**Meet the editor**

Laura Romero-Zerón has been a chemical engineer and a professor in the Chemical Engineering Department at the University of New Brunswick since 2004. She holds a PhD degree in Chemical and Petroleum Engineering from the University of Calgary. Her research interests include optimization of EOR chemical (surfactant) flooding, development of surfactant carrier systems,

polymer flooding, formulation of self-assembling polymeric systems, conformance-improvement treatments, heavy oil recovery, and bitumen upgrading among others. She has published numerous scientific papers, coauthored a book in the area of reservoir conformance improvement, authored three book chapters on EOR, and edited a book on EOR and bioremediation of oil-contaminated sites. Romero-Zerón is an SPE member and holds the US SPE Petroleum Engineering Certification.

## Contents

#### **Preface XI**


## Preface

The global industrial outlook indicates that the commercial application of chemical enhanced oil recovery (cEOR) processes will significantly grow worldwide over the next decade, driven by en‐ ergy security requirements, increasing global oil demand, and technology development.

This release, which is divided into three sections for a total of six chapters, offers a straightfor‐ ward presentation of practical concepts on cEOR. In the first section, Chapter 1 surveys the most commonly applied EOR processes, recent technological improvements, and opportunities for EOR field applications. The second section includes the next four chapters that are focused on cEOR processes such as polymer flooding, polymer gels and foams, surfactant flooding, and mi‐ crobial enhanced oil recovery. The final section containing the sixth chapter describes the electro‐ rheology (ER) technology as an effective approach for modifying the viscosity of crude oils. Each chapter offers wide-ranging information on the corresponding EOR processes, conceptual foun‐ dations of each EOR method, and process benefits and limitations and highlights on the perform‐ ance of some field applications.

The practical-oriented style of this book is intended as a valuable source for a broad audience ranging from field operators, reservoir engineers, reservoir managers, EOR researchers, and other oil field professionals responsible for EOR screening, laboratory testing, managerial decisions, de‐ velopment and planning of strategies, and technical parameters for the customized field applica‐ tion of chemical EOR flooding. It does so by providing crucial knowledge about the basic principles and mechanisms of cEOR processes but also gives practical details to aid the proper process design for field applications. Thus, the level of presentation tends to be practical and real‐ istically suited for readers looking to improve their knowledge and understanding of these proc‐ esses in a concise manner.

Hallmark features of this book include the following:

• Straightforward definitions of the different EOR processes, including the mechanisms responsi‐ ble for incremental oil recovery to guide the decision-making process and the optimum field ap‐ plicability of these processes


• Description of a simple experimental visualization technique for the evaluation of cEOR (i.e., foam) in fractured reservoir formations useful if advanced in situ imaging techniques are not available

• Demonstration of the efficiency of the electrorheology (ER) technology in reducing the viscosity of heavy crude oils through experimental work at laboratory bench scale and field tests.

> **Laura Romero-Zerón** Chemical Engineering Department, University of New Brunswick, NB, Canada

**Enhanced Oil Recovery (EOR) Processes**

#### **EOR Processes, Opportunities and Technological Advancements EOR Processes, Opportunities and Technological Advancements**

Lezorgia Nekabari Nwidee , Stephen Theophilus , Ahmed Barifcani , Mohammad Sarmadivaleh and Stefan Iglauer Lezorgia Nekabari Nwidee, Stephen Theophilus, Ahmed Barifcani, Mohammad Sarmadivaleh and Stefan Iglauer

Additional information is available at the end of the chapter Additional information is available at the end of the chapter

http://dx.doi.org/10.5772/64828

#### **Abstract**

Enhanced oil recovery (EOR) processes are well known for their efficiency in incre‐ menting oil production; however, the selection of the most suitable method to adopt for specific field applications is challenging. Hence, this chapter presents an overview of different EOR techniques currently applied in oil fields, the opportunities associated with these techniques, key technological advancements to guide the decision‐making process for optimum applicability and productivity and a brief review of field applications.

**Keywords:** enhanced oil recovery (EOR), mobility ratio, interfacial tension (IFT), capillary number, viscosity

## **1. Introduction**

#### **1.1. Oil recovery processes**

Oil reservoirs run through series of production stages classified as primary (natural drive mechanism), secondary and tertiary recovery techniques. These stages designate production from a reservoir in a sequential pattern [1] with different recovery efficiencies over time (**Figure 1**). Oil recovery is predominantly influenced by capillary number (*Nc*) at the microscopic scale and mobility ratio (*M*) at the macroscopic scale [2]. Capillary number denotes the ratio of viscous forces to interfacial tension (IFT) forces (Eq. (1)):

© 2016 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited. © 2016 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

**Figure 1.** Reservoir production stages as a function of time [7].

$$N\_{\varepsilon} = V\mu / \sigma \tag{1}$$

where *Nc* represents capillary number; *V* is Darcy's velocity; *µ* is viscosity of displacing fluid; and *σ* is the interfacial tension (IFT) between the displaced and the displacing fluid [2–4]. It has been experimentally shown that an increase in capillary number (from a typical value around 10−7) decreases residual oil saturation. This can be accomplished by an increase in the velocity of the injected fluid (i.e. Darcy's velocity, *V*) and/or viscosity of the displacing fluid (*µ*) and/or a reduction in IFT (*σ*) [5]. However, substantial increase in capillary number is required, thus, surfactant or alkaline flooding [6] is recommended as the most feasible option for micro‐ scale displacement. Mobility ratio (*M*) is the ratio of the mobility of the displacing fluid to the mobility of the displaced fluid Eq. (2)):

$$M = \mathbb{X}\_{\text{log}} \mid \mathbb{X}\_{\text{ad}} \tag{2}$$

and

$$\mathcal{X} = k \mid \mu \tag{3}$$

where *M* is mobility ratio; *λ*ing is displacing fluid mobility; *λ*ed is displaced fluid mobility; *k* is effective permeability (m2 ); and *µ* is fluid viscosity (Pa s) [2]. The stability of displacement, which is of key importance for macroscopic displacement efficiency, is ultimately determined by the mobility ratio (*M*) [2]. If *M* is less than or equal to 1 (*M* ≤ 1), it is considered favourable, and displacement efficiency increases (**Figure 2**); however, if *M* > 1, the mobility ratio is seen as unfavourable [2] and residual oil will be inefficiently displaced.

EOR Processes, Opportunities and Technological Advancements http://dx.doi.org/10.5772/64828 5

**Figure 1.** Reservoir production stages as a function of time [7].

4 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

mobility of the displaced fluid Eq. (2)):

effective permeability (m2

and

/ *N Vµ <sup>c</sup>* =

/ *M* = l l

l

as unfavourable [2] and residual oil will be inefficiently displaced.

 m

where *M* is mobility ratio; *λ*ing is displacing fluid mobility; *λ*ed is displaced fluid mobility; *k* is

which is of key importance for macroscopic displacement efficiency, is ultimately determined by the mobility ratio (*M*) [2]. If *M* is less than or equal to 1 (*M* ≤ 1), it is considered favourable, and displacement efficiency increases (**Figure 2**); however, if *M* > 1, the mobility ratio is seen

s

where *Nc* represents capillary number; *V* is Darcy's velocity; *µ* is viscosity of displacing fluid; and *σ* is the interfacial tension (IFT) between the displaced and the displacing fluid [2–4]. It has been experimentally shown that an increase in capillary number (from a typical value around 10−7) decreases residual oil saturation. This can be accomplished by an increase in the velocity of the injected fluid (i.e. Darcy's velocity, *V*) and/or viscosity of the displacing fluid (*µ*) and/or a reduction in IFT (*σ*) [5]. However, substantial increase in capillary number is required, thus, surfactant or alkaline flooding [6] is recommended as the most feasible option for micro‐ scale displacement. Mobility ratio (*M*) is the ratio of the mobility of the displacing fluid to the

(1)

*ing ed* (2)

= *k* / (3)

); and *µ* is fluid viscosity (Pa s) [2]. The stability of displacement,

**Figure 2.** Displacement fronts during waterflooding for different mobility ratios and pore volumes injected until break‐ through [8].

Oil recovery efficiency is greatly dependent on the microscopic and macroscopic displacement efficiency. Generally, microscopic displacement efficiency measures the extent to which the displacing fluid mobilises the residual oil once in contact with the oil [1, 3, 9], and it is greatly controlled by factors such as rock wettability, relative permeability, IFT and capillary pressure [2]; note that a decrease in oil viscosity, IFT or capillary pressure of the displacing fluid can increase the microscopic efficiency [10].

Macroscopic displacement efficiency, otherwise known as volumetric sweep efficiency, measures the extent to which the displacing fluid is in contact with the oil‐bearing parts of the reservoir (metre to hectometre scale, Eq. (4)) [1, 2, 9, 11], and it is influenced by the rock matrix heterogeneities and anisotropy, displacing and displaced fluid mobility ratio and injection and production well(s) positioning [1, 3]. The product of microscopic (*E*d) and macroscopic (*E*V) displacement efficiency yields the overall displacement efficiency (*E*) of any oil recovery displacement process [1].

$$E = E\_d E\_v \tag{4}$$

and

$$E\_v = E\_i E\_a \tag{5}$$

where *E*<sup>i</sup> is the vertical sweep efficiency [3] and *E*a is the areal sweep efficiency.

Natural drive mechanisms recover oil during the initial or primary production stage of a reservoir by means of the natural energy present in the reservoir without the need of supplying any additional energy [12–15]. These natural mechanisms use the pressure difference between the reservoir and the producing well bottom [15–17]. The total recoverable oil using this method is considered inefficient, as recovery is usually less than 25% of the original oil‐in‐place (OOIP) [2].

Secondary recovery techniques are applied when the natural reservoir drive is depleted ineffectively and inadequately for augmenting production. This technique involves injection of either natural gas or water [3, 12] to stimulate oil wells and maintain reservoir pressure in the injection wells [2, 12]. The injected fluids act as an artificial drive to supplement the reservoir energy [9, 18]. Such fluids boost the flow of hydrocarbon towards the wellhead [19]. If the injected fluid is water, the process is usually termed waterflooding; if the injected fluid is gas, the process usually involves pressure maintenance operations [17, 20]. Gas‐cap expan‐ sion into oil columns (wells) displaces oil immiscibly due to volumetric sweep‐out [1]. Diverse methods are used for fluid injection into oil reservoirs to support the natural forces [17]. Recovery efficiencies in the secondary stage vary from 10 to 40% of the original oil‐in‐place [16, 17, 20]. Other gas processes, whose mechanisms entail oil swelling and viscosity reduction, or favourable phase behaviour [1], are enhanced oil recovery (EOR) processes. Tertiary recovery techniques otherwise called enhanced oil recovery (EOR) processes demonstrate enormous potential in recovering stranded oil trapped at the pore scale after primary and secondary recovery techniques by capillary pressure‐driven snap‐off [21], which leaves behind in the reservoir about one‐third of OOIP [22]. The stranded oil is often located in regions considered inaccessible [23–25]. EOR methods can extract more than half of the total OOIP and signifi‐ cantly more than the primary and secondary recovery methods [26]. Notably, the impact of EOR on oil production is colossal as an increase in recovery factor by only 1% can yield 70 billion barrels of conventional oil reserves globally without the exploitation of unconventional resources [2]. In comparison to primary and secondary recovery methods, EOR undeniably is a better alternative as its contributions to global oil production entails a more economically feasible process.

#### **2. Enhanced oil recovery (EOR)**

Improved oil recovery (IOR) is often erroneously used in place of enhanced oil recovery (EOR). IOR and EOR are two different concepts: IOR is a wider concept that embroils ultimate recovery of oil by any means [2]. The EOR is mainly driven by the ability to recover more oil at an economically feasible production rate [27]. The EOR can be described as a subset of IOR [28]. EOR uses several processes and technologies (**Figure 3**) to increase or uphold recovery from existing fields [29]. These processes often involve the injection of fluid(s) and most recently microbes into a reservoir. These fluids, in turn, supplement the reservoir natural energy for effective oil displacement into the producing well thus yielding an interaction between injected fluid and the reservoir rock/oil system that creates a favourable condition for oil recovery [1]. The key drive for EOR spins around its capability of turning residual cumulative oil into reserves with oil (million barrels) produced from existing fields [30–32], which is achieved by overcoming the physical forces confining hydrocarbons underground (**Table 1**) [1, 33].

**Figure 3.** Classification of EOR techniques.

#### **2.1. Thermal EOR (TEOR)**

and

6 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

where *E*<sup>i</sup>

(OOIP) [2].

feasible process.

**2. Enhanced oil recovery (EOR)**

*E EE v ia* = (5)

is the vertical sweep efficiency [3] and *E*a is the areal sweep efficiency.

Natural drive mechanisms recover oil during the initial or primary production stage of a reservoir by means of the natural energy present in the reservoir without the need of supplying any additional energy [12–15]. These natural mechanisms use the pressure difference between the reservoir and the producing well bottom [15–17]. The total recoverable oil using this method is considered inefficient, as recovery is usually less than 25% of the original oil‐in‐place

Secondary recovery techniques are applied when the natural reservoir drive is depleted ineffectively and inadequately for augmenting production. This technique involves injection of either natural gas or water [3, 12] to stimulate oil wells and maintain reservoir pressure in the injection wells [2, 12]. The injected fluids act as an artificial drive to supplement the reservoir energy [9, 18]. Such fluids boost the flow of hydrocarbon towards the wellhead [19]. If the injected fluid is water, the process is usually termed waterflooding; if the injected fluid is gas, the process usually involves pressure maintenance operations [17, 20]. Gas‐cap expan‐ sion into oil columns (wells) displaces oil immiscibly due to volumetric sweep‐out [1]. Diverse methods are used for fluid injection into oil reservoirs to support the natural forces [17]. Recovery efficiencies in the secondary stage vary from 10 to 40% of the original oil‐in‐place [16, 17, 20]. Other gas processes, whose mechanisms entail oil swelling and viscosity reduction, or favourable phase behaviour [1], are enhanced oil recovery (EOR) processes. Tertiary recovery techniques otherwise called enhanced oil recovery (EOR) processes demonstrate enormous potential in recovering stranded oil trapped at the pore scale after primary and secondary recovery techniques by capillary pressure‐driven snap‐off [21], which leaves behind in the reservoir about one‐third of OOIP [22]. The stranded oil is often located in regions considered inaccessible [23–25]. EOR methods can extract more than half of the total OOIP and signifi‐ cantly more than the primary and secondary recovery methods [26]. Notably, the impact of EOR on oil production is colossal as an increase in recovery factor by only 1% can yield 70 billion barrels of conventional oil reserves globally without the exploitation of unconventional resources [2]. In comparison to primary and secondary recovery methods, EOR undeniably is a better alternative as its contributions to global oil production entails a more economically

Improved oil recovery (IOR) is often erroneously used in place of enhanced oil recovery (EOR). IOR and EOR are two different concepts: IOR is a wider concept that embroils ultimate recovery of oil by any means [2]. The EOR is mainly driven by the ability to recover more oil at an economically feasible production rate [27]. The EOR can be described as a subset of IOR Oil recovery using thermal techniques involve the introduction of heat energy into oil reser‐ voirs. Reservoir temperatures are substantially increased to achieve a significant decrease in oil viscosity [34], which yields a corresponding oil mobility effect. During the process, usually, a shift in rock wettability occurs, which enhances the chances for better oil recovery [29]. Current reports predict that only approximately 30% of the global oil reserves are light oil while the remaining 70% are heavy crude oils [34]. Increasing recovery of these heavier crudes can unlock approximately 300 billion bbl (Bbbl) of oil [35]; thus, TEOR is mainly applicable to heavy and viscous oil formations [34]. The TEOR is considered an effective technique for unlocking such heavy oil reservoirs. Several billion barrels of oil have been recovered using TEOR; for instance, more than 4 Bbbls of oil were produced in the USA through steam flooding (SF) from 1980 to 2002 [36]. Despite its effectiveness in heavy oil formations, TEOR can also be deployed in light oil reservoirs [29]. TEOR is perhaps the best used EOR method for up surging production particularly steam flooding [37], although the environmental footprint is enormous when compared to conventional oil production [29].



**Table 1.** Comprehensive breakdown of EOR processes.

(SF) from 1980 to 2002 [36]. Despite its effectiveness in heavy oil formations, TEOR can also be deployed in light oil reservoirs [29]. TEOR is perhaps the best used EOR method for up surging production particularly steam flooding [37], although the environmental footprint is enormous

> **Technological development**

> THAI, Fast‐ SAGD, NCG‐ SAGD, OTSG, ST‐EOR, GOGD, TAGOGD and TGD

PAM, HPAM, xanthan gum, HPAMAMPS, SAPc

**•** Inexpensive processes **•** Possibilities for incremental **•** High tendency for chemical incompatibi lity **•** Issues with creating contact with the formation oil

oil

HPAI **•** Suitable in

both deeper and shallow reservoirs **•** Production is increased through a combination of mechanisms

**Merits Demerits References**

**•** Eco‐

unfriendly (emissions from surface steam generation) **•** Mobility control issues **•** Expensive cost of operation

[1, 28, 29, 37, 41, 42, 54, 61, 63 – 66]

[1, 25, 63], [68, 67, 86] [88, 109, 117–120]

when compared to conventional oil production [29].

8 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

**applications** 

India, Romania, Canada, U.S.

Brazil, Venezuela, U.S., Indo nesia, the former Soviet Union, Trinidad, Oman, China, Tobago, Canada,

Canada, Venezuela

Brazil, China, Oman, Canada, Suriname, Mexico, Argentina, Austria, U.S, India

Indonesia, Bahrain, U.S.

**Mechanisms Field**

Air is injected into the reser voir as a dry process or with water (wet process) and oil ignition is performed alongside

Steam is injec ted into a well over a period Steam is injected into dedicated injection wells to displace oil towards a production well

Oil is heated by circulating steam at a temperature that improves oil flow

Polymers are injected into the reservoir followed by water

Separate surfactant slug and polymer slug are injected into the reservoir

Aqueous surfactants

**EOR method**

*In Situ* combustion (ISC)

Steam injection **•** Cyclic steam stimu lation **•** Steam flooding

**•** Steam assisted gravity drai nage ( SAGD)

Polymer flooding

Surfactant‐ polymer (SP) flooding

Surfactant flooding

**Chemical EOR (CEOR)**

**Thermal EOR (TEOR)**

#### *2.1.1. Evolution of thermal EOR techniques*

The early history of thermal recovery dates back to 1865 [34]; however, the first industrially significant TEOR project was conducted in 1931 close to Woodson, TX [38]. This was a steam injection test [34]. An advanced steam injection (cyclic steam injection) was later discovered upon release of accrued reservoir fluid pressure through a retrograde flow of injected steam; that coincidentally resulted in considerable oil production instead of the expected steam [34]. Subsequent large‐scale TEOR projects were conducted in Tia Juana [39] and Mene Grande fields, both located in Venezuela. Upon discovery of the Venezuelan field (Mene Grande), steam flooding was selected as the optimal TEOR method, and a continuous steam injection over several weeks was deployed, with the wells shut in for short time intervals to support heat transfer within the reservoir [29].

#### *2.1.2. Thermal EOR classification*

The two key types of thermal EOR techniques are *in situ* combustion (ISC) and steam injection. Steam injection includes three basic categories [28]: namely, cyclic steam stimulation (CSS; huff‐and‐puff), steam flooding and steam‐assisted gravity drainage (SAGD).

#### *2.1.3. Mechanisms of TEOR techniques*

#### *2.1.3.1. In situ combustion*

In *in situ* combustion, air is injected into viscous oil reservoirs to generate heat by burning a portion of the existing oil [28, 29, 40, 41]. The ISC can be a forward or reverse process, which is mainly dependent on the combustion front. The combustion fronts move in the direction of the injected air (forward combustion) or away from the air (reverse combustion). In practice, forward combustion process is generally adopted. Oil recovery is achieved using this process through the energy generated by the combustion reaction between the injected air and the oil:


**Process benefits**. ISC efficiently displaces oil in the regions contacted by the hot fluids in the advancing front, oil recovery rates are mostly high and this process is more cost effective than steam flooding as it uses air. There is a negligible effect of reservoir permeability on the ISC processes, which is effective for oil recovery in various formations as follows [10]:


**•** Light oils: >30° API.

*2.1.1. Evolution of thermal EOR techniques*

10 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

heat transfer within the reservoir [29].

*2.1.3. Mechanisms of TEOR techniques*

downstream which mixes with the crude oil.

**•** Deep reservoirs: depths up to 11,000 ft.

**•** Shallow reservoirs: <1500 ft.

*2.1.3.1. In situ combustion*

the well [10, 42].

*2.1.2. Thermal EOR classification*

The early history of thermal recovery dates back to 1865 [34]; however, the first industrially significant TEOR project was conducted in 1931 close to Woodson, TX [38]. This was a steam injection test [34]. An advanced steam injection (cyclic steam injection) was later discovered upon release of accrued reservoir fluid pressure through a retrograde flow of injected steam; that coincidentally resulted in considerable oil production instead of the expected steam [34]. Subsequent large‐scale TEOR projects were conducted in Tia Juana [39] and Mene Grande fields, both located in Venezuela. Upon discovery of the Venezuelan field (Mene Grande), steam flooding was selected as the optimal TEOR method, and a continuous steam injection over several weeks was deployed, with the wells shut in for short time intervals to support

The two key types of thermal EOR techniques are *in situ* combustion (ISC) and steam injection. Steam injection includes three basic categories [28]: namely, cyclic steam stimulation (CSS;

In *in situ* combustion, air is injected into viscous oil reservoirs to generate heat by burning a portion of the existing oil [28, 29, 40, 41]. The ISC can be a forward or reverse process, which is mainly dependent on the combustion front. The combustion fronts move in the direction of the injected air (forward combustion) or away from the air (reverse combustion). In practice, forward combustion process is generally adopted. Oil recovery is achieved using this process through the energy generated by the combustion reaction between the injected air and the oil: **•** The oil is ignited and air is constantly injected to propagate the combustion front away from

**•** The fluids advance towards the production wells [42] and the lighter ends are transported

**•** The heavy ends are burned resulting in the production of large amount of flue gases [10, 42]. **Process benefits**. ISC efficiently displaces oil in the regions contacted by the hot fluids in the advancing front, oil recovery rates are mostly high and this process is more cost effective than steam flooding as it uses air. There is a negligible effect of reservoir permeability on the ISC

huff‐and‐puff), steam flooding and steam‐assisted gravity drainage (SAGD).

**•** Reservoir fluids are displaced at the elevated temperatures (600–700°C) zone.

processes, which is effective for oil recovery in various formations as follows [10]:

**•** Heavy oils: 10–20° API.

**Process limitations**. Compressed air must be used and the operational variables are complex and difficult to control (i.e. controlling the advancing combustion front) [1]. The ISC process requires very high temperatures, in the order of 700°C and above. The high temperature of this process often damage production tubing and equipment (i.e. failure of pumps, valves, etc.) [43]. Furthermore, an adequate knowledge (i.e. rigorous laboratory evaluation) of the ISC dynamics is required for understanding the stability of the combustion front [44].

#### *2.1.3.2. Steam injection*

Steam injection entails the injection of steam into shallow, thick and permeable reservoirs containing high viscosity crude [32]. Steam injection processes include steam flooding, cyclic steam stimulation (CSS) and steam‐assisted gravity drainage.

In steam flooding, steam is injected into dedicated injection wells, so that the reservoir fluids are driven towards a separate set of producers [45]. Oil recovery is achieved through:


**Process benefits**. The introduction of steam into the reservoir efficiently displaces oil [47] by heating the oil to a temperature at which its viscosity is sufficiently decreased [48]. Steam flooding is the most applied EOR technique worldwide because it is very effective in rendering high oil recovery ratios. Higher sweep efficiency is achieved with steam flooding than with the application of cyclic steam stimulation or CCS.

**Process limitations**. Steam flooding is an expensive venture. Significant heat loss (i.e. heating of injection tubing, heating of overburden and under burden rock, etc.) occurs during the extensive steam injection periods [43]. Avoidance of sand plugging at the bottom hole [49], prevention of steam channelling [50] and improvement of steam sweep efficiency [51] are still key challenges of steam flooding operations, especially in super heavy oil formation. Early steam breakthrough at the producing wells decreases the rate of recoverable oil [49].

Cyclic steam stimulation is applied in three stages as follows [45, 52]:


As the reservoir temperature declines, the oil flow rate drops significantly; at this point in time, another cycle of CSS is applied to re‐attain the high oil production rates [52, 53]. CCS applied for several cycles, until commercial oil flow rates are obtained.

**Process benefits**. CSS is effective in reducing the viscosity of the oil due to the cyclic application of steam in the same well with potential for substantial oil recovery, especially in heavy oil reservoirs having thick pay zones (>15 m) [54]. However, the CSS oil recovery factor is low in comparison to steam flooding.

**Process limitations**. The CSS process is complex. Excessive heat loss occurs and the radius of the heated zone is insignificant [55]. Application of CSS in thin heavy oil (<6 m) reservoirs is uneconomical [54].

In steam‐assisted gravity drainage (SAGD), steam is constantly injected using two horizontal wells—the upper steam injector well and the lower producer well (collects the heated oil and water). The injector and producer wells counterbalance the effect of high viscosity of the oil through prolonged steam (heat)—oil contact and provide the drive force for the movement of the oil towards the producer well [56]. SAGD is influenced by the gravity drainage of the heated oil and condensed water [57]. The process efficiency is predominantly controlled by fluid mobility. In SAGD, oil recovery is achieved when:


and the oil production rate is controlled by the expansion of the steam chamber [56].

**Process benefits**. SAGD is very efficient in recovering bitumen and heavy oil. Oil production increases with the increase in oil pay thickness (>15 m) [60], thus production can be considered economical.

**Process limitations**. Possible loss of injected steam due to poor process control which can lead to low oil recovery rate. SAGD oil production is considered uneconomical in pay zones with thickness <15 m [61], due to the high steam‐to‐oil ratio (SOR) required.

This process is susceptible to low mobility control and rapid gravity segregation. The mobility control is considered a limitation as the steam viscosity is much lower than the viscosity of the oil and water. Similarly, the density of steam is much lower than the density of oil and water [1]. Thus, an upward migration of steam to the top of the reservoir often occurs and the steam overrides a larger part of the heavy oil zone. This issue can be partially controlled by heat conduction away from the steam contact [1]. Other limitations of the SAGD process are the significant production of CO2 emissions during steam generation at surface facilities, heat losses and equipment problems due to the high temperature of the process [1].

#### *2.1.4. TEOR field applications*

As the reservoir temperature declines, the oil flow rate drops significantly; at this point in time, another cycle of CSS is applied to re‐attain the high oil production rates [52, 53]. CCS

**Process benefits**. CSS is effective in reducing the viscosity of the oil due to the cyclic application of steam in the same well with potential for substantial oil recovery, especially in heavy oil reservoirs having thick pay zones (>15 m) [54]. However, the CSS oil recovery factor is low in

**Process limitations**. The CSS process is complex. Excessive heat loss occurs and the radius of the heated zone is insignificant [55]. Application of CSS in thin heavy oil (<6 m) reservoirs is

In steam‐assisted gravity drainage (SAGD), steam is constantly injected using two horizontal wells—the upper steam injector well and the lower producer well (collects the heated oil and water). The injector and producer wells counterbalance the effect of high viscosity of the oil through prolonged steam (heat)—oil contact and provide the drive force for the movement of the oil towards the producer well [56]. SAGD is influenced by the gravity drainage of the heated oil and condensed water [57]. The process efficiency is predominantly controlled by fluid

**•** The upper horizontal well injects steam into a chamber at a temperature that significantly

**•** At the edge of the chamber, heat is released through condensation [57] and reduction in oil

**•** Then the heated oil drains by gravity through the steam chamber towards the production

**Process benefits**. SAGD is very efficient in recovering bitumen and heavy oil. Oil production increases with the increase in oil pay thickness (>15 m) [60], thus production can be considered

**Process limitations**. Possible loss of injected steam due to poor process control which can lead to low oil recovery rate. SAGD oil production is considered uneconomical in pay zones with

This process is susceptible to low mobility control and rapid gravity segregation. The mobility control is considered a limitation as the steam viscosity is much lower than the viscosity of the oil and water. Similarly, the density of steam is much lower than the density of oil and water [1]. Thus, an upward migration of steam to the top of the reservoir often occurs and the steam overrides a larger part of the heavy oil zone. This issue can be partially controlled by heat conduction away from the steam contact [1]. Other limitations of the SAGD process are the significant production of CO2 emissions during steam generation at surface facilities, heat

thickness <15 m [61], due to the high steam‐to‐oil ratio (SOR) required.

losses and equipment problems due to the high temperature of the process [1].

**•** The injection of steam and production of oil occurs concurrently and constantly [59] and the oil production rate is controlled by the expansion of the steam chamber [56].

reduces the viscosity of the heavy oil and/or bitumen, which improves oil flow.

applied for several cycles, until commercial oil flow rates are obtained.

comparison to steam flooding.

12 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

mobility. In SAGD, oil recovery is achieved when:

uneconomical [54].

viscosity occurs.

economical.

well (lower horizontal well) [58].

TEOR, specifically steam injection, and *in situ* combustion have shown great potential worldwide. Steam injection projects have been reported in California, Indonesia, Oman, Alberta (Canada), Venezuela and the former Soviet Union [37]. Field trials of steam injection have been conducted in Brazil, China, Trinidad and Tobago [29]. CSS has been applied in California, Alberta and Venezuela. ISC projects have been reported in Romania, the USA, Canada and India [29]. SAGD is mainly carried out in Alberta, Canada for the recovery of bitumen. SAGD has also been tried in Venezuela, although it has not been very successful [29, 37].

#### *2.1.5. Technological advancement in TEOR techniques*

New areas of research have been considered to tackle fiscal and environmental issues related to TEOR processes (i.e. huge capital expenditures and significant generation of CO2 emissions). These recent advances comprise the development or improvement of several TEOR process such as the Toe‐to‐Heel Air Injection (THAI) process [62], Fast‐SAGD [60], Enclosed Trough Solar Once‐Through Steam Generator (OTSG) EOR System [64], Solar Thermal Enhanced Oil Recovery (ST‐EOR) [29], Gas‐Oil Gravity Drainage (GOGD), Thermally Assisted Gas‐Oil Gravity Drainage (TAGOGD), Tertiary Gravity Drainage (TGD) [65] and High‐Pressure Air Injection (HPAI) [29, 63].

#### **2.2. Chemical EOR techniques (CEOR)**

In chemical EOR (CEOR) techniques, oil is recovered through the injection of chemicals [62, 66, 67]. CEOR is predominantly suitable for heavily depleted and flooded formations (i.e. mature reservoirs) [68]. Typical chemicals are polymers, surfactants, alkalis and formulated mixtures thereof [62, 33, 69]. The efficiency of such formulations is normally screened in laboratory studies [69– 71] and each chemical has different effects on oil production [72]. For example, the application of surfactants or alkali or its mixtures can substantially reduce the interfacial tension between brine and oil [69, 73–75]; significantly improving the microscopic sweep efficiency at the pore scale [76, 77]. Mobility ratios can be considerably improved by adding polymers to the injected water [62, 78]. The addition of polymer to the injection brine increases the viscosity of the aqueous phase, which leads to an improved macroscopic displacement, as water under‐riding is lessened [79]. The addition of surfactants improves the microscopic displacement efficiency through: (a) the reduction of the oil‐water interfacial tension [72, 80, 81] and (b) the production of oil‐water emulsions [62], which mobilises residual oil. The addition of alkalis induces the *in situ* formation of natural surfactants by reacting with the acidic components contained in the crude oil (generally heavy oils). These natural surfac‐ tants function in the reservoir in the same fashion as synthetic surfactants [62, 82].

#### *2.2.1. Evolution of chemical EOR*

In the last few years, CEOR has been undergoing a rebirth. Since the 1960s, polymer flooding has been globally the most widely used of the three types of CEOR techniques [83]. CEOR has

experienced significant chemical developments since its first applications in the 1960s and 1970s [83]. For example, micellar flooding in the 1970s and 1980s was very effective in light and medium oil reservoirs, where CEOR processes applied micellar floodings at surfactant concentrations ranging from 2 to 12% [83]. However, the concentrations of surfactant used have notably decreased to values ranging from 0.1 to 0.5% [84]; while at the same time, micellar floodings at these low surfactant concentrations have demonstrated significantly increased efficiency. In the face of the current oil price instability, interest in surfactant for CEOR processes, have maintained a constant growth trend [84]. However, at present, the high cost of surfactants makes very difficult the economic justification for field applications of surfactant flooding.

#### *2.2.2. Chemical EOR classification*

The most common CEOR techniques are polymer, surfactant, alkaline, surfactant‐polymer (SP) and alkaline‐surfactant‐polymer (ASP) flooding.

#### *2.2.3. CEOR techniques and oil recovery mechanisms*

#### *2.2.3.1. Polymer flooding*

For several decades, hydrogel polymers have been used for mobility control. Likewise, polymers in combination with surfactants and alkalis have been applied over the years to improve both the microscopic and macroscopic sweep efficiency [85]. In recent times, several new polymers for EOR (**Table 2**) have been developed such as synthetic polymers (i.e. polyacrylamide or PAM) (**Figure 4**), hydrolysed polyacrylamide (HPAM), biopolymers (i.e. xanthan gum) and superabsorbent polymer composite (SAPC) [4, 66, 85].



**Table 2.** Effective polymers for EOR processes.

experienced significant chemical developments since its first applications in the 1960s and 1970s [83]. For example, micellar flooding in the 1970s and 1980s was very effective in light and medium oil reservoirs, where CEOR processes applied micellar floodings at surfactant concentrations ranging from 2 to 12% [83]. However, the concentrations of surfactant used have notably decreased to values ranging from 0.1 to 0.5% [84]; while at the same time, micellar floodings at these low surfactant concentrations have demonstrated significantly increased efficiency. In the face of the current oil price instability, interest in surfactant for CEOR processes, have maintained a constant growth trend [84]. However, at present, the high cost of surfactants makes very difficult the economic justification for field applications of surfactant

The most common CEOR techniques are polymer, surfactant, alkaline, surfactant‐polymer (SP)

For several decades, hydrogel polymers have been used for mobility control. Likewise, polymers in combination with surfactants and alkalis have been applied over the years to improve both the microscopic and macroscopic sweep efficiency [85]. In recent times, several new polymers for EOR (**Table 2**) have been developed such as synthetic polymers (i.e. polyacrylamide or PAM) (**Figure 4**), hydrolysed polyacrylamide (HPAM), biopolymers (i.e.

> **EOR application**

**•** Used mainly for mobility control **•** Used in combination with surfactants and alkali for improvement of sweep efficiency

**•** Increases the brine viscosity **•** Improves EOR performance

**References**

[4, 66, 85]

[85]

xanthan gum) and superabsorbent polymer composite (SAPC) [4, 66, 85].

pseudo plastic fluids **•** The fluid viscosity is a function of shear rate

**•** First synthetic polymer used for thickening aqueous

mineral surfaces

**•** The thickening potentials exist in its large molecular weight **•** >High adsorption capacity on

solutions

**Polymer description**

flooding.

*2.2.2. Chemical EOR classification*

*2.2.3.1. Polymer flooding*

**Polymers Molecular**

Polyacrylamide (PAM)

**weight**

>1 × 106 g/mol

Hydrogel **•** Non‐newtonian or

and alkaline‐surfactant‐polymer (ASP) flooding.

14 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

*2.2.3. CEOR techniques and oil recovery mechanisms*

Among these polymers, HPAM (**Figure 4**) remains the most effective and commonly used polymer for enhanced oil recovery. According to Sheng [4], the effectiveness of HPAM relies in the following chemical features: (1) the lack of oxygen single bonds (‐O‐) in the polymer backbone (carbon chain) provides thermal stability; (2) the presence of non‐ionic hydrophilic group (i.e. ‐CONH2) promotes chemical stability and (3) the carboxyl group (‐COO‐) resulting from the hydrolysis of the amide groups reduces the adsorption tendency of HPAMs onto rock surfaces and increases its viscosity.

Other characteristics that makes HPAM very attractive for EOR includes: (1) fairly easy application with great potential for incremental oil at standard reservoir conditions (i.e. low temperatures and low salinity and hardness concentration); (2) availability of the polymer in various molecular range (>20 million Da); (3) the cost of the polymer is relatively low; and (4) its viscosifying and psychochemical characteristics [85].

**Figure 4.** Structure of: (a) polyacrylamide (PAM), and (b) partially hydrolysed polyacrylamide (HPAM) (refer to **Table 2**).

Xanthan gum is a biopolymer also commonly used for EOR applications. The main limitation of this biopolymer is its vulnerability to microbial degradation. Salt compliant microbes (aerobic and anaerobic) have the potential to degrade the xanthan gum chains, which results in viscosity loss [86–88]. Therefore, biocides are injected alongside with xanthan gum to avert microbial degradation [85]. However, xanthan performs remarkably well in brines having high salinity concentrations [85]. Generally, high salinity brines (i.e. 10,000 ppm TDS) polyacryla‐ mide co‐polymers shows lower viscosities than biopolymers [4]. Nonetheless, HPAMs have better potential for reducing the water relative permeability than xanthan during flow through formation rocks.

In polymer flooding, polymers (dissolved in water) are injected into the reservoir, followed by a long‐term waterflooding, which is performed to drive the slug and the oil bank in the direction of the production wells. The addition of polymer to the injected brine increases the viscosity of the aqueous phase and reduces the effective permeability to water due to polymer retention (adsorption and mechanical trapping) in the formation rock.

The main objective of polymer flooding is to lower the mobility ratio of the waterflooding process. It is well established that the lower the mobility ratio, the more stable the displacing fluid front, and the more efficient the macroscopic displacement process. Therefore, mobility ratio (*M*) should be controlled to values less than one (*M* < 1) to prevent the onset of viscous fingering of the water phase through the oil phase, which will result in unswept regions, where oil is left behind the displacement front [1, 77].

The overall mechanisms of oil recovery by polymer flooding are as follows:


**Process benefits**. Polymers are effective brine viscosifying agents [85] and successfully reduced the effective permeability to brine (i.e. polymer retention). Overall, polymer flooding is a cost‐ effective EOR process.

**Process limitations**. Some of the limitations of polymer flooding are their susceptibility of polymers to thermal (i.e. high temperature reservoirs), chemical (i.e. high salinity and hardness concentration in the injected and formation brine), mechanical and bacterial degradation. Some polymer systems are incompatible with the reservoir fluids and conditions (i.e. temperature). The application of polymer flooding in low permeability rocks may cause problems of injectivity and formation plugging [85].

#### *2.2.3.2. Surfactant flooding*

various molecular range (>20 million Da); (3) the cost of the polymer is relatively low; and (4)

**Figure 4.** Structure of: (a) polyacrylamide (PAM), and (b) partially hydrolysed polyacrylamide (HPAM) (refer to

Xanthan gum is a biopolymer also commonly used for EOR applications. The main limitation of this biopolymer is its vulnerability to microbial degradation. Salt compliant microbes (aerobic and anaerobic) have the potential to degrade the xanthan gum chains, which results in viscosity loss [86–88]. Therefore, biocides are injected alongside with xanthan gum to avert microbial degradation [85]. However, xanthan performs remarkably well in brines having high salinity concentrations [85]. Generally, high salinity brines (i.e. 10,000 ppm TDS) polyacryla‐ mide co‐polymers shows lower viscosities than biopolymers [4]. Nonetheless, HPAMs have better potential for reducing the water relative permeability than xanthan during flow through

In polymer flooding, polymers (dissolved in water) are injected into the reservoir, followed by a long‐term waterflooding, which is performed to drive the slug and the oil bank in the direction of the production wells. The addition of polymer to the injected brine increases the viscosity of the aqueous phase and reduces the effective permeability to water due to polymer

The main objective of polymer flooding is to lower the mobility ratio of the waterflooding process. It is well established that the lower the mobility ratio, the more stable the displacing fluid front, and the more efficient the macroscopic displacement process. Therefore, mobility ratio (*M*) should be controlled to values less than one (*M* < 1) to prevent the onset of viscous fingering of the water phase through the oil phase, which will result in unswept regions, where

**•** Decreasing of the water‐oil mobility ratio that improves the macroscopic sweep efficiency.

retention (adsorption and mechanical trapping) in the formation rock.

The overall mechanisms of oil recovery by polymer flooding are as follows:

**•** Decreasing of the effective permeability to water due to polymer retention.

oil is left behind the displacement front [1, 77].

**•** Increasing of the water viscosity.

its viscosifying and psychochemical characteristics [85].

16 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

**Table 2**).

formation rocks.

Surfactants are amphiphilic in nature (hydrophobic and hydrophilic) and are soluble in water and organic solvents. Surfactants effectively reduce the interfacial tension (IFT) between oil and water (i.e. brine). Four basic categories of surfactants (**Table 3**) exist: anionic, cationic, non‐ ionic and zwitterionic [91, 92].


**Table 3.** Effective EOR surfactants [4, 194].

In surfactant flooding applications, a dilute aqueous surfactant solution [93] is injected into the reservoir. Mechanistically, the injected surfactant migrates to the oil‐water interface reduces the interfacial tension (IFT) between oil and water and essentially increases the miscibility of these phases [3]. To put this into perspective, in a typical waterflooding process, IFT is approximately 30 mN/m; the addition of small concentrations of surfactant (in the range of 0.1–5.0 wt%) to the injected water [1–3, 33, 94, 95] can significantly reduce IFT to values of 0.01 mN/m or lower [33]. The critical micelle concentration (CMC), phase behaviour and oil solubilisation ratio [97] are key parameters for the characterisation of the efficiency of the surfactant formulation. For effective oil displacement:


**Process benefits**. Effective reduction of the interfacial tension between brine and water that significantly enhances the microscopic sweep efficiency.

**Process limitations**. The achievement of ultra‐low IFT for effective residual oil mobilisation is a complex process. Large amounts of surfactants are required to achieve substantial oil recovery. The viscosity of the surfactant formulation is often lower than that the viscosity of the oil, thus, to augment the viscosity of the surfactant slug, the addition of polymers to the surfactant formulation is required. The high cost of surfactants makes its deployment in the field highly dependent on oil price [97].

#### *2.2.3.3. Alkaline flooding*

Alkaline flooding involves the injection of an aqueous solution of alkaline chemical such as sodium hydroxide, sodium carbonate or sodium orthosilicate in a slug form [2, 98, 99] (**Table 4**); the most commonly used alkaline chemical is sodium hydroxide [3].


**Table 4.** Effective alkaline chemicals for EOR [4].

During alkaline flooding, the alkaline solution and organic acids present in the crude oil react to form natural surfactants *in situ*, which cause the reduction of IFT between the brine and oil. Natural surfactants induce the formation of oil and water emulsions and wettability alteration of the reservoir rock [3, 93, 100]. All these physicochemical interactions occur at the oil‐water rock interfaces, which invariably improves oil recovery.

**Process benefits**. Alkaline flooding shows potential for heavy oil recovery in thin formations [101]. This process promotes effective IFT reduction and crude oil emulsification. Overall, alkaline flooding is characterised for low operational costs.

**Process limitations**. Scale formation is a serious issue during alkaline flooding. Furthermore, the low viscosity of the alkaline solution is associated with the occurrence of unfavourable fingering and poor volumetric sweep efficiency [102].

## *2.2.3.4. Surfactant‐polymer (SP) flooding*

solubilisation ratio [97] are key parameters for the characterisation of the efficiency of the

**•** This leads to the mobilisation of the residual oil and creation of oil banks, which allows the

**Process benefits**. Effective reduction of the interfacial tension between brine and water that

**Process limitations**. The achievement of ultra‐low IFT for effective residual oil mobilisation is a complex process. Large amounts of surfactants are required to achieve substantial oil recovery. The viscosity of the surfactant formulation is often lower than that the viscosity of the oil, thus, to augment the viscosity of the surfactant slug, the addition of polymers to the surfactant formulation is required. The high cost of surfactants makes its deployment in the

Alkaline flooding involves the injection of an aqueous solution of alkaline chemical such as sodium hydroxide, sodium carbonate or sodium orthosilicate in a slug form [2, 98, 99] (**Table**

**•** Better IFT reduction potentials than sodium hydroxide in hard water

During alkaline flooding, the alkaline solution and organic acids present in the crude oil react to form natural surfactants *in situ*, which cause the reduction of IFT between the brine and oil. Natural surfactants induce the formation of oil and water emulsions and wettability alteration of the reservoir rock [3, 93, 100]. All these physicochemical interactions occur at the oil‐water

**Process benefits**. Alkaline flooding shows potential for heavy oil recovery in thin formations [101]. This process promotes effective IFT reduction and crude oil emulsification. Overall,

**•** Weaker alkali in comparison to sodium hydroxide and sodium orthosilicate

**•** Reduces water hardness through formation of silicates which are less soluble than the

**4**); the most commonly used alkaline chemical is sodium hydroxide [3].

**•** Most commonly used alkaline for EOR

**•** Corrosion and scale formation issues

**•** Precipitation or scale formation issues

**•** Corrosion and scale formation issues

**•** Used for IFT reduction

hydroxides

rock interfaces, which invariably improves oil recovery.

alkaline flooding is characterised for low operational costs.

surfactant formulation. For effective oil displacement:

**•** The injected slugs must attain ultra‐low IFT.

18 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

continuous phase flow of oil and water [96].

field highly dependent on oil price [97].

*2.2.3.3. Alkaline flooding*

Sodium hydroxide

Sodium orthosilicate

Sodium carbonate Na2CO3

NaOH

Na4O4Si

**Alkaline Characteristics**

**Table 4.** Effective alkaline chemicals for EOR [4].

significantly enhances the microscopic sweep efficiency.

**•** Dilute aqueous surfactant solutions are injected in slugs.

In surfactant‐polymer flooding, separate surfactant and polymer slugs are injected into the reservoir. The alternate injections of surfactant and polymer slugs have the potential to sweep larger reservoir volumes and to increase oil displacement efficiency.

The mobility control is established during SP flooding by injecting the chemical slugs according to the following injection scheme: surfactant slug, polymer slug [103], polymer buffer (to protect the integrity of the polymer slug) and chase water [104].

Accurate formulation of the surfactant‐polymer (SP) mixture can promote capillary number increase (due to the presence of surfactants through IFT reduction) and reduction in mobility ratio. However, an incompatible SP formulation can cause surfactant and polymer phase separation even when oil is not present [103]. Two essential factors for consideration during SP flooding are: (a) IFT reduction and (b) viscosity increase [13, 104, 105]. In addition, the effective permeability to water is reduced due to polymer retention in the formation rock [106]. Therefore, an overall improvement of mobility ratio and sweep efficiency [106, 107] is achieved rendering incremental oil recovery [108].

**Process benefits**. Accurate SP formulation can achieve ultra‐low oil‐brine IFT, which promotes effective displacement of residual oil saturation.

**Process limitations**. The main limitation of the SP flooding process is chemical incompatibility among the additives and brine (injection and formation brine).

#### *2.2.3.5. Alkaline‐surfactant‐polymer (ASP) flooding*

ASP flooding uses alkali‐surfactant‐polymer cocktails for further improvement of oil recovery efficiency [107, 109]. The key reasons for the combination of the three chemicals are IFT reduction and mobility ratio improvement [2]. Alkali decreases surfactant adsorption onto rock surface through an increase of the negative charge density at the rock surface yielding a more water‐wet surface [95, 110]. Surfactant decreases the IFT [111] between oil and brine, which promotes oil mobilisation and oil bank formation, whereas polymer offers mobility control [106]. The amount of chemical consumed per unit volume of oil produced during ASP flooding is usually low when the three chemical slugs (alkaline, surfactant and polymer) are injected in sequence or as a single slug [2, 100].

**Process benefits**. ASP is a cost‐effective process. The synergistic effects of the ASP mixture make this process attractive for EOR applications.

**Process limitations**. Some of the limitations of the ASP process are related to issues with chemical separation, emulsions instability and scale formation that could make the process complex.

#### *2.2.4. Technological advancement in CEOR techniques*

Research has led to recent advances in CEOR aiming to improve the economic feasibility of the field application of CEOR processes. Particularly, the development and improvement of effective polymers for EOR is noticeable. Some of these polymers include polyacrylamides (PAM) [66, 85], hydrolysed polyacrylamide (HPAM—the most commonly used polymer) [66, 85], biopolymers (i.e. xanthan gum) [4, 85] and superabsorbent polymer composite (SAPC) [86]. Other recent modified polymers are hydrolysed polyacrylamide‐acrylamido methyl propane sulfonic acid (HPAM‐AMPS) co‐polymers, and sulphonated polyacrylamides, which are produced as powders and self‐inverting emulsions that are suitable for high temperature applications ranging from 104 to 120°C [85].

