Section 2 Miscible Flooding

#### **Chapter 2**

## Carbon Dioxide-Oil Minimum Miscibility Pressure Methods Overview

*Eman Mohamed Ibrahim Mansour*

#### **Abstract**

One of the essential parameters in carbon dioxide (CO2) miscible flooding is the minimum miscibility pressure (MMP). Minimum miscibility pressure (MMP) is defined as the lowest pressure at which recovery of oil is (90–92%) at injection (1.2 PV) of carbon dioxide (CO2). The injected gas and oil become a multi-contact miscible at a fixed temperature. Before any field trial, minimum miscibility pressure (MMP) must be determined. This parameter must be determined before any field trial because any engineer needs a suitable plan to develop an injection and surface facilities environment**.** Estimation of reliable (MMP) maybe by traditional laboratory techniques, but it is very costly and time-consuming. Also, it can rely on various literature **(MMP)** empirical correlations, but this is not a good strategy because each minimum miscibility pressure (MMP) correlation relates to a unique formation condition.

**Keywords:** enhanced oil recovery, CO2 injection, minimum miscibility pressure (MMP), slim-tube test, computational method

#### **1. Introduction**

Miscible gas injection could enhance light oil reservoirs' enhanced recovery (EOR) process. Recycling CO2 into oil formation reservoirs allows good gas storage in subsurface formations; consequently, the oil recovery will improve [1]. Miscible flooding project design mostly depends on his success in the minimum miscibility pressure correct determination [2]. The minimum flooding pressure reached the miscibility point, which is the maximum oil recovery achieved (90–92%) at the lowest pressure during injection (1.2 PV) of carbon dioxide (CO2) [3]. Incremental oil recovery is negligible at a higher (CO2) flooding project pressure than the MMP. In addition, recovery will sharply decrease at a pressure lower than MMP [4].

#### **1.1 Importance of the minimum miscibility pressure (MMP)**

• Minimum miscibility pressure (MMP) is an essential parameter in any design project of gas injection. At the minimum miscibility pressure (MMP), all oil was recovered within a porous medium of (CO2).

• When oil and gas are miscible, displacement efficiency will be 100% [5].

#### **1.2 Factors affecting minimum miscibility pressure (MMP)**

oil composition, reservoir temperature, and (CO2) purity effect on minimum miscibility pressure (MMP), where [6]:


#### **2. Methods of estimating (MMP)**

There are several experimental, equation of state, and empirical equations for estimating (MMP).

#### **2.1 Experimental methods for estimating minimum miscibility pressure (MMP)**

Minimum miscibility pressure (MMP) estimates through several testing methods: slim-tube experiments, rising bubble experiments, multiple-contact experiments, and vanishing interfacial tension experiments [7].

#### *2.1.1 Slim-tube experiment*

These experiments are widely accepted experimental methods for estimating minimum miscibility pressure (MMP) because they can repeat the interaction of gas and oil in a one-dimensional porous medium [8]. As a result, that slim-tube experiment can replicate oil and gas interaction in a one-dimensional porous medium. It remains the most reliable method of estimating minimum miscibility pressure (MMP)[9]. The slim-tube basic test is the small-diameter tube packed with an unconsolidated porous medium [3]. It is an idealized medium for carbon dioxide (CO2) and oil to develop dynamic miscibility [10]. The slim-tube experiment comes close to a one-dimensional displacement due to this large length-to-diameter ratio, thus the isolating of phase behavior affects the efficiency of removal [11]. A slim-tube is a long thin stainless steel-tube that is fifteen-meter, packed with sand or glass beads (commonly, sand packing is 160 to 200 mesh) [12]. The slim schematic-tube appears in **Figures 1** and **2**.