#### *2.2.5 CEOR field applications*

CEOR projects implemented in the United States in the 1980s did not show technical and/or economic success. However, in the last decade CEOR successes, specifically polymer flooding, which is the most applied CEOR method worldwide [112], has been reported in China [28, 113], along with ASP flooding successfully implemented at pilot and commercial scale in the Daqing, Xinjiang and Shengli oil fields in China [114].

Polymer flooding has also been reported in Canada (East Bodo field), Oman (Marmul field), Suriname (Tambaredjo field) and Mexico (Vacuum field) [115]. Other countries that have reported successful applications of ASP flooding are India (Viraj field), Venezuela (Lagomar LVA field) and in the United States (Cambridge Minnelusa field, the West Kiehl and Tanner fields in Wyoming, and Lawrence field in Illinois) [115, 116]. Surfactant flooding has been reported in Indonesia (Baturaja formation in the Semoga field), Bahrain (Mauddud field), Texas (Yates field and the Cretaceous Upper Edwards reservoir) and Wyoming (Cottonwood Creek field). Surfactant‐polymer flooding has been reported in China (Gudong field) [115]. Alkali flooding has been reported in Hungary (H field), India (North Gujarat field), Russia (W field) and the United States (Whittier field in California) [115].

#### **2.3. Gas injection EOR (GEOR) technique**

In EOR gas injection (**Figure 5**), oil is displaced towards the production wells by injecting gas. Two predominant factors determine the success of this process: (a) the displacement efficiency and (b) the sweep efficiency. The displacement efficiency is the percentage of oil displaced by the injected fluid, whereas sweep efficiency accounts for the reservoir volume contacted (swept by) the injected fluids [12]. Gases commonly used for GEOR are carbon dioxide, hydrocarbon gases and nitrogen [62]. Among these gases, CO2 is the most frequently applied and it accounts for over 50% of the GEOR production [67, 117]. For instance, in 2009, Ferguson et al. [118] reported that 101 GEOR projects in the US produced approximately 250,000 barrels of oil per day. In the United States, CO2‐EOR has been considered the best GEOR method to produce incremental EOR [119]. Nevertheless, GEOR processes are often associated with viscous and density fingering [1, 120].

**Figure 5.** CO2 gas injection EOR [121].

*2.2.4. Technological advancement in CEOR techniques*

20 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

applications ranging from 104 to 120°C [85].

Daqing, Xinjiang and Shengli oil fields in China [114].

and the United States (Whittier field in California) [115].

**2.3. Gas injection EOR (GEOR) technique**

density fingering [1, 120].

*2.2.5 CEOR field applications*

Research has led to recent advances in CEOR aiming to improve the economic feasibility of the field application of CEOR processes. Particularly, the development and improvement of effective polymers for EOR is noticeable. Some of these polymers include polyacrylamides (PAM) [66, 85], hydrolysed polyacrylamide (HPAM—the most commonly used polymer) [66, 85], biopolymers (i.e. xanthan gum) [4, 85] and superabsorbent polymer composite (SAPC) [86]. Other recent modified polymers are hydrolysed polyacrylamide‐acrylamido methyl propane sulfonic acid (HPAM‐AMPS) co‐polymers, and sulphonated polyacrylamides, which are produced as powders and self‐inverting emulsions that are suitable for high temperature

CEOR projects implemented in the United States in the 1980s did not show technical and/or economic success. However, in the last decade CEOR successes, specifically polymer flooding, which is the most applied CEOR method worldwide [112], has been reported in China [28, 113], along with ASP flooding successfully implemented at pilot and commercial scale in the

Polymer flooding has also been reported in Canada (East Bodo field), Oman (Marmul field), Suriname (Tambaredjo field) and Mexico (Vacuum field) [115]. Other countries that have reported successful applications of ASP flooding are India (Viraj field), Venezuela (Lagomar LVA field) and in the United States (Cambridge Minnelusa field, the West Kiehl and Tanner fields in Wyoming, and Lawrence field in Illinois) [115, 116]. Surfactant flooding has been reported in Indonesia (Baturaja formation in the Semoga field), Bahrain (Mauddud field), Texas (Yates field and the Cretaceous Upper Edwards reservoir) and Wyoming (Cottonwood Creek field). Surfactant‐polymer flooding has been reported in China (Gudong field) [115]. Alkali flooding has been reported in Hungary (H field), India (North Gujarat field), Russia (W field)

In EOR gas injection (**Figure 5**), oil is displaced towards the production wells by injecting gas. Two predominant factors determine the success of this process: (a) the displacement efficiency and (b) the sweep efficiency. The displacement efficiency is the percentage of oil displaced by the injected fluid, whereas sweep efficiency accounts for the reservoir volume contacted (swept by) the injected fluids [12]. Gases commonly used for GEOR are carbon dioxide, hydrocarbon gases and nitrogen [62]. Among these gases, CO2 is the most frequently applied and it accounts for over 50% of the GEOR production [67, 117]. For instance, in 2009, Ferguson et al. [118] reported that 101 GEOR projects in the US produced approximately 250,000 barrels of oil per day. In the United States, CO2‐EOR has been considered the best GEOR method to produce incremental EOR [119]. Nevertheless, GEOR processes are often associated with viscous and

#### *2.3.1. Evolution of gas injection EOR*

Gas injection was first developed in the United States, where it is still largely applied. Gas injection is one of the oldest fluid injection processes implemented for pressure maintenance. The first gas injection project was a pressure maintenance job initiated in 1864, after drilling the Drake well in Titusville, Pennsylvania. The project was aimed at boosting fast oil produc‐ tion [12]. In 1930, the earliest gas drive project was successfully performed in West Texas [122]. In the 1970s, another gas injection trial was performed at the Surry County, Texas [119]. In the past two decades, gas injection has gained significant interest and recent projects are focused in combining hydrocarbon recovery with CO2 geo‐storage [123]. Geological storage of CO2 (CO2‐EOR) is one of the most promising technologies for promoting ultimate oil recovery, while it simultaneously alleviates the problem of greenhouse gas accumulation in the atmos‐ phere [124, 125]. CO2‐EOR has been extensively deployed since the mid‐1980s in the Permian Basin of West Texas with high profit margins achieved over the past three decades [126].

#### *2.3.2. Types of gas injection*

The two main gas injection processes involve miscible and immiscible gas flooding.

#### *2.3.3. Mechanisms of gas injection for EOR*

#### *2.3.3.1. Miscible flooding*

In miscible gas flooding, gas completely mixes with the crude oil through single or multiple contacts between the gas phase and the crude oil phase. The gas injected reaches miscibility with the crude oil at or above the minimum miscibility pressure (MMP) [127]. MMP is the minimum pressure at which crude oil becomes miscible with the injected gas at the reservoir temperature [121]. MMP is a determining factor during miscible gas (e.g. CO2) flooding, as displacement efficiency is highly dependent on it [128]. CO2 achieves miscibility with crude oil through multiple contacts between the oil phase and the CO2 phase. In this mechanism of multiple contact miscibility, light hydrocarbons (lighter‐low carbon, low density) from the crude oil are transferred (vaporised) into the CO2 phase. Progressively, the gas phase becomes richer in the vaporised light hydrocarbons, which continuously change the composition of the gas phase that eventually becomes heavier and denser. This heavier gas phase condenses into the crude oil zone ahead of the displacement front (i.e. miscible zone) causing the reduction in crude oil viscosity and density [121]. As miscibility occurs between the residual oil and the injected CO2, the IFT between the gas and the oil phase becomes zero, thus this mixture is displaced as a single phase from the pores of the rock towards the producing well [121]. Very low residual oil saturation is achieved as the interfacial tension (IFT) in the miscible zone reduces to zero, thus there is no interface between oil and gas anymore [62, 129].

**Process benefits**. Miscible gas injection increases the overall displacement efficiency, minimis‐ es residual oil saturation, promotes ultra‐low (near zero) IFT and increases oil production significantly. Based on operational costs, miscible gas flooding is usually more cost effective [115] in comparison to TEOR flooding methods.

**Process limitations**. Miscible gas injection requires higher (expensive) operational costs (i.e. high gas compression costs). The changes in the crude oil density during the miscibility process can alter the flow path of the oil during the period when the lighter hydrocarbons vaporise into the CO2 gas phase or when the rich gas phase (CO2 plus light hydrocarbons) dissolves (condenses) into the oil phase [130]. Failure in miscibility may occur if pressure is not at or above the MMP leading to an unsuccessful miscible displacement process.

#### *2.3.3.2. Immiscible flooding*

Immiscible gas flooding entails the injection of gas below the MMP. Below the MMP, there is no miscibility between CO2 and oil [174]. Technically, immiscible flooding produces about half of the recovery of miscible gas flooding [131]. During immiscible flooding, incremental oil recovery is mainly achieved through oil swelling, which improves the macroscopic displace‐ ment efficiency [127]. At microscopic level, three‐phase (oil‐gas‐water) flow is observed with a complex interplay of the different phases [63, 132, 133]. Although these microscopic processes are still poorly understood, there is clearly significant potential to further improve oil recovery at the pore level. Notably, constant immiscible gas flooding with gases such as CO2 is more favourable to light oil than heavy oil reservoirs [134]. To improve recovery in heavy oil formations using CO2, co‐injection or the injection of water alternate gas, known as the WAG process, is performed to somehow control viscous fingering, gas channelling and early gas breakthrough. Upon injection of water and gas into the reservoir, a portion of the injected gas (CO2) usually dissolves in the oil that leads to oil viscosity reduction [134]. A recent advance‐ ment in immiscible flooding is polymer water alternate gas (PWAG) for overcoming viscous fingering and improvement of sweep efficiency [134].

**Process benefits**. Immiscible gas injection improves oil displacement efficiency. The oil recovery potential from the application of this process is higher from light oil formations [134].

**Process limitations**. Viscosity ratios of the injected gas (i.e. CO2) to oil (light or heavy oil) are unfavourable [134] triggering the occurrence of gravity override and viscous fingering through permeable zones [134], early gas breakthrough and poor sweep efficiency [135]. This process renders poor oil recovery potentials in heavy crude oil formations in comparison to thermal EOR.

#### *2.3.4. Technological advancement in GEOR techniques*

Advances in gas injection EOR include water alternate gas (WAG) injection; the simultaneous water alternate gas injection (SWAG) [136], polymer water alternate gas (PWAG) injection [134], the development of CO2 gas membrane separation technology and field applications of immiscible gas‐assisted gravity drainage (GAGD) [137, 138].

#### *2.3.5. GEOR field applications*

*2.3.3. Mechanisms of gas injection for EOR*

22 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

[115] in comparison to TEOR flooding methods.

*2.3.3.2. Immiscible flooding*

In miscible gas flooding, gas completely mixes with the crude oil through single or multiple contacts between the gas phase and the crude oil phase. The gas injected reaches miscibility with the crude oil at or above the minimum miscibility pressure (MMP) [127]. MMP is the minimum pressure at which crude oil becomes miscible with the injected gas at the reservoir temperature [121]. MMP is a determining factor during miscible gas (e.g. CO2) flooding, as displacement efficiency is highly dependent on it [128]. CO2 achieves miscibility with crude oil through multiple contacts between the oil phase and the CO2 phase. In this mechanism of multiple contact miscibility, light hydrocarbons (lighter‐low carbon, low density) from the crude oil are transferred (vaporised) into the CO2 phase. Progressively, the gas phase becomes richer in the vaporised light hydrocarbons, which continuously change the composition of the gas phase that eventually becomes heavier and denser. This heavier gas phase condenses into the crude oil zone ahead of the displacement front (i.e. miscible zone) causing the reduction in crude oil viscosity and density [121]. As miscibility occurs between the residual oil and the injected CO2, the IFT between the gas and the oil phase becomes zero, thus this mixture is displaced as a single phase from the pores of the rock towards the producing well [121]. Very low residual oil saturation is achieved as the interfacial tension (IFT) in the miscible zone

reduces to zero, thus there is no interface between oil and gas anymore [62, 129].

above the MMP leading to an unsuccessful miscible displacement process.

**Process benefits**. Miscible gas injection increases the overall displacement efficiency, minimis‐ es residual oil saturation, promotes ultra‐low (near zero) IFT and increases oil production significantly. Based on operational costs, miscible gas flooding is usually more cost effective

**Process limitations**. Miscible gas injection requires higher (expensive) operational costs (i.e. high gas compression costs). The changes in the crude oil density during the miscibility process can alter the flow path of the oil during the period when the lighter hydrocarbons vaporise into the CO2 gas phase or when the rich gas phase (CO2 plus light hydrocarbons) dissolves (condenses) into the oil phase [130]. Failure in miscibility may occur if pressure is not at or

Immiscible gas flooding entails the injection of gas below the MMP. Below the MMP, there is no miscibility between CO2 and oil [174]. Technically, immiscible flooding produces about half of the recovery of miscible gas flooding [131]. During immiscible flooding, incremental oil recovery is mainly achieved through oil swelling, which improves the macroscopic displace‐ ment efficiency [127]. At microscopic level, three‐phase (oil‐gas‐water) flow is observed with a complex interplay of the different phases [63, 132, 133]. Although these microscopic processes are still poorly understood, there is clearly significant potential to further improve oil recovery at the pore level. Notably, constant immiscible gas flooding with gases such as CO2 is more favourable to light oil than heavy oil reservoirs [134]. To improve recovery in heavy oil formations using CO2, co‐injection or the injection of water alternate gas, known as the WAG

*2.3.3.1. Miscible flooding*

As previously mentioned, CO2, N2 and hydrocarbon gases are used in GEOR. Technically, the injection of carbon dioxide (CO2) and hydrocarbon gases achieve higher oil recovery efficien‐ cies. However, natural gas is expensive and there is growing concern about its impact as greenhouse gas; thus, CO2 is considered the most appropriate gas for injection, although oil recovery using CO2 is also a costly venture. Certain costs are often associated with its deploy‐ ment such as: (a) cost of the CO2 itself which can add about \$20–30 per barrel of oil produced [139]; (b) cost of surface facilities for separation of the CO2 from the production streams and compressing it back into the oil reservoir; and (c) financial costs for the time delay associated with the re‐pressurising of old reservoirs [139]. According to the US Energy Information Administration, Annual Energy Outlook (AEO) 2014 report (**Figure 6**), the application of CO2 for EOR purposes appears to be dependent on oil prices. Hence, an economic feasibility study is recommended to ascertain whether or not a specific CO2‐EOR project is viable. For instance, an analysis between crude oil produced from CO2 injection and the cost of injection using a case study was conducted for current, and forecasted (**Figure 6a** and **b**) projects to examine how oil prices would affect the feasibility of field implementation of CO2‐EOR. **Figure 6(a)** shows oil production in million barrels per day using CO2‐EOR and **Figure 6(b)** shows the West Texas Intermediate (WTI) crude oil prices (past and future projections) for different cases: a reference case that accounts for 10% of total US crude oil production, low and high oil prices and high and low oil and gas resources. **Figure 6(a)** clearly shows the effect of crude oil price and hydrocarbon resources on crude oil production. At low oil prices, the WTI crude oil is expected to reach \$73 per barrel by 2040 (**Figure 6b**) with CO2‐EOR production expected to reach 480,000 barrels per day by 2040, which is less than 35% of the reference case. Therefore, this scenery will not favour the field application of CO2‐EOR [139]. While in the high oil price case (\$202 per barrel that is 45% higher than in the reference case), expectations are that oil production will be 960,000 barrels per day by 2040 (30% higher than in the reference case of 740,000 barrels per day), which favours the profitable application of CO2‐EOR in old oil fields [139]. At the reference case, 10% of total US crude oil production is achieved using CO2‐EOR against the low oil price case (8%) and high oil price case (12%) [139]. **Figure 6(b)** also indicates that the low oil and gas resource case projects are more profitable than the high oil and gas resource case projects [139].

Despite the high production costs associated with CO2‐EOR processes, CO2 injection into oil reservoirs at high pressure reduces the oil viscosity and causes oil to swell, which in turn yields an increase in cumulative volume of produced oil and in the percentage of recoverable oil [139]. In the United States, large oil production has been achieved through miscible CO2

**Figure 6.** CO2‐EOR projected dependence on oil price. (a) CO2‐EOR as a function of time, oil price and hydrocarbon resources. (b) West Texas Intermediate (WTI) crude oil price as a function of time, number of fields that can profitable produced oil using CO2‐EOR technology and hydrocarbon resources [139].

flooding, specifically from West Texas, Wyoming and Mississippi oil fields, where natural sources of CO2 are readily available at affordable price [131]. In North America, the majority of miscible CO2 flooding projects are currently taking place in carbonates reservoirs in the Permian Basin of West Texas and in Saskatchewan, Canada (Weyburn‐Midale oil field) [28]. CO2‐EOR successes in the United States are due to the readily available CO2 sources located adjacent to oil fields, whereas in Canada, the CO2 sources are located in North Dakota [28]. Prospective candidate oil fields for CO2‐EOR have been determined in Louisiana, Texas, the Gulf Coast, Mississippi, Alabama and in onshore areas of Florida [131]. Nevertheless, these fields are located away from existing natural CO2 sources [131]. The incremental CO2‐EOR oil production from different regions in the United States (see **Table 5**) was 282,000 bpd in 2012; while in 2014 a constant oil production rate of 280,000 bpd was attained in 2014. A production rate growth to 615,000 bpd is expected by 2020 [140].


**Table 5.** USA regional CO2‐EOR oil production projection [140].

reach 480,000 barrels per day by 2040, which is less than 35% of the reference case. Therefore, this scenery will not favour the field application of CO2‐EOR [139]. While in the high oil price case (\$202 per barrel that is 45% higher than in the reference case), expectations are that oil production will be 960,000 barrels per day by 2040 (30% higher than in the reference case of 740,000 barrels per day), which favours the profitable application of CO2‐EOR in old oil fields [139]. At the reference case, 10% of total US crude oil production is achieved using CO2‐EOR against the low oil price case (8%) and high oil price case (12%) [139]. **Figure 6(b)** also indicates that the low oil and gas resource case projects are more profitable than the high oil and gas

Despite the high production costs associated with CO2‐EOR processes, CO2 injection into oil reservoirs at high pressure reduces the oil viscosity and causes oil to swell, which in turn yields an increase in cumulative volume of produced oil and in the percentage of recoverable oil [139]. In the United States, large oil production has been achieved through miscible CO2

**Figure 6.** CO2‐EOR projected dependence on oil price. (a) CO2‐EOR as a function of time, oil price and hydrocarbon resources. (b) West Texas Intermediate (WTI) crude oil price as a function of time, number of fields that can profitable

produced oil using CO2‐EOR technology and hydrocarbon resources [139].

resource case projects [139].

24 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

**Figure 7.** U.S. EOR supply and storage of CO2 for EOR [140].

In the United States, the utilisation of CO2 from natural gas processing and other industrial CO2 sources for EOR amounted to 0.4 MMcf/d in 2012 [139]. It is predicted that by 2020, the volume of CO2 will reach approximately 6.4 MMcf/d (**Figure 7**) and the key CO2 sources will be obtained from industrial plants along the Gulf Coast and natural CO2 sources. **Figure 8** displays the projected sources of CO2 for EOR operations by 2020.

**Figure 8.** Projected CO2‐EOR operations and CO2 sources by 2020 [140].

However, in the absence of a local CO2 market, hydrocarbon gases, which are also excel‐ lent solvents for light oil reservoirs, can be used for oil production augmentation. For in‐ stance, hydrocarbon gases have been applied in Libya, Alaska, Canada and Venezuela [28]. Other gases aside CO2 and hydrocarbon gases have been moderately applied. In the 1950s, N2 gas was used for well completion and well workover processes [141]; N2 has also been extensively used in oil field operations such as reservoir pressure maintenance, gas lift and gas cycling [111]. Most recently, N2 has been used as a substitute for CO2 due to its inert and noncorrosive nature. N2 is most suitable for deep light to medium oil res‐ ervoirs [2, 111, 113] with a proven high recovery rate of about 45–90% of the original oil‐ in‐place (OOIP) [111]. N2 is considered economically viable for oil recovery by miscible gas displacement in high‐pressure reservoirs where the high cost and poor accessibility to CO2 and natural gas are an issue (**Figure 9**) [111, 142].

Miscible displacement conditions can be achieved using N2 at high pressure, alongside with the reduction in oil viscosity [143]. N2 gas injection has been reported for the Hawkins Field (Texas), Cantarell Field (Mexico) and Elk Hills (California) [144].

**Figure 9.** Nitrogen gas displacement EOR [111].

#### **2.4. Microbial EOR**

In the United States, the utilisation of CO2 from natural gas processing and other industrial CO2 sources for EOR amounted to 0.4 MMcf/d in 2012 [139]. It is predicted that by 2020, the volume of CO2 will reach approximately 6.4 MMcf/d (**Figure 7**) and the key CO2 sources will be obtained from industrial plants along the Gulf Coast and natural CO2 sources. **Figure 8**

However, in the absence of a local CO2 market, hydrocarbon gases, which are also excel‐ lent solvents for light oil reservoirs, can be used for oil production augmentation. For in‐ stance, hydrocarbon gases have been applied in Libya, Alaska, Canada and Venezuela [28]. Other gases aside CO2 and hydrocarbon gases have been moderately applied. In the 1950s, N2 gas was used for well completion and well workover processes [141]; N2 has also been extensively used in oil field operations such as reservoir pressure maintenance, gas lift and gas cycling [111]. Most recently, N2 has been used as a substitute for CO2 due to its inert and noncorrosive nature. N2 is most suitable for deep light to medium oil res‐ ervoirs [2, 111, 113] with a proven high recovery rate of about 45–90% of the original oil‐ in‐place (OOIP) [111]. N2 is considered economically viable for oil recovery by miscible gas displacement in high‐pressure reservoirs where the high cost and poor accessibility to

Miscible displacement conditions can be achieved using N2 at high pressure, alongside with the reduction in oil viscosity [143]. N2 gas injection has been reported for the Hawkins Field

displays the projected sources of CO2 for EOR operations by 2020.

26 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

**Figure 8.** Projected CO2‐EOR operations and CO2 sources by 2020 [140].

CO2 and natural gas are an issue (**Figure 9**) [111, 142].

(Texas), Cantarell Field (Mexico) and Elk Hills (California) [144].

#### *2.4.1. Microbial EOR techniques (MEOR)*

In MEOR, indigenous or exogenous bacteria can be activated or injected into the reservoir to generate metabolic chemicals that interact with the crude oil and increase oil production [19]. For these applications, bacteria should be small, spherical and less than 20% of the size of the pore throats in the formation [145]. Small cell size (between 0.5 and 5.0 μm) pene‐ trates easily through the reservoir porous medium [146]. Typically, mixed microbial popula‐ tions are used in combination with metabolic products such as solvents, acids or gases to increase recovery and prolong the life span of the oil wells [14, 15, 19]. These metabolic products are produced by different bacteria (microbes) and exhibit different functionalities in MEOR processes Solvents such as acetone, butanol and propan‐2‐diol (produced by *Clos‐ tridium, Zymomonas* and *Klebsiella*) reduce oil viscosity and thus improve oil mobility [147, 148]. *Clostridium, Enterobacter and Methanobacterium* produce methane and hydrogen, which reduce IFT, oil viscosity [149] and increase oil mobilisation. Among several microbes used for MEOR processes. *Clostridium* microbes are the most applicable owing to their resistant endospores that enable survival at unfavourable conditions [150]. *Bacillus* strains are also effective MEOR agents [19, 20].

#### *2.4.2. Evolution of microbial EOR (MEOR)*

The MEOR process was first proposed by Beckmann in 1926, though it was brought to recognition in the 1940s through the work by ZoBell [151]. The first MEOR implementation happened in 1954 in the Lisbon fields in Union County, Louisiana, USA [14, 55]. The acceptance of MEOR as an oil recovery technique found worldwide resistance for decades. One of the reasons was that microbiology was less than 100 years old at the time this EOR technique was proposed. Therefore, the effectiveness of the MEOR process was viewed as a mere curiosity [19]. Prior to the 1940s university laboratories conducted MEOR research [145]. These research efforts continued and eventually led to MEOR growth from extended laboratory work in the 1980s to field level in the 1990s [19].

#### *2.4.3. Mechanism of MEOR*

MEOR involves the application of bacteria in oil reservoir for recovery purposes. The bacteria are mostly naturally occurring bacteria in reservoir rocks, hydrocarbon utilising or non‐ pathogenic [16]. These bacteria produce desired EOR chemicals *in situ* through metabolic reactions [19], that results from multiple biochemical process steps to generate the EOR chemicals [14, 15]. Nutrients (e.g. fermentable carbohydrates) are injected to provide favour‐ able conditions for microbial metabolism [15], which results in the production of biosurfac‐ tants, biopolymers and gases (**Table 6**) [19].


**Table 6.** Effective agents for MEOR adapted from [14, 19].

**Biosurfactants**. Biosurfactants are biodegradable and more effective in emulsifying aqueous hydrocarbon mixtures than synthetic surfactants [152]. Biosurfactants can be produced in bioreactors *ex situ* and injected as an aqueous surfactant formulation into the reservoir. As surfactant migrates towards the oil‐aqueous interface, IFT is reduced and capillary number increases displacing and recovering residual oil [19, 152].

The production of *in situ* biosurfactants takes place by injecting the biosurfactant‐producing microbes into the formation ensuring proper propagation of the microbes into the oil reservoir [153]. Selected nutrients are also injected to stimulate the growth of the biosurfactant‐produc‐ ing indigenous microbes in the reservoir [152].

**Biopolymers**. Biopolymers are mainly used for selective plugging of high permeability thief zones. In this MEOR application, bacteria in aqueous solutions are injected into the formation that preferentially flows through the high‐permeability pathways, where the growth of biomass plugs the pore throats, leading to permeability reduction [19]. Plugging of high permeability thief zones diverts waterflood towards the lower permeability oil saturated areas.

**Bacterial consortia**. Bacterial consortia are used for the selective production of biogases (i.e. methane, carbon dioxide and hydrogen), biosolvents (i.e. acetone, ethanol, 1‐butanol, buta‐ none, etc.) and bioacids (i.e. acetic, propionic, butyric, etc.). In a pressure‐depleted formation, biogases assist in pressure build‐up and at high pressures, biogases can dissolve within the oil phase reducing its viscosity [19]. Bioacids are capable of dissolving carbonate rocks leading to porosity and permeability increase in the oil formation [19, 147]

**Process benefits**. MEOR is environmentally friendly as the MEOR bioproducts are biodegrad‐ able [14], low oil production costs, MEOR is not dependent on oil price like the conventional CEOR processes and MEOR consumes less energy than the TEOR processes [19, 154]. MEOR is economically attractive for application in marginally producing oil fields because the injected bacteria and nutrients are low priced [14].

**Process limitations**. The MEOR process is complex because it depends on the reservoir chemistry for bacteria functionality and isolation. MEOR renders low incremental oil recov‐ ery [19].

## *2.4.4. MEOR field applications*

*2.4.2. Evolution of microbial EOR (MEOR)*

28 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

1980s to field level in the 1990s [19].

tants, biopolymers and gases (**Table 6**) [19].

**Table 6.** Effective agents for MEOR adapted from [14, 19].

**MEOR agents (Microbes) Functionality**

**Biosurfactants** (i.e. Bacillus,

**Biopolymers** (i.e. Bacillus,

**BioSolvents:** Clostridium, Zymomonas; **Bioacids**: Clostridium, Enterobacter)

**Biomass** (i.e. Bacillus, Xanthomonas)

Arthrobacter)

Xanthomonas)

**Bacterial consortia** (**Biogases:** Clostridium,

Enterobacter;

*2.4.3. Mechanism of MEOR*

The MEOR process was first proposed by Beckmann in 1926, though it was brought to recognition in the 1940s through the work by ZoBell [151]. The first MEOR implementation happened in 1954 in the Lisbon fields in Union County, Louisiana, USA [14, 55]. The acceptance of MEOR as an oil recovery technique found worldwide resistance for decades. One of the reasons was that microbiology was less than 100 years old at the time this EOR technique was proposed. Therefore, the effectiveness of the MEOR process was viewed as a mere curiosity [19]. Prior to the 1940s university laboratories conducted MEOR research [145]. These research efforts continued and eventually led to MEOR growth from extended laboratory work in the

MEOR involves the application of bacteria in oil reservoir for recovery purposes. The bacteria are mostly naturally occurring bacteria in reservoir rocks, hydrocarbon utilising or non‐ pathogenic [16]. These bacteria produce desired EOR chemicals *in situ* through metabolic reactions [19], that results from multiple biochemical process steps to generate the EOR chemicals [14, 15]. Nutrients (e.g. fermentable carbohydrates) are injected to provide favour‐ able conditions for microbial metabolism [15], which results in the production of biosurfac‐

**•** IFT reduction between oil and water

**•** Effective for wettability alteration

**•** Effective for selective plugging

**•** Promotes oil emulsification owing to reduced IFT

**•** Water viscosity can be greatly improved which promotes mobility control

**•** Used for modifying viscosity of the formation water and injectivity profile

**•** Produces gases such as N2, CH4, CO2, and H2 that are effective in promoting oil viscosity

**•** Produces solvents such as alcohols and ketones which dissolves in oil and promotes

**•** Produces acids that promotes dissolution of clays increasing porosity and permeability

**•** Displaces oil through bacterial growth between the oil and the surface of rock and water

**•** Improvement of residual oil displacement

reduction, IFT reduction, and oil swelling

**•** Effective for selective plugging within the porous media

**•** Effective for the partial degradation of crude oil

IFT reduction and oil emulsification

**•** Effective for altering rock wettability

MEOR field projects have been conducted worldwide in past decades. In Australia, MEOR was applied in the Alton field producing approximately 40% of incremental oil after 1 year of treatment application [155]. In the Asian region, MEOR has also been deployed in China, India and Malaysia [156, 157]. Notable MEOR successes with incremental oil productions ranging up to 204% at field trials have been reported in Argentina, US, Romania, India and Russia [158]. Other MEOR application successes at laboratory and field scale have been reported in Bulgaria, Canada, Former East Germany, Saudi Arabia, the Netherlands, Oman, Romania, Norway and Hungary [159].

#### *2.4.5. Technological advancements in MEOR*

MEOR has developed from laboratory studies between the 1940s and 1980s to successful field applications in the last two decades [19]. Several advances have been made in its application such as the injection of adapted mixed enrichment cultures (AMEC) into reservoirs [160, 161], the stimulation of indigenous microbiota through the use of salts and oxygen alongside water injection [162], and the selective plugging of high‐permeability channels through the use of ultra‐micro‐bacteria formed by selective starvation [163]. Recently, the two notable advances in MEOR are genetically engineered micro‐organisms EOR (GEMEOR), and the enzyme EOR (EEOR). Both advances involve the growing of microbes that can withstand extreme reservoir conditions using genetic engineering tools and techniques [19].

## **3. EOR techniques**

#### **3.1. Production performance**

In thermal EOR, oil production is increased in heavy oil formations through several mecha‐ nisms such as oil viscosity reduction, oil swelling and steam flashing and stripping [1]. Among the TEOR techniques, steam flooding has the highest potential for additional oil recovery than CSS, SAGD and ISC. Steam flooding requires intensive heating and trillions of barrels of heavy oil are recovered as a result of this intense heating [29]. In chemical EOR, polymer flooding exhibits better oil production potentials in comparison to SP and ASP. Whereas ASP demon‐ strate better recovery efficiency than SP as it prolongs the production life of the formation [107]. In gas injection EOR, the most effective and promising method is CO2 injection. Although CO2 is capable of displacing oil by miscible and immiscible flooding, miscible flooding has proven to be more efficient. Although, immiscible flooding shows lower recovery factors, it may still be economical due to the lower cost of the immiscible gases, e.g. N2 [164]. Microbial EOR is economically attractive; however, a longer time interval is a requirement to attain incremental oil production. More so, oil production rates are often low when compared to the oil production rates of TEOR, CEOR and GEOR processes [19].

#### **3.2. Cost of EOR Implementation**

TEOR projects are expensive ventures. A vast capital is required for project operations, specifically, steam generation and injection [26], which are often large scale and require high financial costs for multiple injection wells. Likewise, steam generators for such projects are usually high priced, yet essential components. CEOR is cost‐effective in comparison to TEOR, since the chemicals for its operations are readily accessible and relatively cheap [3, 165], although surfactant injection remains an expensive undertaking [98]. Gas injection is again a relatively expensive practice when compared to CEOR and MEOR, but more cost‐effective than the TEOR processes. However, the incremental oil production usually outweighs the production costs, especially for immiscible gas injection [2]. MEOR is a much cheaper alter‐ native owing to the low energy requirements unlike TEOR. The application of MEOR is independent of oil price [19, 59], and thus it is considered economical. However, MEOR operations involve complex mechanisms [14, 15] that require proper technical understanding for its application. Therefore, cost should not be the only factor considered for adopting MEOR in the field.

#### **3.3. Environmental friendliness**

*2.4.5. Technological advancements in MEOR*

30 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

**3. EOR techniques**

**3.1. Production performance**

**3.2. Cost of EOR Implementation**

conditions using genetic engineering tools and techniques [19].

oil production rates of TEOR, CEOR and GEOR processes [19].

MEOR has developed from laboratory studies between the 1940s and 1980s to successful field applications in the last two decades [19]. Several advances have been made in its application such as the injection of adapted mixed enrichment cultures (AMEC) into reservoirs [160, 161], the stimulation of indigenous microbiota through the use of salts and oxygen alongside water injection [162], and the selective plugging of high‐permeability channels through the use of ultra‐micro‐bacteria formed by selective starvation [163]. Recently, the two notable advances in MEOR are genetically engineered micro‐organisms EOR (GEMEOR), and the enzyme EOR (EEOR). Both advances involve the growing of microbes that can withstand extreme reservoir

In thermal EOR, oil production is increased in heavy oil formations through several mecha‐ nisms such as oil viscosity reduction, oil swelling and steam flashing and stripping [1]. Among the TEOR techniques, steam flooding has the highest potential for additional oil recovery than CSS, SAGD and ISC. Steam flooding requires intensive heating and trillions of barrels of heavy oil are recovered as a result of this intense heating [29]. In chemical EOR, polymer flooding exhibits better oil production potentials in comparison to SP and ASP. Whereas ASP demon‐ strate better recovery efficiency than SP as it prolongs the production life of the formation [107]. In gas injection EOR, the most effective and promising method is CO2 injection. Although CO2 is capable of displacing oil by miscible and immiscible flooding, miscible flooding has proven to be more efficient. Although, immiscible flooding shows lower recovery factors, it may still be economical due to the lower cost of the immiscible gases, e.g. N2 [164]. Microbial EOR is economically attractive; however, a longer time interval is a requirement to attain incremental oil production. More so, oil production rates are often low when compared to the

TEOR projects are expensive ventures. A vast capital is required for project operations, specifically, steam generation and injection [26], which are often large scale and require high financial costs for multiple injection wells. Likewise, steam generators for such projects are usually high priced, yet essential components. CEOR is cost‐effective in comparison to TEOR, since the chemicals for its operations are readily accessible and relatively cheap [3, 165], although surfactant injection remains an expensive undertaking [98]. Gas injection is again a relatively expensive practice when compared to CEOR and MEOR, but more cost‐effective than the TEOR processes. However, the incremental oil production usually outweighs the production costs, especially for immiscible gas injection [2]. MEOR is a much cheaper alter‐ native owing to the low energy requirements unlike TEOR. The application of MEOR is Thermal EOR, in comparison to microbial, chemical and gas EOR, is eco‐unfriendly due to the generation of large volumes of greenhouse gas emissions. Specifically, the production of steam from the combustion of fossil fuels significantly increases emissions of carbon dioxide and nitrous oxide [26]. ISC also contributes to gas emissions such as CO2, H2S, CO and volatile hydrocarbons, which are generated during this process [41, 166]. Steam injection has fewer hydrocarbons, which are generated during this process [41, 166]. Steam injection has less environmental sustainability than ISC, since no current control measures over gas emissions during the steam generation process are in place [29]. MEOR is an eco‐friendly method in comparison to thermal, chemical and gas methods [19] as MEOR does not release polluting and/or toxic gases such as H2S and CO; thus, MEOR offers a better environmental sustaina‐ bility.

## **4. Global EOR status and some case studies**

EOR gas injection projects were stagnant in the mid‐1908s [167], while thermal and chemical EOR processes experienced a decline in the 1980s [167]. However, since 2000, GEOR projects have been on the rise due to the growth in the implementation of CO2‐EOR projects [167]. Minor increases in thermal projects have been observed in recent times due to the increase in

**Figure 10.** Global EOR project status [93].

the application of high‐pressure air injection (HPAI) projects [167]. Between 2004 and 2014, gas EOR (i.e. miscible flooding) and thermal EOR techniques have been the most extensively applied EOR processes worldwide (**Figure 10**) [94].

The global oil demand has been steadily on the rise (**Figure 11**), with the exception of the temporary drop in oil demand between 1979 and 1983. Simultaneously, there has been a continuous decline in conventional oil resources. According to the U.S. Energy Information Administration, the worldwide oil consumption in 2014 increased by 1.2 million b/d, which on average corresponded to 92.4 million b/d [168]. At the end of year 2015, oil production reached approximately 97 million b/d [169], increase that was equivalent to a rise in oil consumption of 1.4 million b/d [170]. Expectations are that global oil consumption will grow by 1.4 million b/d in 2016 and 1.5 million b/d in 2017 (**Figure 11**). It is also important to mention that since 2014 to present, there is more oil supply than oil demand, which is clearly reflected by the drop in oil price. However, the current excess in oil supply comes from the exploitation of unconventional oil resources (i.e. tight reservoirs).

**Figure 11.** Global oil production and consumption [170].

The dramatic increase in oil demand over time has constantly prompted the quest for novel methods to enhance oil production. In 1998, global EOR projects achieved the production of 2.3 million b/d from steam flooding in the Duri field (Indonesia), which was the largest steam flooding project at the time [3]. EOR production of 480,000 b/d was further reported in Canada and China with an EOR production of 280,000 and 200,000 b/d, respectively [3].

In recent times, the EOR global market has experienced an unceasing progression in its growth pattern. In 2012, the global EOR market was 2095 million barrels [171]. By 2013, it further increased to 2681.6 million barrels. Globally, EOR contributes around 3.5% of daily oil production [172, 173], which corresponds to approximately 3 million barrels of oil per day [28]. A compound annual growth rate of 29.9% has been projected through 2014–2020; thus, a much higher growth above 16,000 million barrels is expected by 2020 that will amount to about US \$ 283 billion [173].

#### **4.1. Impact of EOR in the Kern River oil field (California)**

The Kern River heavy oil field near Bakersfield, California, was discovered in 1899 [174]. In 1961, heavy oil production was approximately 19,000 b/d, which was considered low and prompted the introduction of steam flooding in 1964 and 1966 [174]. Steam flooding increased heavy oil production to 53,000 b/d in 1966 and production peaked at 141,000 b/d in 1985, followed by a lower production rate of 80,000 b/d [175]. After more than 100 years of produc‐ tion, the field is still producing and 60% of the oil output has been achieved by steam flooding EOR [176]. Kern River (a sandstone formation) has demonstrated the efficacy of thermal EOR for heavy oil reservoirs. In this field, a 60% recovery factor of the original oil‐in‐place (OOIP) has been achieved, which is significantly higher than the average global recovery factor of 32– 35%. In the Kern River oil field, primary recovery and hot water injection produced around 5– 10% to 15–25%, respectively, of the OOIP [176].

#### **4.2. Impact of EOR on Russian oil fields**

the application of high‐pressure air injection (HPAI) projects [167]. Between 2004 and 2014, gas EOR (i.e. miscible flooding) and thermal EOR techniques have been the most extensively

The global oil demand has been steadily on the rise (**Figure 11**), with the exception of the temporary drop in oil demand between 1979 and 1983. Simultaneously, there has been a continuous decline in conventional oil resources. According to the U.S. Energy Information Administration, the worldwide oil consumption in 2014 increased by 1.2 million b/d, which on average corresponded to 92.4 million b/d [168]. At the end of year 2015, oil production reached approximately 97 million b/d [169], increase that was equivalent to a rise in oil consumption of 1.4 million b/d [170]. Expectations are that global oil consumption will grow by 1.4 million b/d in 2016 and 1.5 million b/d in 2017 (**Figure 11**). It is also important to mention that since 2014 to present, there is more oil supply than oil demand, which is clearly reflected by the drop in oil price. However, the current excess in oil supply comes from the exploitation

The dramatic increase in oil demand over time has constantly prompted the quest for novel methods to enhance oil production. In 1998, global EOR projects achieved the production of 2.3 million b/d from steam flooding in the Duri field (Indonesia), which was the largest steam flooding project at the time [3]. EOR production of 480,000 b/d was further reported in Canada

In recent times, the EOR global market has experienced an unceasing progression in its growth pattern. In 2012, the global EOR market was 2095 million barrels [171]. By 2013, it further increased to 2681.6 million barrels. Globally, EOR contributes around 3.5% of daily oil production [172, 173], which corresponds to approximately 3 million barrels of oil per day [28]. A compound annual growth rate of 29.9% has been projected through 2014–2020; thus, a much

and China with an EOR production of 280,000 and 200,000 b/d, respectively [3].

applied EOR processes worldwide (**Figure 10**) [94].

32 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

of unconventional oil resources (i.e. tight reservoirs).

**Figure 11.** Global oil production and consumption [170].

Russia, which is the second largest oil producer in the world, had an estimated ultimate oil production of 4.6 million b/d in 1988 [175, 177]. Russian's oil recovery factors have been on the decline in the last 30 years because of the depletion of giant fields [178]. The breakdown of the Soviet Union in 1991 also contributed to a production decrease of approximately 2.2 billion b/ d [175]. In the 1960s, the oil recovery factor was 50%, but by 1993, the recovery factor dropped b/d [176]. In the 1960s, the oil recovery factor was 50%, but by 1993, the recovery factor dropped to 40% [178, 179]. Further decline (560 kb/d) in Russian's oil production is expected between 2014 and 2020. Projections indicate that the total production of liquid hydrocarbons in Russia will fall from 10.9 Mb/d in 2014 to 10.4 Mb/d by 2020. However, an increase in production of natural gas liquids (NGL) and condensate is expected by 2020 owing to the projected higher

**Figure 12.** IEA: The Oil Market Report (OMR) on current Russian oil production [180].

gas production rate with and average NGL output of 975 kb/d [180]. **Figure 12** shows the current Russian oil production and production projections up to 2020.

Several EOR techniques (TEOR, GEOR and MEOR) have been deployed in Russian oil fields, even though MEOR applications are restricted [181]. GEOR, specifically, miscible gas flooding, is considered the EOR process with the greatest potential [182]. Although, several EOR processes have been implemented in Russian oil fields, estimations of the actual number of implemented EOR projects are difficult to obtain. Based on oil companies' data, Russian oil production from 1996 to 2000 increased by 2.5–2.8 times [178]. Current Russian EOR oil production is approximately 17–18 MM tons with chemical EOR processes accounting for 81– 82% of the incremental oil production and 0.35–0.4 MM tons of oil production from gas flooding and WAG applications [178]. Projections indicate that gas EOR technologies, WAG and combined technologies will be adopted in Russia in the near future [178].

### **4.3. Impact of EOR on the Cantarell oil field (Mexico)**

Cantarell is the biggest oil field in Mexico [183]. Oil production commenced in 1979. Between 1980 and 1996, the production capacity of the Cantarell oil field was 1 MMbd. In 2000, nitrogen flooding was initiated and by 2005, the field responded to nitrogen flooding with an outstand‐ ing production increase [174]. The initial results were great, however, subsequently production dropped by approximately 400,000 bpd [183]. This oil production behaviour might indicate that nitrogen injection could be viewed as a method that accelerates oil recovery without upsurging ultimate recovery [174, 183].

#### **4.4. Impact of EOR on the Oman oil field**

Oman is the largest oil and natural gas producer in the Middle East outside the OPEC. Oil production peaked in year 2000 at 970,000 b/d and then declined to 710,000 b/d in 2007 [184]. The decline was prevented through the application of several EOR techniques, which increased production again to 919,000 b/d in 2012. Henceforth, Oman's incremental oil and natural gas

**Figure 13.** EOR impact on Oman Oil Production [186].

production is highly dependent on advanced extraction technologies [185]. EOR techniques such as polymer, miscible gas flooding and steam injection have been the main drivers of the country's rebounding oil production since 2007 [184]. In the Marmul oil field, polymer flooding produced about 75,000 b/d in 2012. Polymer flooding has been more effective than steam injection [184]. Miscible gas injection, which was deployed in the Harweel oil field cluster, improved the oil production rate to 23,000 b/d in 2012. Steam injection has also been deployed in the Mukhaizna, Marmul, Amal‐East, Amal‐West and Qarn Alam oil fields, among others [184]. Currently, oil production in Oman has remained on the increase since 2007 with a notable production increase of over a million b/d in 2015 (**Figure 13**) [186]. Projections indicate that the application of thermal EOR in the Amal‐East and Amal‐West oil fields will increase oil production by 23,000 b/d in 2018 [184]. In Oman's oil fields application of conventional and advanced EOR techniques will promote further production growth [185, 186]. Currently, expectations are that 16% of Oman's oil production will come from EOR projects this year (2016), which is more than five times the EOR production in 2012 [185].

#### **4.5. Impact of EOR on the U.S. Permian Basin**

gas production rate with and average NGL output of 975 kb/d [180]. **Figure 12** shows the

Several EOR techniques (TEOR, GEOR and MEOR) have been deployed in Russian oil fields, even though MEOR applications are restricted [181]. GEOR, specifically, miscible gas flooding, is considered the EOR process with the greatest potential [182]. Although, several EOR processes have been implemented in Russian oil fields, estimations of the actual number of implemented EOR projects are difficult to obtain. Based on oil companies' data, Russian oil production from 1996 to 2000 increased by 2.5–2.8 times [178]. Current Russian EOR oil production is approximately 17–18 MM tons with chemical EOR processes accounting for 81– 82% of the incremental oil production and 0.35–0.4 MM tons of oil production from gas flooding and WAG applications [178]. Projections indicate that gas EOR technologies, WAG

Cantarell is the biggest oil field in Mexico [183]. Oil production commenced in 1979. Between 1980 and 1996, the production capacity of the Cantarell oil field was 1 MMbd. In 2000, nitrogen flooding was initiated and by 2005, the field responded to nitrogen flooding with an outstand‐ ing production increase [174]. The initial results were great, however, subsequently production dropped by approximately 400,000 bpd [183]. This oil production behaviour might indicate that nitrogen injection could be viewed as a method that accelerates oil recovery without

Oman is the largest oil and natural gas producer in the Middle East outside the OPEC. Oil production peaked in year 2000 at 970,000 b/d and then declined to 710,000 b/d in 2007 [184]. The decline was prevented through the application of several EOR techniques, which increased production again to 919,000 b/d in 2012. Henceforth, Oman's incremental oil and natural gas

current Russian oil production and production projections up to 2020.

34 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

and combined technologies will be adopted in Russia in the near future [178].

**4.3. Impact of EOR on the Cantarell oil field (Mexico)**

upsurging ultimate recovery [174, 183].

**4.4. Impact of EOR on the Oman oil field**

**Figure 13.** EOR impact on Oman Oil Production [186].

The United States Permian Basin has shown successful deployment of EOR processes since the early 1970s [187], which started with two large CO2‐EOR projects [188]. In 1985, CO2 was injected into the Denver Unit of the giant Wasson (San Andres) oil field to remediate the sharp decline of oil production that dropped from approximately 90,000 to 40,000 b/d. Upon deployment of the CO2 flooding project, oil production increased to about 50,000 b/d [189]. In 2009, 105 miscible and 61 immiscible CO2‐EOR applications were implemented in the U.S. within the Permian Basin producing over 182,000 b/d [188]. In the United States, the number of CO2‐EOR projects has continuously increased over the years. In 2010, production rates of approximately 200,000 b/d in the Permian Basin were achieved using CO2‐EOR in oil fields ranging from the fieldwide CO2 flood in the giant Wasson (San Andres) oil field to the small 160‐acre pilot CO2 flood at Dollarhide Clearfork reservoir [32, 190, 191]. **Table 7** presents details of several CO2‐EOR projects implemented in the Permian Basin [32].


Note: \*Joint recovery from six Wasson units and \*\*Joint recovery from nine Slaughter units.

**Table 7.** CO2‐EOR oil recovery from the Permian Basin [32].

In 2012 and 2015, incremental oil production from CO2‐EOR operations in the Permian Basin was estimated at 186,000 and 241,000 b/d, respectively, with further projections of 301,000 b/d by 2020 [141].

## **5. Conclusions**

Crude oil recovery takes place in three production stages primary, secondary and tertiary oil recovery processes. On average, oil recovery from the primary and secondary production stages is approximately one‐third of the original oil‐in‐place (OOIP), while the remaining two‐ thirds of the oil, can be partially recovered through the application of tertiary processes also known as enhanced oil recovery (EOR) processes, which are key drivers for incremental oil recovery. EOR processes include thermal (TEOR), chemical (CEOR), gas flooding miscible and immiscible (GEOR) and microbial or MEOR processes.


Huge potentials for incremental oil recovery exist through the application of EOR processes; however, the volume of recoverable oil is greatly dependent on the implemented EOR technique. Among the key EOR techniques deployed in oil fields, miscible gas injection EOR and thermal EOR processes are currently the most commonly used techniques in the field. Continuous evolution of EOR processes in the near future should take a synergistic approach from different EOR technologies.

#### **Nomenclature**

In 2012 and 2015, incremental oil production from CO2‐EOR operations in the Permian Basin was estimated at 186,000 and 241,000 b/d, respectively, with further projections of 301,000 b/d

Crude oil recovery takes place in three production stages primary, secondary and tertiary oil recovery processes. On average, oil recovery from the primary and secondary production stages is approximately one‐third of the original oil‐in‐place (OOIP), while the remaining two‐ thirds of the oil, can be partially recovered through the application of tertiary processes also known as enhanced oil recovery (EOR) processes, which are key drivers for incremental oil recovery. EOR processes include thermal (TEOR), chemical (CEOR), gas flooding miscible and

**•** Thermal EOR techniques are applied for the recovery of heavy oils. In particular, steam‐ flooding is the dominant thermal EOR technique worldwide. Increase in oil productivity is achieved through viscosity reduction, oil swelling, steamstripping and thermal cracking [1].

**•** Chemical EOR techniques are suitable for application in mature oil fields. Globally, oil recovery using CEOR techniques have remained insignificant since the 1990s with the exception of China [79, 193]. Among the CEOR techniques, polymer/surfactant flooding through IFT reduction between the displacing liquid (i.e. water) and oil has the best potential for ultimate oil recovery [1]. However, polymer flooding is less complex and the most widely

**•** Miscible and immiscible gas injection or GEOR are suitable for application in light, con‐ densate and volatile oil reservoirs [114]. CO2 is considered the most widely used gas for GEOR injection especially in the US Permian Basin, where most of the CO2 field projects have been deployed. In the US, continuous growth of CO2 flooding projects is expected. N2 and hydrocarbon gas injection projects have been deployed in Canada and the US, although

**•** MEOR is a promising and eco‐friendly recovery process with potential for future incre‐ mental oil recovery [19]. The main downsides of MEOR are longer time intervals are required to attain incremental oil production and MEOR renders the lowest oil recovery in

Huge potentials for incremental oil recovery exist through the application of EOR processes; however, the volume of recoverable oil is greatly dependent on the implemented EOR technique. Among the key EOR techniques deployed in oil fields, miscible gas injection EOR and thermal EOR processes are currently the most commonly used techniques in the field. Continuous evolution of EOR processes in the near future should take a synergistic approach

immiscible (GEOR) and microbial or MEOR processes.

36 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

deployed technique for mobility control [83, 112].

incremental oil recovery from these processes has been negligible.

a given period in comparison to other EOR techniques.

from different EOR technologies.

by 2020 [141].

**5. Conclusions**


## **Author details**

Lezorgia Nekabari Nwidee1 , Stephen Theophilus2 , Ahmed Barifcani1,3, Mohammad Sarmadivaleh1 and Stefan Iglauer1\*

\*Address all correspondence to: stefan.iglauer@curtin.edu.au

1 Department of Petroleum Engineering, Curtin University, Perth, Western Australia

2 School of Energy, Construction and Environment, Coventry University, Coventry, United Kingdom

3 Department of Chemical Engineering, Curtin University, Perth, Western Australia

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52 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

**Chapter 2 Provisional chapter**

#### **Polymer Flooding Polymer Flooding**

#### Antoine Thomas Antoine Thomas

Additional information is available at the end of the chapter Additional information is available at the end of the chapter

http://dx.doi.org/10.5772/64623

#### **Abstract**

The focus of this chapter is on polymers and their use to enhance oil recovery through the process known as polymer flooding. Emphasis is given to practical information relevant to field application(s) of polymer flooding. Therefore, the purpose of this chapter is to provide a brief but thorough overview of key concepts necessary to understand this technology for its successful implementation in the field.

**Keywords:** polymer flooding, polymers, polyacrylamide, chemical enhanced oil re‐ covery, viscosity, sweep efficiency, pilot

## **1. Introduction**

Among all the chemical‐enhanced oil recovery methods (cEOR), polymer flooding is a straightforward technique with a lengthy commercial history and proven results. This technology by far outnumbers other chemical technologies because the risk of polymer flooding application is indeed very low and the envelope of application has greatly widened over the past years, with field cases in high temperature and high salinity reservoirs. Polymer flooding consists of injecting polymer‐augmented water into a subterranean oil formation in order to improve the sweep efficiency in the reservoir. The increased viscosity of the water causes a better mobility control between the injected water and the hydrocarbons within the reservoir.

The early pioneering work on polymers was carried out by Pye [1], Sandiford [2], Mungan [3], and Gogarty [4] with later studies performed by Mungan et al. [5], Smith [6], Szabo [7], and others. The first "large" commercial uses of polymers to increase oil recovery date back to the 1960s and 1970s in the United States during a crude oil price control period. Economic incentive programs have played an important role in the development of chemical EOR processes in the

© 2016 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited. © 2016 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

United States. ERDA (Energy Research and Development Association), DOE (Department of Energy), and the Cost‐sharing Program provided direct financial support to oil companies for the implementation of EOR processes from 1974 through 1980. The DOE‐EOR Incentive Program launched from 1979 to 1981 allowed frontend recoupment of expenses by allowing companies to sell oil at higher prices. The Crude Oil Windfall Profit Tax Act of 1980 reduced tax rates for EOR projects. The Economic Recovery Tax Act of 1981 provided research and experimentation tax credits. However, that program had a loophole which allowed EOR project incentives to be ring‐fenced with full field production, which was exploited by oil companies. The result was higher "Tier 3" oil prices for projects that barely used EOR techni‐ ques, bringing economic successes but technical failures. For polymer flooding, few studies were carried out at the time and a number of projects used minute amounts of polymer, being totally inefficient at improving the sweep efficiency in reservoirs. In the end, the misconception that the technology did not work remained in the minds of petroleum engineers.

The number of projects abruptly decreased in the 1980s for several reasons including oil prices and poor global understanding of the technology. However, research has continued over the years and polymer flooding regained interest in China in the mid‐1990s.

The largest polymer injection aimed at improving the mobility ratio was implemented in 1996 in the Daqing oilfield. As of 2004, more than 31 commercial projects were implemented, involving approximately 2427 injection wells and 2916 production wells. Polymer injection in the Shengli and Daqing oilfields yielded incremental oil recoveries ranging from 6 to 12%, contributing to 250,000 barrels per day in 2004. At the end of 2006, water consumption had decreased by 21.8 m3 per cubic meter of oil produced, with a water‐cut reduction of one‐fourth resulting in important savings in regards to produced water treatment and disposal.

Another example of successful polymer injection in the 1990s was in Courtenay, France, where extra oil recoveries from 5 to 30% have been reported after the technology was conducted in a secondary recovery mode as augmented waterflooding. Other examples will be discussed later in this chapter.

The objective of the following work is to give a summarized overview of the key concepts necessary to understand this technology, which would allow its successful implementation in the field. Other chemical‐enhanced oil recovery techniques that involve the use of polymers such as surfactant‐polymer flooding and alkali‐surfactant‐polymer flooding are not discussed in detail here. There has been a wealth of papers and books published in recent years that the reader can refer to for further clarifications or details on polymer flooding and other cEOR techniques, part of which are cited in the following sections of this chapter.

## **2. Introduction to polymer flooding**

## **2.1. History and concepts**

Muskat [8] first recognized in 1949 that fluids mobility would affect waterflood performance. In 1950, Stiles [9] used permeability and capacity distribution in waterflood calculations; while Dykstra and Parsons showed the effect of mobility ratio and permeability variations on oil recovery. The mobility ratio concept was then discussed by Aronofsky and Ramey as well as its influence on flood patterns, injection, and production histories in a five-spot waterflood in 1956. Dyes et al. [10] presented studies of the influence of mobility ratio on oil production after breakthrough. Following these studies, it was suggested to increase water viscosity to improve reservoir sweep efficiency. It was established a couple of years later by Pye and Sandiford [1, 2] that the mobility of the injected brine could be effectively reduced by the addition of small quantities of water-soluble polymers. More recently, studies have focused in essence on polymers and their behavior in reservoirs. This will be discussed in more detail shortly.

If waterflooding of an oil reservoir proves to be inefficient, due to premature water production and low oil recovery factor at water breakthrough, polymer flooding may be considered as a possible option. The value of adding polymer to a conventional waterflood can be explained by the mobility ratio which is defined by the following relationship:

$$\mathsf{M} = \frac{\lambda\_{\circ}}{\lambda\_{\circ}} = \frac{\mathfrak{mu}/k\_{\circ}}{\mathfrak{mu}/k\_{\circ}}$$

where *λ*, *μ*, and *k* are the mobility, viscosity, and effective endpoint permeabilities, respectively, and where the subscripts *w* and *o* refer to water and oil. Effective permeabilities are considered since it allows considering the selective reduction of (usually) water permeability by polymer retention and pore-blocking mechanisms.

Oil is left behind in a waterflood either because it is trapped by the capillary forces (residual oil) or because it is bypassed [11]. The mobility ratio improvement associated with the use of polymers minimizes the bypassing effect.

Polymer flooding is often implemented in two cases [12]:

United States. ERDA (Energy Research and Development Association), DOE (Department of Energy), and the Cost‐sharing Program provided direct financial support to oil companies for the implementation of EOR processes from 1974 through 1980. The DOE‐EOR Incentive Program launched from 1979 to 1981 allowed frontend recoupment of expenses by allowing companies to sell oil at higher prices. The Crude Oil Windfall Profit Tax Act of 1980 reduced tax rates for EOR projects. The Economic Recovery Tax Act of 1981 provided research and experimentation tax credits. However, that program had a loophole which allowed EOR project incentives to be ring‐fenced with full field production, which was exploited by oil companies. The result was higher "Tier 3" oil prices for projects that barely used EOR techni‐ ques, bringing economic successes but technical failures. For polymer flooding, few studies were carried out at the time and a number of projects used minute amounts of polymer, being totally inefficient at improving the sweep efficiency in reservoirs. In the end, the misconception

that the technology did not work remained in the minds of petroleum engineers.

years and polymer flooding regained interest in China in the mid‐1990s.

56 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

decreased by 21.8 m3

in this chapter.

The number of projects abruptly decreased in the 1980s for several reasons including oil prices and poor global understanding of the technology. However, research has continued over the

The largest polymer injection aimed at improving the mobility ratio was implemented in 1996 in the Daqing oilfield. As of 2004, more than 31 commercial projects were implemented, involving approximately 2427 injection wells and 2916 production wells. Polymer injection in the Shengli and Daqing oilfields yielded incremental oil recoveries ranging from 6 to 12%, contributing to 250,000 barrels per day in 2004. At the end of 2006, water consumption had

Another example of successful polymer injection in the 1990s was in Courtenay, France, where extra oil recoveries from 5 to 30% have been reported after the technology was conducted in a secondary recovery mode as augmented waterflooding. Other examples will be discussed later

The objective of the following work is to give a summarized overview of the key concepts necessary to understand this technology, which would allow its successful implementation in the field. Other chemical‐enhanced oil recovery techniques that involve the use of polymers such as surfactant‐polymer flooding and alkali‐surfactant‐polymer flooding are not discussed in detail here. There has been a wealth of papers and books published in recent years that the reader can refer to for further clarifications or details on polymer flooding and other cEOR

Muskat [8] first recognized in 1949 that fluids mobility would affect waterflood performance. In 1950, Stiles [9] used permeability and capacity distribution in waterflood calculations; while

resulting in important savings in regards to produced water treatment and disposal.

techniques, part of which are cited in the following sections of this chapter.

**2. Introduction to polymer flooding**

**2.1. History and concepts**

per cubic meter of oil produced, with a water‐cut reduction of one‐fourth


**Figure 1.** Water breakthrough can be delayed and sweep efficiency improved by increasing the viscosity of the injected fluid with polyacrylamide polymers (PAM) (modified with permission from Sorbie [11]).

In the first case, there is an inefficient macroscopic displacement that promotes early water breakthrough followed by a long period of two‐phase production with increasing water‐cuts. This situation can simply be illustrated by the viscous fingering concept which occurs espe‐ cially in heavy oil reservoirs or when the mobility ratio *M* is larger than 1 (*M* > 1) (**Figure 1**). Fractional flow calculations extensively described in the literature can be useful to visualize the benefits of polymer injection and compare simple cases.

The second case is often overlooked. It appears that, even if the mobility ratio is equal or below 1, the presence of high‐permeability channels or large‐scale reservoir layering and heteroge‐ neities can greatly impair the areal and vertical sweep efficiencies during water injection. The presence of high‐permeability layers will also lead to early water breakthrough, in these cases significant improvement can be gained using polymers to increase the viscosity of the injected water. This aspect should be remembered when screening the candidates for polymer injection to not overlook reservoirs that contain very light oils. The mechanisms of oil recovery using polymers in heterogeneous systems are quite complex and a detailed explanation of those mechanisms is beyond the scope of this chapter. A proper overview is given in Sorbie's Polymer Improved Oil Recovery [11].

An important parameter in polymer flooding is how the improvement in oil recovery can be assessed compared to waterflooding. For this, two approaches can be used. The first one considers that polymer flooding produces only the moveable oil and does not change the residual oil saturation. In this case, the final amount of oil recovered should be the same between a waterflood and a polymer flood: the only difference would be the timescale to produce the same amount of oil for each case with polymer essentially accelerating oil production (**Figure 2**). However, this approach is highly dependent on reservoir characteristics since the presence of important heterogeneities would greatly hinder water from sweeping the entire reservoir, leaving some mobile oil behind.

**Figure 2.** Production profiles for waterflood and polymer flood showing the economic limit [11].

Some recent studies [14, 15] have discussed the possible impact of polymers on residual oil saturation bringing forward the notion of viscoelasticity. In this case, in addition to pushing mobile oil, polymers would be able to decrease the residual oil saturation therefore recovering more oil than a simple waterflood, whatever the timescale considered.

The definition of incremental oil is therefore linked to the mechanisms behind polymer injection and the timescale considered for the project. For the latter, it would be necessary to compare water injection and polymer injection scenarios over the practical reservoir develop‐ ment period and the corresponding economic limits. This can be done with simulation studies which are not discussed in detail here.

### **2.2. Polymer flooding plan**

In the first case, there is an inefficient macroscopic displacement that promotes early water breakthrough followed by a long period of two‐phase production with increasing water‐cuts. This situation can simply be illustrated by the viscous fingering concept which occurs espe‐ cially in heavy oil reservoirs or when the mobility ratio *M* is larger than 1 (*M* > 1) (**Figure 1**). Fractional flow calculations extensively described in the literature can be useful to visualize

The second case is often overlooked. It appears that, even if the mobility ratio is equal or below 1, the presence of high‐permeability channels or large‐scale reservoir layering and heteroge‐ neities can greatly impair the areal and vertical sweep efficiencies during water injection. The presence of high‐permeability layers will also lead to early water breakthrough, in these cases significant improvement can be gained using polymers to increase the viscosity of the injected water. This aspect should be remembered when screening the candidates for polymer injection to not overlook reservoirs that contain very light oils. The mechanisms of oil recovery using polymers in heterogeneous systems are quite complex and a detailed explanation of those mechanisms is beyond the scope of this chapter. A proper overview is given in Sorbie's Polymer

An important parameter in polymer flooding is how the improvement in oil recovery can be assessed compared to waterflooding. For this, two approaches can be used. The first one considers that polymer flooding produces only the moveable oil and does not change the residual oil saturation. In this case, the final amount of oil recovered should be the same between a waterflood and a polymer flood: the only difference would be the timescale to produce the same amount of oil for each case with polymer essentially accelerating oil production (**Figure 2**). However, this approach is highly dependent on reservoir characteristics since the presence of important heterogeneities would greatly hinder water from sweeping the

the benefits of polymer injection and compare simple cases.

58 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

Improved Oil Recovery [11].

entire reservoir, leaving some mobile oil behind.

**Figure 2.** Production profiles for waterflood and polymer flood showing the economic limit [11].

Some recent studies [14, 15] have discussed the possible impact of polymers on residual oil saturation bringing forward the notion of viscoelasticity. In this case, in addition to pushing There is no general rule defining the quantity of polymer that should be injected into a reservoir. The number generally given, based on experience, is a minimum of 30% of the reservoir pore volume, with the following sequence:


As previously indicated, the larger the volume of polymer injected expressed as reservoir pore volume, the higher the efficiency of the process. This is explained by looking at what is happening when the injection of polymer is switched back to water injection at the end of the process: if the polymer slug volume is too small, there is a high probability that the chase water will again finger through the polymer slug, thereby decreasing the efficiency of the whole process.

Another technique described in the literature in regards to the application of polymer flooding in the Daqing oilfield is the sequential injection of high‐viscosity polymer slugs to improve reservoir conformance and redistribute the flow inside the reservoir by decreasing the flow in the high‐permeability zones [16].

The vast majority of polymer floods inject concentrations of active polymer between 1000 and 2000 parts per million (ppm), whatever the reservoir characteristics and oil viscosity. These "magic" numbers do not always have a scientific basis: normally, if the oil viscosity is very high or the reservoir heterogeneities are important, a higher viscosity should be considered at least for the pilot stage to check the acceptable reservoir pressure limits; while the final viscosity of the polymer solution to be injected is often dictated by the economics and the oil price at the time of the project approval.

Finally, the incremental oil recovery from polymer injections averages an extra 10% of oil originally in place (OOIP). The Courtenay oil field in France yielded from 5 up to 30%, the Daqing oil field showed approximately 12%, and the Marmul field roughly 10% of incremental oil recovery.

#### **2.3. Timing**

The paradox with enhanced oil recovery methods is that they are often classified as tertiary recovery methods, even if it is well‐known that primary recovery followed by water injection is, for a significant number of reservoirs, not able to produce more than 35% OOIP on average. The question that pops up is therefore: why do we wait to change the field development approach and implement the so‐called enhanced oil recovery techniques from the very beginning? There are probably multiple answers to this question:


The appropriate timing for a polymer injection can be summarized in a simple statement: the earlier the better! The economics of secondary EOR application will always be better than the economics of tertiary (and late) EOR, knowing that polymer flooding brings forward the oil production profile, delays water breakthrough and the overall handled water volumes and associated costs of water treatment and disposal. Nevertheless, there is still a significant benefit of implementing the technology even in watered‐out reservoirs and especially for heavy oil pools [17].

#### **2.4. Screening criteria for polymer application**

Historically, it appears that sandstones were preferred over carbonates when considering polymer injection. For instance, when looking at the projects in the USA between 1971 and 1990, 320 pilot projects or field wide chemical floods have been identified in the literature among which 57 were conducted in carbonate reservoirs. This preference can probably be explained by the fact that anionic polymers present several advantages: they have a high viscosifying power, very high molecular weights, and are cheap to produce by opposition to synthetic cationic polymers which are expensive to produce, highly shear sensitive, and display lower molecular weights on average. For sandstone and clayey reservoirs, which are negatively charged, the injection of anionic macromolecules is obviously preferred to limit ionic interactions.

Papers published in the 1960s, 1970s, or even 1980s indicate that polymers for EOR were limited to a narrow range of oil field conditions (**Tables 1** and **2**). A literature review on polymer field applications shows that the maximum reservoir temperature was 200°F (90°C), crude oil viscosity had to be below 200 cP, and injection water must not exceed a certain amount of divalent ions (300–500 ppm).


Reservoirs with strong natural water drive, large gas caps, gross channeling, or major natural fractures should be avoided

**Table 1.** Screening criteria for polymer flooding according to Chang [18].

Daqing oil field showed approximately 12%, and the Marmul field roughly 10% of incremental

The paradox with enhanced oil recovery methods is that they are often classified as tertiary recovery methods, even if it is well‐known that primary recovery followed by water injection is, for a significant number of reservoirs, not able to produce more than 35% OOIP on average. The question that pops up is therefore: why do we wait to change the field development approach and implement the so‐called enhanced oil recovery techniques from the very

**•** Lack of knowledge on the green field: geometry, fluid distributions, pressure responses to a viscous fluid injection, optimal well placement, and connectivity between zones, etc.

**•** How to quantify the efficiency of an EOR method and incremental oil without baseline data

The appropriate timing for a polymer injection can be summarized in a simple statement: the earlier the better! The economics of secondary EOR application will always be better than the economics of tertiary (and late) EOR, knowing that polymer flooding brings forward the oil production profile, delays water breakthrough and the overall handled water volumes and associated costs of water treatment and disposal. Nevertheless, there is still a significant benefit of implementing the technology even in watered‐out reservoirs and especially for heavy oil

Historically, it appears that sandstones were preferred over carbonates when considering polymer injection. For instance, when looking at the projects in the USA between 1971 and 1990, 320 pilot projects or field wide chemical floods have been identified in the literature among which 57 were conducted in carbonate reservoirs. This preference can probably be explained by the fact that anionic polymers present several advantages: they have a high viscosifying power, very high molecular weights, and are cheap to produce by opposition to synthetic cationic polymers which are expensive to produce, highly shear sensitive, and display lower molecular weights on average. For sandstone and clayey reservoirs, which are negatively charged, the injection of anionic macromolecules is obviously preferred to limit

Papers published in the 1960s, 1970s, or even 1980s indicate that polymers for EOR were limited to a narrow range of oil field conditions (**Tables 1** and **2**). A literature review on polymer field applications shows that the maximum reservoir temperature was 200°F (90°C), crude oil viscosity had to be below 200 cP, and injection water must not exceed a certain amount of

beginning? There are probably multiple answers to this question:

**2.4. Screening criteria for polymer application**

oil recovery.

60 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

**2.3. Timing**

for comparison?

pools [17].

ionic interactions.

divalent ions (300–500 ppm).

In 1991, Sorbie described some limits which were within the same range, i.e., *T*max = 95°C, oil viscosity < 70 cP, and reservoir permeability above 20 mD (**Table 2**).

Seright [17] proposed several explanations for these screening criteria considering the state of the technology and oil prices at that time:


Many improvements have widened the range of polymer applicability for polymers in cEOR. In addition to a better understanding of polymer flow behavior through the rock formation and a better knowledge of the geology and dynamics of the reservoirs, many developments in chemistry have allowed manufacturing polymers that are more stable to high temperatures, tolerant to high salinity and hardness concentration, and shear resistant polymers. The addition of protective additives to prolong the chemical stability of the polymers has been also performed. Furthermore, new equipment has been designed to maximize the injection efficiency of polymer solutions while decreasing the overall risk of degradation before entering the reservoir. For instance, Vermolen et al. [19] described the stability of *N*‐vinyl pyrrolidone (NVP)‐based ter‐polymers for 1 year at 120°C in 180 g/L TDS brine. Gaillard et al. [20] tested the efficiency of protective additives on temperature and salinity resistant polymers. Seright et al. described the implementation of polymers in a field with 500 cP oil. Kulawardana et al. [21] demonstrated the efficient propagation of NVP ter‐polymers in 50 mD cores at 100°C. This is just a very small view into the work that has been conducted in the past years to validate the polymer technology for EOR applications. Many references are given for further reading at the end of the chapter.

Some unchanging parameters that must be considered before the implementation of polymer flooding are:



**Table 2.** Screening criteria for polymer flooding according to Sorbie [11].

**Table 3** presents updated screening criteria for polymer flooding, in which only the upper values of the respective ranges are provided for the most important criteria.


**Table 3.** Current screening criteria for polymer flooding application (updated after [11] and [18]).

#### **2.5. Other technologies**

Some unchanging parameters that must be considered before the implementation of polymer

**•** Water injectivity: obviously, good water injectivity will ensure appropriate polymer

**•** Clays: a high percentage of clays can be detrimental to polymer propagation (adsorption

**•** Presence of aquifers: to avoid dilution and chemical losses, injection should occur outside

**Comment**

normal polymer

worse with polymer

>20 mD To avoid excessive polymer retention

The indicator in both cases is early water breakthrough and low sweep efficiency

Polymers degrade at higher temperatures

If there are some problems with water, they will be

Additional retention losses in transport to oil leg

High salinity/hardness biopolymer Low salinity/hardness = PAM

For heterogeneity control less severe contrast does not require polymer and more severe is too high for

**Heterogeneity control polymer flood**

Usually 0.4 cP < *μo* < 10 cP Max 20 cP

Some heterogeneity by definition 4 < horizontal perm. /average permeability/ *k*av < 30

injectivity. Several guidelines will be provided later on.

**Viscosity control polymer flood**

62 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

< 30 cP Max 70

Low formation should be as homogeneous as possible

cP

**Temperature** Lower temperature best

Best <80°C Max <95°C

**Water injectivity** Should be good preferably with some

may help

spare injection capacity—fracturing

Injection not deep in aquifer or far

Not critical but determine which

**Clays** Should be generally low Tend to give high polymer retention

values of the respective ranges are provided for the most important criteria.

**Table 3** presents updated screening criteria for polymer flooding, in which only the upper

below oil/water contact

polymer can be used

**Table 2.** Screening criteria for polymer flooding according to Sorbie [11].

flooding are:

**Screening criterion** 

**Level of large -scale heterogeneity**

**Absolute permeability**

**Aquifer/oil/water**

**Injection brine salinity/**

**contact**

**hardness**

and retention).

of the aquifer zone.

**Oil viscosity** Usually 5 cP < *μo*

**•** Surfactant‐polymer (SP) and alkali‐surfactant‐polymer (ASP)

Capillary forces cause large quantities of oil to be bypassed in well‐swept zones of water‐ flooded oil reservoirs [13, 22]. Surfactant injection (surface active agents) can reduce the interfacial tension between the oil and water and release trapped oil; while the injection of a large polymer slug provides mobility control. However, it is often necessary to inject signifi‐ cantly higher dosages of costly surfactants to balance their adsorption onto the rock surface. This effect can be offset by addition of alkali to the solution. The latter will adsorb onto rocks (decreasing surfactant adsorption), increase the pH, and generate *in situ* soaps. This process often requires expensive water treatment facilities, and combined with the surfactant, can generate difficulties to break the produced emulsion. Surfactant‐polymer and alkali‐surfac‐ tant‐polymer require a careful design and should be monitored cautiously [13].

**•** Gels and derivatives

As discussed by Seright et al. [23], the preliminary discussion is to point out the main differences between a gel used for reservoir conformance control and a polymer flood. Conventional gels used in "conformance control" are intended to block or reduce the flow capacity of high‐permeability channels without damaging the less‐permeable hydrocarbon‐ productive zones. It is therefore compulsory to minimize penetration of gelants into the less‐ permeable zones. Any gel or blocking agent that enters the less‐permeable zones can hinder or even shut off any subsequent injected fluids from entering and displacing oil from those

**Figure 3.** Comparison between polymer flood and gel systems (modified with permission from Seright [23]).

zones. In contrast, polymer floods are designed to directly displace oil from lower permeability zones. As a matter of fact, a viscous polymer solution should enter as much as possible into these lower permeability zones to displace oil from these poorly swept areas (**Figure 3**, [23]).

Particularly, colloidal dispersion gels—low polymer concentration with a metallic cationic cross‐linker—are often claimed to be more efficient and cost‐effective than conventional polymer floods. Several questions arise in regards to this claim and are as follows:


Some positive results have been reported from field applications of this technology. However, the extra‐oil recovery observed might be caused by:


In any case, laboratory studies involving coreflooding using long reservoir core plugs should be performed to ensure that the entire system propagates through the core plug prior to implementation in the field.

## **3. Polymer characteristics**

Polymers are chemical compounds composed of repeating units called monomers. Biopoly‐ mers and synthetic polymers are the two families of polymers usually considered by the oil industry when attempting to increase water viscosity and to improve the sweep efficiency of the reservoir. These types of polymers will be briefly described in the following paragraphs. However, a particular focus will be directed to synthetic polymers, which are the most commonly used polymers by the oil industry, primarily due to their availability and favorable costs.

#### **3.1. Biopolymers**

Xanthan gum and more recently schizophyllan are the main biopolymers considered for applications in the oil industry.

**Figure 4.** Molecular structure of Xanthan gum [24].

zones. In contrast, polymer floods are designed to directly displace oil from lower permeability zones. As a matter of fact, a viscous polymer solution should enter as much as possible into these lower permeability zones to displace oil from these poorly swept areas (**Figure 3**, [23]).

Particularly, colloidal dispersion gels—low polymer concentration with a metallic cationic cross‐linker—are often claimed to be more efficient and cost‐effective than conventional

**•** Does the cross‐linker propagate inside the reservoir without any retention on the negatively charged clays and sandstone? Obviously, the answer would be probably no in this case.

**•** Are these gels plugging mainly the high‐permeability layers allowing the chase fluid to go into the low‐permeability zones? This statement defies basic reservoir engineering laws

Some positive results have been reported from field applications of this technology. However,

**•** A decreased mobility ratio obtained by the added polymer within the colloidal dispersion gel formulation, even at low polymer concentrations. It should be noticed that increasing

**•** A decreased relative permeability to water that could be induced by both: overall polymer retention (mechanical retention and adsorption) and the formation of gel in all zones of the

In any case, laboratory studies involving coreflooding using long reservoir core plugs should be performed to ensure that the entire system propagates through the core plug prior to

Polymers are chemical compounds composed of repeating units called monomers. Biopoly‐ mers and synthetic polymers are the two families of polymers usually considered by the oil industry when attempting to increase water viscosity and to improve the sweep efficiency of the reservoir. These types of polymers will be briefly described in the following paragraphs. However, a particular focus will be directed to synthetic polymers, which are the most commonly used polymers by the oil industry, primarily due to their availability and favorable

Xanthan gum and more recently schizophyllan are the main biopolymers considered for

the water viscosity from 1 to 2 cP divides the mobility ratio expression by 2.

polymer floods. Several questions arise in regards to this claim and are as follows:

including Darcy's law.

implementation in the field.

**3. Polymer characteristics**

costs.

**3.1. Biopolymers**

applications in the oil industry.

the extra‐oil recovery observed might be caused by:

64 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

reservoir, with a temporary effect on the oil recovery.

Xanthan gum is a fermentation product produced by a mutant of *Xanthamonas campestris*. Xanthan gum is a polysaccharide made from saccharide monomer units which are D‐glucose, D‐mannose, and D‐glucuronic acid. This biopolymer has a cellulose‐like backbone composed of repeating β ‐D‐ (1‐4) glucose units with mannose and glucuronic acid side chains, and the mannose partially modified with acetyl and pyruvate ketal groups (**Figure 4**). The rigid structure of xanthan gum provides good shear and brine tolerance when compared to polyacrylamides. However, some drawbacks still remain such as cost and availability and the fact that the biopolymer should be protected from any biological attack with biocides.

Xanthan gum is available in different forms:


Schizophyllan is a homo‐glucan with an average molecular weight of 2–3 million Dalton produced by a fungus in a fermentation process from a carbon source (**Figure 5**) [13]. The polymer has a linear structure without charged functional groups which yields high viscosity as well as salt tolerance. The rigidity of the structure is also responsible for the mechanical and temperature stabilities.

**Figure 5.** Chemical structure of β‐1, 3:β‐1,6 glucan [13].

A critical step for the development of this biopolymer was the biotechnological process required to separate the fungus from the biopolymer and make it viable at large scales.

#### **3.2. Partially hydrolyzed polyacrylamide**

The most common synthetics polymers used in polymer flooding are partially hydrolyzed polyacrylamides (HPAMs) and synthetic flexible straight chains of acrylamide monomers.

HPAMs are prepared with a typical degree of hydrolysis of 30%, but it can be adjusted to be higher or lower. These polymers are usually delivered in two forms:


**Figure 6.** Inverse emulsion system [25].

#### *3.2.1. Polymerization processes*

These polymers can be manufactured using different chemical paths as follows:


**Figure 7.** Overview of the copolymerization process [25].

A critical step for the development of this biopolymer was the biotechnological process required to separate the fungus from the biopolymer and make it viable at large scales.

The most common synthetics polymers used in polymer flooding are partially hydrolyzed polyacrylamides (HPAMs) and synthetic flexible straight chains of acrylamide monomers.

HPAMs are prepared with a typical degree of hydrolysis of 30%, but it can be adjusted to be

**•** Emulsion: as a water‐in‐oil emulsion with 30% active content, which must be properly

These polymers can be manufactured using different chemical paths as follows:

**•** Cohydrolysis or posthydrolysis of a polyacrylamide (**Figure 8**).

**•** Copolymerization of acrylamide and sodium acrylate (or/and sodium acrylamido‐tertiary‐

**•** Copolymerization or terpolymerization of acrylamide with other ionic or nonionic func‐ tional monomers. Functional monomers can enhance the resistance to temperature and salinity (example of *N*‐vinylpyrrolidone for improved thermal and salinity resistance) [26].

higher or lower. These polymers are usually delivered in two forms:

**3.2. Partially hydrolyzed polyacrylamide**

66 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

inverted to release the polymer (**Figure 6**).

**•** Powder: >90% active content.

**Figure 6.** Inverse emulsion system [25].

*3.2.1. Polymerization processes*

butyl sulfonate (ATBS)) (**Figure 7**).

**Figure 8.** Overview of the posthydrolysis process [25].

Depending upon the manufacturing process, the distribution of the anionic charges along the polymer chain differs, which induces different physical properties during and after hydration. Posthydrolyzed polyacrylamides are composed of a wide range of anionic chains, some being highly charged and others less charged. The copolymerization of acrylamide and sodium acrylate produces a polymer with a more even charge distribution along the backbone. These properties are paramount for the behavior of the polymers in an aqueous solution, especially in the presence of divalent cations such as calcium and magnesium [13].

There are several ways to characterize anionic polyacrylamides including their molecular weight (*M*w) and molecular weight distribution or polydispersity index (PDI). The range of *M*<sup>w</sup> typically lies between 4 and 30 million g/mol and it is often determined using intrinsic viscosity measurement. As of today, PDI cannot be determined since neither standards with low PDIs nor GPC (gel permeation chromatography) techniques exist today for such high *M*w. However, as with the anionicity, a relatively wide range of molecular weights is present in one given product. Moreover, the structure of copolymers is more easily controlled than the post‐ hydrolyzed molecules. **Figures 9** and **10** show some common polymer structures [26].

**Figure 9.** Example of acrylamide and sodium acrylate copolymer [26].

**Figure 10.** Example of acrylamide‐ATBS copolymer [26].

#### *3.2.2. Viscosity*

The thickening or viscosifying capability of anionic polyacrylamides is linked to the level of entanglement of the high molecular weight macromolecules and also to the intra‐ and intermolecular electrostatic repulsions between polymer coils. When polyelectrolytes are dissolved in water containing electrolytes (salts), a reduction in viscosity is observed [27]. This is attributed to the shielding effect of the charges leading to a decreased electrostatic repulsion and therefore to a minimum expansion of the polymer coils in the aqueous solution. The result is a lower hydrodynamic volume and consequently a lower viscosity [28]. In addition to the salt dependency, other factors influencing the viscosity of partially hydrolyzed polyacrylamide solutions are the degree of hydrolysis, solution temperature, molecular weight (**Figure 11**), tridimensional structure, and solvent quality [29].

nor GPC (gel permeation chromatography) techniques exist today for such high *M*w. However, as with the anionicity, a relatively wide range of molecular weights is present in one given product. Moreover, the structure of copolymers is more easily controlled than the post‐ hydrolyzed molecules. **Figures 9** and **10** show some common polymer structures [26].

The thickening or viscosifying capability of anionic polyacrylamides is linked to the level of entanglement of the high molecular weight macromolecules and also to the intra‐ and intermolecular electrostatic repulsions between polymer coils. When polyelectrolytes are dissolved in water containing electrolytes (salts), a reduction in viscosity is observed [27]. This is attributed to the shielding effect of the charges leading to a decreased electrostatic repulsion and therefore to a minimum expansion of the polymer coils in the aqueous solution. The result is a lower hydrodynamic volume and consequently a lower viscosity [28]. In addition to the salt dependency, other factors influencing the viscosity of partially hydrolyzed polyacrylamide solutions are the degree of hydrolysis, solution temperature, molecular weight (**Figure 11**),

**Figure 9.** Example of acrylamide and sodium acrylate copolymer [26].

68 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

**Figure 10.** Example of acrylamide‐ATBS copolymer [26].

tridimensional structure, and solvent quality [29].

*3.2.2. Viscosity*

**Figure 11.** Viscosity of several polymers as a function of concentration. The average molecular weight increases from Flopaam 3130S to 3630S [25].

**Figure 12.** Viscosity versus temperature for several polymers including thermoresponsive (DP/TLB) and conventional polymers (AN132SH). Brines are displayed as 130K + 35K meaning 130 g/L NaCl + 35 g/L CaCl2 (from Leblanc et al. [31]).

At isomolecular weight and at isoconcentration conditions, polyelectrolytes are likely to behave differently depending on their chemistry and on the composition of the aqueous media. For instance, if the polymer is compatible with the injection and/or formation brine, the polymer molecule will uncoil allowing interchain interactions. In the other case, if the polymer is not compatible with the injection and/or formation brine, the polymer molecule will coil up resulting in intramolecular associations.

Other strategies exist to enable intermolecular associations independently of the molecular weight of the polymer. One approach is the incorporation of hydrophobic moieties within a hydrophilic molecule in the polymer backbone—leading to segments that associate. A concise overview of this technology including the chemistry of these so‐called associative polymers is given by Wever et al. [30]. More recently [31], thermosensitive polymers have been developed (**Figure 12**). The thermosensitive concept involves water‐soluble main chains with blocks or side groups which possess lower critical solution temperature or LCST moieties [32]. These thermosensitive polymers display viscosity increase as a function of salinity and temperature. Other advantages of these thermosensitive polymers would include the highly improved injectivity of the viscous polymer solutions inside oil‐bearing formations since the viscosity would build progressively with temperature and/or salinity.

#### *3.2.3. Rheology*

Polyacrylamide fluids behave as non‐Newtonian fluids meaning that the viscosity is depend‐ ent on the applied shear (**Figure 13**). They show a pseudo‐plastic (or shear thinning) behavior: viscosity decreases as shear stress increases following a power‐law model (**Figure 14**). The viscosity is dependent upon the concentration and the molecular weight of the polymer in the aqueous solution. Moreover, the rheological behavior of synthetic polymers in porous media is quite different from their rheological behavior in bulk (in a viscometer measuring device). This topic is beyond the scope of this chapter and it will not be discussed here.

**Figure 13.** Types of fluids and their characteristics [25].

**Figure 14.** Viscosity profile for a typical non‐Newtonian polyacrylamide fluid as a function of shear rate fitted using a power law equation [33].

#### *3.2.4. Solubility*

At isomolecular weight and at isoconcentration conditions, polyelectrolytes are likely to behave differently depending on their chemistry and on the composition of the aqueous media. For instance, if the polymer is compatible with the injection and/or formation brine, the polymer molecule will uncoil allowing interchain interactions. In the other case, if the polymer is not compatible with the injection and/or formation brine, the polymer molecule will coil up

Other strategies exist to enable intermolecular associations independently of the molecular weight of the polymer. One approach is the incorporation of hydrophobic moieties within a hydrophilic molecule in the polymer backbone—leading to segments that associate. A concise overview of this technology including the chemistry of these so‐called associative polymers is given by Wever et al. [30]. More recently [31], thermosensitive polymers have been developed (**Figure 12**). The thermosensitive concept involves water‐soluble main chains with blocks or side groups which possess lower critical solution temperature or LCST moieties [32]. These thermosensitive polymers display viscosity increase as a function of salinity and temperature. Other advantages of these thermosensitive polymers would include the highly improved injectivity of the viscous polymer solutions inside oil‐bearing formations since the viscosity

Polyacrylamide fluids behave as non‐Newtonian fluids meaning that the viscosity is depend‐ ent on the applied shear (**Figure 13**). They show a pseudo‐plastic (or shear thinning) behavior: viscosity decreases as shear stress increases following a power‐law model (**Figure 14**). The viscosity is dependent upon the concentration and the molecular weight of the polymer in the aqueous solution. Moreover, the rheological behavior of synthetic polymers in porous media is quite different from their rheological behavior in bulk (in a viscometer measuring device).

This topic is beyond the scope of this chapter and it will not be discussed here.

resulting in intramolecular associations.

70 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

*3.2.3. Rheology*

would build progressively with temperature and/or salinity.

**Figure 13.** Types of fluids and their characteristics [25].

In the field, polyacrylamides are solubilized in injection brine which contains dissolved salts. Total dissolution of the polyacrylamide in the brine is achieved when no insoluble or swollen particles remain in the solution, as determined by the filtration test. If high molecular weight polymers with *M*<sup>w</sup> > 1 million g/mol or even higher molecular weight (*M*w ≈ 18 million g/mol) polymers are used in the field, injectivity issues can be observed if total dissolution of the polymer in the brine is not achieved. Furthermore, polymers may contain low concentration of partially soluble species (i.e., branched or cross‐linked chains) due to the manufacturing process. Therefore, it is necessary to ensure that minute undissolved polymer clusters known as fish‐eyes are not formed during the polymer dissolution process, in order to limit potential damages to the formation during polymer injection.

#### *3.2.5. Stability tests*

Long‐term stability tests are useful to ensure that polymer degradation will not occur within the reservoir during the transit time between the injection and production wells. Polymer solutions are prepared under anaerobic conditions inside a glove (**Figure 15**) and stored in specially designed stainless steel ampoules which are stored in oven at the specific reservoir temperature. Viscosity is checked on a regular basis inside the glove box using concentric cylinder Brookfield rheometers. Some stability studies can last several years for offshore projects where the spacing between the injector and producer is large and transit times are significant.

**Figure 15.** Typical glove box set‐up to perform tests in anaerobic conditions [25].

#### *3.2.6. Coreflooding*

Polymer injection into porous medium (i.e., coreflooding tests) is a useful testing procedure to check the propagation of the macromolecules through core plugs from the reservoir to ensure that irreversible damage to the formation will not occur. However, it is necessary to be mindful that a core plug will never be representative of what will happen in a field application, in particular at the harsh conditions near the injection wellbore. Therefore, it is important to define the goal of coreflooding testing, such as the establishment of face plugging and the verification of proper polymer propagation along the core plug. Likewise, it is important to understand that coreflooding testing will not provide information on the following aspects:


More realistic objectives for polymer coreflooding testing are:

**Figure 15.** Typical glove box set‐up to perform tests in anaerobic conditions [25].

72 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

Polymer injection into porous medium (i.e., coreflooding tests) is a useful testing procedure to check the propagation of the macromolecules through core plugs from the reservoir to ensure that irreversible damage to the formation will not occur. However, it is necessary to be mindful that a core plug will never be representative of what will happen in a field application, in particular at the harsh conditions near the injection wellbore. Therefore, it is important to define the goal of coreflooding testing, such as the establishment of face plugging and the verification of proper polymer propagation along the core plug. Likewise, it is important to understand that coreflooding testing will not provide information on the following aspects:

**•** Polymer coreflooding testing does not provide information of the actual injectivity of the polymer in the field. Wellbore effects (even if radial corefloods are performed) on polymer flooding, such as completion, flow rates, the presence of microfractures, and damage formation, among others, cannot be evaluated during coreflooding testing. An example is the polymer shear‐thickening behavior observed in the laboratory that will probably never occur in the field when considering the presence of microfractures created after completing

**•** Polymer coreflooding testing does not provide information on true polymer overall retention values. Even if it seems obvious, it is important to remember that every reservoir have some degree of heterogeneity, therefore, polymer retention in the field will be likely

the well (i.e., perforations, stress changes) or during the waterflooding stage.

greater than polymer retention observed in the laboratory [34].

*3.2.6. Coreflooding*


Preliminary screening can be performed using analog core plugs before using the actual reservoir core plugs to obtain more realistic retention and mobility reduction values.

Two important parameters are usually evaluated, the mobility reduction (or resistance factor) and the permeability reduction (or residual resistance factor). The mobility reduction (*FR*) is the apparent relative viscosity of polymer solution during its flow through the porous medium, defined by:

$$FR = \frac{\Delta P\_{\text{polymer}\quad\text{solution}}}{\Delta P\_{\text{breine}}} \text{ o } \frac{\mu\_{\text{polymer}\quad\text{solution}}}{\mu\_{\text{breine}}}.$$

where *ΔP*polymer solution/brine is the pressure drop during polymer injection and brine, respectively, and *μ* is the viscosity of the fluid considered.

The permeability reduction or residual resistance factor, *FRR*, is the reduction of permeability due to several mechanisms such as polymer adsorption onto the rock surface, mechanical retention of polymers in pore constrictions that are of smaller size than the polymer macro‐ molecules, and any other condition that retains polymer in the porous media (i.e., polymer precipitation due to interactions with divalent cations present in the reservoir brines). The residual resistance factor (*FRR*) is defined as:

$$FRR = \frac{\Delta P\_{\text{post polymer}}}{\Delta P\_{\text{brine}}} \text{ o } \frac{k\_{\text{brine}}}{k\_{\text{post polymer}}}$$

Polymer retention would be a more appropriate wording since it includes adsorption, mechanical, and hydrodynamic entrapment as explained for instance in Sorbie [11] (**Figure 16**). Retention can be determined using several methods, either in static or dynamic conditions, the latter being the most relevant. Common acceptable values for polymer retention by sandstones range from 10 to 50 μg of lost polymer per gram of rock. Polymer retention depends on the lithology of the rock (i.e., the presence of clay, clay content, and types of clays) and on the polymer characteristics (i.e., molecular weight, chemistry, degree of hydrolysis, etc.).

**Figure 16.** Mechanisms of polymer retention (modified with permission from Sorbie [11]).

Polymer retention in the porous media can be controlled by manipulating the polymer chemistry (i.e., the addition of ATBS is known to favor polymer propagation), the molecular weight (lower molecular weight means less hydrodynamic retention), and by adding sacrificial agents upfront to condition the reservoir before polymer injection, such as low molecular weight polyacrylates [35]. Determining a "true" residual resistance factor often requires the injection of many pore volumes of water. Injecting water behind a polymer slug creates an unstable displacement front and cleaning the core from any residual polymer in this case could take a long time. It is therefore recommended to take a value of FRR equal to 1 for simulation purposes to be conservative.

#### *3.2.7. Polymer degradation*

The stability and chemical reliability of polymers used for cEOR are significant factors for oil field applications. Polymers can undergo chemical, mechanical, and thermal degradation during EOR flooding operations.

Currently, there are limited data available from actual polymer oil field applications in regards to the degree of degradation endured by the polymer injected during the flooding operation. Internal reports and papers published on polymer floodings carried out at the Daqing and Shengli oil fields (China), indicate that the viscosity of the produced polymer solution was low [36, 37]. Additionally, polymer concentration in the produced solution was 50% lower than the concentration of the injected polymer, the anionicity of the polymer was increased, and the produced polymer average molecular weight was much lower compared to the molecular weight of the injected polymer. For field applications, it is also important to determine where polymer degradation occurs—at the surface facilities, down hole of the injection well, or inside the reservoir. In any case, it is paramount to minimize any potential degradation to maintain a reasonable viscosity of the polymer solution injected during the duration of the cEOR flooding to maximize the extra oil recovery.

A brief review on the chemical, mechanical, and thermal degradation of polymers within the context of cEOR is presented in the following paragraphs.

#### **•** Chemical degradation

**Figure 16.** Mechanisms of polymer retention (modified with permission from Sorbie [11]).

simulation purposes to be conservative.

74 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

*3.2.7. Polymer degradation*

during EOR flooding operations.

flooding to maximize the extra oil recovery.

context of cEOR is presented in the following paragraphs.