The slim-tube is saturated with at least two PV light oils at the reservoir temperature. Then the system pressurized gradually to the operating pressure in the

*Carbon Dioxide-Oil Minimum Miscibility Pressure Methods Overview DOI: http://dx.doi.org/10.5772/intechopen.106637*

**Figure 1.** *Schematic diagram of the slim-tube test setup.*

**Figure 2.** *Actual slim-tube test system.*

backpressure regulator's presence [3]. It is pressure generally kept constant by a backpressure regulator. Upstream pressure changed with the backpressure regulator as it set [13]. To avoid pressure from one side of the diaphragm in the backpressure regulator from becoming significantly higher than the pressure on the other side and damaging the diaphragm [14]. It was required to pressurize the tube system gradually. Just the required pressure is reached, and the system will be equilibrated under this pressure. The carbon dioxide (CO2) pressure pump was adjusted a little above the pressure of the backpressure regulator. The carbon dioxide (CO2) flow rate is 4 to 8cm3/ hr. at a constant rate [15]. The experiment terminated when at least 1.2 PV of carbon dioxide (CO2) was injected. Effluent flashed to atmospheric conditions, where the flow meter collects separator gas and the separated oil collects in a graduate cylinder. The pump's initial and final volumes of carbon dioxide (CO2) were recorded to ensure the pump was not empty. The system was depressurized by venting loading gas gradually. After that, use two PV of methylene chloride in the slim-tube to remove residual oil and be ready for the next experiment [16]. The bubble point pressure of the formation oil must measure before the slim-tube experiment. On these results, the slim-tube test can repeat numerous times at different pressures greater than bubblepoint pressure. The injected gas pour volume and oil recovery are recorded in each experiment. After indirect 1.2 gas pore volume, the minimum miscibility pressure (MMP) was observed from recovery data.

As shown in **Figure 3** [17].

#### *2.1.2 Rising bubble experiment*

Christiansen and Haines [18] are the first to introduce the rising bubble experiment as a fast option to the slim-tube test, where it can be measured within one hour. This method consists of eight inches high-pressure crystal clear-tube long packed with oil and set at a definite pressure and temperature. Gas introduces through the way of a needle at the tube bottom, forming a bubble and rising through the column [19]. This

**Figure 3.** *Minimum miscibility pressure for (CO2).*

#### *Carbon Dioxide-Oil Minimum Miscibility Pressure Methods Overview DOI: http://dx.doi.org/10.5772/intechopen.106637*

method can visually observe the miscibility between a gas bubble and an oil. The disadvantage of this method is significant limitations as not expensive and fast compared to the slim-tube method. This method is unreliable in predicting minimum miscibility pressure (MMP) in condensing drive and condensing/vaporizing gas drive (Mansour and Ragab, 2021) (**Figure 4**) [18].

#### *2.1.3 Multiple-contact experiment*

Multiple-contact experiments can detect minimum miscibility pressure (MMP) definite conditions. A multiple-contact test aims to study the gas and oil injection phase behavior [20]. The multiple-contact test is always on contacts between oil and gas. Oil and gas are mixed in a pressure-volume-temperature (PVT) cell [21]. A single PVT cell uses to make repeated contacts between oil and gas forward or backward. In a forward contract, the equilibrium gas retains after each contact.

In contrast, the equilibrium oil replaces with fresh oil—consequently, the equilibrium gas from the previous stage contacts fresh oil at each stage [22]. Equilibrium oil is retained in a backward connection, and the gas is replaced with new injection gas. The contacts are repeated till no change in the phase composition. These tests are repeated at different pressures until the repeated contacts result in a single phase (as shown visually from the cell window) [23]. The disadvantages of this method are that it can provide useful minimum miscibility pressure (MMP) and phase behavior data for gas floods that are purely condensing or vaporizing. Still, most gas flooding is condensing/ evaporating drives, meaning that they have both condensing and drive features, but this makes the results of such experiments less accurate [24].