Polymer retention in the porous media can be controlled by manipulating the polymer chemistry (i.e., the addition of ATBS is known to favor polymer propagation), the molecular weight (lower molecular weight means less hydrodynamic retention), and by adding sacrificial agents upfront to condition the reservoir before polymer injection, such as low molecular weight polyacrylates [35]. Determining a "true" residual resistance factor often requires the injection of many pore volumes of water. Injecting water behind a polymer slug creates an unstable displacement front and cleaning the core from any residual polymer in this case could take a long time. It is therefore recommended to take a value of FRR equal to 1 for

The stability and chemical reliability of polymers used for cEOR are significant factors for oil field applications. Polymers can undergo chemical, mechanical, and thermal degradation

Currently, there are limited data available from actual polymer oil field applications in regards to the degree of degradation endured by the polymer injected during the flooding operation. Internal reports and papers published on polymer floodings carried out at the Daqing and Shengli oil fields (China), indicate that the viscosity of the produced polymer solution was low [36, 37]. Additionally, polymer concentration in the produced solution was 50% lower than the concentration of the injected polymer, the anionicity of the polymer was increased, and the produced polymer average molecular weight was much lower compared to the molecular weight of the injected polymer. For field applications, it is also important to determine where polymer degradation occurs—at the surface facilities, down hole of the injection well, or inside the reservoir. In any case, it is paramount to minimize any potential degradation to maintain a reasonable viscosity of the polymer solution injected during the duration of the cEOR

A brief review on the chemical, mechanical, and thermal degradation of polymers within the

Chemical degradation is related to the formation of free radicals that can react with the polymer backbone resulting in a drop of molecular weight [38, 39] and viscosity loss. Redox reactions are often involved in the formation of free radicals [40]. The presence of chemicals or contam‐ inants such as oxygen contributes to the formation of such radicals. For example, iron II and/or H2S in contact with oxygen cause polymer degradation. Stabilizer compounds are added to some commercial grade polymers to delay the unavoidable occurrence of chemical degradation. **Figure 17** shows the percentage of viscosity loss of the polymer solution as a function of iron and oxygen concentration. The viscosity loss can reach 50% with the addition of only 1 ppm of iron and 300 ppb of oxygen.

**Figure 17.** Polymer degradation in presence of oxygen and iron 2 in 7.086 g/L TDS brine [26].

**Oxygen.** A concentration of oxygen below 5 ppb allows for good stability of a polyacrylamide solution up to 120°C for more than 200 days [41, 42]. The addition of oxygen scavengers such as dithionite and sodium sulfite [41, 43] to the brine is beneficial to maintain the concentration of free oxygen at a low level in the brine. However, any reexposure to any trace of oxygen in the presence of residual oxygen scavenger will act to break the polymer chains. It is therefore compulsory to keep the oxygen content as well as the presence of oxygen scavenger in the brine under control.

**Iron.** To limit the effect of polymer degradation due to the presence of iron in the injection brine, several complexing agents can be added to the solution such as EDTA (ethylene diamine tetra‐acetic acid). However, using a chelating agent to complex iron can lead to an increase of the degradation of the polymer [44]. Another approach is to partially precipitate the iron contained in the injection brine by increasing the pH of the solution with sodium carbonate [42].

**•** Mechanical degradation

Mechanical degradation occurs when the polymer backbone is subjected to a large shear rate, high velocity (i.e., flow rate), and singular pressure drop. The critical points which must be assessed along the injection facilities are chokes, valves, and certain types of pumps, as well as the well completion [26, 45].

In every case, choosing the right polymer is paramount: the higher the average molecular weight, the higher the sensitivity to shear. Breaking a high molecular weight polymer can possibly improve the injectivity with a minor viscosity loss. A drawback to this method can be the loss of the viscoelastic effect which is mainly given by the highest molecular weight fraction of the polymer [46]. **Figure 18** shows the impact of shear degradation on polymers with different molecular weights. This experiment was carried out using a pipe of 0.875 mm internal diameter and a pipe length of 200 mm. As mentioned previously, the higher the molecular weight, the higher the irreversible viscosity loss. Large‐scale studies and field cases (especially dealing with the effect of well completion on the mechanical degradation of polymer) can be found in the following references [47–49].

**•** Thermal degradation

Thermal degradation varies with the type of polymer and reservoir conditions. For typical HPAM polymers, a temperature increase will lead to an increase in the hydrolysis of acryla‐

**Figure 18.** Shear degradation and percentage of viscosity loss for polymers having the same chemistry but different molecular weights (from high molecular weight polymer, Flopaam 3630S, to lower molecular weight polymer, Flo‐ paam 3230S) [26].

mide moieties generating a higher charge density of anionic functionalities along the polymer backbone (**Figure 19**).

**Figure 19.** Hydrolysis of acrylamide moieties along the polymer backbone [25].

the degradation of the polymer [44]. Another approach is to partially precipitate the iron contained in the injection brine by increasing the pH of the solution with sodium carbonate [42].

Mechanical degradation occurs when the polymer backbone is subjected to a large shear rate, high velocity (i.e., flow rate), and singular pressure drop. The critical points which must be assessed along the injection facilities are chokes, valves, and certain types of pumps, as well

In every case, choosing the right polymer is paramount: the higher the average molecular weight, the higher the sensitivity to shear. Breaking a high molecular weight polymer can possibly improve the injectivity with a minor viscosity loss. A drawback to this method can be the loss of the viscoelastic effect which is mainly given by the highest molecular weight fraction of the polymer [46]. **Figure 18** shows the impact of shear degradation on polymers with different molecular weights. This experiment was carried out using a pipe of 0.875 mm internal diameter and a pipe length of 200 mm. As mentioned previously, the higher the molecular weight, the higher the irreversible viscosity loss. Large‐scale studies and field cases (especially dealing with the effect of well completion on the mechanical degradation of

Thermal degradation varies with the type of polymer and reservoir conditions. For typical HPAM polymers, a temperature increase will lead to an increase in the hydrolysis of acryla‐

**Figure 18.** Shear degradation and percentage of viscosity loss for polymers having the same chemistry but different molecular weights (from high molecular weight polymer, Flopaam 3630S, to lower molecular weight polymer, Flo‐

**•** Mechanical degradation

76 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

as the well completion [26, 45].

**•** Thermal degradation

paam 3230S) [26].

polymer) can be found in the following references [47–49].

If the brine contains significant amounts of divalent cations such as calcium and magnesium, a viscosity drop is observed due to ionic bridges that can ultimately result in precipitation of the polymer [50]. The incorporation of sulfonate monomer (ATBS) to the polymer backbone improves its tolerance to calcium (AN125SH) at high temperature but in general with an increased polymer cost (**Figure 20**). An optimal polymer composition (i.e., addition of ATBS monomers) can be customized in the laboratory for a particular reservoir and its unique conditions.

**Figure 20.** Salt tolerance of different polymer chemistries. The three polymers on the right side of the graph have in‐ creasing ATBS content [25].

It is clear that fine‐tuning the polymer chemical structure (i.e., composition and molecular weight) is crucial to optimize the polymer stability for application at specific reservoir conditions. The selection of the best reservoir for polymer flooding application must take into consideration the analysis of the following three reservoir parameters: reservoir temperature, brine composition (salinity, divalent cations, dissolved oxygen, iron, and hydrogen sulfide), and permeability. Polymer stability tests can be carried out over several months or years to ensure that viscosity loss is not observed during ageing in the presence of contaminants [26]. It is mandatory to perform these experiments under controlled anaerobic conditions (in glove box for instance) to quantify the level of degradation.

## **4. Polymer flooding: design and implementation**

#### **4.1. Reservoir screening**

The objective of any reservoir screening process is to identify the best technology to improve oil recovery at a reasonable cost. Several criteria can be used during the screening process. General guidelines are provided in the following paragraphs. However, very often, a variety of parameters are assessed and obtaining a clear depiction of what would be the best technol‐ ogy‐reservoir duo could be difficult.

Two general screening rules for polymer flooding are:


Specific parameters that need to be checked to determine if polymer flooding would be a viable option for the selected reservoir(s) are as follows:


$$\mathcal{R}^+ = \frac{\sum \left( \text{Diivalent actions} \right)}{\sum \left( \text{Cations} \right)}$$

The above list can appear to be quite short and simple, when indeed there are many other factors related to the oil field that should be considered. However, if these criteria are met, there is already a good chance that injecting polymer would, technically speaking, increase the recovery factor. The next question would be: is it economically viable?

Obviously, among the mentioned parameters, the most important is probably the oil saturation and the corresponding remaining oil in place. If it is considered (and generally accepted) that polymer flooding does not displace residual oil saturation, then the presence of moveable oil is compulsory to make the injection viable. The *in situ* oil viscosity is a secondary criterion: even in those cases where oil viscosity is low and the mobility ratio of the displacement process (i.e., waterflooding) appears to be favorable, oil formations are generally heterogeneous by nature. Therefore, there is a good chance that even in those cases of favorable mobility ratio, sweep efficiency can be improved by the implementation of a polymer flooding.

brine composition (salinity, divalent cations, dissolved oxygen, iron, and hydrogen sulfide), and permeability. Polymer stability tests can be carried out over several months or years to ensure that viscosity loss is not observed during ageing in the presence of contaminants [26]. It is mandatory to perform these experiments under controlled anaerobic conditions (in glove

The objective of any reservoir screening process is to identify the best technology to improve oil recovery at a reasonable cost. Several criteria can be used during the screening process. General guidelines are provided in the following paragraphs. However, very often, a variety of parameters are assessed and obtaining a clear depiction of what would be the best technol‐

**•** The selection of reservoirs which have poor waterflooding sweep efficiency due to high oil

**•** The review of the overall conditions of the selected reservoir to determine if polymer

Specific parameters that need to be checked to determine if polymer flooding would be a viable

**•** Salinity of injection water: <200 g/L total dissolved salts. For salinity, another parameter

The above list can appear to be quite short and simple, when indeed there are many other factors related to the oil field that should be considered. However, if these criteria are met, there is already a good chance that injecting polymer would, technically speaking, increase the

is usually considered. It is defined as the weight ratio of cationic divalent ions

flooding implementation will fix the poor sweep efficiency problem.

**•** Current oil saturation: above residual oil saturation or presence of mobile oil

divided by the total of cationic ions as in following equation:

recovery factor. The next question would be: is it economically viable?

box for instance) to quantify the level of degradation.

78 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

Two general screening rules for polymer flooding are:

viscosity and/or large‐scale heterogeneity.

option for the selected reservoir(s) are as follows:

**•** Temperature: below 140°C (preferred below 100°C)

**4.1. Reservoir screening**

**•** Lithology: sandstone

called *R*<sup>+</sup>

**•** Permeability: above 10 mD **•** Oil viscosity: below 10,000 cP

ogy‐reservoir duo could be difficult.

**4. Polymer flooding: design and implementation**

Other parameters for consideration are linked to the choice of the most suitable polymer chemistry and the polymer concentration needed to reach a reasonable target viscosity. The higher the temperature and salinity, the higher the polymer concentration needed to obtain a sufficient viscosity to improve the recovery factor and, therefore, the higher the cost of the polymer flooding.

**Figure 21.** Example of workflow for polymer flooding implementation [25].

After the first selection has been made, more conventional reservoir studies can be performed before the implementation of a pilot test (**Figure 21**). The engineers should look at the reservoir geology (large‐scale sand body connectivity and heterogeneity), distribution of target oil, presence and location of faults, shales, aquifers, and distribution of clays. The simultaneous analysis of the reservoir production history helps to understand and refine the current knowledge of the reservoir and the behavior of the injected and produced fluids to avoid chemical dispersion and polymer losses during polymer flooding.

**Tracer test**. Tracer flooding testing aids in improving the reservoir description using a range of techniques. This test provides information on well‐to‐well communication and transit time, data on large‐scale layering, and an approximate estimate of areal sweep, and in‐layer dispersion. Frequently, it is not necessary to perform an explicit tracer flood since there is virtually always a difference in the composition of each ion in the injection and formation brines (Na+ , Ca2+, Cl‐ , SO4 2‐, etc.). Therefore, a careful analysis of the breakthrough composition of the produced brine would provide very useful information. However, it can be complicated by ion exchanges within the reservoir, especially for Ca2+. It should be pointed out that the polymer is in itself a good tracer, with its detection in producing wells during the pilot using the kaolinite flocculation method. This will provide additional input regarding the flow streams.

In some cases, profile modification before polymer injection has been reported [51]. Another approach would be to start polymer injection with high‐viscosity slugs in an attempt to seal the high‐permeability zones without plugging them irreversibly. This approach has been demonstrated successfully in both the Daqing and Kazakhstan oil fields.

#### **4.2. Importance of water quality**

Field observations showed that a well‐performing waterflood with "clean water" and good injectivity will translate into a well‐performing polymer flood. The composition of a "clean water" provided here is a common guideline found in the oil industry when considering injecting water in order to maintain a decent injectivity during the life of a project [52, 53]. The recommended composition of "clean water" is:


The composition of a "clean water," except for oxygen content, do not have a major impact on the polymer behavior or stability, but it could affect the overall performance of surface facilities and injection wells.

The viscosity of the polymer solution is designed to reduce the overall mobility ratio of the fluids in the reservoir. Other than minimizing polymer degradation, it is important to inject the polymer consistently at the target viscosity. This can be achieved with periodic polymer sampling or by inline viscosity monitoring of the polymer injected. Since water quality can change, a target concentration of polymer shall not be considered. Inversely, polymer concen‐ tration must be adapted to obtain the target viscosity, depending on water quality changes.

#### **4.3. Pilot injection and monitoring**

After the first selection has been made, more conventional reservoir studies can be performed before the implementation of a pilot test (**Figure 21**). The engineers should look at the reservoir geology (large‐scale sand body connectivity and heterogeneity), distribution of target oil, presence and location of faults, shales, aquifers, and distribution of clays. The simultaneous analysis of the reservoir production history helps to understand and refine the current knowledge of the reservoir and the behavior of the injected and produced fluids to avoid

**Tracer test**. Tracer flooding testing aids in improving the reservoir description using a range of techniques. This test provides information on well‐to‐well communication and transit time, data on large‐scale layering, and an approximate estimate of areal sweep, and in‐layer dispersion. Frequently, it is not necessary to perform an explicit tracer flood since there is virtually always a difference in the composition of each ion in the injection and formation

of the produced brine would provide very useful information. However, it can be complicated by ion exchanges within the reservoir, especially for Ca2+. It should be pointed out that the polymer is in itself a good tracer, with its detection in producing wells during the pilot using the kaolinite flocculation method. This will provide additional input regarding the flow

In some cases, profile modification before polymer injection has been reported [51]. Another approach would be to start polymer injection with high‐viscosity slugs in an attempt to seal the high‐permeability zones without plugging them irreversibly. This approach has been

Field observations showed that a well‐performing waterflood with "clean water" and good injectivity will translate into a well‐performing polymer flood. The composition of a "clean water" provided here is a common guideline found in the oil industry when considering injecting water in order to maintain a decent injectivity during the life of a project [52, 53]. The

demonstrated successfully in both the Daqing and Kazakhstan oil fields.

2‐, etc.). Therefore, a careful analysis of the breakthrough composition

chemical dispersion and polymer losses during polymer flooding.

brines (Na+

streams.

, Ca2+, Cl‐

**4.2. Importance of water quality**

**•** Solids content <20 ppm

and injection wells.

recommended composition of "clean water" is:

**•** Oil content <100 ppm (to minimize reservoir plugging)

**•** Solid particle size <5 μm (to minimize reservoir plugging)

**•** Consistent salinity over the life of a project to minimize viscosity variations

**•** Oxygen content <20 ppb (to avoid polymer degradation if iron II or H2S are present)

The composition of a "clean water," except for oxygen content, do not have a major impact on the polymer behavior or stability, but it could affect the overall performance of surface facilities

The viscosity of the polymer solution is designed to reduce the overall mobility ratio of the fluids in the reservoir. Other than minimizing polymer degradation, it is important to inject

, SO4

80 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

The objectives of a pilot polymer injection are to:


The most important goal of a pilot polymer injection test is to determine the maximum flow rates and viscosities that can be accepted by the reservoir. Some guidelines for consideration during the implementation and monitoring of a pilot polymer flooding test are given below:


**Figure 22.** Hall Plot indicating different injection profiles and their interpretation (modified after [55]).

Continuous viscosity monitoring can be achieved by the use of an inline viscometer and periodic sampling at the wellhead to make sure the viscosity of the injected solution is the targeted one. This fluid sampling process must be carried out carefully to ensure the measured viscosity corresponds to the produced solution and not to a degraded polymer sample. An inaccurate sampling method can induce shearing or oxygen entry into the polymer sample, which will trigger chemical reactions between oxygen and potential reducers such as iron II and H2S. This will lead to the formation of free radicals that act to chemically degrade the polymers, with an immediate polymer viscosity drop. This issue is also valid in the laboratory, where viscosity measurements in the presence of contaminants must be performed under an inert atmosphere, such as a nitrogen‐blanketed glove box.

**Injectivity.** Injectivity is a hot topic among reservoir engineers and projects managers. Large polymer injection projects that have been successful in injecting high polymer viscosities are the polymer flooding implemented in the Daqing, Suriname, and Kazakhstan oil fields.

Interestingly, there are very few cases of bad injectivity reported in the literature during polymer flooding. Injectivity failures during polymer injection are usually linked to a flaw flooding design including improper polymer dissolution systems or polymer protection against degradation (chemical, mechanical, and thermal degradation), issues with water quality, well completion, injection of polymer solutions having very low viscosities, and/or polymer injection out of the target zone. Another possible reason is near‐wellbore effects. If the near wellbore area is not modeled properly, or not understood at all, it is easy to overlook this area and to misinterpret what really happens in this zone.

Engineers from Oman Petroleum Development [56] have brought forward ideas to explain why the observed injectivity was better than the injectivity expected and predicted by models:


**Figure 22.** Hall Plot indicating different injection profiles and their interpretation (modified after [55]).

inert atmosphere, such as a nitrogen‐blanketed glove box.

82 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

this area and to misinterpret what really happens in this zone.

Continuous viscosity monitoring can be achieved by the use of an inline viscometer and periodic sampling at the wellhead to make sure the viscosity of the injected solution is the targeted one. This fluid sampling process must be carried out carefully to ensure the measured viscosity corresponds to the produced solution and not to a degraded polymer sample. An inaccurate sampling method can induce shearing or oxygen entry into the polymer sample, which will trigger chemical reactions between oxygen and potential reducers such as iron II and H2S. This will lead to the formation of free radicals that act to chemically degrade the polymers, with an immediate polymer viscosity drop. This issue is also valid in the laboratory, where viscosity measurements in the presence of contaminants must be performed under an

**Injectivity.** Injectivity is a hot topic among reservoir engineers and projects managers. Large polymer injection projects that have been successful in injecting high polymer viscosities are the polymer flooding implemented in the Daqing, Suriname, and Kazakhstan oil fields.

Interestingly, there are very few cases of bad injectivity reported in the literature during polymer flooding. Injectivity failures during polymer injection are usually linked to a flaw flooding design including improper polymer dissolution systems or polymer protection against degradation (chemical, mechanical, and thermal degradation), issues with water quality, well completion, injection of polymer solutions having very low viscosities, and/or polymer injection out of the target zone. Another possible reason is near‐wellbore effects. If the near wellbore area is not modeled properly, or not understood at all, it is easy to overlook

Engineers from Oman Petroleum Development [56] have brought forward ideas to explain why the observed injectivity was better than the injectivity expected and predicted by models:


The last hypothesis is probably the most plausible explanation of the observed remarkable polymer injectivity that has been confirmed by other authors [37]. If this is the case, then it is important to understand the type of "fractures" that has been induced in terms of fracture geometry and extension. In this regards, some thoughts are given as follow:


All in all, it is important to characterize the near‐wellbore area as best as possible and to work with the local heterogeneities to improve the overall chemical injection. Higher area for flow means less pressure drop and therefore less mechanical degradation. Using common reservoir monitoring methods (step‐rate tests, interference tests, and Hall plots, etc.), controlling injection rates and pressure to open up or close microfractures can bring significant improve‐ ment to the polymer flooding field operation. Another simple tool consists in analyzing the value of *q*/Δ*P*:

If *q*/Δ*P* ≤ (Σ *k h*)/[141.2 *μ* ln (*re*/*rw*)], radial flow is probable (matrix injection)

If *q*/Δ*P* ≥ (Σ *k h*)/[141.2 *μ* ln (*re*/*rw*)], linear flow is probable (fracture‐dominated regime)

where *q* is the injection or production rate (BPD), *P* pressure drawdown (psi), *k* permeability (md), *h* formation height (ft), *μ* fluid viscosity (cP), *r*e external drainage radius (ft), and *r*<sup>w</sup> wellbore radius (ft).

Last but not the least, it is paramount to translate these findings into the reservoir simulation models, which often give pessimistic results when injecting a viscous solution into the ground, especially when pressure constrains are set without a clear picture of polymer injectivity as obtained after a pilot test.

**Numerical modeling and simulation**. 3D modeling is a useful tool to predict the efficiency of a polymer flooding, assuming that the user has the proper understanding of the polymer characteristics and polymer flow properties. The most critical issue is modeling the near‐ wellbore area to duplicate the results observed during the field pilot injection. Polymer rheology regimes such as shear‐thinning or shear‐thickening properties should be used carefully, together with a suitable understanding of the well completion, formation damages, and reservoir fractures.

The most important parameters that can be obtained from the laboratory experiments that are useful during numerical simulation of polymer flooding are resistance factors, such as retention and residual resistance factors. If coreflooding experiments were not performed, it is possible to use the low shear viscosity information obtained from conventional rheometers for simulation purposes. Polymer degradation inside the reservoir is usually limited since the chemistry of the polymer is always selected to ensure the stability of the polymer during polymer injection and propagation throughout the reservoir. However, useful information can be gathered from long‐term polymer stability tests.

#### **4.4. Quality control**

Routine quality control procedures are available to check the quality of the polymer to be injected. The main parameters for polymer quality controls are:


**Figure 23.** Typical set‐up used to perform filter ratio tests with vessels (top) and graduated cylinders connected to a stopwatch (bottom) [25].

Some of the laboratory procedures commonly used for polymer quality control are described in the API procedure RP63. Discussions with suppliers can also bring important inputs on the proper handling of the products and control of the overall quality.

As previously indicated, during reservoir polymer flooding, the main parameter to be monitored is polymer solution viscosity, which can be performed via an inline viscometer or by manual and careful polymer solution sampling for bench‐scale viscosity analysis.

## **5. Back-produced polymer**

monitoring methods (step‐rate tests, interference tests, and Hall plots, etc.), controlling injection rates and pressure to open up or close microfractures can bring significant improve‐ ment to the polymer flooding field operation. Another simple tool consists in analyzing the

If *q*/Δ*P* ≤ (Σ *k h*)/[141.2 *μ* ln (*re*/*rw*)], radial flow is probable (matrix injection)

If *q*/Δ*P* ≥ (Σ *k h*)/[141.2 *μ* ln (*re*/*rw*)], linear flow is probable (fracture‐dominated regime)

where *q* is the injection or production rate (BPD), *P* pressure drawdown (psi), *k* permeability (md), *h* formation height (ft), *μ* fluid viscosity (cP), *r*e external drainage radius (ft), and *r*<sup>w</sup>

Last but not the least, it is paramount to translate these findings into the reservoir simulation models, which often give pessimistic results when injecting a viscous solution into the ground, especially when pressure constrains are set without a clear picture of polymer injectivity as

**Numerical modeling and simulation**. 3D modeling is a useful tool to predict the efficiency of a polymer flooding, assuming that the user has the proper understanding of the polymer characteristics and polymer flow properties. The most critical issue is modeling the near‐ wellbore area to duplicate the results observed during the field pilot injection. Polymer rheology regimes such as shear‐thinning or shear‐thickening properties should be used carefully, together with a suitable understanding of the well completion, formation damages,

The most important parameters that can be obtained from the laboratory experiments that are useful during numerical simulation of polymer flooding are resistance factors, such as retention and residual resistance factors. If coreflooding experiments were not performed, it is possible to use the low shear viscosity information obtained from conventional rheometers for simulation purposes. Polymer degradation inside the reservoir is usually limited since the chemistry of the polymer is always selected to ensure the stability of the polymer during polymer injection and propagation throughout the reservoir. However, useful information can

Routine quality control procedures are available to check the quality of the polymer to be

**•** Yield viscosity: definition of the polymer concentration needed in the injection brine to reach

**•** Filterability of the polymer solution: it is important to determine polymer dissolution issues, such as the formation of undissolved polymer clusters and/or fish‐eyes (**Figure 23**).

value of *q*/Δ*P*:

84 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

wellbore radius (ft).

obtained after a pilot test.

and reservoir fractures.

**4.4. Quality control**

the target viscosity.

be gathered from long‐term polymer stability tests.

injected. The main parameters for polymer quality controls are:

**•** Active content of the polymer: active material of the solid powder.

**•** UL viscosity: viscosity of polymer solution at 0.1% active in 1 mole NaCl.

A pilot injection can bring important information on the quality and quantity of back‐produced polymer, as well as its impact on the existing water treatment facilities if the effluents can be isolated and polymer dilution limited.

For an extended field project, the crude and produced water separation stage and the produced water treatment stage must be considered as an important part of the polymer flooding implementation design. The treated water can be either reused or disposed of. The main aspects of the treatment of back‐produced polymer are the following:

**•** Anionic polymer can interact with the oil emulsions breaker system, possibly resulting in an inefficient oil‐water separation. Service companies generally select the most appropriate and compatible oil‐water breaker through several tests including bottle testing. Since polyacrylamide polymers are water soluble, they are considered absent from the oil phase [26].

**•** Anionic polyacrylamides are used widely in water treatment processes as flocculating agents. If the TSS (total suspended solids) is relatively high in the produced fluid, some agglomerates can appear and precipitates can deposit on the surface of process equipment (i.e., heating units). These deposits have to be periodically removed.

Equipment for back‐produced water treatment is usually sized to operate with water viscos‐ ities below 4 cP. An increase in water viscosity after polymer breakthrough will reduce the efficiency of the treating devices in separating hydrocarbons and wetted suspended materials. For example, if the viscosity of the water produced reaches 10 cP, the residence time required for treatment is five times longer and the size of the devices are five times larger [26].

**Figure 24.** Mechanical degradation of polymer solutions at different concentrations (Flopaam 3630S) [25].

Several methods (mechanical, chemical, and filtration, etc.) can be used to decrease the viscosity of the produced effluent in order to maintain the efficiency of the water treatment process [59] as follows:

**•** Mechanical degradation is often a viable and efficient method to decrease the molecular weight of the polymer and thereby to decrease the viscosity of the solution (**Figure 24**). A shearing pump or a choke valve can be used to achieve the required degradation to decrease the viscosity of the polymer solution produced. However, too much shear can stabilize oil in water (O/W) emulsions.


The back‐produced polymer can also have several benefits:


## **6. Equipment and surface facilities**

#### **6.1. Process examples**

and compatible oil‐water breaker through several tests including bottle testing. Since polyacrylamide polymers are water soluble, they are considered absent from the oil phase

**•** Anionic polyacrylamides are used widely in water treatment processes as flocculating agents. If the TSS (total suspended solids) is relatively high in the produced fluid, some agglomerates can appear and precipitates can deposit on the surface of process equipment

Equipment for back‐produced water treatment is usually sized to operate with water viscos‐ ities below 4 cP. An increase in water viscosity after polymer breakthrough will reduce the efficiency of the treating devices in separating hydrocarbons and wetted suspended materials. For example, if the viscosity of the water produced reaches 10 cP, the residence time required

for treatment is five times longer and the size of the devices are five times larger [26].

**Figure 24.** Mechanical degradation of polymer solutions at different concentrations (Flopaam 3630S) [25].

Several methods (mechanical, chemical, and filtration, etc.) can be used to decrease the viscosity of the produced effluent in order to maintain the efficiency of the water treatment

**•** Mechanical degradation is often a viable and efficient method to decrease the molecular weight of the polymer and thereby to decrease the viscosity of the solution (**Figure 24**). A shearing pump or a choke valve can be used to achieve the required degradation to decrease the viscosity of the polymer solution produced. However, too much shear can stabilize oil

(i.e., heating units). These deposits have to be periodically removed.

86 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

[26].

process [59] as follows:

in water (O/W) emulsions.

Depending on the polymer form (emulsion or powder), two different approaches can be considered. When the polymer is supplied in powder form, it should be dissolved into the injection water prior to being pumped for dilution and injected into the reservoir at the target viscosity. A typical set‐up for powder dissolution is presented in **Figure 25**. The polymer in powder form is stored in a hopper and distributed with a dosing screw into a nitrogen‐ blanketed polymer slicing unit (PSU) where it is hydrated. The solution will then pass into a maturation tank where it will achieve full hydration/dissolution. Finally, the mother solution is pumped and diluted to the target concentration (**Figure 25**).

**Figure 25.** Typical dissolution process for polymers in powder form [25].

Skid‐mounted systems are widely used onshore: the polymer dissolution and hydration systems as well as the pumps are placed inside 20 or 40 feet containers that are adapted to the local field conditions (weather, accessibility). As discussed previously, it is recommended to blanket the main equipment with nitrogen to avoid any oxygen ingress and further degrada‐ tion of the polymer solution viscosity. This type of system with a slicing unit allows for quick and proper hydration of the polymer, avoiding fish‐eyes and gels formation, which would require filtration of the polymer solution.

Two configurations can be considered based on the water supply:


**Figure 26.** Configuration for polymer preparation when high pressure water is available [25].

**Figure 27.** Configuration for polymer preparation when low pressure water is available [25].

**Figure 25.** Typical dissolution process for polymers in powder form [25].

88 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

Two configurations can be considered based on the water supply:

**Figure 26.** Configuration for polymer preparation when high pressure water is available [25].

require filtration of the polymer solution.

to ensure the proper hydration of the polymer.

mended.

Skid‐mounted systems are widely used onshore: the polymer dissolution and hydration systems as well as the pumps are placed inside 20 or 40 feet containers that are adapted to the local field conditions (weather, accessibility). As discussed previously, it is recommended to blanket the main equipment with nitrogen to avoid any oxygen ingress and further degrada‐ tion of the polymer solution viscosity. This type of system with a slicing unit allows for quick and proper hydration of the polymer, avoiding fish‐eyes and gels formation, which would

**•** If high pressure water is available, then the configuration shown in **Figure 26** is recom‐

**•** If low pressure water is available, the configuration displayed in **Figure 27** should be used

When using polymer in emulsion form, inline static mixers (with a sufficient pressure drop) are required to invert the water‐in‐oil emulsion (W/O) into an oil‐in‐water emulsion (O/W) which is then injected in the reservoir. The footprint for the process is much less extensive than in the case of polymer in powder form. Nevertheless, due to the active content and the density of the emulsion, the volume of the tank necessary to store the emulsion is often twice the volume of the tank used to prepare polymer in powder form. **Figure 28** presents a simplified flow diagram for the dilution process of polymer in inverse emulsion form.

**Figure 28.** Typical inversion and dilution process for the preparation of polymer in inverse emulsion form [25].

Among the three main types of degradation, chemical and mechanical polymer degradations are susceptible to occur at surface facilities.

Chemical degradation can be minimized by blanketing the equipment with nitrogen or by adding specific scavengers in the flow stream. It is also possible to remove as many contami‐ nants as possible or to add protective additives to the polymer.

Specific guidelines should also be applied to minimize mechanical degradation in dissolution and surface equipment or in the injection lines if restrictions or chokes are present. Progressive cavity or rotary lobes pumps are recommended for low pressure processes. For high pressure, plunger or diaphragm pumps (Triplex or Quintuplex) are preferred. The maximum velocity of the fluid must remain below a critical value, wherever the fluid is moved such as in the agitation process with impellers or in pipes (short distance). For example, in a 2‐inch pipe, it must be kept below 7 m/s.

Chokes must be removed, bypassed, fully opened, or replaced by nonshearing systems to avoid any uncontrolled shearing that would be detrimental to the final viscosity of the polymer solution. Well completion influences the amount of degradation; for example, the density and number of perforations must be taken into account and correlated to the flow rate of the fluid to assess the potential shearing occurring at this step (a value of 12 shots per foot is usually recommended) [26].

#### **6.2. Key points for offshore polymer flooding implementations**

The constraints are very different when designing an offshore or an onshore polymer flooding project. Equipment footprint is the key in offshore operations, therefore it is necessary to know the space and load limits of the Floating Production Storage Offloading (FPSO) or the offshore platform. Logistics and local weather conditions can also dictate the form of the product to be used. Polymer in inverse emulsion form is easier to handle offshore, especially when the weather conditions are particularly unfavorable. It does not require specific systems, the inversion is performed on the fly with sufficient energy and the solution can then be diluted and injected into the reservoir. However, polymer in powder form, with a higher active content (up to 90% compared to the 30 or 50% for an emulsion), is cheaper to implement and requires less logistics.

The main points to consider during the design of polymer flooding for offshore applications are the following:


control the flow and the pressure at each wellhead. Specific solutions shall be selected to minimize viscosity degradation.

**•** Logistics: for chemical EOR, a large quantity of chemicals has to be handled either in liquid or powder form. Therefore, the supply chain has to be secured accordingly.

## **7. Field cases and economics**

### **7.1. Economics**

Chokes must be removed, bypassed, fully opened, or replaced by nonshearing systems to avoid any uncontrolled shearing that would be detrimental to the final viscosity of the polymer solution. Well completion influences the amount of degradation; for example, the density and number of perforations must be taken into account and correlated to the flow rate of the fluid to assess the potential shearing occurring at this step (a value of 12 shots per foot is usually

The constraints are very different when designing an offshore or an onshore polymer flooding project. Equipment footprint is the key in offshore operations, therefore it is necessary to know the space and load limits of the Floating Production Storage Offloading (FPSO) or the offshore platform. Logistics and local weather conditions can also dictate the form of the product to be used. Polymer in inverse emulsion form is easier to handle offshore, especially when the weather conditions are particularly unfavorable. It does not require specific systems, the inversion is performed on the fly with sufficient energy and the solution can then be diluted and injected into the reservoir. However, polymer in powder form, with a higher active content (up to 90% compared to the 30 or 50% for an emulsion), is cheaper to implement and requires

The main points to consider during the design of polymer flooding for offshore applications

**•** Modular solution to limit the installation activities on the FPSO, platform, or any offshore vessel. Those modules should also comply with lifting/handling constrains such as crane

**•** Sensitivity to vibrations during operations (pumps running, conveying, etc.). Specific

**•** Hazardous classified area: specific design is to be provided to adapt equipment and modules to the hazardous classification constrains, especially for the control room, motor control

**•** Environmental conditions: consideration of the vessel motions (rolling, sagging, pitching,

**•** Corrosion: protection against the corrosive atmosphere (stainless steel equipment, specific

**•** Waste management and back produced water: use of chemicals offshore and possible waste

**•** Subsea: polymer is a shear sensitive chemical. For offshore projects, nonshearing injection pumps should be used to transfer the injected solution through the main risers up to the several subsea Christmas trees dedicated to each well. Choke valves will then be used to

heaving), wind loads, and blast loads on structural and equipment design.

to be handled. Specific cleaning procedures have to be foreseen as well.

**•** Specific design considering footprint limitations and loads constraints.

limitation and specific offshore procedures, among others.

painting procedures, nitrogen blanketing, greasing).

attention shall be paid on loads interaction and structural issues.

**6.2. Key points for offshore polymer flooding implementations**

90 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

recommended) [26].

less logistics.

are the following:

center, and utilities shelters.

Three areas of expenses can be defined when considering polymer injection:


Out of the three aforementioned sections, the first one represents approximately 1% of the overall costs while the following two represent 25% and 70–75%, respectively. It is obvious that the bulk of the cost is linked to the injection of the chemicals. An important aspect is the field development plan and the deployment of the injection facilities. Two approaches are often encountered:


The latter helps to optimize the deployment of the facilities in the field by adding modules for polymer dissolution or polymer injection modules, minimizing the capital expenditures upfront. It also allows moving the systems to other parts of the field for short‐term tests.

The average cost of polymer per incremental barrel ranges from \$1 to \$4. The cost of polymer per incremental barrel of oil produced at the Daqing oil field polymer flooding has been estimated at approximately \$2.7/barrel. In this case, it was shown that polymer injection was less expensive than water injection considering the average capital costs per well and the volumes of fluids injected and produced which are significantly less for polymer injection than for water injection.

Another example is the Brintnell polymer flood project (CNRL, Canada) where the average incremental cost for polymer flooding was \$13, but including incremental wells, mixing facilities, water‐treating facilities, additional production facilities, maintenance capital, and the polymer itself, whereas the cost of the polymer alone was \$4 per incremental barrel of oil produced.

#### **7.2. Field cases of polymer flooding**

In 2015, there were more than 50 polymer injections running worldwide, excluding the projects still in the design phase or about ready to start in the field.

It would be hard to summarize the entirety of field cases here, so only few examples will be addressed, highlighting some important design aspects and some key learnings. Also, only publicly available information will be discussed in the upcoming paragraphs.

#### *7.2.1. Canada*

Canadian operators have gained significant experience in the last years on polymer injection for heavy oils. Interestingly, the vast majority of the cases are publicly released in corporate presentations, providing a wealth of information on the efficiency of the process. The constant here is the benefit of injecting viscous solutions to improve recovery from heavy‐oil pools. The list of fields is extensive: Pelican Lake, Brintnell, Mooney, Horsefly, Countess, Bodo, Suffield Caen, Wainwright, Giltedge, Seal, Taber, Wildmere, Wrentham, Provost, Edgerton, etc. [60– 62]. These wells are mainly horizontal, with a short‐spacing often between 50 and 100 m and oil viscosities up to 10,000 cP. **Table 4** presents a summary of reservoir properties of three typical Canadian oil fields in which polymer flooding has been implemented. The incremental oil recovery obtained from each polymer flooding project is also indicated in **Table 4**.


**Table 4.** Summary of reservoir properties of three typical Canadian oil fields in which polymer flooding has been implemented (modified after [60]).

#### *7.2.2. China*

The Daqing polymer flooding case has been extensively discussed previously in this chapter. Incremental oil recovery as a result of polymer injection is approximately 12% OOIP. Other successful polymer flooding projects in Chinese oil fields such as the Shengli and Bohai Bay have been described in the literature [65]. Additionally, some papers report the use of high‐ viscosity polymer slug to further improve oil recovery: the objective is to inject very high viscosity slugs followed by a regular polymer flooding with possible repetition in order to account for reservoir heterogeneities [62–64].

#### *7.2.3. Europe and Middle East*

**7.2. Field cases of polymer flooding**

92 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

*7.2.1. Canada*

implemented (modified after [60]).

*7.2.2. China*

still in the design phase or about ready to start in the field.

In 2015, there were more than 50 polymer injections running worldwide, excluding the projects

It would be hard to summarize the entirety of field cases here, so only few examples will be addressed, highlighting some important design aspects and some key learnings. Also, only

Canadian operators have gained significant experience in the last years on polymer injection for heavy oils. Interestingly, the vast majority of the cases are publicly released in corporate presentations, providing a wealth of information on the efficiency of the process. The constant here is the benefit of injecting viscous solutions to improve recovery from heavy‐oil pools. The list of fields is extensive: Pelican Lake, Brintnell, Mooney, Horsefly, Countess, Bodo, Suffield Caen, Wainwright, Giltedge, Seal, Taber, Wildmere, Wrentham, Provost, Edgerton, etc. [60– 62]. These wells are mainly horizontal, with a short‐spacing often between 50 and 100 m and oil viscosities up to 10,000 cP. **Table 4** presents a summary of reservoir properties of three typical Canadian oil fields in which polymer flooding has been implemented. The incremental

oil recovery obtained from each polymer flooding project is also indicated in **Table 4**.

**Project Pelican Lake Mooney Seal** Company CNRL & Cenovus Black Pearl Murphy Average depth 300–450 900–950 610 Average net pay 1–9 2.5 8.5 Permeability 300–5000 100–10,000+ 300–5800 Reservoir temperature 12–17 29 20 API gravity 12–14 12–19 10–12 Dead oil viscosity 800–80,000 300 5000–12,000 Live oil viscosity 800–80,000 1000–3000 3000–7000

Incremental oil recovery 10–25% ~10% 9%

**Table 4.** Summary of reservoir properties of three typical Canadian oil fields in which polymer flooding has been

The Daqing polymer flooding case has been extensively discussed previously in this chapter. Incremental oil recovery as a result of polymer injection is approximately 12% OOIP. Other successful polymer flooding projects in Chinese oil fields such as the Shengli and Bohai Bay have been described in the literature [65]. Additionally, some papers report the use of high‐ viscosity polymer slug to further improve oil recovery: the objective is to inject very high

publicly available information will be discussed in the upcoming paragraphs.

The number of polymer flooding pilot tests and projects has greatly increased in the past years in Europe, some examples are as follows:


In the Marmul oil field, Petroleum Development Oman (PDO) implemented a pilot polymer injection in 2010. A polyacrylamide polymer and a protective additive were injected in 27 wells. The high‐permeability (multi‐Darcy) reservoir contains a 22° API crude oil with a viscosity of around 90 cP; injection patterns are inverted 9‐ and five‐spot patterns. The polymer solution (15 cP) was injected at an average flow rate of 13,000 m3 /day. Preliminary results as of 2012 are presented in **Figure 29** [56].

**Figure 29.** Water‐cut and oil production rate from the Marmul oil field before and after the start‐up of polymer injec‐ tion [56].

#### *7.2.4. South America*

Polymer flooding pilot injections are on‐going in Argentina, Suriname, and Colombia with polymer flood projects in Brazil and Venezuela. An interesting case is the Sarah Maria field operated by Staatsolie [37] in Suriname. This reservoir is a heterogeneous sandstone, with permeabilities of several Darcie's and a live oil viscosity around 500 cP. Moe Soe Let et al. (2012) have reported the first observations of this polymer flooding. In this project, reservoir fractures have been used to improve the injectivity of the highly viscous polymer solutions (up to 160 cP). The creation and extension of fractures have been monitored through pressure profiles, interwell tracer tests, water‐cut variations, salinity, and polymer breakthrough: the aim was to increase water injection and oil production rates without risking irreversible reservoir damages.

## **Acknowledgements**

The author would like to acknowledge Kimberley McEwen, Nicolas Gaillard, and Olivier Braun for their careful review.

#### **Author details**

Antoine Thomas

Address all correspondence to: athomas@snf.fr

SNF Floerger, Andrezieux‐Boutheon, France

#### **References**


[5] Mungan, N., Smith, F.W., Thompson, J.L., 1966. Some aspects of polymer floods. J. Pet.Tech., vol. 18, issue 09, September, 1143.

*7.2.4. South America*

94 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

damages.

**Acknowledgements**

**Author details**

Antoine Thomas

**References**

Braun for their careful review.

Address all correspondence to: athomas@snf.fr

vol. 16, issue 08, 911–916. AIME, 231.

Tech., April–June, 8, 45.

vol. 07, issue 02, 161–170.

SNF Floerger, Andrezieux‐Boutheon, France

Polymer flooding pilot injections are on‐going in Argentina, Suriname, and Colombia with polymer flood projects in Brazil and Venezuela. An interesting case is the Sarah Maria field operated by Staatsolie [37] in Suriname. This reservoir is a heterogeneous sandstone, with permeabilities of several Darcie's and a live oil viscosity around 500 cP. Moe Soe Let et al. (2012) have reported the first observations of this polymer flooding. In this project, reservoir fractures have been used to improve the injectivity of the highly viscous polymer solutions (up to 160 cP). The creation and extension of fractures have been monitored through pressure profiles, interwell tracer tests, water‐cut variations, salinity, and polymer breakthrough: the aim was to increase water injection and oil production rates without risking irreversible reservoir

The author would like to acknowledge Kimberley McEwen, Nicolas Gaillard, and Olivier

[1] Pye, D.J., 1964. Improved secondary recovery by control of water mobility. J. Pet. Tech.,

[2] Sandiford, B.B., 1964. Laboratory and field studies of waterflood using polymer solutions to increase oil recoveries. J. Pet. Tech., vol. 16, issue 08, 917–922, AIME, 211.

[3] Mungan, N., 1969. Rheology and adsorption of aqueous polymer solutions. J. Can. Pet.

[4] Gogarty, W. B., 1967. Mobility control with polymer solutions. Soc. Pet. Eng. J., June,


Paper SPE 141497 presented at SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 25–28 September, 2011.


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98 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

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**Chapter 3 Provisional chapter**

#### **New Insight from Visualization of Mobility Control for Enhanced Oil Recovery Using Polymer Gels and Foams New Insight from Visualization of Mobility Control for Enhanced Oil Recovery Using Polymer Gels and Foams**

Bergit Brattekås and Martin A. Fernø Bergit Brattekås and Martin A. Fernø

Additional information is available at the end of the chapter Additional information is available at the end of the chapter

http://dx.doi.org/10.5772/64586

#### **Abstract**

Several enhanced oil recovery (EOR) methods have been designed and developed in the past decades to maintain economic production from mature reservoirs with declining production rates. This chapter discuss mitigation of poor sweep efficiency in layered or naturally fractured reservoirs. EOR methods designed for such reservoirs all aim to reduce flow through highly conductive pathways and delay early breakthrough in production wells. Two approaches within this EOR class, injection of foam and polymer, specifically aim to improve the mobility ratio between the injected EOR fluid and the reservoir crude oil. Reduction in fracture conductivity may be achieved by adding a crosslinking agent to a polymer solution to create polymer gel. This may also be combined with water or chemical chasefloods (e.g. foam) for integrated enhanced oil recovery (iEOR). Polymer gel and foam mobility control for use in fractured reservoirs are discussed in this chapter, and new knowledge from experimental work is presented. The experiments emphasized visualization and in situ imaging techniques: CT, MRI and PET. New insight to dynamic behaviour and local variations in fluid saturations during injections was achieved through the use of complementary visualization techniques.

**Keywords:** polymer gel, foam, fractured reservoirs, iEOR, *in situ* imaging

## **1. Introduction**

Polymer gel as a conformance control technique is frequently applied in fractured reservoirs to reduce fracture conductivity close to production wells, but may also be applied to enhance oil recovery when used in the injection well to divert subsequent fluids injected from the fracture network into unswept matrix blocks. Fluid injection following a gel injection is here referred to as a *chaseflood*, and constitutes a range of EOR fluids depending on the reservoir

© 2016 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited. © 2016 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

and availability. Waterflooding was used as the standard chaseflood in this work, and the reader may assume that water is injected if not otherwise specified.

Generally, polymer gels are mixed in fresh water before injection to the field to achieve long‐ term stability of the solution. In this work, polymer gels are made from saline brines and offer a significant advantage compared with fresh water gels because less interaction is expected between the gel and reservoir fluids when the gel solvent (most commonly water) is compa‐ rable to the formation brine, and gel blocking performance is significantly improved when combined with low‐salinity waterfloods in *integrated EOR*—iEOR, a term used here to describe the process where two or more proven EOR techniques are combined or performed in a smart sequence. In heterogeneous and fractured reservoirs, the iEOR approach is particularly effective when polymer gels are combined with mobility control techniques such as foam. The conformance control offered by polymer gels reduces flow in the largest fractures, whereas foam reduces gas mobility and increases the volumetric sweep efficiency of the reservoir resulting in incremental oil recovery. Gas mobility is reduced when bubbles are formed to make the gas phase discontinuous and separated by thin liquid films called lamellae. Foam application is particularly suited for heterogeneous reservoirs and is a field scale proven technique for EOR at both immiscible and miscible conditions and for aquifer remediation.

To successfully apply polymer gels or foams their behaviour and flow properties in porous media must be accurately predicted on a variety of scales. New insight to dynamic behaviour and local variations in fluid saturations during injections may be achieved through the use of complementary visualization techniques. Three imaging techniques are reviewed in this chapter: X‐ray computed tomography (CT), magnetic resonance imaging (MRI) and positron emission tomography (PET). The imaging techniques are used separately or combined to closely monitor flow processes and improve the understanding of EOR techniques and their underlying principles on core plug scale, and new results are discussed in this chapter.

## **2. Polymer gel placement in fractured systems**

From a reservoir engineering point of view, achieving high sweep efficiency in the reservoir to maximize oil recovery represents a challenge when fractures are present. The fractures generally have permeabilities that exceed the rock matrix by several orders of magnitude and therefore represent thief zones for the injected EOR fluid. Rather than displacing oil from the oil‐saturated rock matrix, the injected fluids channel through the fracture network towards the producer, resulting in low sweep efficiency and excess production of water or injected chemicals.

#### **2.1. Gel or gelant injection**

Polymer gel is usually injected to the field as a *gelant* solution—a mixture containing all chemical components, but not yet crosslinked to form a rigid and highly viscous polymer gel. Gelant in many ways resembles the standard polymer solution, but transforms into a gel depending on temperature conditions and time—the time it takes for a gelant to transform into a rigid gel at a given temperature is known as the *gelation time*. Gelant may flow both in the porous matrix and the fractures as a result of the lower viscosity and smaller particles relative to gel. When formed, long polymer chains in the gel structure prevent the gel from flowing through the small pores of the porous media, thus gel is contained to fractures during injection. In field applications, gelant is generally pumped from the surface and enters the reservoir either as a gelant or as a weak gel, depending on reservoir temperature and pumping time. The placement process must be carefully designed because the two fluids deposit differently in the fracture volume, which influences the ability of the gel to reduce fracture conductivity and impact its performance during conformance control operations. Gel blocking capacity as a function of gel state (gelant or gel) has therefore been thoroughly investigated at core plug scale [1–7].

#### **2.2. The leakoff process**

and availability. Waterflooding was used as the standard chaseflood in this work, and the

Generally, polymer gels are mixed in fresh water before injection to the field to achieve long‐ term stability of the solution. In this work, polymer gels are made from saline brines and offer a significant advantage compared with fresh water gels because less interaction is expected between the gel and reservoir fluids when the gel solvent (most commonly water) is compa‐ rable to the formation brine, and gel blocking performance is significantly improved when combined with low‐salinity waterfloods in *integrated EOR*—iEOR, a term used here to describe the process where two or more proven EOR techniques are combined or performed in a smart sequence. In heterogeneous and fractured reservoirs, the iEOR approach is particularly effective when polymer gels are combined with mobility control techniques such as foam. The conformance control offered by polymer gels reduces flow in the largest fractures, whereas foam reduces gas mobility and increases the volumetric sweep efficiency of the reservoir resulting in incremental oil recovery. Gas mobility is reduced when bubbles are formed to make the gas phase discontinuous and separated by thin liquid films called lamellae. Foam application is particularly suited for heterogeneous reservoirs and is a field scale proven technique for EOR at both immiscible and miscible conditions and for aquifer remediation. To successfully apply polymer gels or foams their behaviour and flow properties in porous media must be accurately predicted on a variety of scales. New insight to dynamic behaviour and local variations in fluid saturations during injections may be achieved through the use of complementary visualization techniques. Three imaging techniques are reviewed in this chapter: X‐ray computed tomography (CT), magnetic resonance imaging (MRI) and positron emission tomography (PET). The imaging techniques are used separately or combined to closely monitor flow processes and improve the understanding of EOR techniques and their underlying principles on core plug scale, and new results are discussed in this chapter.

From a reservoir engineering point of view, achieving high sweep efficiency in the reservoir to maximize oil recovery represents a challenge when fractures are present. The fractures generally have permeabilities that exceed the rock matrix by several orders of magnitude and therefore represent thief zones for the injected EOR fluid. Rather than displacing oil from the oil‐saturated rock matrix, the injected fluids channel through the fracture network towards the producer, resulting in low sweep efficiency and excess production of water or injected

Polymer gel is usually injected to the field as a *gelant* solution—a mixture containing all chemical components, but not yet crosslinked to form a rigid and highly viscous polymer gel. Gelant in many ways resembles the standard polymer solution, but transforms into a gel depending on temperature conditions and time—the time it takes for a gelant to transform

reader may assume that water is injected if not otherwise specified.

102 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

**2. Polymer gel placement in fractured systems**

chemicals.

**2.1. Gel or gelant injection**

Although formed gel cannot flow through porous media due to its structure, the gel solvent (a range of solvents may be used, here we discuss water only) may leave the gel and progress through the pore network if the viscous forces become high enough. This fluid transport, called *leakoff*, increases the concentration of the gel in the fracture, resulting in a more rigid gel structure with a higher resistance to pressure during chasefloods. When the gel loses water due to leakoff its mobility decreases compared to the continuously injected ("fresh") gel; fresh gel propagates through internal conduits within the concentrated gel called *wormholes* [3, 8– 10]. The transport of water from the gel depends mainly on gel strength and differential pressures across the gel slug, in addition to rock wettability and two‐phase flow functions, therein capillary forces. Reduction of flow in fractures or high permeability zones after placement of polymer gels have been reported [2, 10–15].

#### **2.3. Gel mechanical strength‐dependency on gel state during placement**

The mechanical strength of a gel in a fracture is an indication of its blocking ability and is often determined in the laboratory by measuring the gel *rupture pressure*—the pressure at which the gel in the fracture breaks apart and permits fluids to pass through it. If the injection pressure exceeds, the rupture pressure of the gel during a chaseflood, the gel‐filled fracture will be partially re‐opened to flow and fluid channelling through the blocked fracture will start again [4, 5, 7, 16]. Measurements of rupture pressures in open fractures with defined geometries have shown that gel mechanical strength after placement is dependent on the gel state during placement [7]. Rupture pressures measured after formed gel placement with leakoff were often to be consistent and predictable. It is assumed that water mobilizes gel from the wormholes during chasefloods and is thereafter contained in the narrow flow channels constituting the wormholes. Because of this, efficient gel blocking may also be achieved after gel rupture and significant water throughput. Rupture pressures measured after gelant injection and subse‐ quent *in situ* gel formation, a process referred to as *gelation*, were comparable to measurements during gel injection, but with more inconsistency. It was suggested that gelation did not always occur [7], because gelant may experience compositional changes that interfere with gelation upon contact with the reservoir rock and fluids [5, 17], e.g. cross‐linker diffusion into the surrounding matrix that may lead to gelation failure [16]. Although initially comparable, the blocking capacity over time during chasefloods was consistently higher for pre‐formed gels compared with gels with *in situ* gelation. This was explained by the presence of wormholes that collapsed and re‐opened depending on the injection pressure.

#### **2.4. Gel volume alterations**

The blocking capacity of a gel placed in a fracture is also determined by the ability of the gel to maintain its volume relative to the fracture volume. After placement, the gel may undergo processes that change its volume and impact the success of a chaseflood. Several processes, such as *syneresis* [18, 19], *dehydration* [20–23] and *gel swelling* [24, 25], have been studied experimentally using bulk gel, core plugs and micromodels. During syneresis and dehydra‐ tion, the gel volume is reduced due to loss of water caused by chemical reactions over time, changes in pressure gradients or matrix capillary forces adjacent to the gel network. Other conditions, such as temperature, solvent composition, ionic strength and external electric field, are the main causes of gel swelling, which impact the gel volume without the loss of water by influencing the osmotic pressure balance between the gel network and its surroundings [26]. The behaviour of a polymer gel during EOR chasefloods will, in summary, depend on both the properties of the gel itself and on the external conditions in the reservoir.

## **3. Foam flooding of fractured systems**

EOR techniques in fractured reservoirs rely on maximizing the contact area between the injected EOR fluid and the rock surface, and therefore, the EOR fluid must transport effectively within the fracture network [27]. Most fracture networks, however, are heterogeneous themselves, with varying fracture aperture, orientation and connectivity.

#### **3.1. Gas mobility reduction**

Heterogeneous fracture networks may result in poor sweep of the injected EOR fluid, and mobility control should be implemented to maximize contact. Two‐phase flow within rough‐ walled fractures has previously been investigated using Newtonian fluids [28–30] and non‐ Newtonian polymer solutions [31, 32]. Foam has the potential to increase oil recovery by better areal sweep, better vertical sweep (less gravity override), less viscous fingering and diversion of gas from higher permeable or previously swept layers [33]. Diversion of gas into lower permeable layers using foams may be important for fractured systems, where a very large permeability contrast exists and cross‐flow between the zones occur [34].

#### **3.2. Foam generation in fractures**

Foam is generated in porous media by snap‐off, lamella division or leave‐behind mechanisms. Foam generation is affected by porous medium topological properties, wetting content, capillary suction pressure, surfactant formulation, gas fractional flow and flow rate. Snap‐off and lamella division create "strong" foam in terms of separate gas bubbles above a critical capillary number [35], whereas leave‐behind forms lamellae oriented parallel to the flow direction with only moderate effect on flow resistance, and the injected gas remains as a continuous phase. In porous media with permeability discontinuities, snap‐off is an important mechanism for foam generation [36–38]. Foam generation within a fracture network was observed in a replica of a rough‐walled fracture with variable aperture [39]. Foam was found to be generated by snap‐off and the bubble size was four times larger during *in situ* generation in the fractured systems as a result of fewer snap‐off sites in the fracture compared to the Berea sandstone used for bubble pre‐generation. The resulting foam texture and the relationship of curvature with foam viscosity determined the flow resistance of the system. Similar snap‐offs in idealized fractures at the transition from narrow to large aperture was reported [40], where the flow resistance increased with greater gas fractional flow and larger aperture. Similarly, flow in rough‐walled fractures was previously characterized [39, 41], and may be favourable for mobility in fracture networks of varying aperture [42].

## **4. Experimental procedures**

surrounding matrix that may lead to gelation failure [16]. Although initially comparable, the blocking capacity over time during chasefloods was consistently higher for pre‐formed gels compared with gels with *in situ* gelation. This was explained by the presence of wormholes

The blocking capacity of a gel placed in a fracture is also determined by the ability of the gel to maintain its volume relative to the fracture volume. After placement, the gel may undergo processes that change its volume and impact the success of a chaseflood. Several processes, such as *syneresis* [18, 19], *dehydration* [20–23] and *gel swelling* [24, 25], have been studied experimentally using bulk gel, core plugs and micromodels. During syneresis and dehydra‐ tion, the gel volume is reduced due to loss of water caused by chemical reactions over time, changes in pressure gradients or matrix capillary forces adjacent to the gel network. Other conditions, such as temperature, solvent composition, ionic strength and external electric field, are the main causes of gel swelling, which impact the gel volume without the loss of water by influencing the osmotic pressure balance between the gel network and its surroundings [26]. The behaviour of a polymer gel during EOR chasefloods will, in summary, depend on both the

EOR techniques in fractured reservoirs rely on maximizing the contact area between the injected EOR fluid and the rock surface, and therefore, the EOR fluid must transport effectively within the fracture network [27]. Most fracture networks, however, are heterogeneous

Heterogeneous fracture networks may result in poor sweep of the injected EOR fluid, and mobility control should be implemented to maximize contact. Two‐phase flow within rough‐ walled fractures has previously been investigated using Newtonian fluids [28–30] and non‐ Newtonian polymer solutions [31, 32]. Foam has the potential to increase oil recovery by better areal sweep, better vertical sweep (less gravity override), less viscous fingering and diversion of gas from higher permeable or previously swept layers [33]. Diversion of gas into lower permeable layers using foams may be important for fractured systems, where a very large

Foam is generated in porous media by snap‐off, lamella division or leave‐behind mechanisms. Foam generation is affected by porous medium topological properties, wetting content, capillary suction pressure, surfactant formulation, gas fractional flow and flow rate. Snap‐off

that collapsed and re‐opened depending on the injection pressure.

properties of the gel itself and on the external conditions in the reservoir.

themselves, with varying fracture aperture, orientation and connectivity.

permeability contrast exists and cross‐flow between the zones occur [34].

**3. Foam flooding of fractured systems**

**3.1. Gas mobility reduction**

**3.2. Foam generation in fractures**

**2.4. Gel volume alterations**

104 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

In this work, experiments providing insight to polymer gel behaviour during and after placement were performed using cylindrical outcrop core plugs with a 1 mm longitudinal fracture and aged to varying wetting states. *In situ* imaging by CT, MRI and PET was used to quantify and explain local saturation behaviour during polymer gel placement and chase‐ floods. Foam was investigated using a fractured marble tile model encased in Plexiglas that enabled us to visualize and describe foam flow in fractures (the marble itself is impermeable) at different gas fractions.

#### **4.1. Establishing stable wettability preferences by dynamic ageing**

Stable, predictable and uniformly distributed wettability preference is essential during core analysis to achieve reliable results [43–45]. The simplest wettability preference to achieve is the *strongly water‐wet* condition, where the contact angle between oil and water on a smooth surface is between 0° and 30° [46]. All clean outcrop rocks are strongly water‐wet before exposure to crude oil, and a strongly water‐wet wettability preference may be achieved and maintained using mineral oils [47]. However, this wettability preference does not reflect the preference of most reservoirs [48], and it is therefore needed to change the wettability of outcrop cores to better reflect reservoir conditions. Because core plugs extracted from the subsurface are exposed to drilling muds and large changes in pressure and temperature conditions during extraction, wettability alteration is also needed for reservoir cores [49]. Based on a decade of wettability alteration studies in chalk [50–54], a dynamic wettability alteration method [55] is outlined below

**1.** Cylindrical core plugs are drilled from outcrop rock blocks and cut to length. The core plugs are thereafter washed in tap water and dried at 60°C for no less than a week. The core plugs are thereafter saturated by brine, and porosity, and permeability measured.


## **4.2. Imaging techniques applied in porous media**

Several imaging techniques are currently applied to study flow in porous media, and most techniques originate from medical imaging. Here, we briefly review three imaging techniques used to study mobility control for EOR in fractured core plug systems.

#### *4.2.1. Positron emission tomography (PET)*

PET is based on positron‐emitting radionuclides where a positron is emitted from the nucleus accompanied by an electron to balance atomic charge. Radioactivity is a spontaneous nuclear phenomenon insensitive to temperature and pressure [56]. The positron loses kinetic energy by interactions with the surroundings, and at near‐zero momentum the positron combines with an electron and annihilates. The use of PET to study flow in porous media was recently reviewed and compared with CT [57]. Spatial fluid saturation is calculated based on the registered activity of the labelled phase, which in this work is water using the fluorine radioisotope 18F.

#### *4.2.2. X‐ray computed tomography (CT)*

**2.** The crude oil is prepared for ageing by being heated to 90°C and thereafter injected through a chalk core at a constant injection rate to remove impurities. Before use, the chalk core filter is flooded with crude oil to low water saturation and aged by flushing crude oil

used for ageing the filter core plug is not re‐used in the wettability alteration study. Due to its aged state, it was assumed that the adsorption of active wettability alteration components on the filter was significantly reduced. After filtration, the crude oil is stored in closed containers at 90°C with minimal interference and without air exposure until used

**3.** The fully water saturated core plugs are oilflooded to irreducible water saturation by crude oil injection at high differential pressures (2 bar/cm) at 90°C. When *S*wi is reached,

**4.** Wettability is measured using the Amott‐Harvey method: spontaneous and forced imbibition of water, followed by spontaneous and forced imbibition of the preferred mineral oil: using mineral oil to represent the oil phase ensures that the wettability of the

**5.** Experiments to investigate enhanced oil recovery (EOR) potential are commonly started

Several imaging techniques are currently applied to study flow in porous media, and most techniques originate from medical imaging. Here, we briefly review three imaging techniques

PET is based on positron‐emitting radionuclides where a positron is emitted from the nucleus accompanied by an electron to balance atomic charge. Radioactivity is a spontaneous nuclear phenomenon insensitive to temperature and pressure [56]. The positron loses kinetic energy by interactions with the surroundings, and at near‐zero momentum the positron combines with an electron and annihilates. The use of PET to study flow in porous media was recently reviewed and compared with CT [57]. Spatial fluid saturation is calculated based on the registered activity of the labelled phase, which in this work is water using the fluorine

diameter cores, respectively. Crude oil is continuously injected throughout the entire ageing process, and the direction of flow reversed midway. The ageing time is determined by the crude oil/rock/brine system and the desired wettability preference. After ageing, the crude oil is miscibly displaced from the core with 5PV of decaline (decahydronaptha‐

the injection rate is reduced to an ageing flow rate of 3 cm3

lene) followed by 5PV mineral oil (e.g. decane), all at 90°C.

core plugs is not further altered for the duration of experiments.

used to study mobility control for EOR in fractured core plug systems.

at the irreducible water saturation, *S*wi.

*4.2.1. Positron emission tomography (PET)*

radioisotope 18F.

**4.2. Imaging techniques applied in porous media**

/h for 96 h, reversing the flow direction midways. The crude oil

/h or 1.5 cm3

/h, for 2″ and 1.5″

through the core at 1 cm3

106 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

to age the cores.

CT measures the X‐ray attenuation through gradual loss in flux intensity through the medium, and produces a time‐averaged density distribution image of the rock [58, 59]. CT imaging relies on sufficient density contrasts which may often be fulfilled in low‐porosity media. Because attenuation depends on both the electron density and the effective atomic number, the CT number will vary with the energy of the rays. Spatial fluid saturation is derived with sufficient fluid density difference.

#### *4.2.3. Magnetic resonance imaging (MRI)*

MRI provides high spatial resolution imaging and fast data acquisition necessary to study flow in porous media. When replacing hydrogen in the aqueous phase (H2O) with deuterium (D2O), the magnetic signal in the water phase is removed and one explicit fluid phase (oil) is imaged in an oil‐water system. MRI has successfully been used to characterize flow behaviour and production mechanisms in fractured chalk and their dependency on wettability, injection rate, fracture aperture and configurations [56, 60].

**Figure 1** shows the different views applied during *in situ* imaging of cylindrical core plugs in this study. The sagittal view was often used to capture the flow dynamics inside the open fracture—which was vertically aligned in all experiments.

**Figure 1.** Schematic representation of the different views applied during *in situ* imaging of a core plug.

## **5. Recent advances in laboratory evaluation of polymer gel and foam for EOR**

#### **5.1.** *In situ* **imaging of polymer gel transport in fractured core plugs**

Complementary *in situ* imaging techniques have been used to investigate different aspects of polymer gel treatments described in the following sections. For most experiments, artificially fractured core plugs with open, longitudinal fractures have been used and the matrix has been saturated by two immiscible phases: oil and water, to mimic the environment in an oil reservoir. The polymer gel used for all experiments was 0.5% HPAM (∼5 million daltons molecular weight) cross‐linked by 0.04% (417 ppm) Cr(III)‐acetate and aged at 41°C for 24 h (five times the gelation time). After ageing, the gel was cooled to ambient temperature of ∼23°C.

#### *5.1.1. Gel shrinkage from spontaneous imbibition*

Gel placement in fractured reservoirs and its behaviour during chasefloods have been widely studied [4, 15, 61], but gel interaction with the porous rock in which the fractures are embedded has been less discussed. The exchange of fluids between the gel and adjacent porous rock may be substantial, even without a viscous pressure gradient across the system, if spontaneous capillary imbibition of water occurs [23]. Spontaneous imbibition impact leakoff during gel placement and gel stability after placement, and the loss of water from the gel is influenced by relative permeability, capillary pressure and the wettability of the porous medium. A severe reduction in gel volume (up to 99%) was documented due to spontaneous imbibition into porous media from adjacent, non‐flowing bulk gel [23], suggesting that gel treatments lose efficiency over time where a potential for spontaneous imbibition exists, because gel‐treated fractures may be opened to flow. Polymer gel is often used to reduce water cut and is therefore placed in a well or zone of the reservoir that is watered‐out, where spontaneous imbibition is reduced. During EOR operations, however, the local fluid saturations may change considera‐ bly, i.e. if an oil bank is generated, and spontaneous imbibition may again have impact on gel mobility control.

#### *5.1.2. Leakoff dependency on wettability*

In a strongly water‐wet rock, a positive capillary force exists to attract water from the gel into the rock matrix. In an oil‐wet rock, however, water will be repelled and must overcome a capillary threshold pressure to invade the pores. These two wettability conditions were directly compared using complementary imaging techniques during mature gel injection into open fractures. Cylindrical core plugs with longitudinal fractures of 1 mm aperture were used, and gel was injected with a constant volumetric injection rate into the fracture at ambient condi‐ tions.

In strongly water‐wet, low‐permeable chalk rock samples, where a strong positive capillary pressure exists, residual oil saturations were reached during gel placement due to water leakoff [25]. The chalk core was placed in a Bruker 4.7T MRI, and a spin‐echo based sequence was used to produce images during D2O‐gel injection. MRI settings must be tuned for each experiments, and depend strongly on the core material used, the fluid saturation and type of experimental setup (e.g. if a core holder or epoxy layers were used as confinement vessel). Finding the right settings for each experiment requires expert knowledge of the imaging apparatus and is not the focus of this chapter. Readers are referred to [62]. **Figure 2** shows MRI images of water leakoff during gel placement in a low‐permeable, strongly water‐wet chalk core (permeability, *K* <10 mD, porosity, *ϕ* = 45%, *d* = 4.96 cm, *L* = 7.6 cm). The rock matrices adjacent to the fracture were initially fully saturated with mineral oil (*n*‐decane) and appear light grey in the images. Bedding planes in the rock sample may be observed as darker features that are constant in the images. A strong positive capillary pressure exists due to the small pore sizes of this rock [63]. Water leaves the gel during leakoff and reduces the oil saturation in the rock matrix adjacent to the fracture first (darker grey regions due to loss of magnetic signal from the oil).

New Insight from Visualization of Mobility Control for Enhanced Oil Recovery Using Polymer Gels and Foams http://dx.doi.org/10.5772/64586 109

*5.1.1. Gel shrinkage from spontaneous imbibition*

108 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

mobility control.

tions.

signal from the oil).

*5.1.2. Leakoff dependency on wettability*

Gel placement in fractured reservoirs and its behaviour during chasefloods have been widely studied [4, 15, 61], but gel interaction with the porous rock in which the fractures are embedded has been less discussed. The exchange of fluids between the gel and adjacent porous rock may be substantial, even without a viscous pressure gradient across the system, if spontaneous capillary imbibition of water occurs [23]. Spontaneous imbibition impact leakoff during gel placement and gel stability after placement, and the loss of water from the gel is influenced by relative permeability, capillary pressure and the wettability of the porous medium. A severe reduction in gel volume (up to 99%) was documented due to spontaneous imbibition into porous media from adjacent, non‐flowing bulk gel [23], suggesting that gel treatments lose efficiency over time where a potential for spontaneous imbibition exists, because gel‐treated fractures may be opened to flow. Polymer gel is often used to reduce water cut and is therefore placed in a well or zone of the reservoir that is watered‐out, where spontaneous imbibition is reduced. During EOR operations, however, the local fluid saturations may change considera‐ bly, i.e. if an oil bank is generated, and spontaneous imbibition may again have impact on gel

In a strongly water‐wet rock, a positive capillary force exists to attract water from the gel into the rock matrix. In an oil‐wet rock, however, water will be repelled and must overcome a capillary threshold pressure to invade the pores. These two wettability conditions were directly compared using complementary imaging techniques during mature gel injection into open fractures. Cylindrical core plugs with longitudinal fractures of 1 mm aperture were used, and gel was injected with a constant volumetric injection rate into the fracture at ambient condi‐

In strongly water‐wet, low‐permeable chalk rock samples, where a strong positive capillary pressure exists, residual oil saturations were reached during gel placement due to water leakoff [25]. The chalk core was placed in a Bruker 4.7T MRI, and a spin‐echo based sequence was used to produce images during D2O‐gel injection. MRI settings must be tuned for each experiments, and depend strongly on the core material used, the fluid saturation and type of experimental setup (e.g. if a core holder or epoxy layers were used as confinement vessel). Finding the right settings for each experiment requires expert knowledge of the imaging apparatus and is not the focus of this chapter. Readers are referred to [62]. **Figure 2** shows MRI images of water leakoff during gel placement in a low‐permeable, strongly water‐wet chalk core (permeability, *K* <10 mD, porosity, *ϕ* = 45%, *d* = 4.96 cm, *L* = 7.6 cm). The rock matrices adjacent to the fracture were initially fully saturated with mineral oil (*n*‐decane) and appear light grey in the images. Bedding planes in the rock sample may be observed as darker features that are constant in the images. A strong positive capillary pressure exists due to the small pore sizes of this rock [63]. Water leaves the gel during leakoff and reduces the oil saturation in the rock matrix adjacent to the fracture first (darker grey regions due to loss of magnetic

**Figure 2.** Coronal slices through a cylindrical, fractured core plug placed in an MRI during gel placement. As D2O‐gel (no signal) progress through the fracture, conventional material balance experiments suggest that the oil in the fracture is displaced; however, the MRI images shown here suggest that some oil remains in the fracture even after significant gel flooding.

The water leakoff from the gel in the fracture to the oil‐saturated matrix was symmetric around the fracture and occurred by combined spontaneous and forced imbibition from the differential pressure generated. This combined displacement resulted in residual oil saturation in the matrix after gel placement, corresponding to 64% OOIP oil recovery during gel injection for the chalk core used. Although significant oil was produced in experiments at core plug scale, gel placement will not in itself contribute significantly to oil production at field scale because of the small fracture volume (1–2%) relative to matrix volume in most reservoirs. Hence, chasefloods are important to recover additional oil after a gel placement. The concept of gel placement is, however, important to study because it greatly affects the success of chaseflood oil recovery.

In oil‐wet and low permeable rocks, a threshold pressure must be overcome to achieve water leakoff. Local water leakoff during mature gel placement in a fractured, oil‐wet carbonate core plug (*K* = 11.7 mD, *ϕ* = 17.6%, *d* = 3.8 cm, *L* = 10.1 cm) was investigated by CT [64]. The CT was a Picker PQ‐6000 with 120 kVP tube voltage. Scans were produced with 4 s scanning time, and the slice thickness was 2 mm. Using a low injection rate of 6 cm3 /h during gel injection reduced the differential pressure and no leakoff was observed. Gel progressed through the fracture without losing water and increasing its concentration—thus, rock saturation remained constant at the irreducible water saturation (**Figure 3**, top and middle). In fully water saturated rock, where capillary forces are not present, the differential pressure limit to achieve leakoff corresponds to the pressure needed to extrude gel through the fracture [3]. Improved sweep efficiency was observed during the subsequent chaseflood when the injected water displaced oil from the rock matrix, predominantly in the inlet part of the core (see **Figure 3**).

**Figure 3.** CT images of a fractured core plug. Top: the core is aligned in the CT at *S*wi. Middle: CT image taken after gel placement. A strong signal from the gel is seen throughout the fracture. Matrix saturation changes were not observed during gel placement. Bottom: Chase waterflooding. A dispersed chase water front was clearly distinguishable by CT.

#### **5.2. Visualization of EOR chaseflood behaviour**

During gel placement in initially oil‐filled fractured systems, it is assumed that the oil residing in the fracture is produced at gel breakthrough [25]. This assumption was based on the high differential pressure observed during chasefloods, comparable to conventional experiments using 100% water saturated cores.

#### *5.2.1. Oil trapped in gel*

Upon careful inspection of **Figure 2**, it is possible to observe oil remaining in the fracture (bright sections) during gel flooding, and also after significant gel throughput. A clear rupture pressure during water chaseflooding suggests that the oil did not impact the blocking capacity of the gel. By employing the MRI further to image the chaseflood (**Figure 4**), we determined that the water flow paths were narrow and presumably through wormholes in the dehydrated gel, and that the oil remaining in the fracture was trapped within the gel structure (light grey areas in **Figure 4**). **Figure 4** shows the water flow paths through the gel in the fracture (bright white). A thresholded image (**Figure 4B**) shows the wormhole flow pattern in more detail.

Wormhole size is known to change with injection rate due to the gel elasticity. Although the gel pressure resistance is stable at low injection rates (below 600 cm3 /h, corresponding to a maximum injection flux of 1100–1600 cm/h when all flow of water is through the fracture), the gel may erode in the vicinity of wormholes at higher injection rates over time (significant water throughput). In experiments where the purpose is to measure wormhole size, it is therefore advisable to use high flow rates within relatively short time intervals. Without imaging, the average wormhole size can be calculated indirectly by measuring the injection rate and average pressure drop across the core plug. With *in situ* imaging, such as applying PET, the wormhole size may be measured directly, and the wormhole dynamics with changes in injection rate directly observed. Wormholes within a gel‐filled fracture were observed and quantified using PET, as shown in **Figure 5**. PET/CT sequences were acquired on a CT 80 W Nanoscan PC imager, featuring spatial resolutions of 800 and 30 μm of the respective PET‐ and CT‐detector systems. The core used was of Edwards limestone material [65] and was fully saturated by brine with a composition equal to the gel solvent. The PET signal was not corrected for attenuation in the analysis because the low CT tube energy (70 kVP) did not penetrate the core to produce spatial core plug density (needed for attenuation correction). The CT was thus only used for core plug positioning. In **Figure 5**, radioactively labelled water (18FDG) was injected into the gel‐filled fracture with a constant injection rate of 60 cm3 /h. When the pressure drop had stabilized across the core (at 1.6 kPa/cm for this injection rate), the wormhole flow pattern, visualized by PET, remained unchanged and covered 22.3% of the fracture volume. Dehy‐ drated gel (no signal) covered the remaining fracture volume. *In situ* imaging by PET showed locally large variations in the wormhole width, from very narrow (almost invisible on images) in some sections of the fracture to spanning large parts of the fracture height in other sections.

**Figure 3.** CT images of a fractured core plug. Top: the core is aligned in the CT at *S*wi. Middle: CT image taken after gel placement. A strong signal from the gel is seen throughout the fracture. Matrix saturation changes were not observed during gel placement. Bottom: Chase waterflooding. A dispersed chase water front was clearly distinguishable by CT.

During gel placement in initially oil‐filled fractured systems, it is assumed that the oil residing in the fracture is produced at gel breakthrough [25]. This assumption was based on the high differential pressure observed during chasefloods, comparable to conventional experiments

Upon careful inspection of **Figure 2**, it is possible to observe oil remaining in the fracture (bright sections) during gel flooding, and also after significant gel throughput. A clear rupture pressure during water chaseflooding suggests that the oil did not impact the blocking capacity of the gel. By employing the MRI further to image the chaseflood (**Figure 4**), we determined that the water flow paths were narrow and presumably through wormholes in the dehydrated gel, and that the oil remaining in the fracture was trapped within the gel structure (light grey areas in **Figure 4**). **Figure 4** shows the water flow paths through the gel in the fracture (bright white). A thresholded image (**Figure 4B**) shows the wormhole flow pattern in more detail.

Wormhole size is known to change with injection rate due to the gel elasticity. Although the

maximum injection flux of 1100–1600 cm/h when all flow of water is through the fracture), the gel may erode in the vicinity of wormholes at higher injection rates over time (significant water throughput). In experiments where the purpose is to measure wormhole size, it is therefore advisable to use high flow rates within relatively short time intervals. Without imaging, the

/h, corresponding to a

gel pressure resistance is stable at low injection rates (below 600 cm3

**5.2. Visualization of EOR chaseflood behaviour**

110 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

using 100% water saturated cores.

*5.2.1. Oil trapped in gel*

**Figure 4.** (A) Three‐dimensional image of the core plug during water chaseflooding. All remaining signal is in the frac‐ ture. Grey areas represent *n*‐decane, whereas white signal represent the intruding water phase. (B) With signal thresh‐ olding the water phase may be separated from the oil to exhibit the wormhole pattern.

Waterflooding after polymer gel placement may be efficient, and even if the gel has ruptured it provides significantly reduced fracture conductivity compared to open fractures. *In situ* imaging of core floods (**Figure 3**) have, however, shown that displacement fronts may be dispersed during water chasefloods. Enhanced oil recovery may be achieved by stabilizing the displacement front, e.g. using foam [64]. The gel treatment may also be strengthened after placement by injecting a water phase with lower salinity relative to the water in the gel [66]. Both injection pressures and matrix production rates during chasefloods increased with reduced salinity compared with chasefloods where the salinity was matched with the gel [25], presumably due to swelling of the polymer gel network. The improvement of the polymer gel treatment was reversible, and gel blocking efficiency immediately decreased during chase‐ floods with matched salinity. This shows that is possible to control the success of a chaseflood by influencing the gel properties. Combining polymer gel placement in fractures with low‐ salinity chasefloods is therefore a promising approach in iEOR. The new findings from PET imaging (**Figure 5**) may be helpful in explaining the mechanism for improved conformance control during low‐salinity chase waterfloods and shed light on wormhole morphology when injected water salinity is varied.

**Figure 5.** Positron emission tomography (PET) during radioactive chase waterflooding of a fractured core where gel has been placed in the fracture. The wormholes in the fracture are clearly seen and their development may be tracked as a function of flow rate and time. The colour pixels represent different spatial concentrations of brine in the fracture: the red signal corresponds to a high spatial concentration of radioactively labelled water, compared to e.g. blue colour (low spatial concentration). CT is applied to correctly position the PET signal in the core space.

#### **5.3. Fractured tile model to investigate 2D foam flow in fractured systems**

An experimental setup was built to visualize flow and to study mobility control by foam generation in fracture networks. A white marble tile was fractured using a ball‐peen hammer and then carefully reassembled within a frame to create a fracture network with rough, calcite fracture surfaces. The (effective) porosity was assumed to be zero in the marble matrix blocks, and flow occurred through the fracture network only. The fracture network was characterized by injecting brine and gas separately into the model. Pure nitrogen (N2) gas injection provided a baseline to which foam injection could be compared. **Figure 6** shows the marble tile model filled with red‐dyed brine.

Aqueous surfactant solution (1 wt% alpha olefin sulfonate (AOS) surfactant in 5 wt% NaCl brine) and N2‐gas were co‐injected into the fracture network at ambient conditions to form foam, using a range of gas fractions, to investigate the impact of the gas fraction on sweep efficiency. The fracture network was initially filled with aqueous solution, and the total flow rate for the co‐injections was 60 cm3 /h.

**Figure 6.** A square marble tile was fractured and reassembled within an aluminium frame sandwiched between two Plexiglas plates. The fracture network consisted mainly of narrow fractures with 12 large fractures. The vugular open fractures were larger bodies of open space varying between 0.4 and 2.2 cm aperture. These cavities were used to ob‐ serve the advancing foam front during co‐injection. In this figure, the marble tile model is filled with red‐dyed brine to emphasize the fracture network.

#### *5.3.1. Sweep efficiency*

reduced salinity compared with chasefloods where the salinity was matched with the gel [25], presumably due to swelling of the polymer gel network. The improvement of the polymer gel treatment was reversible, and gel blocking efficiency immediately decreased during chase‐ floods with matched salinity. This shows that is possible to control the success of a chaseflood by influencing the gel properties. Combining polymer gel placement in fractures with low‐ salinity chasefloods is therefore a promising approach in iEOR. The new findings from PET imaging (**Figure 5**) may be helpful in explaining the mechanism for improved conformance control during low‐salinity chase waterfloods and shed light on wormhole morphology when

**Figure 5.** Positron emission tomography (PET) during radioactive chase waterflooding of a fractured core where gel has been placed in the fracture. The wormholes in the fracture are clearly seen and their development may be tracked as a function of flow rate and time. The colour pixels represent different spatial concentrations of brine in the fracture: the red signal corresponds to a high spatial concentration of radioactively labelled water, compared to e.g. blue colour

An experimental setup was built to visualize flow and to study mobility control by foam generation in fracture networks. A white marble tile was fractured using a ball‐peen hammer and then carefully reassembled within a frame to create a fracture network with rough, calcite fracture surfaces. The (effective) porosity was assumed to be zero in the marble matrix blocks, and flow occurred through the fracture network only. The fracture network was characterized by injecting brine and gas separately into the model. Pure nitrogen (N2) gas injection provided a baseline to which foam injection could be compared. **Figure 6** shows the marble tile model

Aqueous surfactant solution (1 wt% alpha olefin sulfonate (AOS) surfactant in 5 wt% NaCl brine) and N2‐gas were co‐injected into the fracture network at ambient conditions to form foam, using a range of gas fractions, to investigate the impact of the gas fraction on sweep

(low spatial concentration). CT is applied to correctly position the PET signal in the core space.

**5.3. Fractured tile model to investigate 2D foam flow in fractured systems**

injected water salinity is varied.

112 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

filled with red‐dyed brine.

Areal sweep efficiency with changes in gas fraction was evaluated using the fracture network: a high‐resolution camera was used to capture images at short time intervals throughput foam co‐injection. From the images, total sweep was evaluated and it was possible to map flow patterns and calculate dynamic sweep efficiency as function of foam volume injected. Images could capture drainage of liquid from each fracture element, including vugs and narrow fractures. **Figure 7** compares total areal sweep efficiency for three N2‐gas fractions during foam co‐injection: fg = 0.60, fg = 0.80 and fg = 0.90.

**Figure 7** shows the development in sweep efficiency within the fracture network during co‐ injection with three different gas fractions. The sweep efficiency is compared at three time steps: after three fracture elements are filled; after five fracture elements and after seven fracture elements are filled. Only foam in the larger vugs could be visualized directly, but foam was also generated in, and flowed through, the smaller apertures. In general, we see that the sweep efficiency and spread of foam was higher with the increase of gas fractional flow. At higher gas fractions, breakthrough of gas was delayed, but in all cases delayed compared with pure gas injection. This demonstrated that foam reduced gas mobility and was formed within the fracture network itself.

**Figure 7.** Foam propagation through a fractured marble tile system. Foam filling of the first three, five and seven frac‐ ture elements are shown for gas fractions of 60% (top), 80% (middle) and 90% (bottom), respectively. Co‐injection was performed bottom to top in the images.

Unlike the foam bubble shape in a porous medium, where bubble shape is governed by pore configurations [35, 67], the bubbles in fractures are deformed according to interfacial tension, and the gas‐liquid interfacial curvature varies according to gas fractional flow [41]. Foam coalescence in a porous medium is controlled by the 'limiting‐capillary‐pressure' [68] at moderate to high gas fractional flow. The limiting capillary pressure is determined by the pore size, surfactant formulation, local fluid saturation and the interstitial velocity. The capillary pressure in a fracture is much lower (generally set to zero in most simulations—although strictly not correct) at a given aqueous‐phase saturation in comparison to permeable matrix. Capillary suction coalescence of foam lamellae appeared to become significant when the local aqueous phase saturation became very low. With increased gas fraction, the gas bubbles increased in size, on average. Large gas bubbles separated by thin lamellae occupied the majority of the fracture volume, especially at 0.95 gas fraction. This effect may be attributed to thinning of lamella at high gas fractional flow [69], resulting in foam coalescence and merging of smaller bubbles. Fewer and coarser bubbles related to the highest gas fraction are likely caused by thinning of lamellae (a larger fraction of the liquid is located in the Plateau border), followed by film rupture due to higher capillary‐suction pressure compared to lower gas fractional flow. The observations are consistent with earlier results, where larger bubbles were observed with increased gas fractional flow in a fracture network [39, 70].

#### **5.4. Combined polymer gel and foam chasefloods for iEOR**

**Figure 7.** Foam propagation through a fractured marble tile system. Foam filling of the first three, five and seven frac‐ ture elements are shown for gas fractions of 60% (top), 80% (middle) and 90% (bottom), respectively. Co‐injection was

Unlike the foam bubble shape in a porous medium, where bubble shape is governed by pore configurations [35, 67], the bubbles in fractures are deformed according to interfacial tension, and the gas‐liquid interfacial curvature varies according to gas fractional flow [41]. Foam coalescence in a porous medium is controlled by the 'limiting‐capillary‐pressure' [68] at moderate to high gas fractional flow. The limiting capillary pressure is determined by the pore size, surfactant formulation, local fluid saturation and the interstitial velocity. The capillary pressure in a fracture is much lower (generally set to zero in most simulations—although strictly not correct) at a given aqueous‐phase saturation in comparison to permeable matrix. Capillary suction coalescence of foam lamellae appeared to become significant when the local aqueous phase saturation became very low. With increased gas fraction, the gas bubbles increased in size, on average. Large gas bubbles separated by thin lamellae occupied the majority of the fracture volume, especially at 0.95 gas fraction. This effect may be attributed to thinning of lamella at high gas fractional flow [69], resulting in foam coalescence and merging of smaller bubbles. Fewer and coarser bubbles related to the highest gas fraction are likely caused by thinning of lamellae (a larger fraction of the liquid is located in the Plateau border),

performed bottom to top in the images.

114 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

Using a low‐field 8 MHz MRI (Oxford Instruments Maran DRX), we experimentally investi‐ gated an iEOR approach where the first step was polymer gel placement to reduce fracture conductivity and the second step was CO2‐foam injection to improve sweep efficiency com‐ pared to water chasefloods [64]. The experiments were performed at ambient conditions, thus the CO2 was not miscible with the oil (*n*‐decane). Pre‐generated foam was injected into the core after gel placement, using a gas fraction of 0.8 and a surfactant solution containing 1 wt% AOS surfactant. The development in oil saturation during all experimental steps was compared to oil recovery during foam injection without mobility control, using magnetic resonance imaging. Two fractured carbonate core plugs were used (*K* ≈ 30 mD, *ϕ* = 23–24%, *d* = 3.8 cm, *L* = 5.8 cm), with a measured Amott‐Harvey wettability index after dynamic age‐ ing of *I*AH = −0.2, which represents weakly oil‐wet conditions. Waterfloods were not efficient due to the oil‐wet conditions and only recovered 10–20% of the oil in place. *In situ* imaging showed that oil was primarily displaced from the inlet end of the core plugs, where water was injected directly into the matrix through specially designed end pieces [64]. Oil was dis‐ placed into the fracture, and no further oil recovery from the core matrix was detected after water breakthrough. Polymer gel placement was performed at 100 cm3 /h and yielded 20% oil recovery that was caused by the large fracture volume compared to the core pore volume at high injection pressure and low matrix threshold pressure due the weak oil‐wet condi‐ tions. Chaseflooding by immiscible CO2‐foam was performed to mitigate fluid dispersion around the displacement front. **Figure 8** shows the *in situ* development of the oil saturation and displacement fronts during foam flooding in the twin cores, with and without polymer gel conformance control present in the fracture. Oil production was prevailing in the near‐ fracture area by direct foam injection (**Figure 8A**). Haugen et al. [71] showed, using CT imaging of oil‐wet core plug systems, that oil was viscously displaced by surfactant solu‐ tion, forced into the matrix by the increased pressure gradient provided by the foam. In **Fig‐ ure 8B**, polymer gel was placed in the fracture prior to CO2‐foam flooding, and both foam constituents (gas and surfactant solution) entered the matrix during the foam flood. Immis‐ cible foam injection after conformance control by polymer gel provided 28% OOIP (original oil in place) additional oil recovery during 12.7 PV foam injected. In comparison, recovery factors of 14% OOIP (**Figure 8A**) to 20% OOIP were obtained during injection of more than 30 PV foam in comparable core plugs. Improved sweep efficiency was visually observed by MRI during foam chasefloods (**Figure 8**); in which more stable displacement fronts and less tendency to viscous fingering were observed when compared to e.g. chase waterflooding. The combination of two established EOR methods to improve conformance in both the frac‐ ture and matrix has important implications for future work on the development of efficient integrated EOR schemes.

**Figure 8.** Development in *in situ* oil saturation (light grey areas) during foam flooding of fractured, oil‐wet carbonate core plugs: (A) directly after waterflooding and (B) with polymer gel present in the fracture. Injections were performed left to right.

## **6. Conclusions**

*In situ* imaging provides new insight and corroborates results from core analysis applying material balance or gravimetrical measurements, and several different imaging techniques may be used to closely investigate local changes in saturation, fluid flow and oil recovery mechanisms during EOR experiments. Using *in situ* imaging techniques in this work, we found that:


Advanced medical imaging is not always required or available, and important insight may be gained from relatively simple experimental setups, such as the study foam generation in fractures where Plexiglas models provide the visualization needed. We found that foam was generated in a fracture model during co‐injection of surfactant and N2‐gas. A higher fractional flow of gas increased the sweep efficiency and spread of foam in vugs and fractures.

The crux of core plug scale experiments is proper design and planning of the experimental schedule using suitable equipment and imaging tools. When the core plug system is positioned within the imaging apparatus it cannot be moved. Hence, Testing the experimental setup without imaging, using simple material balance, is a good idea.

## **Author details**

**Figure 8.** Development in *in situ* oil saturation (light grey areas) during foam flooding of fractured, oil‐wet carbonate core plugs: (A) directly after waterflooding and (B) with polymer gel present in the fracture. Injections were performed

*In situ* imaging provides new insight and corroborates results from core analysis applying material balance or gravimetrical measurements, and several different imaging techniques may be used to closely investigate local changes in saturation, fluid flow and oil recovery mechanisms during EOR experiments. Using *in situ* imaging techniques in this work, we found

**•** Water leakoff during polymer gel propagation through a fractured, oil‐saturated core plug could be captured using magnetic resonance imaging (MRI). Water leakoff was symmetric around the fracture and occurred by combined spontaneous and forced imbibition from the

**•** Residual oil within the gel structure was observed with MRI after gel injection into a fractured, oil‐saturated core plug. The remaining oil did not impact the flow paths during water chasefloods, and it is likely that only a thin oil layer partly coated some region of

differential pressure generated by the gel injection.

left to right.

that:

the gel.

**6. Conclusions**

116 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

Bergit Brattekås1 and Martin A. Fernø2\*


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#### **Application of Multifunctional Agents During Enhanced Oil Recovery Application of Multifunctional Agents During Enhanced Oil Recovery**

Luis A. Alcázar-Vara, Luis S. Zamudio-Rivera and Eduardo Buenrostro-González Luis A. Alcázar-Vara, Luis S. Zamudio-Rivera and Eduardo Buenrostro-González

Additional information is available at the end of the chapter Additional information is available at the end of the chapter

http://dx.doi.org/10.5772/64792

#### **Abstract**

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During the application of enhanced oil recovery (EOR) processes, complex operational issues, such as the deposition of organic compounds (i.e., wax, resins, and asphaltenes, among others), reservoir formation damage, rock wettability alteration, and high fluids viscosity negatively affect oil recovery. This chapter presents the experimental evaluation of the multifunctional properties of two novel chemical agents recently developed: a zwitterionic surfactant (ZS) and a supramolecular complex (named here as AMESUS) for chemical EOR applications. The performance of the new multifunctional agents and the mechanisms in play on the removal/control of organic compounds deposition oil recovery, asphaltenes inhibition-dispersion activity, reduction in heavy crude oil viscosity, rock wettability modification, and relative permeability are discussed in this chapter.

**Keywords:** chemical enhanced oil recovery, multifunctional surfactants, asphaltenes, formation damage, viscosity reduction

## **1. Introduction**

On average, only one-third of the original oil in place (OOIP) is economically recoverable after the application of primary and secondary oil recovery (SOR) methods. The implementation of enhanced oil recovery (EOR) processes is increasing due to the decline in the discovery of new oil fields during the last decades [1–3]. EOR is defined as a process to reduce oil saturation below the residual oil saturation [4], and it refers to the injection of any fluid (i.e., steam, polymer solution, solvents, etc.) into the reservoir to change and/or to modify the existing rock/oil/brine

© 2016 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited. © 2016 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

interactions. It has been reported that for light and medium oil reservoirs, the residual oil saturation ranges from 50 to 60% of the OOIP, whereas for heavy crude oil reservoirs, it could range from 80 to 95% [1, 5]. Several EOR methods have been reported such as the use of chemical products (polymers and surfactants), thermal methods (steam stimulation, in-situ combustion, electrical heating, vibrational methods etc.), miscible gas injection, and microbial EOR, among others [4]. However, the application of EOR technologies can modify in an adverse way the flow and phase behavior of the reservoir fluids as well as the formation rock (FR) properties that can promote oil productivity decline. Some of these issues include organic compounds deposition leading to formation damage, plugging of the formation rock (within the reservoir and at the wellbore), as well as flow restrictions in tubing, flow lines, and production facilities [2, 3].

Deposition of heavy organics such as asphaltenes can take place at the oil producing slots and at the rock formation face, while the deposition of solid phases (i.e., asphaltenes) over pore surface and/or across pore throats within the oil formation can reduce significantly the effective permeability of the reservoir and severely impair the flow of crude oil through the porous medium (formation damage). The deposition of organic components also renders rock wettability changes from water-wet to oil-wet. Another issue could be the increase in the viscosity of the oil phase due to the formation of water in oil emulsions [6, 7].

This complicated association of problems can occur simultaneously during oil recovery processes. Several methods to remediate these operational problems are available such as the use of chemical additives, which have been used in the field without testing their actual effectiveness in remediating the situation [7, 8]. The removal and control of formation damage caused by asphaltenes deposition are usually achieved by the application of chemical treatments based on aromatic solvents that are applied in both at the wellbore and deeper within the formation. However, there is an economical limitation due to the transient effect of such cleanup methods. Moreover, aromatic solvents do not efficiently dissolve the heavy organic deposits or extract the asphaltenes fractions that remain fixed onto carbonated and clay minerals surfaces [7, 9, 10]. In the case of heavy crude oils, some of the methods that have been reported for viscosity reduction include dilution with lighter crudes or alcohols, the use of chemical additives such as polymers, or nanoparticles, and the use of surfactants to stabilize emulsions [11].

Chemical flooding using surfactants is a method that has been widely studied over several decades; it is considered an efficient process to achieve incremental recovery of residual oil with great potential as an EOR process for the petroleum industry. Although the mechanisms involved in the interactions of the surfactants with oil and brine within the porous media are complex, interfacial-tension reduction and formation rock wettability alteration are the most accepted mechanisms responsible for recovering residual oil saturation [4, 7, 12, 13].

This chapter presents the experimental evaluation of the multifunctional properties of two novel chemical agents recently developed: a zwitterionic surfactant (ZS) and a supramolecular complex (named here as AMESUS) for chemical EOR applications. The performance of the new multifunctional agents and the mechanisms in play on the removal/control of organic compounds deposition oil recovery, asphaltenes inhibition-dispersion activity, reduction in the viscosity of the heavy crude oil, rock wettability modification, and relative permeability are presented and discussed in this chapter.

## **2. Multifunctional agents**

interactions. It has been reported that for light and medium oil reservoirs, the residual oil saturation ranges from 50 to 60% of the OOIP, whereas for heavy crude oil reservoirs, it could range from 80 to 95% [1, 5]. Several EOR methods have been reported such as the use of chemical products (polymers and surfactants), thermal methods (steam stimulation, in-situ combustion, electrical heating, vibrational methods etc.), miscible gas injection, and microbial EOR, among others [4]. However, the application of EOR technologies can modify in an adverse way the flow and phase behavior of the reservoir fluids as well as the formation rock (FR) properties that can promote oil productivity decline. Some of these issues include organic compounds deposition leading to formation damage, plugging of the formation rock (within the reservoir and at the wellbore), as well as flow restrictions in tubing, flow lines, and production facilities [2, 3].

124 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

Deposition of heavy organics such as asphaltenes can take place at the oil producing slots and at the rock formation face, while the deposition of solid phases (i.e., asphaltenes) over pore surface and/or across pore throats within the oil formation can reduce significantly the effective permeability of the reservoir and severely impair the flow of crude oil through the porous medium (formation damage). The deposition of organic components also renders rock wettability changes from water-wet to oil-wet. Another issue could be the increase in the

This complicated association of problems can occur simultaneously during oil recovery processes. Several methods to remediate these operational problems are available such as the use of chemical additives, which have been used in the field without testing their actual effectiveness in remediating the situation [7, 8]. The removal and control of formation damage caused by asphaltenes deposition are usually achieved by the application of chemical treatments based on aromatic solvents that are applied in both at the wellbore and deeper within the formation. However, there is an economical limitation due to the transient effect of such cleanup methods. Moreover, aromatic solvents do not efficiently dissolve the heavy organic deposits or extract the asphaltenes fractions that remain fixed onto carbonated and clay minerals surfaces [7, 9, 10]. In the case of heavy crude oils, some of the methods that have been reported for viscosity reduction include dilution with lighter crudes or alcohols, the use of chemical additives such as polymers, or nanoparticles, and the use of surfactants to stabilize

Chemical flooding using surfactants is a method that has been widely studied over several decades; it is considered an efficient process to achieve incremental recovery of residual oil with great potential as an EOR process for the petroleum industry. Although the mechanisms involved in the interactions of the surfactants with oil and brine within the porous media are complex, interfacial-tension reduction and formation rock wettability alteration are the most

This chapter presents the experimental evaluation of the multifunctional properties of two novel chemical agents recently developed: a zwitterionic surfactant (ZS) and a supramolecular complex (named here as AMESUS) for chemical EOR applications. The performance of the new multifunctional agents and the mechanisms in play on the removal/control of organic compounds deposition oil recovery, asphaltenes inhibition-dispersion activity, reduction in

accepted mechanisms responsible for recovering residual oil saturation [4, 7, 12, 13].

viscosity of the oil phase due to the formation of water in oil emulsions [6, 7].

emulsions [11].

#### **2.1. Zwitterionic surfactant (ZS)**

Surfactants that are composed of two hydrophilic and two hydrophobic groups have been the subject of significant research interest since the early 1990s. These surfactants are called "Gemini" because their chemical structures can be perceived as two classic surfactant molecules chemically connected at or near the head groups. Their chemical arrangement provides a rich array of aggregate morphologies and solution properties that are dependent upon the nature and size of the linking group and/or head groups. These types of surfactants with unsymmetrical geometry have interesting characteristics in terms of self-assembly into aggregates and packing at interfaces [14].

Zwitterionic surfactants (ZSs) are considered among the surfactant molecules that can be applied in EOR with molecular structures made up by two hydrocarbon chains, a bridge, and two polar groups of zwitterionic type that can be a cation and an anion in different atoms of the same molecule. ZSs are electrically neutral, and they can behave as bases or acids (acceptor or donor) according to the properties of the medium where they are found. Therefore, zwitterionic surfactants can play a role as smart wettability modifiers that react efficiently according to the characteristics and properties of the specific medium [8, 15–17].

**Figure 1** displays the general chemical structure of zwitterionic surfactants (ZSs), which corresponds to a recently developed alkyl betaine zwitterionic gemini surfactant with polyethylene spacers [17]. This molecule was designed as a wettability modifier of rock surfaces such as limestone, dolomite, sand, quartz or heterogeneous lithology in the presence of brines with high content of divalent ions (i.e., calcium, magnesium, barium, and strontium), high temperature, and high pressure for EOR applications.

**Figure 1.** General chemical structure of the geminal zwitterionic surfactant. R is dodecyl radical [17].

#### **2.2. Supramolecular complex**

Supramolecular chemistry is based on the phenomenon of molecular recognition through weak forces between molecules, which promotes self-assembly [18]. This is a promising technology that has impacted the design of new materials with interesting applications in the chemical industry including the petroleum industry [7, 19, 20].

Supramolecular technology has been used for EOR applications. For instance, supramolecular assemblies, such as micellar structures, have been developed for applications in wettability alteration where it is beneficial to modify the rock formation wettability from oil-wet to preferentially water-wet to enhance oil recovery [19, 20]. It has also been reported that supramolecular agents can interact with crude oil fractions within the reservoir to reduce their viscosity promoting additional recovery of residual oil [7, 19, 20].

The supramolecular complex, AMESUS, is a surfactant developed from the interactions among cocamidopropyl hydroxysultaine (CAHS), sodium dodecyl alpha-olefin sulfonate, and sodium dodecyl hydroxyl sulfonate. AMESUS offers multifunctional features including foaming, corrosion-inhibition, and wettability-alteration properties. AMESUS can be used in high salinity brines at reservoir conditions without alteration of its molecular structure [19]. **Figure 2** shows the characteristic chemical structure of a supramolecular structure.

**Figure 2.** Characteristic chemical structure of the supramolecular complex, wherein R1, R2, and R3 are alkyl, alkenyl linear, or branched chains, whose length ranges from 1 to 30 carbon atoms [19].

#### **3. Evaluation of the multifunctional properties**

#### **3.1. Interfacial tension (IFT) and contact angle**

The dominant oil recovery mechanisms during surfactant flooding are interfacial tension (IFT) reduction and wettability alteration [12, 13]. The mobilization of residual oil requires the reduction in the interfacial tension at the oil-brine interfaces to ultralow values to overcome the capillary forces responsible for trapping residual oil at the pore scale [8]. Therefore, IFT reduction mechanism depends on the surfactant effectiveness in reducing the oil-water IFT by four to six orders of magnitude. **Figure 3** shows the interfacial tension as a function of surfactant concentration and surfactant type (AMESUS and a ZS) obtained from a light crude oil (31° API)—high-salinity brine (2.6 wt.% NaCl) system.

**2.2. Supramolecular complex**

126 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

Supramolecular chemistry is based on the phenomenon of molecular recognition through weak forces between molecules, which promotes self-assembly [18]. This is a promising technology that has impacted the design of new materials with interesting applications in the

Supramolecular technology has been used for EOR applications. For instance, supramolecular assemblies, such as micellar structures, have been developed for applications in wettability alteration where it is beneficial to modify the rock formation wettability from oil-wet to preferentially water-wet to enhance oil recovery [19, 20]. It has also been reported that supramolecular agents can interact with crude oil fractions within the reservoir to reduce their

The supramolecular complex, AMESUS, is a surfactant developed from the interactions among cocamidopropyl hydroxysultaine (CAHS), sodium dodecyl alpha-olefin sulfonate, and sodium dodecyl hydroxyl sulfonate. AMESUS offers multifunctional features including foaming, corrosion-inhibition, and wettability-alteration properties. AMESUS can be used in high salinity brines at reservoir conditions without alteration of its molecular structure [19].

**Figure 2.** Characteristic chemical structure of the supramolecular complex, wherein R1, R2, and R3 are alkyl, alkenyl

The dominant oil recovery mechanisms during surfactant flooding are interfacial tension (IFT) reduction and wettability alteration [12, 13]. The mobilization of residual oil requires the

linear, or branched chains, whose length ranges from 1 to 30 carbon atoms [19].

**3. Evaluation of the multifunctional properties**

**3.1. Interfacial tension (IFT) and contact angle**

**Figure 2** shows the characteristic chemical structure of a supramolecular structure.

chemical industry including the petroleum industry [7, 19, 20].

viscosity promoting additional recovery of residual oil [7, 19, 20].

**Figure 3.** Interfacial tension (mN/m) as a function of surfactant concentration and surfactant type.

As expected, multifunctional agents (surfactants) decrease the interfacial tension as the concentration of surfactant increases until the critical micelle concentration is reached. According to the data presented in **Figure 3**, "ultra-low" IFT values were not obtained for this system with these surfactants. However, it is important to realize that oil recovery is not only influenced by IFT reduction, there are other several factors affecting the mobilization of oil at pore scale such as rock wettability (contact angle), capillary and viscous forces, and fluid properties, among others [4, 8, 12, 13]. Wettability determines the adhering tendency of a fluid toward a solid surface in the presence of other immiscible fluids, and it is a function of the interfacial chemistry of the phases present in the system. Contact angle is the point at which the oil or water interface meet at the solid (i.e., rock) surface; therefore, it indicates the affinity of the solid surface for any of the fluids present in the system. Contact angle determination is commonly used to establish wettability changes of solid surfaces [21]. In this regard, reliable wettability alteration measurement tools are necessary for the accurate evaluation and monitoring of wettability alteration treatments.

**Figure 4** shows the effect of multifunctional agents (i.e., surfactant) addition on the contact angle for each system as a function of time. The solid surfaces used were carbonate minerals (dolomite), and the concentration of multifunctional agents was 0.1 g/L in high salinity brine concentrations (3.2 wt.% NaCl). As observed in **Figure 4**, both multifunctional agents changed the contact angle between oil and the solid surface. In the AMESUS system, the contact angle was changed from 0 to 51°, while for the ZS system the contact angle changed from 0 to 30°. These results demonstrate the effectiveness of these additives as wettability modifiers. Therefore, these results show that despite the slow decrease in interfacial tension, these multifunctional agents are efficient in altering the rock wettability.

**Figure 4.** Effect of multifunctional agents on contact angle between oil and the solid surface.

#### **3.2. Asphaltenes aggregation inhibition and dispersion activity**

Asphaltenes can be defined according to their solubility as the fraction of oil that is insoluble in low-molecular-weight alkanes, specifically n-pentane and n-heptane, but completely soluble in aromatic hydrocarbons, such as benzene and toluene. Asphaltenes fraction is formed of associated systems of polynuclear aromatics bearing alkyl side chains and organic molecules containing oxygen, nitrogen, sulfur, vanadium, and nickel porphyrins [22]. Asphaltenes are known to aggregate due to the propensity of their fused aromatic ring systems to stack via π-bonding [23].

Oil production operations can induce asphaltenes precipitation because of pressure and temperature decrease and oil-phase compositional changes. The disruption of the initial reservoir conditions could induce undesirable phase separation that negatively impacts every stage of the oil production process. As mentioned earlier, deposition of asphaltenes aggregates onto the rock surface can modify the wettability of the reservoir from water-wet to oil-wet, affecting significantly the oil displacement efficiency during the oil recovery processes. Thus, surfactants agents designed for chemical enhanced oil recovery must effectively interact with the heavy fractions of the crude oil such as asphaltenes and resins. Surfactants must inhibit their aggregation and/or disperse their aggregates to prevent their deposition or accumulation onto the rock surface, which would alter the wettability and the effective permeability of the formation rock affecting oil sweep efficiency.

(dolomite), and the concentration of multifunctional agents was 0.1 g/L in high salinity brine concentrations (3.2 wt.% NaCl). As observed in **Figure 4**, both multifunctional agents changed the contact angle between oil and the solid surface. In the AMESUS system, the contact angle was changed from 0 to 51°, while for the ZS system the contact angle changed from 0 to 30°. These results demonstrate the effectiveness of these additives as wettability modifiers. Therefore, these results show that despite the slow decrease in interfacial tension, these

multifunctional agents are efficient in altering the rock wettability.

128 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

**Figure 4.** Effect of multifunctional agents on contact angle between oil and the solid surface.

Asphaltenes can be defined according to their solubility as the fraction of oil that is insoluble in low-molecular-weight alkanes, specifically n-pentane and n-heptane, but completely soluble in aromatic hydrocarbons, such as benzene and toluene. Asphaltenes fraction is formed of associated systems of polynuclear aromatics bearing alkyl side chains and organic molecules containing oxygen, nitrogen, sulfur, vanadium, and nickel porphyrins [22]. Asphaltenes are known to aggregate due to the propensity of their fused aromatic ring systems to stack via

Oil production operations can induce asphaltenes precipitation because of pressure and temperature decrease and oil-phase compositional changes. The disruption of the initial reservoir conditions could induce undesirable phase separation that negatively impacts every stage of the oil production process. As mentioned earlier, deposition of asphaltenes aggregates onto the rock surface can modify the wettability of the reservoir from water-wet to oil-wet, affecting significantly the oil displacement efficiency during the oil recovery processes. Thus, surfactants agents designed for chemical enhanced oil recovery must effectively interact with the heavy fractions of the crude oil such as asphaltenes and resins. Surfactants must inhibit their aggregation and/or disperse their aggregates to prevent their deposition or accumulation

**3.2. Asphaltenes aggregation inhibition and dispersion activity**

π-bonding [23].

Multifunctional agents used as asphaltenes aggregation inhibitors have been evaluated through ultraviolet-visible (UV-vis) spectroscopy by determining the concentration of asphaltenes remaining in solution after induced precipitation with n-heptane [8]. This study was carried out taking advantage of the insolubility of the asphaltenes fraction in lowmolecular-weight alkanes such as n-heptane. However, under these conditions, the addition of the chemical agents promotes a colloidal stability to the asphaltenes particles in the liquid phase by preventing their aggregation through steric hindering or by modifying the electrostatic forces involved in the system [8].

The asphaltenes used in this experimental study were extracted from a Mexican heavy crude oil sample (18°API) using n-heptane. The solvent (volume) to heavy oil (mass) ratio was 40:1 (cm3 /g of oil). The solution was mixed for 8 h, filtered (1 μm porous size membrane), and dried under vacuum at 60°C. The obtained fraction of asphaltenes was redissolved at a concentration of 10 wt.% in methylene chloride, reprecipitated using n-heptane, and refiltered.

**Figure 5.** Performance of zwitterionic surfactant on asphaltenes aggregation inhibition and dispersion activity.

**Figure 5** shows the effect of the zwitterionic surfactant (ZS) on asphaltenes aggregation inhibition and dispersion activity. The evaluations of the inhibition properties were carried out using solutions (1000 μL) of 5.0 g/L of asphaltenes in toluene mixed with *n*-heptane solutions (9000 μL) at different concentrations (0.5, 1, and 2 g/L) of ZS according to experimental techniques described elsewhere [8]. The dispersion activity experiment was performed using a sample of sediment extracted from a light crude oil (35° API) by centrifugation and with a composition of 59.99 wt.% saturates, 20.82 wt.% aromatics, 17.47 wt.% resins, and 1.45 wt.% asphaltenes [8]. **Figure 5** shows that the efficiency of asphaltenes aggregation inhibition increases as the concentration of ZS increases, while the dispersion activity efficiency increases initially as the concentration of ZS increases but it levels off at a concentration of ZS of 0.5 g/L.

The mechanism by which ZS inhibits asphaltenes aggregation can be elucidated through interactions between asphaltenes and ZS resulting in the formation of ion-dipole pairs that generate disorder in the system by steric effects [8]. This multifunctional agent (ZS) not only inhibits asphaltenes aggregation but also exhibits suitable asphaltenes dispersion performance (**Figure 5**).

#### **3.3. Formation damage**

The assessment, control, and remediation of formation damage are among the most important issues to be resolved to ensure the efficient exploitation of hydrocarbon reservoirs. Formation damage is a detrimental operational and costly problem that could arouse during several stages of oil and gas production. Formation damage can occur during drilling, production, hydraulic fracturing, workover operations, and EOR [24].

Organic deposition is one of the main factors that can induce formation damage due to permeability impairment. For instance, asphaltenes deposition is a common cause of formation damage [24, 25]. It has been reported that asphaltenes induced formation damage can be explained by three mechanisms: (1) increase in the reservoir fluid viscosity due to the formation of water-in-oil emulsions and/or due to the increased concentration of asphaltenes particles in the bulk of the oil phase, especially in the near wellbore region as the oil converges radially toward the wellbore; (2) change in the wettability of the reservoir formation from water-wet to oil-wet by the adsorption of asphaltenes onto the rock surface; and (3) reduction in the reservoir formation permeability by plugging of pore throats and/or constrictions by asphaltenes particles [24].

This section summarizes the experimental evaluation of the effectiveness of multifunctional agent AMESUS in removing and inhibiting the deposition of heavy organics components onto the porous media. As heavy crude oil flows through porous media, the interactions between the asphaltenes aggregates contain in the heavy oil and some of the mineral compounds present in the rock surface induce the adsorption of asphaltenes onto the rock surfaces, which results in the gradual decrease in the effective permeability of the rock [7, 25].

This experimental work was performed by conducting coreflooding tests at reservoir conditions: temperature of 150°C, average pore pressure of 2400 psi, and overburden pressure of 3500 psi.

The experimental procedure was carried out as follows: (1) core damage was generated by flowing a sample of crude oil (1 ml/min) with high propensity for asphaltenes precipitation, through the porous medium (at least 50 pore volumes, PV). It was assumed that core impairment was caused by asphaltenes deposition. The degree of core damage was evaluated through the determination of permeability reduction; (2) application of the corresponding chemical treatment either xylene or AMESUS solutions dissolved in brine at a concentration of 2.0 g/L to the damaged core. The volume of treatment applied was five PV injected at a flow rate of 1 ml/min that was followed by a soaking period of 6 h; (3) injection of crude oil through the treated core plug in order to evaluate the effectiveness of the applied chemical treatment in removing the damage previously caused to the core [7]. **Table 1** summarizes the composition and other properties of the crude oil sample, and **Table 2** lists some petrophysical properties of the core plug used (Bedford limestone).


**Table 1.** Composition and other physical properties of the crude oil.

initially as the concentration of ZS increases but it levels off at a concentration of ZS of

The mechanism by which ZS inhibits asphaltenes aggregation can be elucidated through interactions between asphaltenes and ZS resulting in the formation of ion-dipole pairs that generate disorder in the system by steric effects [8]. This multifunctional agent (ZS) not only inhibits asphaltenes aggregation but also exhibits suitable asphaltenes dispersion perform-

The assessment, control, and remediation of formation damage are among the most important issues to be resolved to ensure the efficient exploitation of hydrocarbon reservoirs. Formation damage is a detrimental operational and costly problem that could arouse during several stages of oil and gas production. Formation damage can occur during drilling, production,

Organic deposition is one of the main factors that can induce formation damage due to permeability impairment. For instance, asphaltenes deposition is a common cause of formation damage [24, 25]. It has been reported that asphaltenes induced formation damage can be explained by three mechanisms: (1) increase in the reservoir fluid viscosity due to the formation of water-in-oil emulsions and/or due to the increased concentration of asphaltenes particles in the bulk of the oil phase, especially in the near wellbore region as the oil converges radially toward the wellbore; (2) change in the wettability of the reservoir formation from water-wet to oil-wet by the adsorption of asphaltenes onto the rock surface; and (3) reduction in the reservoir formation permeability by plugging of pore throats and/or constrictions by asphal-

This section summarizes the experimental evaluation of the effectiveness of multifunctional agent AMESUS in removing and inhibiting the deposition of heavy organics components onto the porous media. As heavy crude oil flows through porous media, the interactions between the asphaltenes aggregates contain in the heavy oil and some of the mineral compounds present in the rock surface induce the adsorption of asphaltenes onto the rock surfaces, which

This experimental work was performed by conducting coreflooding tests at reservoir conditions: temperature of 150°C, average pore pressure of 2400 psi, and overburden pressure of

The experimental procedure was carried out as follows: (1) core damage was generated by flowing a sample of crude oil (1 ml/min) with high propensity for asphaltenes precipitation, through the porous medium (at least 50 pore volumes, PV). It was assumed that core impairment was caused by asphaltenes deposition. The degree of core damage was evaluated through the determination of permeability reduction; (2) application of the corresponding chemical treatment either xylene or AMESUS solutions dissolved in brine at a concentration of 2.0 g/L to the damaged core. The volume of treatment applied was five PV injected at a flow rate of 1 ml/min that was followed by a soaking period of 6 h; (3) injection of crude oil through the

results in the gradual decrease in the effective permeability of the rock [7, 25].

hydraulic fracturing, workover operations, and EOR [24].

0.5 g/L.

ance (**Figure 5**).

**3.3. Formation damage**

130 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

tenes particles [24].

3500 psi.


**Table 2.** Some petrophysical properties of the core plug sample.

**Figure 6.** Performance of chemical treatments in removing and inhibiting the deposition of asphaltenes.

**Figure 6** plots the experimental results obtained during the application of different remediation treatments. The reference case (black solid circles in **Figure 6**), in which the core plug was flooded with 80 pore volumes (PV) of crude oil without a previous chemical treatment, shows a severe permeability reduction due to the retention and adsorption of asphaltenes and resins within the porous medium sample [7]. The application of the xylene treatment to the damaged core (blue solid square symbols in **Figure 6**) shows that permeability is recovered to some extent, while the application of AMESUS (green solid triangles in **Figure 6**) revealed a significant recovery of the core plug permeability. These results demonstrate the effectiveness of the supramolecular complex (AMESUS) in simultaneously removing the organic deposits and inhibiting the further adsorption of asphaltenes onto the core plug during the second stage of crude oil injection. It seems that the application of AMESUS changes the surface properties of the core by adhesion to the mineral surface forming a film that alters its wettability and thus inhibits the adsorption of asphaltenes and prevents further formation damage [7].

#### **3.4. Effect of the multifunctional agents on crude oil viscosity**

Residual oil saturation in heavy crude oil reservoirs has been reported to range from 80 to 95% of the OOIP, after primary and secondary oil recovery [1, 5]. The most practical approach to enhance the recovery of heavy oil is viscosity reduction through thermal EOR.

This section of the chapter describes the effectiveness of the multifunctional agents in reducing the viscosity of heavy oil. An Anton-Paar Physica MCR-301 rheometer equipped with a 50 mm PP50 plate-plate configuration and a gap of 1 mm was used to determine the viscosity of the oil samples. **Figure 7** summarizes the composition, API°, and viscosity behavior of the heavy oil as a function of temperature and shear rate.

**Figure 7.** Heavy crude oil: composition and viscosity as a function of temperature and shear rate.

The high viscosity of this heavy oil can be attributed to its high content of resins and asphaltenes (33.79 and 21.86%, respectively). In addition, this heavy oil exhibits a non-Newtonian rheological behavior at 25°C (**Figure 7**), most likely due to the formation of wax-resin aggregates within the bulk of the oil phase at this temperature.

The multifunctional agents—AMESUS and the zwitterionic surfactant—were diluted in a fixed volume of n-heptane (1 ml) at preestablished concentrations to achieve a final concentration of the chemicals in the crude oil sample of 0.5 g/L. For comparative purposes, a reference system was prepared by dosing the heavy oil sample with the equivalent fixed volume of nheptane that was used for dilution of the chemical agents. **Figure 8** plots the apparent viscosity of the crude oil as a function of shear rate and chemical treatment. The experiments were conducted at 25°C, and the range of shear rate evaluated was 0.1/s to 100.0/s.

**Figure 8.** Apparent viscosity as a function of shear rate and chemical treatment.

**Figure 8** indicates that the viscosity of the samples (baseline and chemical treated oil) decreases as the shear rate increases following a shear thinning behavior. The chemical-treated oil samples show lower viscosities when compared with the viscosity of the reference sample. Therefore, both multifunctional agents are effective in decreasing the viscosity. Nevertheless, AMESUS offers a better performance in reducing the viscosity of the heavy oil than the ZS agent. Moreover, the performance of the ZS agent is hindered as the shear rate increases.

These experimental observations demonstrate that the multifunctional agents interact with the asphaltenes and resins contained in the heavy oil sample providing a significant viscosity reduction. The AMESUS supramolecular complex exhibits a suitable performance in preventing the aggregation of asphaltenes and resins which allows reducing the viscosity of the heavy crude oil evaluated [7].

#### **3.5. Oil recovery**

within the porous medium sample [7]. The application of the xylene treatment to the damaged core (blue solid square symbols in **Figure 6**) shows that permeability is recovered to some extent, while the application of AMESUS (green solid triangles in **Figure 6**) revealed a significant recovery of the core plug permeability. These results demonstrate the effectiveness of the supramolecular complex (AMESUS) in simultaneously removing the organic deposits and inhibiting the further adsorption of asphaltenes onto the core plug during the second stage of crude oil injection. It seems that the application of AMESUS changes the surface properties of the core by adhesion to the mineral surface forming a film that alters its wettability and thus

Residual oil saturation in heavy crude oil reservoirs has been reported to range from 80 to 95% of the OOIP, after primary and secondary oil recovery [1, 5]. The most practical approach to

This section of the chapter describes the effectiveness of the multifunctional agents in reducing the viscosity of heavy oil. An Anton-Paar Physica MCR-301 rheometer equipped with a 50 mm PP50 plate-plate configuration and a gap of 1 mm was used to determine the viscosity of the oil samples. **Figure 7** summarizes the composition, API°, and viscosity behavior of the heavy

inhibits the adsorption of asphaltenes and prevents further formation damage [7].

enhance the recovery of heavy oil is viscosity reduction through thermal EOR.

**Figure 7.** Heavy crude oil: composition and viscosity as a function of temperature and shear rate.

within the bulk of the oil phase at this temperature.

The high viscosity of this heavy oil can be attributed to its high content of resins and asphaltenes (33.79 and 21.86%, respectively). In addition, this heavy oil exhibits a non-Newtonian rheological behavior at 25°C (**Figure 7**), most likely due to the formation of wax-resin aggregates

**3.4. Effect of the multifunctional agents on crude oil viscosity**

oil as a function of temperature and shear rate.

132 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

This section describes the experimental evaluation of the multifunctional agents as chemical additives for enhanced oil recovery (EOR) through coreflooding displacement tests at reservoir conditions. **Figure 9** displays the experimental setup of the coreflooding apparatus [7, 8]. The dead volumes of the flow lines were measured and accounted for in all material balance calculations. The performance of the corresponding chemical EOR applications was estimated in terms of incremental oil recovery [7, 8].

**Figure 9.** Experimental setup for coreflooding displacement tests.

The protocol used during coreflooding testing was as follows:


**4.** *Waterflooding* (*WF*) *stage*. Waterflooding as a secondary oil recovery (SOR) process was carried out by injecting brine at a constant flow rate of 1 ml/min. The produced fluids were collected using graduated centrifuge flasks. Pressure profile data along the core plug were recorded. The residual oil saturation (*S*or) was established when the production of crude oil became negligible. Oil recovery (% OOIP) was calculated by material balance as a function of time.

calculations. The performance of the corresponding chemical EOR applications was estimated

in terms of incremental oil recovery [7, 8].

134 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

**Figure 9.** Experimental setup for coreflooding displacement tests.

initial oil saturation (*S*oi) were determined.

The protocol used during coreflooding testing was as follows:

permeability of the core plug was 139 mD and the porosity 20%.

core plug was saturated with brine at a flow rate of 1 ml/min.

**1.** *Core plug preparation*. First, the core was cleaned using solvents such as toluene/methanol; afterward, the core was dried at 120°C for 24 h. The clean core plug was positioned into a standard core holder (manufactured by Core Laboratories). Flooding conditions were set at: temperature, 90°C; average core pressure, 2400 psi;, and overburden pressure, 3500 psi. A Bedford limestone (BL), core plug was used, which consists of 100 wt.% CaCO3. The dimensions of the core plug were 6.7 cm in length and 3.8 cm in diameter. The absolute

**2.** *Brine injection*. Brine with a concentration of 2.6 wt.% in NaCl was used. In this step, the

**3.** *Crude oil injection*. **Table 1** displays the composition and some physical characteristics of the crude oil used in this experimental section. The core plug was flooded with crude oil at a constant flow rate of 1 ml/min. In this stage, the irreducible water saturation (*S*wi) and **5.** *Surfactant flooding* (*SF*) *stage*. This stage was carried out injecting the corresponding multifunctional agent dissolved in brine at a fixed concentration of 1.0 g/L at a flow rate of 1 ml/min [7, 8].

**Figure 10** shows the experimental results of oil recovery (OOIP %) as a function of the volume of fluid injected, recovery stage, and type of surfactant treatment (AMESUS or ZS).

An incremental oil recovery of 12.9% was obtained for the AMESUS chemical flooding, whereas an incremental oil recovery of 10.2% was achieved for the ZS chemical flooding. Therefore, the multifunctional agents evaluated are effective in mobilizing and displacing residual oil. This indicates that the proper physicochemical interactions among the chemical solutions, rock, and crude oil were established during surfactant flooding.

**Figure 10.** Oil recovery (OOIP %) versus volume of fluid injected (PV), recovery stage, and surfactant type.

Rock permeability, porosity, and the spatial distribution of these parameters within the porous media influence oil recovery [26]. Thus, in order to evaluate the effect of permeability on oil recovery during surfactant flooding, coreflooding displacement tests were conducted using two different core plugs. A formation rock (FR), which consists of 92% calcite and 8% clays (kaolinite and sodium montmorillonite), having an absolute permeability of 9 mD, a porosity of 19%, a length of 8.3 cm, and a diameter of 3.8 cm. The second core plug was a Bedford limestone (BL), containing 100 wt.% CaCO3, an absolute permeability of 139 mD, 20% porosity, a length of 6.7 cm, and a diameter of 3.8 cm. In terms of rock wettability and as shown below in section 3.6 by using oil-water relative permeability curves, the FR rock is more oil-wet than the BL core [8].


**Table 3.** Composition and some physical characteristics of the crude oil.

A sample of crude oil with the properties presented in **Table 3** and brine (2.6 wt.% NaCl) were used in these experimental runs. The displacement tests were conducted following the injection protocol previously described. During the surfactant flooding stage, the ZS chemical was used at a concentration of 1.0 g/L. **Figure 11** summarizes these experimental observations, which indicate that the secondary oil recovery stage is significantly affected by the core permeability and mineralogy: the heterogeneous FR core with lower permeability (*K*absgas = 9 mD) had the higher residual oil saturation (*S*or = 56.4%) after waterflooding, whereas a lower residual oil saturation of 39.3% was obtained for the homogeneous BL core sample (*K*absgas = 139 mD). As expected, the higher the permeability of the rock, the higher the oil recovery. Furthermore, a higher oil recovery by waterflooding was obtained from the more water-wet or BL core, as previously reported [7].

As **Figure 11** shows, after the waterflooding stage, surfactant EOR flooding was carried out. An incremental oil recovery of 10.2% of the OOIP was obtained from the BL core plug, while only an incremental oil recovery of 4.9% was obtained from the FR core plug.

The higher incremental EOR obtained from the BL core sample might be explained by the higher permeability and wettability conditions (more water-wet) of this core as has been previously reported [8]. Nonetheless, the ZS multifunctional agent is effective in rendering incremental EOR from both porous media that otherwise would not be recovered.

**Figure 11** also shows the pressure drop profiles as a function of volume injected. Both porous media show similar behavior. At the beginning of waterflooding, the pressure drop rises slightly as oil production increases; however, as soon as brine breakthrough at the production end, pressure drop declines progressively, as well as oil production. During surfactant flooding, the pressure drop rapidly decreases, whereas oil production increases slowly. The pressure drop profiles exhibited in **Figure 11** also show that despite the high salinity characteristics of the brine used (2.6 wt.% NaCl), surfactant precipitation and/or blockage of the core plug was not observed during the flooding processes [8].

a length of 6.7 cm, and a diameter of 3.8 cm. In terms of rock wettability and as shown below in section 3.6 by using oil-water relative permeability curves, the FR rock is more oil-wet than

 gravity 31° SARA analysis (wt.%) Saturates 41.05

Colloidal instability index 0.75 Acidity (mg KOH/g) 0.13

A sample of crude oil with the properties presented in **Table 3** and brine (2.6 wt.% NaCl) were used in these experimental runs. The displacement tests were conducted following the injection protocol previously described. During the surfactant flooding stage, the ZS chemical was used at a concentration of 1.0 g/L. **Figure 11** summarizes these experimental observations, which indicate that the secondary oil recovery stage is significantly affected by the core permeability and mineralogy: the heterogeneous FR core with lower permeability (*K*absgas = 9 mD) had the higher residual oil saturation (*S*or = 56.4%) after waterflooding, whereas a lower residual oil saturation of 39.3% was obtained for the homogeneous BL core sample (*K*absgas = 139 mD). As expected, the higher the permeability of the rock, the higher the oil recovery. Furthermore, a higher oil recovery by waterflooding was obtained from the more water-wet

As **Figure 11** shows, after the waterflooding stage, surfactant EOR flooding was carried out. An incremental oil recovery of 10.2% of the OOIP was obtained from the BL core plug, while

The higher incremental EOR obtained from the BL core sample might be explained by the higher permeability and wettability conditions (more water-wet) of this core as has been previously reported [8]. Nonetheless, the ZS multifunctional agent is effective in rendering

**Figure 11** also shows the pressure drop profiles as a function of volume injected. Both porous media show similar behavior. At the beginning of waterflooding, the pressure drop rises slightly as oil production increases; however, as soon as brine breakthrough at the production end, pressure drop declines progressively, as well as oil production. During surfactant flooding, the pressure drop rapidly decreases, whereas oil production increases slowly. The pressure drop profiles exhibited in **Figure 11** also show that despite the high salinity characteristics of the brine used (2.6 wt.% NaCl), surfactant precipitation and/or blockage of the core

only an incremental oil recovery of 4.9% was obtained from the FR core plug.

incremental EOR from both porous media that otherwise would not be recovered.

plug was not observed during the flooding processes [8].

**Table 3.** Composition and some physical characteristics of the crude oil.

136 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

or BL core, as previously reported [7].

Aromatics 36.66 Resins 20.32 Asphaltenes 1.97

the BL core [8].

APIo

**Figure 11.** Influence of porous media on oil recovery performance of zwitterionic surfactant (ZS).

The effectiveness of AMESUS during surfactant flooding was also evaluated. In these experiments, the rock sample used was a Bedford limestone (BL) (100 wt.% CaCO3), with absolute permeability of 139 mD, a porosity of 20% porosity, a length of 6.7 cm, and a diameter of 3.8 cm. Samples of crude oil (31° API) and brine (2.6 wt.% NaCl) were used following the injection sequence previously described. Furthermore, in these coreflooding tests, different concentrations of AMESUS (0.5 g/L, 1 g/L, and 2 g/L) were evaluated to establish the effect of surfactant concentration on oil recovery. **Figure 12** presents oil recovery as a function of pore volume of fluid injected and surfactant concentration. These experimental results indicate that as the concentration of AMESUS increases, oil recovery increases.

**Figure 12.** Effect of AMESUS concentration on oil recovery performance.

#### **3.6. Relative permeability**

Oil-water relative permeability data offer relevant insights into the simultaneous flow of crude oil and brine that allows predicting the performance of waterflooding processes. Oil-water relative permeability is influenced by several variables such as fluids saturation, fluids saturation history, interfacial tension, fluids viscosity, overburden pressure, temperature, flow rate, wettability, and capillary end effects [27]. In addition, relative permeability curves provide information on the wettability of the porous media, which significantly affect oil recovery processes [7, 8].

In this study, the oil-water relative permeability curves were obtained following the Johnson-Bossler-Neumann (JBN) method and the data were fitted using a Corey-type correlation [7, 8, 28–30].

The effect of the multifunctional agent ZS on the oil-water relative permeability curves was evaluated to establish their efficiency in altering rock wettability.

In this experimental work, the wettability of the core plugs was determined after waterflooding. **Figure 13** presents the oil-water relative permeability curves after waterflooding. The crossover point (equal relative permeabilities) of the oil and water relative permeability curves shown in **Figure 13** indicates that both porous media (BL and FR rocks) are predominantly oilwet, which is expected for calcite rock formations [31]. However, the FR core plug is more oilwet (crossover point more shifted toward the left side of the relative permeability curves) than the crossover point of the BL core, which also explains the waterflooding oil recovery behavior presented in **Figure 11**, where a higher secondary oil recovery was obtained from the rock sample showing less oil-wetting tendency (i.e., BL core plug).

Application of Multifunctional Agents During Enhanced Oil Recovery http://dx.doi.org/10.5772/64792 139

**Figure 13.** Relative permeability curves after waterflooding.

**Figure 12.** Effect of AMESUS concentration on oil recovery performance.

138 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

evaluated to establish their efficiency in altering rock wettability.

sample showing less oil-wetting tendency (i.e., BL core plug).

Oil-water relative permeability data offer relevant insights into the simultaneous flow of crude oil and brine that allows predicting the performance of waterflooding processes. Oil-water relative permeability is influenced by several variables such as fluids saturation, fluids saturation history, interfacial tension, fluids viscosity, overburden pressure, temperature, flow rate, wettability, and capillary end effects [27]. In addition, relative permeability curves provide information on the wettability of the porous media, which significantly affect oil recovery

In this study, the oil-water relative permeability curves were obtained following the Johnson-Bossler-Neumann (JBN) method and the data were fitted using a Corey-type correlation [7, 8,

The effect of the multifunctional agent ZS on the oil-water relative permeability curves was

In this experimental work, the wettability of the core plugs was determined after waterflooding. **Figure 13** presents the oil-water relative permeability curves after waterflooding. The crossover point (equal relative permeabilities) of the oil and water relative permeability curves shown in **Figure 13** indicates that both porous media (BL and FR rocks) are predominantly oilwet, which is expected for calcite rock formations [31]. However, the FR core plug is more oilwet (crossover point more shifted toward the left side of the relative permeability curves) than the crossover point of the BL core, which also explains the waterflooding oil recovery behavior presented in **Figure 11**, where a higher secondary oil recovery was obtained from the rock

**3.6. Relative permeability**

processes [7, 8].

28–30].

**Figure 14.** Effect of ZS chemical agent on the relative permeability curves. (a) BL core and (b) FR core.

The effect of rock wettability on oil recovery has been reported in the literature [32, 33]. **Figure 14** displays the effect of surfactant flooding (SF) using the ZS agent on the oil-water relative permeability curves corresponding to the oil-recovery coreflooding results previously discussed (**Figure 11**). **Figure 14** shows the end points of the relative permeability curves of both waterflooding (WF) and surfactant flooding (SF) processes. For the WF process, the initial water saturation (*S*Wi) and the residual oil saturation (*S*or) are presented, whereas for the SF process, the final residual oil saturation (*S*or(SF)) and the final relative permeability (*K*rw-s at *S*or(SF)) obtained for both the BL and the FR core plugs are presented.

These results demonstrate that the injection of ZS alters the wettability of both core plugs toward more water-wet conditions, which is in agreement with the incremental oil recovery previously presented [8].

## **4. Mechanisms**

Key mechanisms involved in the multifunctional activity of the chemical agents evaluated in this work are proposed and discussed in this section.

In the context of this study, formation damage is caused by the deposition of polar heavy organic fractions present in the crude oil, such as asphaltenes and resins, which could form a hydrophobic layer on the rock surface altering its wettability toward more oil-wet [**Figure 15(a)**]. Remediation of this type of formation damage by chemical treatment using the multifunctional agents AMESUS and ZS takes place due to the strong interactions established between the chemicals and the deposited layer of asphaltenes and resins, as sketched in **Figure 15(a)** and **(b)**. The interactions between the chemical agents and asphaltenes are different for each of the multifunctional agents. For instance, the ZS-asphaltenes interactions are of the iondipole pair types [16], whereas the asphaltenes-AMESUS interactions are of the dipole-dipole pair types [7]. As a result, the deposited asphaltenes are desorbed, disaggregated, and dispersed within the crude oil phase by the multifunctional agents, while simultaneously part of the chemical agents is adsorbed onto the rock surface replacing the previously deposited asphaltenes molecules [**Figure 15(d)**]. Moreover, the adsorption of the multifunctional agents onto the mineral surface modifies the wettability of the rock toward more water-wet condition and inhibits the further adsorption of asphaltenes, which prevents formation damage. Furthermore, the interactions of the multifunctional agents with the crude (bulk) oil indicate their effectiveness in inhibiting the formation of asphaltenes aggregates. Therefore, these surfactants are efficient in dispersing these heavy oil fractions within the crude oil reducing its viscosity [7, 8, 16].

It is important to emphasize that the mechanisms proposed here might be dependent on the characteristics of the brine/rock/crude oil system including resins and asphaltenes content, rheological properties of crude oil, brine composition, and the mineralogy of the porous media [7, 8]. Therefore, wettability alteration and reduction in crude oil viscosities are considered the key mechanisms that allow the multifunctional agents to increase oil recovery. Application of Multifunctional Agents During Enhanced Oil Recovery http://dx.doi.org/10.5772/64792 141

**Figure 15.** Sketch of the suggested mechanisms: (a) initial conditions, asphaltenes adsorbed onto the rock surface (oilwet core condition), (b) chemical flooding, (c) multifunctional agent-asphaltene interactions promoting asphaltenes desorption, and (d) wettability alteration to less oil-wet conditions due to the adsorption of the chemical agents onto the rock surface.

## **5. Conclusions**

The effect of rock wettability on oil recovery has been reported in the literature [32, 33]. **Figure 14** displays the effect of surfactant flooding (SF) using the ZS agent on the oil-water relative permeability curves corresponding to the oil-recovery coreflooding results previously discussed (**Figure 11**). **Figure 14** shows the end points of the relative permeability curves of both waterflooding (WF) and surfactant flooding (SF) processes. For the WF process, the initial water saturation (*S*Wi) and the residual oil saturation (*S*or) are presented, whereas for the SF process, the final residual oil saturation (*S*or(SF)) and the final relative permeability (*K*rw-s at

These results demonstrate that the injection of ZS alters the wettability of both core plugs toward more water-wet conditions, which is in agreement with the incremental oil recovery

Key mechanisms involved in the multifunctional activity of the chemical agents evaluated in

In the context of this study, formation damage is caused by the deposition of polar heavy organic fractions present in the crude oil, such as asphaltenes and resins, which could form a hydrophobic layer on the rock surface altering its wettability toward more oil-wet [**Figure 15(a)**]. Remediation of this type of formation damage by chemical treatment using the multifunctional agents AMESUS and ZS takes place due to the strong interactions established between the chemicals and the deposited layer of asphaltenes and resins, as sketched in **Figure 15(a)** and **(b)**. The interactions between the chemical agents and asphaltenes are different for each of the multifunctional agents. For instance, the ZS-asphaltenes interactions are of the iondipole pair types [16], whereas the asphaltenes-AMESUS interactions are of the dipole-dipole pair types [7]. As a result, the deposited asphaltenes are desorbed, disaggregated, and dispersed within the crude oil phase by the multifunctional agents, while simultaneously part of the chemical agents is adsorbed onto the rock surface replacing the previously deposited asphaltenes molecules [**Figure 15(d)**]. Moreover, the adsorption of the multifunctional agents onto the mineral surface modifies the wettability of the rock toward more water-wet condition and inhibits the further adsorption of asphaltenes, which prevents formation damage. Furthermore, the interactions of the multifunctional agents with the crude (bulk) oil indicate their effectiveness in inhibiting the formation of asphaltenes aggregates. Therefore, these surfactants are efficient in dispersing these heavy oil fractions within the crude oil reducing

It is important to emphasize that the mechanisms proposed here might be dependent on the characteristics of the brine/rock/crude oil system including resins and asphaltenes content, rheological properties of crude oil, brine composition, and the mineralogy of the porous media [7, 8]. Therefore, wettability alteration and reduction in crude oil viscosities are considered the key mechanisms that allow the multifunctional agents to increase oil recovery.

*S*or(SF)) obtained for both the BL and the FR core plugs are presented.

this work are proposed and discussed in this section.

previously presented [8].

140 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

**4. Mechanisms**

its viscosity [7, 8, 16].

This chapter summarizes the evaluation of the multifunctional properties of two novel chemical agents applied for enhanced oil recovery (EOR). These chemical agents demonstrate suitable performance during surfactant flooding at reservoir conditions (i.e., temperature and pressure) and high salinity brine concentration. These chemical agents are effective as asphaltenes aggregation inhibitors. Similarly, they are suitable asphaltenes dispersants. Therefore, these agents are applicable for the removal and prevention of asphaltenes deposition and/or adsorption onto the rock surface. Furthermore, these multifunctional agents can significantly decrease the viscosity of heavy oil through the breaking and dispersion of asphaltenes and resin aggregates within the bulk oil phase.

The dominant mechanisms responsible for the multifunctional activity of these chemical agents are the reduction in the viscosity of the heavy oil and the modification of the rock wettability. Finally, the novel multifunctional chemical agents have the potential of providing a feasible technological solution to the complex problems related to the heavy crude oil viscosity reduction and formation damage commonly found in the petroleum industry.

## **Acknowledgements**

The authors express gratitude to the Instituto Mexicano del Petróleo (IMP) for both providing the research facilities and granting permission to publish these results. L.A.A.-V. thanks both the IMP for the postdoctoral fellowship granted to conduct the research presented in this work and the Dirección de Cátedras CONACYT for the financial support provided during the writing of this chapter. This work was supported by the IMP Projects D.00509, H.61003 and Y. 00123 and CONACYT-SENER-HIDROCARBUROS Fund (Project 146735).

## **Author details**

Luis A. Alcázar-Vara1\*, Luis S. Zamudio-Rivera2 and Eduardo Buenrostro-González2

\*Address all correspondence to: luis.alcazar.v@gmail.com

1 CONACYT—Mexican Institute of Petroleum (IMP), Mexico, Mexico

2 Mexican Institute of Petroleum (IMP), Mexico, Mexico

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The authors express gratitude to the Instituto Mexicano del Petróleo (IMP) for both providing the research facilities and granting permission to publish these results. L.A.A.-V. thanks both the IMP for the postdoctoral fellowship granted to conduct the research presented in this work and the Dirección de Cátedras CONACYT for the financial support provided during the writing of this chapter. This work was supported by the IMP Projects D.00509, H.61003 and Y.

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Decker, 1999.


#### **Microbial Enhanced Oil Recovery Microbial Enhanced Oil Recovery**

Aliya Yernazarova, Gulzhan Kayirmanova, Almagul Baubekova and Azhar Zhubanova Aliya Yernazarova, Gulzhan Kayirmanova, Almagul Baubekova and Azhar Zhubanova

Additional information is available at the end of the chapter Additional information is available at the end of the chapter

http://dx.doi.org/10.5772/64805

#### **Abstract**

The ever-rising global demand for energy and the issue of large volumes of unrecovered oil after primary and secondary oil production operations are driving the development and/or advancement of enhanced oil recovery (EOR) techniques. Conventional EOR processes include thermal, immiscible and miscible gas injection, chemical, and microbial enhanced oil recovery (MEOR), among others. This chapter provides an overview of MEOR including its history, strata microflora, mechanisms of MEOR for oil recovery, and a brief recount of field MEOR applications.

**Keywords:** microbial enhanced oil recovery, MEOR, microorganisms, strata microflora, biosurfactants, oil reservoirs

## **1. Introduction**

The necessity of improving and/or advancing the current enhanced oil recovery (EOR) processes to make them more efficient has attracted the attention of researchers and oil field operators. Thus, over the last few decades, this problem has received constant attention resulting in slow but steady growth of the average oil recovery factors. For instance, at present the worldwide average recovery rate is about 30%, whereas in the USA, the average oil recovery factor is 39%. However, many experts believe that in the foreseeable future the recovery factor may well reach 50–60% and even 70–80% [1].

The development of an oilfield refers to the process of displacing the accumulated liquid and gas hydrocarbons in the reservoir towards production wells. Oil is produced initially using the natural driving energy of the reservoir (i.e., primary recovery operations), or by introduc-

ing energy into the reservoir during secondary oil recovery (i.e., waterflooding or gas flooding), as soon as the natural reservoir energy is depleted.

Particularly, in Kazakhstan most of the hydrocarbon deposits have already been discovered and commercially produced. Currently, fewer and fewer drilling sites in those mature reservoirs are of interest from the commercial standpoint. In this regard, the residual oil left behind in these mature hydrocarbon deposits after primary and secondary oil recovery offers an opportunity for the implementation of EOR processes, including the application of microbial enhanced oil recovery (MEOR) technology.

## **2. Review on MEOR**

#### **2.1. History of MEOR**

In 1926, J. W. Beckman [2] came to the conclusion that it was necessary to develop additional methods to augment oil recovery beyond primary and secondary oil recovery processes. Therefore, he proposed the utilization of microorganisms as one of the solutions to the oil recovery issue. Later on, the use of microorganisms for oil recovery enhancement was patented by C. E. ZoBell in 1946 [3], since then, the MEOR process has been validated by numerous studies and successful fields tests, the first of them carried out in Arkansas, USA, in 1954 [4].

Since the 1970s, intense research efforts on MEOR have been made in the USA, USSR, Czechoslovakia, Hungary, and Poland. The oil crisis in the 1970s further aroused the interest in MEOR research in more than 15 countries. For instance, in 1976, the Soviet Government enacted a special regulation "…concerning measures on achieving the most efficient oil recovery processes." This regulation defined the target volumes of additional oil recovery that were required using tertiary enhancement methods and provided economic incentives to encourage oil-production enterprises [5].

Since year 1970 until the 2000s, microbial ecology and deposit characterization were the focus of MEOR research. By 1990, MEOR reached interdisciplinary technological status. In 2007, a review of 322 MEOR projects in USA showed that 78% of the total number of projects were successful in enhancing oil recovery; while no cases of lowered oil recovery were revealed [6]. At present, there is a grown interest in the application of MEOR to enhance oil production from depleted reservoirs, because its low capital cost and environmental friendliness.

MEOR mechanisms are the same mechanisms obtained from other chemical enhanced oil recovery (EOR) methods; however, MEOR presents the advantage that microbial metabolites are directly produced in the reservoir rock formation, which makes them more effective. Furthermore, microorganisms metabolize different hydrocarbons at different rates [6].

**Figure 1** presents a breakdown of the worldwide recoverable petroleum reserves by type and region prepared by Meyer and Attanasi [7] and Schmitt [8].

**Figure 1.** World's current recoverable petroleum reserves by oil type and region in billions of barrels. From Meyer and Attanasi [7] and Schmitt [8].

Worldwide accumulations of heavy oil and bitumen are about five times higher than the reserves of light conventional oils. For instance, heavy oil resources are an essential part of the oil industry in Kazakhstan as well as in a number of other oil-producing countries.

The largest reserves of bitumen and heavy oil are located in Canada and Venezuela; while significant reserves are also found in Mexico, the United States, Russia, Kuwait, and China [9].

Kazakhstan is currently experiencing a period of late-stage development. Oil fields under waterflooding have reached a high water cut ranging from 80 to 90%, while a large volume of undeveloped oil reserves (up to 60–-70%) are located in deep oil reservoir formations. In addition, most deposits of Kazakhstan are characterized by high viscosity oils and complex geological structures [10].

#### **2.2. MEOR: Challenges and Opportunities**

ing energy into the reservoir during secondary oil recovery (i.e., waterflooding or gas flooding),

Particularly, in Kazakhstan most of the hydrocarbon deposits have already been discovered and commercially produced. Currently, fewer and fewer drilling sites in those mature reservoirs are of interest from the commercial standpoint. In this regard, the residual oil left behind in these mature hydrocarbon deposits after primary and secondary oil recovery offers an opportunity for the implementation of EOR processes, including the application of

In 1926, J. W. Beckman [2] came to the conclusion that it was necessary to develop additional methods to augment oil recovery beyond primary and secondary oil recovery processes. Therefore, he proposed the utilization of microorganisms as one of the solutions to the oil recovery issue. Later on, the use of microorganisms for oil recovery enhancement was patented by C. E. ZoBell in 1946 [3], since then, the MEOR process has been validated by numerous studies and successful fields tests, the first of them carried out in Arkansas, USA, in

Since the 1970s, intense research efforts on MEOR have been made in the USA, USSR, Czechoslovakia, Hungary, and Poland. The oil crisis in the 1970s further aroused the interest in MEOR research in more than 15 countries. For instance, in 1976, the Soviet Government enacted a special regulation "…concerning measures on achieving the most efficient oil recovery processes." This regulation defined the target volumes of additional oil recovery that were required using tertiary enhancement methods and provided economic incentives to encourage

Since year 1970 until the 2000s, microbial ecology and deposit characterization were the focus of MEOR research. By 1990, MEOR reached interdisciplinary technological status. In 2007, a review of 322 MEOR projects in USA showed that 78% of the total number of projects were successful in enhancing oil recovery; while no cases of lowered oil recovery were revealed [6]. At present, there is a grown interest in the application of MEOR to enhance oil production

MEOR mechanisms are the same mechanisms obtained from other chemical enhanced oil recovery (EOR) methods; however, MEOR presents the advantage that microbial metabolites are directly produced in the reservoir rock formation, which makes them more effective. Furthermore, microorganisms metabolize different hydrocarbons at different rates [6].

**Figure 1** presents a breakdown of the worldwide recoverable petroleum reserves by type and

region prepared by Meyer and Attanasi [7] and Schmitt [8].

from depleted reservoirs, because its low capital cost and environmental friendliness.

as soon as the natural reservoir energy is depleted.

148 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

microbial enhanced oil recovery (MEOR) technology.

**2. Review on MEOR**

oil-production enterprises [5].

**2.1. History of MEOR**

1954 [4].

Primary and secondary oil recovery processes achieve on a worldwide basis an average recovery of 33% of the original oil in place (OOIP); while the unrecovered oil (67%) might be retained in the reservoir by viscous and/or capillary forces. Conventional chemicals, such as solvents and surface-active compounds (surfactants) are used during chemical EOR applications. Solvents reduce the oil viscosity to improve the oil mobility by overcoming viscous forces; while surfactants reduce the interfacial tension between oil and rock or oil and water overcoming capillary forces. These chemicals are added to the injection water and transported within the reservoir during water flooding, however, the chemicals reach only the places where oil has already been displaced by water; furthermore, the chemicals could be partially consumed and/or retained within the rock formation before they reach the target area in the reservoir for their intended use [6].

The injection of solvents and surfactants into some reservoirs have yield unsatisfactory results because the chemicals failed to contact the residual oil for the required time period, which is needed to achieve a long-term effect. Another problem is the natural heterogeneity of the reservoirs; therefore, the injected chemicals inevitably flow along the paths of least resistance (i.e., high permeability zones, natural fractures, etc.) where the saturation of residual oil is usually the lowest.

It has been known for decades that specifically selected microorganisms are capable of metabolizing hydrocarbons producing organic solvents, such as alcohols, aldehydes, surfaceactive fatty acids, and other metabolites which can interact with the crude oil improving its fluidity. Other oil production issues such as the presence of paraffin, emulsions, and corrosion problems can also be controlled using microorganisms. For instance, extensive research has been conducted on the use of biosurfactants (BS) for enhanced oil recovery applications [11– 14].

Prior to the application of MEOR technologies, the projects are assessed to determine the compatibility of the crude oil and reservoir properties with MEOR taking into account the physicochemical properties of the crude oil, reservoir production performance, and reservoir properties (i.e., temperature). At the preliminary stage, reservoir fluid samples are collected and tested for compatibility with the MEOR systems. The first stage is the identification of the indigenous hydrocarbon-consuming bacteria, which is already adapted to the in situ reservoir conditions; after which the best action strategy for each project is designed and developed [4, 6].

MEOR can be applied on individual wells as follows: (1) from the well being treated or (2) from the target well and adjacent wells of the same reservoir. The MEOR solution is injected into adjacent wells in the same way as water is injected into the reservoir. The volume of the MEOR biomaterial to be injected is calculated based on the pore volume of the target reservoir. The solution is mixed and pumped through the injection well followed by the injection of water to drive the biological solution into the oil saturated zones. Then, the treated well is shut in for the required period of time (normally 24 h to 7 days) after which oil production is resumed. This procedure is repeated every 3–6 months to enable microorganisms to move deeper into the deposit to oil saturated zones [6].

Some of the general advantages of MEOR are outlined as follows:


In terms of the quality of the oil produced, some benefits are [9]:

**•** An increase of light alkanes <C20;

overcoming capillary forces. These chemicals are added to the injection water and transported within the reservoir during water flooding, however, the chemicals reach only the places where oil has already been displaced by water; furthermore, the chemicals could be partially consumed and/or retained within the rock formation before they reach the target area in

The injection of solvents and surfactants into some reservoirs have yield unsatisfactory results because the chemicals failed to contact the residual oil for the required time period, which is needed to achieve a long-term effect. Another problem is the natural heterogeneity of the reservoirs; therefore, the injected chemicals inevitably flow along the paths of least resistance (i.e., high permeability zones, natural fractures, etc.) where the saturation of residual oil is

It has been known for decades that specifically selected microorganisms are capable of metabolizing hydrocarbons producing organic solvents, such as alcohols, aldehydes, surfaceactive fatty acids, and other metabolites which can interact with the crude oil improving its fluidity. Other oil production issues such as the presence of paraffin, emulsions, and corrosion problems can also be controlled using microorganisms. For instance, extensive research has been conducted on the use of biosurfactants (BS) for enhanced oil recovery applications [11–

Prior to the application of MEOR technologies, the projects are assessed to determine the compatibility of the crude oil and reservoir properties with MEOR taking into account the physicochemical properties of the crude oil, reservoir production performance, and reservoir properties (i.e., temperature). At the preliminary stage, reservoir fluid samples are collected and tested for compatibility with the MEOR systems. The first stage is the identification of the indigenous hydrocarbon-consuming bacteria, which is already adapted to the in situ reservoir conditions; after which the best action strategy for each project is designed and developed [4,

MEOR can be applied on individual wells as follows: (1) from the well being treated or (2) from the target well and adjacent wells of the same reservoir. The MEOR solution is injected into adjacent wells in the same way as water is injected into the reservoir. The volume of the MEOR biomaterial to be injected is calculated based on the pore volume of the target reservoir. The solution is mixed and pumped through the injection well followed by the injection of water to drive the biological solution into the oil saturated zones. Then, the treated well is shut in for the required period of time (normally 24 h to 7 days) after which oil production is resumed. This procedure is repeated every 3–6 months to enable microorganisms to move deeper into

**•** Increase in the total oil produced and more efficient operation of wells and oil fields;

the reservoir for their intended use [6].

150 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

the deposit to oil saturated zones [6].

**•** Increase of the productivity of the oil fields [9];

Some of the general advantages of MEOR are outlined as follows:

usually the lowest.

14].

6].


MEOR methods can be divided into two main groups:


*In-situ* MEOR can be divided into two categories depending upon the method of injection of microorganisms and nutritional media (e.g., molasses, whey, and other waste food or chemical products) into the reservoir [17]. The first category consists in the *in-situ* stimulation of the natural indigenous microflora of the reservoir by means of injecting nutrients into the reservoir. The alternative (second category) is the injection of microbial cultures (exogenous or indigenous) along with nutrients; which is the preferred mode of application in the field. In any case, the development of these methods is impossible without the knowledge of the physicochemical and microbiological conditions in the oil bed. Oil recovery by water flooding is characterized at later stages by the formation of a mature biocenosis. The growth of this integrated microorganism community depends on the availability of nutrients.

The *in-situ* production of metabolites is carried out in two stages. First, water and oxygen are pumped into the formation as a water-air mixture containing mineral salts, nitrogen, and phosphorous to activate the indigenous microflora. In the presence of water and air, aerobic bacteria oxidize hydrocarbons producing low molecular weight organic acids (acetic, propionic, butyric, etc.), alcohols (methanol and ethanol), biosurfactants, and carbon dioxide, which increase the pressure in the reservoir [18–20].

In the second step, oxygen-free water is injected into the reservoir to activate anaerobic indigenous bacteria that metabolize crude oil to acids, and gas (i.e., methane, carbon dioxide). The accumulation of these biogases increases the reservoir pressure. If the pressure in the reservoir is high enough, methane could be dissolved into the liquid hydrocarbon phase reducing its viscosity. Similarly, carbon dioxide could also reduce the oil viscosity if the pressure in the formation allows the miscibility of CO2 into the bulk oil phase. A reduction of the oil viscosity improves the oil-displacing properties through the reservoir increasing oil production [14]. Furthermore, CO2 could react with the minerals in the rock and dissolve carbonate increasing the permeability of the formation rock.

In the oil industry, MEOR has been applied for several uses besides enhanced oil recovery, such as well stimulation; remediation of oil spills in soil and ground water; and to clean borehole, down hole equipment, and piping, among others.

#### **2.3. MEOR process components**

The MEOR process consists of two essential components: hydrocarbon-consuming microorganisms and a nutritional medium as the source of nitrogen and phosphorus. Hydrocarbonconsuming microorganisms can be exogenous or indigenous. Indigenous are isolated for characterization from the hydrocarbon deposit where they will be employed.

The use of industrial byproducts as nutritional media such as molasses [21–24], corn steep liquor [25], and cheese whey [24] has been documented. The injection of nitrate aqueous solution at a concentration of 1.5 g/l of injected water has been recommended to suppress the activity of sulfate-reducing bacteria [22]. Reduction of the cost of nutrients during the application of MEOR processes can be achieved by injecting only nitrogen and phosphorous sources. Nitrogen is an essential nutrient for bacterial growth. Likewise, phosphorous is another key nutrient. If phosphorous nutrients are lacking, microbial cells cannot synthesize enough ATP for their metabolic activity [26].

#### **2.4. Reservoir microflora**

Microbial communities in oil rock formations are dated as the Earth's most ancient biocenoses, which sank to great depths along with organic residues and biogenic sludge.

Numerous varieties of microorganisms have been isolated and detected from different oil reservoirs such as sulfate and sulfur reducers hydrogenotrophic and heterotrophic methanogens [27–30], fermentative bacteria [31, 32], hydrocarbon and oil-oxidizing bacteria [19, 33], iron and manganese reducing microbes [34].

The presence of indigenous microflora and exogenous microorganisms in water and oilbearing deposits has been demonstrated [3]. Exogenous microorganisms have been introduced into the reservoirs during drilling and flooding (i.e., secondary and tertiary oil recovery) operations. In the absence of molecular oxygen (i.e., absence of a terminal electron acceptor), microbial hydrocarbon decomposition is possible through anaerobic respiration using nitrate, iron oxide, carbon dioxide, or sulfate. Interspecific electron transfer is also possible with methanogenic or sulfate reducing bacteria as biological acceptors. In oil strata with temperatures between 20 and 80°C, there are complex microbial communities made up by fermentative bacteria and methanogens that can oxidize hydrocarbons and reduce sulfur, sulfate, and iron. The microbial count in high temperature oil reservoirs is low.

The *in-situ* production of metabolites is carried out in two stages. First, water and oxygen are pumped into the formation as a water-air mixture containing mineral salts, nitrogen, and phosphorous to activate the indigenous microflora. In the presence of water and air, aerobic bacteria oxidize hydrocarbons producing low molecular weight organic acids (acetic, propionic, butyric, etc.), alcohols (methanol and ethanol), biosurfactants, and carbon dioxide,

In the second step, oxygen-free water is injected into the reservoir to activate anaerobic indigenous bacteria that metabolize crude oil to acids, and gas (i.e., methane, carbon dioxide). The accumulation of these biogases increases the reservoir pressure. If the pressure in the reservoir is high enough, methane could be dissolved into the liquid hydrocarbon phase reducing its viscosity. Similarly, carbon dioxide could also reduce the oil viscosity if the pressure in the formation allows the miscibility of CO2 into the bulk oil phase. A reduction of the oil viscosity improves the oil-displacing properties through the reservoir increasing oil production [14]. Furthermore, CO2 could react with the minerals in the rock and dissolve

In the oil industry, MEOR has been applied for several uses besides enhanced oil recovery, such as well stimulation; remediation of oil spills in soil and ground water; and to clean

The MEOR process consists of two essential components: hydrocarbon-consuming microorganisms and a nutritional medium as the source of nitrogen and phosphorus. Hydrocarbonconsuming microorganisms can be exogenous or indigenous. Indigenous are isolated for

The use of industrial byproducts as nutritional media such as molasses [21–24], corn steep liquor [25], and cheese whey [24] has been documented. The injection of nitrate aqueous solution at a concentration of 1.5 g/l of injected water has been recommended to suppress the activity of sulfate-reducing bacteria [22]. Reduction of the cost of nutrients during the application of MEOR processes can be achieved by injecting only nitrogen and phosphorous sources. Nitrogen is an essential nutrient for bacterial growth. Likewise, phosphorous is another key nutrient. If phosphorous nutrients are lacking, microbial cells cannot synthesize

Microbial communities in oil rock formations are dated as the Earth's most ancient biocenoses,

Numerous varieties of microorganisms have been isolated and detected from different oil reservoirs such as sulfate and sulfur reducers hydrogenotrophic and heterotrophic methanogens [27–30], fermentative bacteria [31, 32], hydrocarbon and oil-oxidizing bacteria [19, 33],

characterization from the hydrocarbon deposit where they will be employed.

which sank to great depths along with organic residues and biogenic sludge.

which increase the pressure in the reservoir [18–20].

152 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

carbonate increasing the permeability of the formation rock.

borehole, down hole equipment, and piping, among others.

**2.3. MEOR process components**

enough ATP for their metabolic activity [26].

iron and manganese reducing microbes [34].

**2.4. Reservoir microflora**

The studies of microbial communities conducted on samples of formation water from the Zhetybay and Kulsary oil fields located in Western Kazakhstan gave total aerobic counts of 1.8 106 and 25.1 106 cells/ml, respectively. The number of aerobic microorganisms present in the water samples from the Zhetybay field is lower than the bacterial count from the Kulsary field by an order of magnitude. While the count of anaerobes is 0.38 105 cells/ml for the Zhetybay field sample and 0.5 102 cells/ml for the Kulsary field. These observations correlate well with the respective depth of each reservoir; the water samples from the Kulsary field were collected at a depth of 250 m; while the water samples of the Zhetybay field were collected at a depth of 1900 m, therefore it is expected that at deeper reservoirs conditions (i.e., Zhetybay field) anaerobic microorganism would adjust better. It has been reported that in deep water and oilbearing strata the total bacterial count is as high as 10 million cells/ml [35].

The effect of microorganisms is significant if they are numerous and physiologically active. An arbitrary threshold for bacteria is estimated at 1 million/1 g substrate since it is only in such quantities that they can have significant ecological impact. For each ecological factor (temperature, amount of nutrients, concentration of microcells, and trace elements), there are optimum values which favor the growth of an organism and the extreme values at which growth is suppressed. At values close to the extremes of the preferred range for a given organism, its survival is still possible though its growth is limited because the organism is under physical stress conditions. Microbiological studies on bacteria obtained from the Zhetybay and Kulsary hydrocarbon deposits show that aerobes play an important ecological role since they are found in large numbers and in physiologically active states [35].

Exogenous bacteria such as allochthonic bacteria are present in oil reservoirs, which were introduced during water injection creating a mixture of exogenous and indigenous microflora. At reservoir depths of 1–3 km, thermophilic microbial communities are found. These microbial communities are made up of microorganisms commonly found in deep reservoirs and bacteria normally encountered in shallow areas of the reservoirs (i.e., <1 km) but in lower numbers.

For instance, the Zhetybay and Kulsary oil reservoirs contain several groups of microorganisms including spore-forming bacteria, *Micromyce*tes, *Pseudomo*nas, *Bacil*lus, *Enterobacteriac*eae, with the most prevalent being the spore-forming bacteria whose counts reach 0.12 105 cells/ml [35].

Total bacterial counts and the abundance of certain groups of aerobic and anaerobic bacteria are remarkably lower in oil reservoirs than the count of bacteria determined in the water used during waterflooding. The reason is that not all microorganisms survive extreme reservoir oil conditions. Some bacteria may be immobilized on the surface of the rocks lowering the number of bacteria in the liquid phase. Viable cells of methanogenic microorganisms have been found in reservoir fluids (i.e., formation brine) with salinity as high as 200 g/l, however, these and other microorganisms were also present in large numbers in substantially desalinated fluids [35].

Microbial community in oil reservoirs can be considered as closed and semiclosed systems, because they exist in an environment hindered from water exchange, which is characterized by a slow mass transfer at constant temperature in the absence of atmospheric air and sunlight. In this ecosystem, oil is the main source of energy for the microbial community. Molecular nitrogen and ammonium nitrogen are sufficient to meet the needs of the microflora. The phosphorus content is small, which limits the biogenic processes in this ecosystem. Therefore, microbiological processes proceed slowly due to low water exchange and lack of nutrients. The development of oil reservoirs by water injection introduces dissolved oxygen into the system that activates microbiological processes and as result oil biodegrades [36].

Aerobic microorganisms have been found in formations with temperatures ranging from 20 to 70°C and pH ranging from 6.0 to 8.4. Some of these aerobic bacteria have been identified as *Rhodococcus ruber, Arthrobacter oxydans, Kocuria rosea, Gordonia rubropertincta, Cellulomonas cellulans, Bacillus subtilis, B. cereus, Pseudomonas fluorescens* [14, 22, 37–40]. Thermophilic microorganisms can grow at oil reservoir temperatures ranging from 40 to 70°C, at pH ranging from 6.0 to 7.8, and salinity concentrations from 0 to 5% NaCl. In high temperature oil reservoirs, hydrocarbon-oxidizing bacteria are a common component of the biocenoses in the bottom-hole areas of the water injection wells through which dissolved oxygen enters the stratum. Hydrocarbon-oxidizing bacteria found in these locations are often spore-forming, which allows survival in extreme environmental conditions [35].

Wang et al. isolated three thermophilic hydrocarbon-degrading species, such as *Bacillus* sp., *Geobacillus* sp., and *Petrobacter* sp. that could tolerate 55°C of temperature [41].

Thermophilic bacteria were isolated from a reservoir, located at Maracaibo Lake, Venezuela, which has temperatures ranging from 60 to 80°C and pressures ranging from 1200 to 1500 psi [42]. Moderately, thermophilic spore-forming sulfate-reducing bacteria (*Desulfotomaculum* and *Bacillus*) have been identified in the Zhetybay high temperature oil field in Kazakhstan [35].

The anaerobic microflora present in oil reservoirs are commonly bacteria of the genera *Bacteroides, Clostridium, Thermoanaerobacter, Thermococcus, Thermotogales* [43], *Petrotoga* [44], *Thermotoga* [45], *Desulfotomaculum* [46], *Caminicella* [47], *Geosporobacter* [48]. Screening for microbial consortia from some Omani oil wells by Al-Bahry et al. [49] showed a total of 30 genera and 69 species of microorganisms. In this study, most of the detected genera were found to be anaerobic, thermophilic, and halophilic and some of them were documented to be suitable candidates for MEOR.

#### **2.5. MEOR oil recovery mechanisms**

Total bacterial counts and the abundance of certain groups of aerobic and anaerobic bacteria are remarkably lower in oil reservoirs than the count of bacteria determined in the water used during waterflooding. The reason is that not all microorganisms survive extreme reservoir oil conditions. Some bacteria may be immobilized on the surface of the rocks lowering the number of bacteria in the liquid phase. Viable cells of methanogenic microorganisms have been found in reservoir fluids (i.e., formation brine) with salinity as high as 200 g/l, however, these and other microorganisms were also present in large numbers in substantially desalinated fluids

Microbial community in oil reservoirs can be considered as closed and semiclosed systems, because they exist in an environment hindered from water exchange, which is characterized by a slow mass transfer at constant temperature in the absence of atmospheric air and sunlight. In this ecosystem, oil is the main source of energy for the microbial community. Molecular nitrogen and ammonium nitrogen are sufficient to meet the needs of the microflora. The phosphorus content is small, which limits the biogenic processes in this ecosystem. Therefore, microbiological processes proceed slowly due to low water exchange and lack of nutrients. The development of oil reservoirs by water injection introduces dissolved oxygen into the

Aerobic microorganisms have been found in formations with temperatures ranging from 20 to 70°C and pH ranging from 6.0 to 8.4. Some of these aerobic bacteria have been identified as *Rhodococcus ruber, Arthrobacter oxydans, Kocuria rosea, Gordonia rubropertincta, Cellulomonas cellulans, Bacillus subtilis, B. cereus, Pseudomonas fluorescens* [14, 22, 37–40]. Thermophilic microorganisms can grow at oil reservoir temperatures ranging from 40 to 70°C, at pH ranging from 6.0 to 7.8, and salinity concentrations from 0 to 5% NaCl. In high temperature oil reservoirs, hydrocarbon-oxidizing bacteria are a common component of the biocenoses in the bottom-hole areas of the water injection wells through which dissolved oxygen enters the stratum. Hydrocarbon-oxidizing bacteria found in these locations are often spore-forming,

Wang et al. isolated three thermophilic hydrocarbon-degrading species, such as *Bacillus* sp.,

Thermophilic bacteria were isolated from a reservoir, located at Maracaibo Lake, Venezuela, which has temperatures ranging from 60 to 80°C and pressures ranging from 1200 to 1500 psi [42]. Moderately, thermophilic spore-forming sulfate-reducing bacteria (*Desulfotomaculum* and *Bacillus*) have been identified in the Zhetybay high temperature oil field in Kazakhstan [35].

The anaerobic microflora present in oil reservoirs are commonly bacteria of the genera *Bacteroides, Clostridium, Thermoanaerobacter, Thermococcus, Thermotogales* [43], *Petrotoga* [44], *Thermotoga* [45], *Desulfotomaculum* [46], *Caminicella* [47], *Geosporobacter* [48]. Screening for microbial consortia from some Omani oil wells by Al-Bahry et al. [49] showed a total of 30 genera and 69 species of microorganisms. In this study, most of the detected genera were found to be anaerobic, thermophilic, and halophilic and some of them were documented to

*Geobacillus* sp., and *Petrobacter* sp. that could tolerate 55°C of temperature [41].

system that activates microbiological processes and as result oil biodegrades [36].

which allows survival in extreme environmental conditions [35].

be suitable candidates for MEOR.

[35].

154 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

During the MEOR process, the components are mixed at surface facilities and injected into the oil reservoir. Inside the reservoir, MEOR-bacteria are transported by the injected water and accumulate in porous zones at the oil/rock and oil/water interfaces. Bacteria utilize very small amounts of oil and produce metabolites such as solvents, surfactants, acids, and carbon dioxide. These bioproducts interact with the oil in the reservoir to reduce the oil viscosity, interface tension at the oil/rock and oil/water interfaces, improve rock permeability by removing paraffin, mud, and other debris that plug the porous media [15, 50]. Microbial cells are continuously generated as well as the *in-situ* production of metabolites. The prolong interaction of metabolites with the oil in the reservoir, changes the oil properties in such a way that immobile unrecoverable oil is converted into movable oil that can flow to the production wells increasing oil output accordingly.

Microbial degradation of oil, which is a complex chemical compound, is the result of cometabolism of microorganisms where the metabolism's products of the hydrocarbon-oxidizing bacteria serve as the substrate for other physiological groups in the reservoir. Hydrocarbons are decomposed to produce fatty acids that can be utilized by other microorganisms [51].

The main mechanisms acting on oil recovery by MEOR are summarized as follows:


One of the most important functionalities of oil-oxidizing microorganisms is their capability of using hydrocarbons to produce biosurfactants, which emulsify hydrocarbons. The hydrocarbon-oxidizing microorganism's strains that are very active in producing biosurfactants are: *Pseudomonas aeruginosa, Bacillus subtilis, Mycobacterium rhodochrous, Rhodococcus erythropolis, Candida lipolytica*, and *Torulopsis gropengiesseri*. Microorganisms belonging to different genera have the ability to metabolize hydrocarbons including more than 300 fungal, bacterial, yeast, and actinomycetes strains. The hydrocarbon-oxidizing ability is quite common in bacteria belonging to the genera *Mycobacterium, Rhodococcus, Pseudomonas, Micrococcus*, and *Bacillus*. In fungi and yeast-like organisms, this faculty is often found in nonsporogenic *Candida, Trichosporon*, and *Exophialia*. The vast majority of *Rhodotorula* species is also capable of oxidizing hydrocarbons [65–69].

The implementation of MEOR requires low capital investment; while it offers high efficiency, and environmental friendliness. The initial phase of the MEOR process is the partial oxidation of residual oil in the bottom-hole area that yields bioproducts such as carbon dioxide, lowmolecular-weight fatty acids, and other organic compounds. Further, when these bioproducts are transported by the injected water into the anaerobic zones of the reservoir, methanogenic microorganisms are activated. Production of methane is important because this is an easily extractible gas that can be dissolved into the oil phase (i.e., if the reservoir pressure is high enough) improving the oil mobility [70].

During waterflooding, dissolved oxygen in the water is delivered to the strata. This oxygen is rapidly consumed at the bottom-hole area during the microbial oxidation of residual oil, which causes the stimulation of anaerobic bacteria, particularly, methanogens, in the oxygen-free zone of the stratum [70]. The number of aerobic hydrocarbon-oxidizing and oligocarbophilic bacteria grows to a less extent, however, at the same time the content of anaerobic metabolism products in oil formation waters increases significantly. During this process, carbonate and sulfate content increases.

Foam-forming organic substances that reduce the interfacial tension at the oil/water interface by a factor of 100 have been identified to be caused by microbiological oil oxidation products in the bottom-hole area [71].

Oil recovery by waterflooding can be viewed as a natural fermenter, where continuous microbial cultures could be maintained. These microbial cultures could be activated by the injection of microorganisms and nutritional medium components. In this case, residual oil serves as the main substrate for microorganisms; while in the bottom-hole area, a specific microbial community is formed whose activity can be regulated [71].

The temperature of the oil reservoirs determines the types of microbial communities. In the bottom-hole areas of the injection wells, the temperature corresponds to the temperature of the injected water. In high temperature reservoirs, as is the case of the Zhetybay oil field, cold water is injected, therefore mesophilic bacteria prevail at these conditions compared to the thermophilic communities of the Uzen oil field in Kazakhstan, where hot water is injected [71].

The implementation of MEOR starts with the addition of biological materials to the injection water. Microorganisms enter the reservoir mixed with the injected water through the existing flooding system without affecting the injection rate or pressure. The implementation of MEOR process requires very small modifications, if any, to the existing water injection equipment, so that the flooding process is not interrupted [6].

After the implementation of the MEOR project, it is continuously monitored through bacteria population growth and the oil output rate within certain period of time. The hydrocarbonoxidizing bacteria population is kept under continuous surveillance after the injection of MEOR fluids. The population size is compared to that of the indigenous hydrocarbonoxidizing bacteria before the beginning of the process. Normally, such population starts to grow slowly. In addition, the fluids produced are also monitored for the presence of hydrocarbon-oxidizing bacteria in order to assess how far the microorganisms have moved into the reservoir after injection [6].

#### **2.6. Field tests applications of MEOR**

of residual oil in the bottom-hole area that yields bioproducts such as carbon dioxide, lowmolecular-weight fatty acids, and other organic compounds. Further, when these bioproducts are transported by the injected water into the anaerobic zones of the reservoir, methanogenic microorganisms are activated. Production of methane is important because this is an easily extractible gas that can be dissolved into the oil phase (i.e., if the reservoir pressure is high

During waterflooding, dissolved oxygen in the water is delivered to the strata. This oxygen is rapidly consumed at the bottom-hole area during the microbial oxidation of residual oil, which causes the stimulation of anaerobic bacteria, particularly, methanogens, in the oxygen-free zone of the stratum [70]. The number of aerobic hydrocarbon-oxidizing and oligocarbophilic bacteria grows to a less extent, however, at the same time the content of anaerobic metabolism products in oil formation waters increases significantly. During this process, carbonate and

Foam-forming organic substances that reduce the interfacial tension at the oil/water interface by a factor of 100 have been identified to be caused by microbiological oil oxidation products

Oil recovery by waterflooding can be viewed as a natural fermenter, where continuous microbial cultures could be maintained. These microbial cultures could be activated by the injection of microorganisms and nutritional medium components. In this case, residual oil serves as the main substrate for microorganisms; while in the bottom-hole area, a specific

The temperature of the oil reservoirs determines the types of microbial communities. In the bottom-hole areas of the injection wells, the temperature corresponds to the temperature of the injected water. In high temperature reservoirs, as is the case of the Zhetybay oil field, cold water is injected, therefore mesophilic bacteria prevail at these conditions compared to the thermophilic communities of the Uzen oil field in Kazakhstan, where hot water is injected [71].

The implementation of MEOR starts with the addition of biological materials to the injection water. Microorganisms enter the reservoir mixed with the injected water through the existing flooding system without affecting the injection rate or pressure. The implementation of MEOR process requires very small modifications, if any, to the existing water injection equipment, so

After the implementation of the MEOR project, it is continuously monitored through bacteria population growth and the oil output rate within certain period of time. The hydrocarbonoxidizing bacteria population is kept under continuous surveillance after the injection of MEOR fluids. The population size is compared to that of the indigenous hydrocarbonoxidizing bacteria before the beginning of the process. Normally, such population starts to grow slowly. In addition, the fluids produced are also monitored for the presence of hydrocarbon-oxidizing bacteria in order to assess how far the microorganisms have moved into the

microbial community is formed whose activity can be regulated [71].

that the flooding process is not interrupted [6].

reservoir after injection [6].

enough) improving the oil mobility [70].

156 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

sulfate content increases.

in the bottom-hole area [71].

There is extensive MEOR published literature on laboratory research data and pilot field trials. Although at present widespread commercial use of the MEOR technology has not taken place yet.

Biotechnological methods for increasing oil recovery have to solve a number of practical problems [72], which are summarized as follows:


Maudgalya et al. [73] reviewed 407 MEOR field trials worldwide. The field trials were classified according to the following parameters: reservoirs' lithology and properties, microorganisms, nutrients, type of test, and type of recovery mechanism. From the total 407 field trials, 333 field trials were applied following the well stimulation method, 26 of the trials were conducted using the waterflooding and 44 field trials were conducted as single well (huff-puff scheme) applications; while details of the application method for the remaining four field trials were not provided. This survey indicated that the primary mechanisms for MEOR were permeability profile modification, increase of capillary number (i.e., biosurfactants, alcohols, biopolymers, and acids), biodegradation of heavy crude oil components making the oil less viscous, and the swelling of the oil due to the absorption of biogas (i.e., CO2 and CH4) within the bulk oil phase.

Careful review of the common characteristics and results observed from these 407 MEOR field trials indicate that successful field trials were obtained at the following conditions:


The Activated Environment for Recovery Optimization (AERO) technology has been developed for improving waterflood performance. The AERO system is a microbial process designed to increase oil recovery during waterflooding by the following mechanisms: improved sweep efficiency due to microdiversion of fluid pathways at the pore level, interfacial tension reduction, and residual oil mobilization (i.e., biosurfactants). This technology has been successfully implemented by Statoil offshore Norway and in the Stirrup field in southwest Kansas, USA. Highlights of this technology are minimum to none capital investment with very low risk for implementation and high performance efficiency at low operational costs [74].

Research conducted to establish the potential for MEOR application at the heavy oil Schrader Bluff formation on the North Slope of Alaska indicated that the viable mechanisms for driving incremental heavy oil recovery are:


This study also demonstrated that the most important criteria for selecting a reservoir for MEOR applications are the reservoir temperature and formation brine salinity, which must favor bacterial growth. Furthermore, an effective MEOR application depends on the optimal use of the appropriate microbes and nutrients and their proper application in the reservoir [75].

DuPont possesses a solid expertise in MEOR and considers it a low-risk and low-cost technology to produce incremental oil from mature fields. DuPont has established a set of reservoir criteria for its successful application as follows:


According to DuPont's experience, the main mechanisms for oil recovery are permeability modification due to the formation of a biofilm on the rock surface and wettability modification. Successful field trials conducted by DuPont indicate that oil recovery from mature fields can be increased up to 25% with a cost of \$10 per incremental barrel of oil. Furthermore, DuPont considers the MEOR technique to be more cost effective compared to other EOR processes, such as CO2 flooding or polymer flood [76].

A biopolymer, Schizophyllan, has been developed by Wintershall. The unique properties of this biopolymer are tolerance to high salinity (up to 19 wt%), tolerance to temperatures as high as 275°F, mechanical stability, and high viscosity. Therefore, the Schizophyllan biopolymer would make possible the application of polymer flooding in harsh reservoir environments. The main downside of this biopolymer is its susceptibility to bacterial degradation; however, this has been prevented by the addition of biocides. A pilot test has indicated that the performance of polymer flooding using this biopolymer has rendered oil recoveries ranging from 20 to 25 % higher than the oil recoveries expected from conventional waterflooding [77].

Successful MEOR application in a mature waterflooded reservoir in Saskatchewan, Canada has been reported [78]. This MEOR application consisted in the stimulation of indigenous bacteria through the injection of the appropriate nutrients. Production data obtained from this MEOR field application indicate higher oil production rates, incremental oil recovery, and decreased water cuts (up to 10%), which decreased operating costs due to reduced lifting and water treatment costs. In this field application, it was considered that the main MEOR mechanism was modification of the oil and water relative permeability driven by the interactions at the oil-water-microbes interface. Several benefits of this MEOR approach compare to other MEOR applications schemes and other EOR processes are as follows [78]:

**•** Low application costs;

**•** Bacteria species commonly used: anaerobic bacteria (i.e., *Clostridia*). The bacterium *Clostridium* showed to be effective in both sandstone and carbonate reservoirs. *Bacillus* (i.e., aerobic) species were also used or combination of them. The use of indigenous bacteria is strongly recommended because they only need the supply of nutrients and have a greater chance of

**•** Nutrient: the most common organic nutrient used was molasses; while phosphorus and

**•** Candidate fields most suitable for MEOR are waterflooded fields with relatively high oil

The Activated Environment for Recovery Optimization (AERO) technology has been developed for improving waterflood performance. The AERO system is a microbial process designed to increase oil recovery during waterflooding by the following mechanisms: improved sweep efficiency due to microdiversion of fluid pathways at the pore level, interfacial tension reduction, and residual oil mobilization (i.e., biosurfactants). This technology has been successfully implemented by Statoil offshore Norway and in the Stirrup field in southwest Kansas, USA. Highlights of this technology are minimum to none capital investment with very low risk for implementation and high performance efficiency at low operational costs [74].

Research conducted to establish the potential for MEOR application at the heavy oil Schrader Bluff formation on the North Slope of Alaska indicated that the viable mechanisms for driving

This study also demonstrated that the most important criteria for selecting a reservoir for MEOR applications are the reservoir temperature and formation brine salinity, which must favor bacterial growth. Furthermore, an effective MEOR application depends on the optimal use of the appropriate microbes and nutrients and their proper application in the reservoir [75].

DuPont possesses a solid expertise in MEOR and considers it a low-risk and low-cost technology to produce incremental oil from mature fields. DuPont has established a set of reservoir

**•** Reservoir permeability above 30 md to ensure the propagation of the microbes and nutrients

**•** Permeability modification causing improvement of reservoir conformance;

**•** Some reduction of the interfacial tension between oil and water.

growing at reservoir conditions, making the process less costly;

nitrogen fertilizers were the most common inorganic nutrients;

**•** Oil saturation: ranging between 45 and 70%;

158 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

saturations [73].

incremental heavy oil recovery are:

criteria for its successful application as follows:

**•** Moderate salinity levels up to 100,000 ppm;

**•** The reservoir must be under a waterflooding recovery.

**•** Reservoir temperatures <160°F;

deep into the reservoir;

**•** Wettability alteration;


Numerical modeling has been used to attempt the quantitative prediction of the performance of the MEOR process [73]. A study conducted by Eduarda et al. [79] in which a finite difference method was applied, indicated that appropriate bacterial growth within the reservoir is the determining variable affecting the oil recovery factor.

## **3. Conclusion**

MEOR technology makes use of special indigenous or exogenous microbial strains and nutrients that are injected into the reservoir to enhance oil production. The metabolic action of the injected exogenous microbial strains and the indigenous reservoir microflora produce metabolites such as gases, alcohols, and surface active compounds (biosurfactants) that interact with the crude oil. Biogases provide additional reservoir driving pressure; while bioalcohols and biosurfactants reduce oil viscosity and surface tension between oil-water and oil-rock, respectively. Under the effect of metabolites, the crude oil flowing properties are modified causing its release and mobilization toward the production wells enhancing the oil flow output.

The following metabolites interact with the crude oil changing its physicochemical properties:


MEOR is an easy-to-use process which requires minimum, if any, upgrade of the existing process equipment and facilities. This process has the potential to recover oil reserves that otherwise would remain immobile and unrecoverable. This process overcomes natural and chemical barriers in oil deposits that hinder microbial growth. MEOR is safe and environmentally friendly that does not cause any threat to plants, animals, and humans.

## **Author details**

Aliya Yernazarova1,2\*, Gulzhan Kayirmanova1 , Almagul Baubekova1 and Azhar Zhubanova1


2 Institute of Ecology, Almaty, Kazakhstan

## **References**


[3] Zobell CE. Bacterial release of oil from oil-bearing materials. World Oil. 1947; 26:36–47.

the injected exogenous microbial strains and the indigenous reservoir microflora produce metabolites such as gases, alcohols, and surface active compounds (biosurfactants) that interact with the crude oil. Biogases provide additional reservoir driving pressure; while bioalcohols and biosurfactants reduce oil viscosity and surface tension between oil-water and oil-rock, respectively. Under the effect of metabolites, the crude oil flowing properties are modified causing its release and mobilization toward the production wells enhancing the oil

The following metabolites interact with the crude oil changing its physicochemical properties:

MEOR is an easy-to-use process which requires minimum, if any, upgrade of the existing process equipment and facilities. This process has the potential to recover oil reserves that otherwise would remain immobile and unrecoverable. This process overcomes natural and chemical barriers in oil deposits that hinder microbial growth. MEOR is safe and environ-

1 Department of Biotechnology, Al-Farabi Kazakh National University, Almaty, Kazakhstan

[1] Sandrea I, Sandrea R. Global oil reserves – recovery factors leave vast target for EOR

[2] Beckman JW. The action of bacteria on mineral oil. Industrial and Engineering Chem-

, Almagul Baubekova1

and Azhar Zhubanova1

**•** Solvents (i.e., acetone, aldehydes, low-molecular-weight alcohols, ketones, etc.);

mentally friendly that does not cause any threat to plants, animals, and humans.

**•** Organic acids (i.e., acetic, propionic, and butyric acids);

**•** Biopolymers (i.e., xanthan, scleroglucan, polysaccharides);

**•** Biosurfactants (i.e., rhamnolipid, surfactin);

160 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

Aliya Yernazarova1,2\*, Gulzhan Kayirmanova1

2 Institute of Ecology, Almaty, Kazakhstan

istry, News Edition. 1926;4:23–26.

\*Address all correspondence to: aliya.yernazarova@gmail.com

technologies. Oil and Gas Journal.2007;105(41):44–47.

**•** Biogases (i.e., methane, CO2, etc.).

flow output.

**•** Biomass (i.e., cell debris);

**Author details**

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**Electrorheology Technology**

#### **Application of Electrorheology to Improve Crude Oil Flowing Properties Through Pipeline Application of Electrorheology to Improve Crude Oil Flowing Properties Through Pipeline**

R. Tao R. Tao

Additional information is available at the end of the chapter Additional information is available at the end of the chapter

http://dx.doi.org/10.5772/64858

#### **Abstract**

This chapter describes a new technology based on electrorheology (ER) that simulta‐ neously reduces oil viscosity and suppresses flow turbulence. The application of a strong electric field in a small section of the oil pipeline causes the polarization of suspended particles contained in the oil phase aggregating them into short chains along the flow direction. This particle aggregation breaks the rotational symmetry and makes the oil viscosity anisotropic, which in turn reduces the oil viscosity along the flow direction. Simultaneously, oil viscosity increases in the direction perpendicular to the flow, which supresses flow turbulence. This green technology does not involve the addition of chemicals to the oil phase and is environmentally friendly. This approach is also energy efficient because it only targets the particles suspended in the oil phase causing the formation of aggregates. Furthermore, heat is not required to reduce the viscosity of the oil phase. Neutron scattering experiments and field tests demonstrate the effectiveness of this technology. Electrorheology will play an important role during enhanced heavy oil recovery and/or production operations and transportation via pipeline.

**Keywords:** electrorheology, crude oil viscosity, turbulence suppression, anisotropic viscosity, pipeline

## **1. Introduction**

Currently, hydrocarbons remain as the leading energy source. While the amount of conven‐ tional light crude oil becomes less and less available, heavy crude oils and offshore crude oils are becoming very important resources. The high viscosity of these hydrocarbons becomes a critical issue during oil recovery and/or production operations. This is also a problem for

© 2016 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited. © 2016 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

offshore crude oil production, which also shows very high viscosities because of the low temperatures (i.e. 1.5–1.6°C) of the reservoirs.

The flow of high viscosity oils through pipelines is very difficult, requiring much higher pumping power. This creates complications during oil production and transportation. Therefore, reducing the viscosity of the crude oil is paramount [1–4].

Although, there has been extensive research into this issue for more than 30 years, little progress has been achieved thus far. Currently, the dominant method to reduce the viscosity of heavy crude oil remains heating by the injection of steam and/or hot water. The application of these thermal processes requires time due to heat transfer issues. Furthermore, these processes are energy‐intensive and environmentally unfavorable (i.e. large volumes of CO2 emissions during the generation of steam). Moreover, the application of thermal methods for the recovery of offshore heavy crude oils is technically difficult and expensive.

Flow turbulence is an additional issue relevant here [5–9]. The efficient transportation of crude oil via pipelines requires the suppression of turbulence, because under turbulent flow regime, much more pumping energy is required.

**Figure 1.** (a) Laminar flow in pipeline. (b) Turbulent flow in pipeline.

Flow is laminar when the Reynolds number is (**Figure 1a**):

$$N\_{\mathbb{R}} = \rho \text{v}D / \eta \le 2300 \tag{1}$$

where *D* is the diameter of the pipeline, *v* is the average flow velocity, *ρ* is the oil density, and *η* is the oil viscosity. Equation (2) gives the friction factor for laminar flow:

$$f = 64 / N\_{\pi} \tag{2}$$

The pressure drop Δ*P* is as follows,

$$
\Delta P \,/\, L = \frac{1}{2} \rho \mathbf{v}^2 f \,/\, D = 32 \text{v} \eta \,/\, D^2 \tag{3}
$$

where *L* is the length of the pipeline.

Equation (4) gives the flow rate *Q* for laminar flow:

Application of Electrorheology to Improve Crude Oil Flowing Properties Through Pipeline http://dx.doi.org/10.5772/64858 173

$$\mathcal{Q} = \frac{\pi D^4}{128\eta} (\Delta P / L) \tag{4}$$

**Figure 1b** shows a turbulent flow inside a pipeline. Flow is turbulent when the Reynolds number is higher than 2300 (*N*R > 2300), which causes an erratic flow pattern in all directions, resulting in significant loss of energy. Therefore, the flow of fluids (i.e. heavy crude oil) under turbulent flow regime requires much more pumping power.

The friction factor for turbulent flow within 2300 *N*R < 100000 can be estimated by the Blasius equation [10] as follows,

$$f = 0.3164 \left( \left( N\_{\bar{\kappa}} \right)^{0.25} \right. \tag{5}$$

Equation (6) gives the flow rate for turbulent flow:

offshore crude oil production, which also shows very high viscosities because of the low

The flow of high viscosity oils through pipelines is very difficult, requiring much higher pumping power. This creates complications during oil production and transportation.

Although, there has been extensive research into this issue for more than 30 years, little progress has been achieved thus far. Currently, the dominant method to reduce the viscosity of heavy crude oil remains heating by the injection of steam and/or hot water. The application of these thermal processes requires time due to heat transfer issues. Furthermore, these processes are energy‐intensive and environmentally unfavorable (i.e. large volumes of CO2 emissions during the generation of steam). Moreover, the application of thermal methods for

Flow turbulence is an additional issue relevant here [5–9]. The efficient transportation of crude oil via pipelines requires the suppression of turbulence, because under turbulent flow regime,

> / 2300 *N vD <sup>R</sup>* = £ r

*η* is the oil viscosity. Equation (2) gives the friction factor for laminar flow:

 h

where *D* is the diameter of the pipeline, *v* is the average flow velocity, *ρ* is the oil density, and

1 2 2 <sup>2</sup> D= = *P L vf D v D* / / 32 / r

 h

(1)

64 / *<sup>R</sup> f N* = (2)

(3)

Therefore, reducing the viscosity of the crude oil is paramount [1–4].

the recovery of offshore heavy crude oils is technically difficult and expensive.

temperatures (i.e. 1.5–1.6°C) of the reservoirs.

172 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

much more pumping energy is required.

The pressure drop Δ*P* is as follows,

where *L* is the length of the pipeline.

Equation (4) gives the flow rate *Q* for laminar flow:

**Figure 1.** (a) Laminar flow in pipeline. (b) Turbulent flow in pipeline.

Flow is laminar when the Reynolds number is (**Figure 1a**):

$$Q = 2.2526 \frac{D^{19/7}}{\rho^{3/7} \eta^{1/7}} (\Delta P / L)^{4/7} \tag{6}$$

Equations (4) and (6) indicate that flow under laminar conditions is energetically more efficient than under turbulent conditions. For example, under laminar flow conditions, a 30% increase in the oil flow rate requires a 30% increase in pumping pressure; while under turbulent flow conditions, it requires a pressure increase of 58.3%; which means that the pump needs to provide 94.3% more power. Therefore, suppressing turbulence is crucial during oil transpor‐ tation by pipelines. For instance, a common practice in the field is to add drag‐reducing agents, DRA (i.e. chemical additives based on polymers) to the oil before pumping it through pipelines to suppress turbulence [11]. However, the addition of DRA agents increases the oil viscosity, and it has no effect on laminar flow.

The crucial and challenging issue is clear: the efficient transportation of oil through pipelines requires the simultaneous reduction of the oil viscosity and suppression of turbulence. These issues are not only crucial for the engineering field but also important for several other technical fields, because turbulence remains as one of the most important unsolved problems of classical physics [8].

Currently, conventional pipeline transportation methods cannot simultaneously and effec‐ tively reduce fluid (i.e. crude oil) viscosity and suppress turbulence. Thermal methods for crude oil viscosity reduction cannot suppress turbulence. As the temperature increases, the oil viscosity decreases, the Reynolds number increases, and as a result turbulence increases. Other conventional technologies to reduce oil viscosity, such as heavy oil dilution with solvents, cannot accomplish the simultaneous reduction of viscosity and suppression of turbulence, either.

An unconventional technology is required to solve these challenging issues. It is necessary to enhance oil flow output by simultaneously decreasing the oil viscosity along the flow direction, while increasing it in the direction perpendicular to the pipeline axis, because turbulence always starts from the vortices and expands perpendicular to the flow direction. In other words, oil viscosity must be anisotropic: reduced along the pipeline direction and increased in the direction perpendicular to the flow, which makes the flow regime laminar along the pipeline axis even if *N*R>> 2300.

This chapter describes the electrorheology (ER) technology, which provides an efficient solution for the simultaneous reduction of oil viscosity and suppression of turbulence during crude oil transportation via pipeline [2, 3, 9].

Crude oil is a liquid suspension, which depending on the chemical composition might contain particles suspended within the liquid hydrocarbon phase, such as asphaltenes, resins, fine sand particles, and wax particles. The application of a strong electric field in a small section of the pipeline causes the polarization of the suspended particles contained in the oil phase, aggregating them into short chains along the flow direction. This ER application is significantly different from traditional ER fluids, where the applied electric field is perpendicular to the flow direction, leading to increase the effective viscosity or even solidify the ER fluids [12]. Here the applied electric field and the aggregated chains are in the flow direction (**Figure 2**).

**Figure 2.** Aggregation of suspended particles into short chains under the influence of a local electric field.

Such aggregation breaks the rotational symmetry and makes the oil viscosity anisotropic, accomplishing two goals: the reduction of the viscosity along the flow direction and the substantial increase in the viscosity in the direction perpendicular to the flow. These viscosity changes supress all vortices and rotating motions; hence, turbulence is suppressed, which enhances the flow parallel to the pipeline horizontal axis. This green technology does not involve the application of chemical additives to the oil phase and is environmentally friendly. It is also energy efficient since it only aggregates the particles and does not heat the bulk of the oil phase. Neutron scattering experiments and field tests on pipelines fully support the theoretical approach of this technology. It is anticipated that electrorheology (ER) will play an important role during heavy crude oil recovery and/or production, enhanced oil recovery applications, and transportation through pipelines.

## **2. The New Technology (ER)**

An unconventional technology is required to solve these challenging issues. It is necessary to enhance oil flow output by simultaneously decreasing the oil viscosity along the flow direction, while increasing it in the direction perpendicular to the pipeline axis, because turbulence always starts from the vortices and expands perpendicular to the flow direction. In other words, oil viscosity must be anisotropic: reduced along the pipeline direction and increased in the direction perpendicular to the flow, which makes the flow regime laminar along the

This chapter describes the electrorheology (ER) technology, which provides an efficient solution for the simultaneous reduction of oil viscosity and suppression of turbulence during

Crude oil is a liquid suspension, which depending on the chemical composition might contain particles suspended within the liquid hydrocarbon phase, such as asphaltenes, resins, fine sand particles, and wax particles. The application of a strong electric field in a small section of the pipeline causes the polarization of the suspended particles contained in the oil phase, aggregating them into short chains along the flow direction. This ER application is significantly different from traditional ER fluids, where the applied electric field is perpendicular to the flow direction, leading to increase the effective viscosity or even solidify the ER fluids [12]. Here the applied electric field and the aggregated chains are in the flow direction (**Figure 2**).

**Figure 2.** Aggregation of suspended particles into short chains under the influence of a local electric field.

applications, and transportation through pipelines.

Such aggregation breaks the rotational symmetry and makes the oil viscosity anisotropic, accomplishing two goals: the reduction of the viscosity along the flow direction and the substantial increase in the viscosity in the direction perpendicular to the flow. These viscosity changes supress all vortices and rotating motions; hence, turbulence is suppressed, which enhances the flow parallel to the pipeline horizontal axis. This green technology does not involve the application of chemical additives to the oil phase and is environmentally friendly. It is also energy efficient since it only aggregates the particles and does not heat the bulk of the oil phase. Neutron scattering experiments and field tests on pipelines fully support the theoretical approach of this technology. It is anticipated that electrorheology (ER) will play an important role during heavy crude oil recovery and/or production, enhanced oil recovery

pipeline axis even if *N*R>> 2300.

crude oil transportation via pipeline [2, 3, 9].

174 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

Refined fractions of crude oil such as gasoline, kerosene, and diesel have very low viscosities and low dielectric constants. Paraffinic and heavier oils have higher viscosities because these oils contain randomly suspended paraffin, asphaltenes, resins, sulfur, and other solid com‐ pounds having large molecular weights. These suspended particles have higher dielectric constants that make them polarized in a strong electric field (**Figure 2**). Under the influence of a strong electric field, similar to conventional electrorheological fluids, these particles in crude oil form chains that aggregate into thick columns [12, 13, 15].

During the aggregation of dipoles into chains or chain‐based columns, the total energy *U*(*N*) of the system is negative making it energetically favorable. As the total number of particles, *N*, in the aggregated chain or column increases, the energy per particle *U*(*N*)*/N* is more negative. The probability to have such structure of *N* aggregated particles is proportional to exp[‐*U*(*N*)/*k*B*T*]. Therefore, an increase in *N* accelerates particle aggregation. The aggregated structure is more stable if it has more particles. For this reason, the formation of thick columns takes place in ER fluids under the application of an electric field.

In the ideal aggregated structure, all particles would aggregate into one thick column, body‐ centered tetragonal lattice [13, 14]. In reality, the aggregation process is very fast, and particle aggregation spontaneously spreads under the electric field leading to quick formation of many stable thick columns.

#### **2.1. Neutron scattering experiments**

Small‐angle neutron scattering is a useful technique to confirm the induced aggregation of solid particles contained in crude oil when subjected to a strong electric field [15].

The NG7 Small‐Angle Neutron Scattering or SANS facility, NCNR, is located in Gaithersburg, Maryland, USA. The SANS instrument is 30‐m long, and it is equipped with a high‐resolution

**Figure 3.** Neutron scattering experimental set‐up.

2D detector and focusing refractive lenses. The *Q*‐range of the instrument goes from 0.008 to 7.0 nm−1 to enable the detection of structural features in materials ranging from roughly 1 nm to over 500 nm.

As shown in **Figure 3**, the crude oil sample goes in a special capacitor, consisting of two pieces of cadmium electrodes and two pieces of quartz glass windows. The neutron beam passes through the quartz windows and through the crude oil sample into a detector. The application of a high voltage to the cadmium electrodes produces an electric field perpendicular to the neutron beam. Cadmium electrodes are suitable neutron absorbers, which reduces neutron scattering noise.

**Figure 4.** Scattering patterns at various electric fields obtained from a paraffin base crude oil. (a) *E* = 0 V/cm, (b) *E* = 2500 V/cm, (c) *E* = 4000 V/cm, (d) *E* = 7500 V/cm, (e) *E* = 11,000 V/cm, (f) *E* = 15,000 V/cm.

In this experimental work, the samples evaluated were a light paraffin base crude oil (API° 34) and a heavy asphalt base crude oil (API° 21). The test results have confirmed that under the influence of a strong electric field, the suspended particles from both the paraffin base crude and the asphalt base crude oil aggregated into short chains. As shown in **Figure 4a**, in the absence of an electric field, the scattering was isotropic and sparse indicating a random dispersion of particles in the oil phase. The application of an initial electric field of 250 V/mm induced the onset of particles aggregation. The scattering signal revealed that the particles suspended in the light paraffin base crude oil started to aggregate into a short chain with a length of 68 nm and a thickness of 34 nm (**Figure 4b**). As the applied electrical field increased to *E* = 400 V/mm, the neutron scattering signal indicated that the short chain acquired a prolate spheroid shape with a length of 75.2 nm and a thickness of 37.6 nm (**Figure 4c**). At a higher electrical field of *E* = 750 V/mm, the chain length increased to 94 nm long and the thickness to 38.4 nm (**Figure 4d**). At a higher electric field of 1100 V/mm, the chain reached a length of 94.8 nm and a thickness of 38.6 nm (**Figure 4e**). Finally, at the highest value of the electrical field applied of *E* = 1500 V/mm (**Figure 4f**), the chain dimensions were 94.8 nm length and 45 nm thickness. Therefore, as the electric field increases, the aggregated chains become longer and thicker (**Table 1**).


**Table 1.** Aggregated short chains of light paraffin base crude oil.

2D detector and focusing refractive lenses. The *Q*‐range of the instrument goes from 0.008 to 7.0 nm−1 to enable the detection of structural features in materials ranging from roughly 1 nm

As shown in **Figure 3**, the crude oil sample goes in a special capacitor, consisting of two pieces of cadmium electrodes and two pieces of quartz glass windows. The neutron beam passes through the quartz windows and through the crude oil sample into a detector. The application of a high voltage to the cadmium electrodes produces an electric field perpendicular to the neutron beam. Cadmium electrodes are suitable neutron absorbers, which reduces neutron

**Figure 4.** Scattering patterns at various electric fields obtained from a paraffin base crude oil. (a) *E* = 0 V/cm, (b) *E* =

2500 V/cm, (c) *E* = 4000 V/cm, (d) *E* = 7500 V/cm, (e) *E* = 11,000 V/cm, (f) *E* = 15,000 V/cm.

to over 500 nm.

176 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

scattering noise.

The asphalt base crude oil showed similar behavior under the ER treatments at different electric field intensities. For example, under an electric field of 1000 V/mm, the asphalt particles aggregated into a short chain in a prolate spheroid shape with a length of 78 nm and a thickness of 50 nm [15].

Based on the neutron scattering information, it is possible to approximate the short chain to a prolate spheroid (**Figure 5**) with its rotational z‐axis along the flow direction.

**Figure 5.** Aggregated short chains or prolate spheroids.

Equation (7) allows determining the dimensions of the prolate spheroid (short chain of agglomerates) as follows:

$$(\left(\mathbf{x}^2 + \mathbf{y}^2\right)/b^2 + z^2 / a^2 = 1\tag{7}$$

Here > and the electric field is along the z‐direction. Generally, a heavy crude oil contains numerous solid particles suspended within the bulk of the liquid hydrocarbon phase. In this case, the application of an electric field induces a strong aggregation of particles forming numerous short chains and/or prolate spheroids.

Einstein studied the viscosity of dilute liquid suspensions and found that the intrinsic viscosity for spheres is [*η*] = 2.5 [16]. For the prolate spheroids, the intrinsic viscosity along the z‐axis [η‖] is smaller than 2.5, while the intrinsic viscosity along the directions perpendicular to the z‐axis, [*η*⊥] is higher than 2.5. For crude oils with API° gravities lower than 34° (heavier crude oils), the aggregated chains will be longer than the aggregated chains observed in the nuclear scattering experiment for paraffinic oil. If for instance, it is assumed that (*a−b*)*/a=* 0.8, then [*η*‖] = 2.035 and [*η*⊥] = 3.548 [17]. This information of intrinsic viscosities enables the calculation of the viscosities using the Krieger‐Dougherty equation [18],

$$\ln \eta\_i \mid \eta\_0 = (1 - \phi \nmid \phi\_{\text{max}})^{-\{\eta\_i\}\phi\_{\text{max}}} \tag{8}$$

where *ηi* is the effective viscosity, 0 is the viscosity of base liquid, [*η*<sup>i</sup> ] is the intrinsic viscosity of the particles, and max is the maximum volume fraction for randomly packed particles. Recent work found that max strongly depends on the particle shape. For spheres, ℎ = 0.64 and for spheroids ℎ <sup>≥</sup> 0.72 [19, 20]. If the particle volume fraction = 0.5, then the initial viscosity of the crude oil is = 11.380. After the electric field is applied, then the effective viscosity along the flow direction is reduced to *η*‖= 5.68*η*0, which corresponds to a viscosity reduction of 50.1%, while the effective viscosity perpendicular to the flow direction is increased to ⊥ = 20.670 that represents a viscosity increase of 81.6%. The flow behaviour of this electric‐field treated crude oil is similar to the flow of a nematic liquid crystal with its molecules in alignment with the flow direction [21].

A viscosity increase in the direction perpendicular to the flow causes the suppression of turbulence because the vortices in turbulent flow move in the direction transversal to the pipeline axis. For this reason, the formation of aggregated short chains in the bulk of the crude oil plays a similar function as the addition of drag‐reducing agents (DRA) to the crude oil. However, the addition of DRA could cause further issues at the oil refineries. Moreover, the more significant aspect of this technology is the simultaneous reduction of viscosity, which enhances the flow output, while the addition of DRA to the oil phase cannot reduce the viscosity of the oil.

Another advantage of this technology is that the aggregated chains in the laminar flow migrate toward the center of the pipe that corresponds to minimum shear rate zone due to the Segré‐ Silberberg effect [22]. Therefore, this technology also reduces the sedimentation and/or deposition of particles on the pipeline walls. All these factors are essential for significant improvement of oil transportation via pipelines.

#### **2.2. Laboratory evaluation of viscosity reduction**

Equation (7) allows determining the dimensions of the prolate spheroid (short chain of

Here > and the electric field is along the z‐direction. Generally, a heavy crude oil contains numerous solid particles suspended within the bulk of the liquid hydrocarbon phase. In this case, the application of an electric field induces a strong aggregation of particles forming

Einstein studied the viscosity of dilute liquid suspensions and found that the intrinsic viscosity for spheres is [*η*] = 2.5 [16]. For the prolate spheroids, the intrinsic viscosity along the z‐axis [η‖] is smaller than 2.5, while the intrinsic viscosity along the directions perpendicular to the z‐axis, [*η*⊥] is higher than 2.5. For crude oils with API° gravities lower than 34° (heavier crude oils), the aggregated chains will be longer than the aggregated chains observed in the nuclear scattering experiment for paraffinic oil. If for instance, it is assumed that (*a−b*)*/a=* 0.8, then [*η*‖] = 2.035 and [*η*⊥] = 3.548 [17]. This information of intrinsic viscosities enables the calculation of

<sup>0</sup> max / (1 / ) *<sup>i</sup>*

of the particles, and max is the maximum volume fraction for randomly packed particles. Recent work found that max strongly depends on the particle shape. For spheres, ℎ = 0.64 and for spheroids ℎ <sup>≥</sup> 0.72 [19, 20]. If the particle volume fraction = 0.5, then the initial viscosity of the crude oil is = 11.380. After the electric field is applied, then the effective viscosity along the flow direction is reduced to *η*‖= 5.68*η*0, which corresponds to a viscosity reduction of 50.1%, while the effective viscosity perpendicular to the flow direction is increased to ⊥ = 20.670 that represents a viscosity increase of 81.6%. The flow behaviour of this electric‐field treated crude oil is similar to the flow of a nematic liquid crystal

A viscosity increase in the direction perpendicular to the flow causes the suppression of turbulence because the vortices in turbulent flow move in the direction transversal to the pipeline axis. For this reason, the formation of aggregated short chains in the bulk of the crude oil plays a similar function as the addition of drag‐reducing agents (DRA) to the crude oil. However, the addition of DRA could cause further issues at the oil refineries. Moreover, the more significant aspect of this technology is the simultaneous reduction of viscosity, which enhances the flow output, while the addition of DRA to the oil phase cannot reduce the

 ff

is the effective viscosity, 0 is the viscosity of base liquid, [*η*<sup>i</sup>

max [ ]


] is the intrinsic viscosity

h f

2 2 2 22 ( )/ / 1 *x y b za* + += (7)

agglomerates) as follows:

where *ηi*

viscosity of the oil.

numerous short chains and/or prolate spheroids.

178 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

the viscosities using the Krieger‐Dougherty equation [18],

*i*

h h

with its molecules in alignment with the flow direction [21].

A series of laboratory tests evaluated the performance of different types of crude oils [23]. However, this chapter summarizes only the behavior of the Daqing crude oil, which is a well‐ known paraffinic crude oil with a pour point of around 30°C from the Daqing oil field, China.

The experimental procedure was as follows. The crude oil sample was loaded at the top of a cylindrical container. Underneath the cylinder, a valve allowed the flow of crude oil through three electrodes into a long capillary tube with a diameter of 0.2673 cm. A cup on a microba‐ lance collected the crude oil that flowed down through the capillary tube. A computer connected to the microbalance recorded the oil mass as a function of time using a LabVIEW data acquisition system, which allowed determining the flow rate, *Q*. This experimental device was located inside an oven to keep the target temperature at 35.1°C during the experimenta‐ tion. The middle electrode was connected to the positive output of the high‐voltage power supply. The other two electrodes were connected to the negative output of the power supply. After the power supply was turned on, the strong electric field was produced in both capacitors along the flow direction, one vertically up and the other vertically down, forcing the suspended particles in the crude oil to aggregate into streamlined short chains along the flow direction causing the reduction of the crude oil effective viscosity. Since there are only dipolar interac‐ tions involved, such arrangement of the electrodes works well. It reduces the requirement of high voltage and makes the technology safer. **Figure 6** shows a picture of the experimental set‐up.

**Figure 6.** Experimental set‐up.

In these experimental runs, the *N*R was very low, and the crude oil flowed through the capillary tube under laminar flow conditions, which allowed determining the oil viscosity along the flow direction using Eq. (9),

$$\eta = \frac{\pi \rho^2 \text{g}R^4}{8Q} \left( 1 + \frac{h}{L} - \frac{\nu^2}{2 \text{g}L} \right) \tag{9}$$

where *R* and *L* are the respective radius and length of the capillary tube, *h* is the height of the oil level above the capillary tube, is the density of the oil, and *g* is the acceleration of gravity. Equation (10) allows estimating the average flow velocity,

$$\mathbf{v} = \underline{Q} / (\rho \pi R^{\mathbb{Z}}) \tag{10}$$

where *Q* is the flow rate, *R* is the radius of the capillary tube, and is the density of the oil.

In all the experimental runs, crude oil flowed down by gravity in the absence of electric field to allow the stabilization of the oil and to obtain the baseline behavior of the crude oil (i.e. initial oil viscosity). Afterwards, crude oil flowed down by gravity under the effect of different electric field intensities. The oil flow rate increased rapidly under the effect of the tested electric fields. **Figure 7** shows the mass of oil passing through the electric field as a function of time and electric field. In **Figure 7**, a sudden change of the slope corresponds to a rapid increase in the mass of oil passing down as a function of time. Therefore, it was straightforward to determine the viscosity of the oil before and after the application of the electric field.

**Figure 7.** Mass of oil as a function of time and electric field.

Application of Electrorheology to Improve Crude Oil Flowing Properties Through Pipeline http://dx.doi.org/10.5772/64858 181

In these experimental runs, the *N*R was very low, and the crude oil flowed through the capillary tube under laminar flow conditions, which allowed determining the oil viscosity along the

> 24 2 1 8 2 *gR h v Q L gL*

= +- ç ÷

æ ö

(9)

(10)

è ø

where *R* and *L* are the respective radius and length of the capillary tube, *h* is the height of the oil level above the capillary tube, is the density of the oil, and *g* is the acceleration of gravity.

where *Q* is the flow rate, *R* is the radius of the capillary tube, and is the density of the oil.

determine the viscosity of the oil before and after the application of the electric field.

In all the experimental runs, crude oil flowed down by gravity in the absence of electric field to allow the stabilization of the oil and to obtain the baseline behavior of the crude oil (i.e. initial oil viscosity). Afterwards, crude oil flowed down by gravity under the effect of different electric field intensities. The oil flow rate increased rapidly under the effect of the tested electric fields. **Figure 7** shows the mass of oil passing through the electric field as a function of time and electric field. In **Figure 7**, a sudden change of the slope corresponds to a rapid increase in the mass of oil passing down as a function of time. Therefore, it was straightforward to

pr

h

Equation (10) allows estimating the average flow velocity,

**Figure 7.** Mass of oil as a function of time and electric field.

flow direction using Eq. (9),

180 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

**Figure 8.** Effect of electric field on Daqing crude oil. (a) Mass flow rate as a function of electric field (b) Viscosity as a function of electric field. Data obtained a temperature of 35.1°C.

This study allowed determining the optimum electric field that induced the largest reduction of oil viscosity. As shown in **Figure 7**, the mass flow rate in the absence of electric field was 0.04182 g/s, which corresponded to a viscosity of 764.5 cP. The application of an electric field of 7200 V/cm increased the flow rate to 0.28252 g/s, which corresponded to a viscosity of 113.16 cP. A further increase of the electric field to 8000 V/cm increased the flow rate to 0.318095 g/s that was equivalent to a final viscosity of 100.5 cP from an initial value of 764.5 cP.

Replication tests gave consistent results and confirmed that the application of the ER treatment effectively reduces irection.

**Figure 8a** plots the mass flow rate as a function of electric field. The mass flow rate of the oil increased by 661% when the electric field was increased from 0 to 8000 V/cm, which induced the simultaneous reduction of the crude oil viscosity by 86.9%.

**Figure 9.** The photo of the AOT device installed in the pipeline.

#### **2.3. Field tests under laminar flow conditions**

These field tests employed the testing pipeline route at the Rocky Mountain Oil Test Center (RMOTC) facility near Casper, Wyoming, equipped with a positive displacement (PD) pump. The electrical device or Applied Oil Technology (AOT) device was connected at 7.219 km of the testing route (**Figure 9**). Sensors inside the pipeline (inner diameter of 14.163 cm) at various locations measured the oil pressure and temperature.

**Figure 9** shows a photo of the AOT device installed at the RMOTC pipeline system. The device was connected downstream the pump, which pumped the crude oil to the top of the device. Then, the oil flowed down through the electric field and the pipeline. Several mesh electrodes (39 units) inside the vertical pipe of the device with a gap of 3 cm between two neighboring ones induced the axial electric field inside the vertical pipe.

The field tests used two loops as follows:

(1) **Close loop**. The oil flowed through the pump, the AOT device, and the pipeline for several cycles.

(2) **Open loop**. In this case, after one cycle, the oil flowed to a storage tank and fresh oil from another supply tank was pumped through the device and pipeline.

**Figure 10.** Pressure loss across the test loop as a function of the application of an electric field using the AOT device.

In these tests, the viscosity reduction was first determined along the flow direction under laminar flow regime (*N*R = 1205.21). The pump was set at a constant *Q* of 46.56 m3 /h, which provided a linear velocity of 82.09 cm/s. The properties of the crude oil were API° = 34, initial viscosity = 81.6 cP at 12.1°C, and density = 0.8459 g/cm3 . As the untreated oil flowed through the pipeline, the pressure loss was 1.07 bar/km. The application of an electric field of 2300 V/cm caused a reduction of pressure loss across the loop from 1.07 to 0.641 bar/km (40% reduction). Similarly, the viscosity along the flow direction reduced from 81.6 cP to 48.95 cP (40% reduction). Then, the AOT device was turned‐off and the pressure loss across the loop gradually returned to the original value in the absence of the electric field (**Figure 10**). Meas‐

urement of the pumping power requirements is useful to evaluate the effect of the ER treatment on the flow properties of the crude oil. Before the application the ER treatment, the pump required a total power of 14.2 kW. However, the ER treatment gradually reduced the pumping requirements to a steady value of 8.9 kW, which is equivalent to an energy saving of 5.3 kW. The AOT device utilized less than 100 W of electric power during the lifespan of the experi‐ mentation.

#### **2.4. Suppression of turbulent flow conditions**

**2.3. Field tests under laminar flow conditions**

182 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

locations measured the oil pressure and temperature.

ones induced the axial electric field inside the vertical pipe.

another supply tank was pumped through the device and pipeline.

The field tests used two loops as follows:

cycles.

These field tests employed the testing pipeline route at the Rocky Mountain Oil Test Center (RMOTC) facility near Casper, Wyoming, equipped with a positive displacement (PD) pump. The electrical device or Applied Oil Technology (AOT) device was connected at 7.219 km of the testing route (**Figure 9**). Sensors inside the pipeline (inner diameter of 14.163 cm) at various

**Figure 9** shows a photo of the AOT device installed at the RMOTC pipeline system. The device was connected downstream the pump, which pumped the crude oil to the top of the device. Then, the oil flowed down through the electric field and the pipeline. Several mesh electrodes (39 units) inside the vertical pipe of the device with a gap of 3 cm between two neighboring

(1) **Close loop**. The oil flowed through the pump, the AOT device, and the pipeline for several

(2) **Open loop**. In this case, after one cycle, the oil flowed to a storage tank and fresh oil from

**Figure 10.** Pressure loss across the test loop as a function of the application of an electric field using the AOT device.

laminar flow regime (*N*R = 1205.21). The pump was set at a constant *Q* of 46.56 m3

viscosity = 81.6 cP at 12.1°C, and density = 0.8459 g/cm3

In these tests, the viscosity reduction was first determined along the flow direction under

provided a linear velocity of 82.09 cm/s. The properties of the crude oil were API° = 34, initial

the pipeline, the pressure loss was 1.07 bar/km. The application of an electric field of 2300 V/cm caused a reduction of pressure loss across the loop from 1.07 to 0.641 bar/km (40% reduction). Similarly, the viscosity along the flow direction reduced from 81.6 cP to 48.95 cP (40% reduction). Then, the AOT device was turned‐off and the pressure loss across the loop gradually returned to the original value in the absence of the electric field (**Figure 10**). Meas‐

/h, which

. As the untreated oil flowed through

These tests were conducted with a Reynolds number near the critical value of 2300 first, then extended to Reynolds number well above 6000. The pump was set at a constant *Q* of 95.392 m3 /h that corresponded to a flow velocity *v* of 168.2 cm/s. The conditions of the initial test were crude oil with an initial viscosity of 93.7 cP at 11.5 °C, a *Q* of 95.392 m3 /h, laminar flow with a = 2160.82, and a pressure drop along the pipeline of 2.51 bar/km. The application of an electric field of 2300 V/cm reduced the oil viscosity to 85.5 cP, which increased the *N*R to 2368.1, which corresponds to a turbulent flow regime. However, if the flow were turbulent, the pressure loss would increase to 3.85 bar/km (Eq. 3); while in fact, the pressure loss was 2.296 bar/km and the pump power requirement was 52.4 kW (reduced from 57.4 KW). This experi‐ mental run confirmed that the flow of crude oil under the influence of the ER treatment remained laminar.

A further increase of the electric field to 3000 V/cm caused an additional reduction of the oil viscosity to 75.6 cP and an increase in the *N*R to 2678.2. Likewise, if the flow regime were turbulent at this condition, the pressure drop along the loop would increase to 3.73 bar/km. On the contrary, the pressure loss along the pipeline reduced to 2.03 bar/km, and the pump power requirement decreased to 48.3 kW, which corresponds to a laminar flow regime. Observations from replication tests were consistent.

Another field test evaluated the performance of the paraffin base Daqing crude oil, which has a pour point around 30°C. The transportation of this oil requires that the temperature within the pipeline system must be maintained in the range of 55–72°C through 15–20 km of insulated pipeline length (pipeline inner diameter 14.5 cm), before the pipeline system reaches another heating station.

Initially, several pre‐tests established the conditions for turbulent flow regime within the temperature range previously indicated. For example, crude oil at 55.6°C and viscosity of 16.92 cP was flowed through the pipeline at a flow rate of 34.46 m3 /h and a pressure of 7.0 bar; under these conditions, *N*R was 4128.3 (turbulent regime). In another pre‐test, crude oil at 71.1°C and a viscosity of 12.4 cP was pumped at a pressure of 7.0 bar. The experimentally measured *Q* was 36 m3 /h. According to Eq. (6), under these flow conditions (i.e. pressure and oil viscosity), *Q* must be 36.02 m3 /h for a turbulent flow regime, which was in agreement with the experimen‐ tally measured *Q*. On the other hand, if the flow were laminar at the same flow conditions, the calculated *Q* using Eq. (1) should be 47.02 m3 /h, which is much higher than the measured *Q*.

In other pre‐experimental run, crude oil at 55.6°C was flowed through the test loop at a pumping pressure of 8.35 bar. The measured *Q* was 38.1 m3 /h. If the flow were laminar, according to Eq. (1), the *Q* should be 41.1 m3 /h. However, the measured *Q* (38.1 m3 /h) was equal to the *Q* estimated using the Blasius formula (Eq. 6) of 38.11 m3 /h.

Overall, these pre‐tests demonstrated that the flow of crude oil at 55.6 and 71.1°C was turbulent and more importantly that heating of the crude oil does not suppress turbulence.

The procedure used to evaluate the effect of the application of an electric field on the suppres‐ sion of turbulence during the flow of crude oil through the test loop was as follows.

#### *(1) AOT device turned-off*

Flow conditions: temperature of crude oil = 55.6 °C, pumping pressure = 3.1 bar, *Q* = 16.4 m3 /h, and *N*R = 1964.7 (laminar flow regime).

#### *(2) AOT device turned-on*

The application of an electric field of 13.3 kV/cm reduced the oil viscosity along the flow direction to 14.14 cP and gradually increased *Q* to 19.6 m3 /h. Although *N*<sup>R</sup> increased to 2808.9, the flow regime was still laminar (based on the theoretical flow rate, which was in agreement with the experimentally measured *Q*).

In order to test the crude oil flow behavior at much higher *N*<sup>R</sup> at a constant electric field of 13.3 kV/cm, the flowing pressure was increased from 3.1 to 5.0 bar and *Q* was increased to 31.6 m3 /h, which corresponded to an *N*<sup>R</sup> of 4528.6. Nevertheless, under these conditions the flow remained laminar because the measured *Q* was in agreement with the theoretical esti‐ mation (Eq. 1) of *Q* = 31.61 m3 /h for a laminar flow regime.

A further increase in the pumping pressure to 7.0 bar, under a constant electric field of 13.3 kV/cm, caused an increase in *Q* to 44.3 m3 /h and an *N*R of 6348.7. However, according to Eq. (1), the flow of crude oil remained laminar. **Table 2** summarizes these experimental observa‐ tions.


**Table 2.** Test results with *N*R > 2300.

Application of Electrorheology to Improve Crude Oil Flowing Properties Through Pipeline http://dx.doi.org/10.5772/64858 185

**Figure 11.** Pumping pressure versus flow rate.

according to Eq. (1), the *Q* should be 41.1 m3

184 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

and *N*R = 1964.7 (laminar flow regime).

with the experimentally measured *Q*).

kV/cm, caused an increase in *Q* to 44.3 m3

mation (Eq. 1) of *Q* = 31.61 m3

**Viscosity (cP)**

**Table 2.** Test results with *N*R > 2300.

direction to 14.14 cP and gradually increased *Q* to 19.6 m3

**Reynolds number**

*(1) AOT device turned-off*

*(2) AOT device turned-on*

31.6 m3

tions.

**Flow rate (m3 /h)**

to the *Q* estimated using the Blasius formula (Eq. 6) of 38.11 m3

Overall, these pre‐tests demonstrated that the flow of crude oil at 55.6 and 71.1°C was turbulent

The procedure used to evaluate the effect of the application of an electric field on the suppres‐

Flow conditions: temperature of crude oil = 55.6 °C, pumping pressure = 3.1 bar, *Q* = 16.4 m3

The application of an electric field of 13.3 kV/cm reduced the oil viscosity along the flow

the flow regime was still laminar (based on the theoretical flow rate, which was in agreement

In order to test the crude oil flow behavior at much higher *N*<sup>R</sup> at a constant electric field of 13.3 kV/cm, the flowing pressure was increased from 3.1 to 5.0 bar and *Q* was increased to

flow remained laminar because the measured *Q* was in agreement with the theoretical esti‐

A further increase in the pumping pressure to 7.0 bar, under a constant electric field of 13.3

(1), the flow of crude oil remained laminar. **Table 2** summarizes these experimental observa‐

**Electric field (V/mm)**

34.36 16.92 4128.3 0 7.0 55.6 Turbulent 36.0 12.40 5890.3 0 7.0 71.1 Turbulent 38.1 16.92 4565.6 0 8.35 55.6 Turbulent 16.4 16.92 1964.7 0 3.1 55.6 Laminar 19.6 14.14 2808.9 1333 3.1 55.6 Laminar 31.6 14.14 4528.6 1333 5.0 55.6 Laminar 44.3 14.14 6348.7 1333 7.0 55.6 Laminar

/h for a laminar flow regime.

/h, which corresponded to an *N*<sup>R</sup> of 4528.6. Nevertheless, under these conditions the

**Pressure (bar)**

and more importantly that heating of the crude oil does not suppress turbulence.

sion of turbulence during the flow of crude oil through the test loop was as follows.

/h. However, the measured *Q* (38.1 m3

/h.

/h. Although *N*<sup>R</sup> increased to 2808.9,

/h and an *N*R of 6348.7. However, according to Eq.

**Temperature (°C)**

**Flow regime**

/h) was equal

/h,

**Figure 11** plots the applied pumping pressure as a function of *Q* (m3 /h) for untreated and treated crude oil. It is clear that even at very high *Q* (40 m3 /h) and large *N*R= 6348, the flow regime of the ER‐treated crude oil remained laminar. On the contrary, the flow of the untreated oil became turbulent *N*R >2300. These experimental observations clearly confirm that the ER treatment effectively suppresses the onset of turbulent flow regime.

#### **2.5. Field tests on a section of the keystone pipeline**

These field tests employed a section of the Keystone Phase II pipeline near Wichita, Kansas. **Figure 12** shows a picture of the AOT device installed in this pipeline system. The device was downstream of the pump, which pumped the crude oil to the top of the device, entering the four parallel cylinders through the mesh electrodes, and then to the pipeline downstream.

**Figure 12.** AOT device installed on the Keystone pipeline system.

These tests evaluated the performance of an asphalt base crude oil. The crude oil had a density of 0.887 g/cm3 and a viscosity of 214.1 cP at 25°C. The inner diameter of the pipeline was 35 inch (88.9 cm) and *Q* was kept constant at 2280 m3 /h, which corresponds to a flow velocity of 1.02 m/s. Under these conditions, the *N*R was 3757.9, which indicates turbulent flow conditions. From Eq. (5), the estimated friction factor for this turbulent flow is *f*<sup>T</sup> *=* 0.04011; while the pressure difference along the pipeline was estimated using Eq. (11) as follows,

$$
\Delta P = \frac{1}{2} \rho \mathbf{v}^2 f\_\mathbf{r} L / D \tag{11}
$$

where *L* is the distance between the Keystone pump station and the next downstream pump station, ρ is the flow velocity, and *D* is the pipeline diameter.

Equation (12) allows estimating the required pumping power, *P*wi.

$$P\text{vi} = \underline{Q}\Delta P = \pi\rho\text{v}^3 \text{DL}f\_T / 8 \tag{12}$$

where *Q* is the flow rate and Δ*P* is the pressure difference in Eq. (11). The application of an electric field caused the reduction of the crude oil viscosity along the flow direction from 214.1 to 142.5 cP; while the viscosity of the oil in the direction perpendicular to the flow was significantly increased (>700 cP). Under these conditions, the treated oil flow was laminar. **Figure 13** shows that after the AOT device is turned‐on, the treated crude oil flowing under laminar conditions pushes the rear of the untreated oil downstream the pipeline, which flows under turbulent conditions.

**Figure 13.** Treated oil under laminar flow conditions pushes the untreated oil under turbulent flow conditions down‐ stream the pipeline.

If the AOT device was on for time *t* (**Figure 13**), the length of the laminar flow section is *vt* along the pipeline; while the turbulent flow had length of *L-vt*. The Reynolds number for the laminar flow was 5646.1, and the friction factor was *f*L = 0.011335258. Equation (13) allows the estimation of the pump power requirements for the period 0 < < / as follows,

$$Pw(t) = \pi p \text{v}^{\flat} D \| \text{v} f\_{\perp} + (L - \text{vt}) f\_{\perp} \| \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \begin{array}{c} \text{\, } p \text{\, } q \text{\, } \space \& \, \space \} \, \space \, \space \} \space \, \space \, \space \, \space \, \space \, \space \, \space \, \space \, \begin{array}{c} \text{\, } p \text{\, } q \text{\, } \space \} \, \space \} \end{array} \right \, \space \, \space$$

Substituting the values for and , the pump power requirements for the period of 0 < < / were calculated as follows (Eq. 14):

$$PW(t) = PW(l - 0.7195\text{vt} / \, L) \tag{14}$$

Application of Electrorheology to Improve Crude Oil Flowing Properties Through Pipeline http://dx.doi.org/10.5772/64858 187

inch (88.9 cm) and *Q* was kept constant at 2280 m3

186 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

station, ρ is the flow velocity, and *D* is the pipeline diameter.

under turbulent conditions.

stream the pipeline.

Equation (12) allows estimating the required pumping power, *P*wi.

1.02 m/s. Under these conditions, the *N*R was 3757.9, which indicates turbulent flow conditions. From Eq. (5), the estimated friction factor for this turbulent flow is *f*<sup>T</sup> *=* 0.04011; while the

where *L* is the distance between the Keystone pump station and the next downstream pump

where *Q* is the flow rate and Δ*P* is the pressure difference in Eq. (11). The application of an electric field caused the reduction of the crude oil viscosity along the flow direction from 214.1 to 142.5 cP; while the viscosity of the oil in the direction perpendicular to the flow was significantly increased (>700 cP). Under these conditions, the treated oil flow was laminar. **Figure 13** shows that after the AOT device is turned‐on, the treated crude oil flowing under laminar conditions pushes the rear of the untreated oil downstream the pipeline, which flows

**Figure 13.** Treated oil under laminar flow conditions pushes the untreated oil under turbulent flow conditions down‐

If the AOT device was on for time *t* (**Figure 13**), the length of the laminar flow section is *vt* along the pipeline; while the turbulent flow had length of *L-vt*. The Reynolds number for the laminar flow was 5646.1, and the friction factor was *f*L = 0.011335258. Equation (13) allows the

Substituting the values for and , the pump power requirements for the period of

*f vt L* (13)

*Pw t Pwi* ( ) (1 0.7195 = - *vt L*/ ) (14)

estimation of the pump power requirements for the period 0 < < / as follows,

( ) [ ( ) ] / 8 [1 (1 / ) /] *L T L T Pw t v D vtf L vt f Pwi f* = + - = --

3

pr

0 < < / were calculated as follows (Eq. 14):

pressure difference along the pipeline was estimated using Eq. (11) as follows,

1 2 <sup>2</sup> / D = *P vfL D* r

<sup>3</sup> / 8 *Pwi Q P v DLf* =D= pr

/h, which corresponds to a flow velocity of

*<sup>T</sup>* (11)

*<sup>T</sup>* (12)

**Figure 14.** (a) Estimated pump power requirements as a function of time and electric field. (b) Experimental pump power versus time.

After /, only treated oil occupied the test section of the pipeline, and the calculated pump power was 0.28 *P*wi. This indicates that the application of the ER treatment reduced the pumping requirements by 72%. **Figure 14** presents these calculated power requirements (**Figure 14a**) and the experimental pump power requirements (**Figure 14b**).

**Figure 14b** displays the experimental pump power reduction after the application of ER treatment. Before the treatment, the pump required a power of 2826 kW to transport the crude oil. After 2 hours of treatment, the pump power requirements stabilized at around 800 kW, while *Q* remained constant at 2280 m3 /h. In this case, the total reduction of pumping power requirements was 71.7%.

In this experimental study, the AOT device required <1 kW of power; while the pumping power required to transport the heavy crude oil at a *Q* = 2280 m3 /h was significantly reduced with overall power savings > 2000 kW. These experimental observations confirm the theoretical predictions and demonstrate the efficiency of this technology for transporting heavy crude oil via pipeline.

#### **2.6. Lasting effect of the ER treatment on crude oil flowing properties**

The anisotropic viscosity of the crude oil is the result of the aggregation of suspended particles into short chains along the flow direction under the effect of an electric field. Therefore, the reduced crude oil viscosity along the flow direction and the turbulence suppression effect will diminish if the aggregated short chains deassembled partially or completely.

Laboratory‐bench scale tests evaluated the lifespan of the anisotropic viscosity effect after the ER treatment. The experimental procedure consisted in the application of the electric field to the oil sample at a pre‐established temperature for about 5 seconds. Afterwards, the sample was stored at the corresponding temperature, and the crude oil viscosity was measured as a function of time. **Tables 3** and **4** summarize the experimental results obtained from the evaluation of two crude oils.


**Table 3.** Viscosity performance of the Daqing crude oil after the ER treatment at 35.1°C. The applied electric field was 8 kV/cm for 5 seconds.


**Table 4.** Viscosity performance of crude oil (API 34°) after the ER treatment at −3.1°C. The applied electric field was 1.6 kV/mm for 5 seconds.

These experimental results indicate that while the aggregated chains gradually deassembled as a function of time, the deaggregation process is slow and the viscosity of the crude oil increases very slowly. In these experiments, the anisotropic viscosity of the treated crude oil lasted for more than 24 hours.

**Figure 15.** Crude oil viscosity and temperature as a function of time.

Tests at the RMOTC pipeline also evaluated the lifespan of the ER treatment. These field tests used the pipeline loop described in Section C and employed a crude oil with an API° 34° and an initial viscosity of 118.06 cP. The positive displacement pump drove the crude oil through the AOT device and the pipeline loop during six and half hours. The electric field applied was 2 kV/cm, which reduced the viscosity of the crude oil along the flow direction from 118.06 to 51.8 cP (viscosity reduction of 56.12%). After 6.5 hours, the AOT device was turned‐off, but the crude oil circulated the pipeline loop for more than 11 hours. During this period, the pressure loss across the pipeline loop and the pump power requirements were continuously monitored. The experimental observations indicate that the reduced viscosity of the treated oil, the pressure loss, and the pump power requirements remained stable during a period of 11 hours. Afterwards, the pressure loss and pump power requirements started to increase, signifying that the viscosity reduction effect on the treated crude oil began to disappear. **Figure 15** summarizes these experimental observations.

The lasting effect of the ER treatment (11 hours) obtained in the pipeline loop (field test) was shorter than the lasting effect determined at the laboratory scale (>24 hours). In the field test, the PD pump continuously pumped the crude oil through the pipeline loop. This continuous pumping through the PD pump could cause the disruption and breaking of the aggregated particles that induce the oil viscosity increase; while in the experiments conducted in the laboratory, only Brownian motion caused shear forces on the aggregated chains.

Nevertheless, in industrial ER applications, a treatment lifespan of 11 hours seems to be practical, considering that the electric field can be re‐applied to adjust the viscosity of the crude oil as needed. Furthermore, the lasting effect of the ER treatment simultaneously suppresses turbulence [24].

## **3. Conclusions**

Viscosity (cP) 911 390 408 421 441 480 487 Time (h) Untreated 0 4 8 12 23 26

Viscosity (cP) 261.3 121.1 151.2 172.4 Time (h) Untreated 0 12 24

kV/cm for 5 seconds.

188 Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

kV/mm for 5 seconds.

lasted for more than 24 hours.

**Figure 15.** Crude oil viscosity and temperature as a function of time.

**Table 3.** Viscosity performance of the Daqing crude oil after the ER treatment at 35.1°C. The applied electric field was 8

**Table 4.** Viscosity performance of crude oil (API 34°) after the ER treatment at −3.1°C. The applied electric field was 1.6

These experimental results indicate that while the aggregated chains gradually deassembled as a function of time, the deaggregation process is slow and the viscosity of the crude oil increases very slowly. In these experiments, the anisotropic viscosity of the treated crude oil

Tests at the RMOTC pipeline also evaluated the lifespan of the ER treatment. These field tests used the pipeline loop described in Section C and employed a crude oil with an API° 34° and an initial viscosity of 118.06 cP. The positive displacement pump drove the crude oil through the AOT device and the pipeline loop during six and half hours. The electric field applied was 2 kV/cm, which reduced the viscosity of the crude oil along the flow direction from 118.06 to 51.8 cP (viscosity reduction of 56.12%). After 6.5 hours, the AOT device was turned‐off, but the crude oil circulated the pipeline loop for more than 11 hours. During this period, the pressure loss across the pipeline loop and the pump power requirements were continuously monitored. Electrorheology, ER, is effective in simultaneously reducing the viscosity and suppressing turbulence during oil transportation via pipeline.

Experimental work at laboratory bench scale and field tests demonstrate the ER technology efficiently induces the aggregation of suspended particles contained in crude oils. These aggregated particles form short chains along the flow direction, which simultaneously reduce the crude oil viscosity and suppress turbulence, enhancing flow output.

Typical flow of crude oil in pipeline becomes turbulent when the Reynolds number exceeds 2300; the ER‐treated crude oil remains laminar even at Reynolds numbers close to 10,000. Furthermore, field tests indicate that the ER effect on the viscosity and flow properties of the crude oil lasts 11 hours, after the ER treatment has ceased. The application of this technology for oil transportation via pipeline is in rapid development.

The ER technology shows great potential for heavy oil extraction and EOR operations; however, these applications require significant more research.

## **Author details**

R. Tao

Address all correspondence to: rtao@temple.edu

Department of Physics, Temple University, Philadelphia, PA, USA

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## *Edited by Laura Romero-Zeron*

Commercial application of chemical enhanced oil recovery (cEOR) processes is expected to grow significantly over the next decade. Thus, Chemical Enhanced Oil Recovery (cEOR): A Practical Overview offers key knowledge and understanding of cEOR processes using an evidence-based approach intended for a broad audience ranging from field operators, researchers, to reservoir engineers dealing with the development and planning of cEOR field applications. This book is structured into three sections; the first section surveys overall EOR processes. The second section focuses on cEOR processes, while the final section describes the electrorheology technology. These sections are presented using a practical and realistic approach tailored for readers looking to improve their knowledge and understanding of cEOR processes in a nutshell.

Photo by kodda / iStock

Chemical Enhanced Oil Recovery (cEOR) - a Practical Overview

Chemical Enhanced Oil

Recovery (cEOR)

a Practical Overview

*Edited by Laura Romero-Zeron*