#### *2.1.4 Vanishing interfacial tension experiment*

Rao (1997) planned the vanishing interfacial tension (VIT) test as a technique for defining minimum miscibility pressure (MMP). This method involves a high temperature and pressure cell occupied with the CO2 injection. A drop of crude oil (about 10% of the cell volume) is introduced through a capillary-tube [25]. It measures the interfacial tension (IFT) between oil and CO2 injected gas at numerous pressures and a specific temperature. The analyzing data were determined by the shape of the hanging oil drop and the oil and gas densities. The pressure increases by pumping more gas into the cell, and the interfacial tension (IFT) measurement is repeated

**Figure 4.** *Rising bubble experiment.*

several times [26]. The minimum miscibility pressure (MMP) is approached by extrapolating the interfacial tension (IFT) plot versus pressures. The disadvantage of this test is that after extending their analysis to a multi-component mixture, and concluding that vanishing interfacial tension (VIT) experiments may not be a dependable method of determining minimum miscibility pressure (MMP) [27]. Among these, all experimental methods, the only known experiment of minimum miscibility pressure (MMP) between oil and injection gas is the slim-tube testing.

The experimental methods for estimating minimum miscibility pressure (MMP) have much money and time-overwhelming disadvantages. But these tests can provide us with useful phase behavior data that can be used to estimate and confirm the reliability of a computational minimum miscibility pressure (MMP) [26].

#### **2.2 Computational method of estimating minimum miscibility pressure (MMP)**

Empirical correlations for approximating minimum miscibility pressure (MMP) provide fast and cheap alternatives to experimental methods. It is beneficial for quick screening reservoirs for potential carbon dioxide (CO2) flooding. Various empirical correlations for estimating minimum miscibility pressure (MMP) have been calculated from regression data analysis of slimtube data [28]. Generally, empirical correlations for the predicting of minimum miscibility pressure (MMP) reservoir temperature, the (C2-C6) content of reservoir fluid, and API (oil gravity) as input parameters [29]. This study includes popular minimum miscibility pressure (MMP) empirical correlations reported in the petroleum literature are included in this study. It can be used as a practical guide for the application of different reservoir oils, such as Cronquist [30], Lee [31], Yelling and Metcalfe [32], Alston et al. [33], Emera and Sarma [34], Liao et al. [35], and Mansour et al. [36].

#### *2.2.1 Cronquist empirical correlation*

Cronquist [30] empirical correlation is based on the reservoir temperature, pentane plus (C5 + ) molecular weight, and volatile oil fraction as (CH4 and N2) for minimum miscibility pressure (MMP) estimation as shown in Eq. (1) [30].

$$\text{MMP} = \mathbf{0.11027} + (\mathbf{1.8T\_R} + \mathbf{32})^\text{y} \tag{1}$$

where Y = 0.744206 + 0.0011038 � MWTC5++0.0015279 � Vol. The experimental data range tested used in this study is as the following:


#### *2.2.2 Lee empirical correlation*

Lee [31] predicted a model to estimate minimum miscibility pressure (MMP) using reservoir temperature as input data only by considering carbon dioxide (CO2) vapor pressure, as shown in Eq.(2). If any reservoir oil's bubble point pressure (BP) is more than minimum miscibility pressure (MMP), the bubble point pressure (BP) takes as

minimum miscibility pressure [31]. The bubble point can be detected from the constant mass study test [37].

$$\text{MMP} = 7.3924 \times 10^{\text{b}} \tag{2}$$

where b = 2.772�(1519/(492 + 1.8TR)).

#### *2.2.3 Yelling and metcalfe empirical correlation*

Yelling and Metcafe (1980) proposed an empirical correlation for estimating minimum miscibility pressure (MMP) at different reservoir temperatures by using the equation Eq. (3). This correlation is not dependent on oil composition and is based only on reservoir conditions. The empirical correlation of minimum miscibility pressure (MMP) is varied from 15 to 19 Mpa approximately [32].

$$\text{MMP} = \text{12.6472} + 0.015531 \times (\text{1.8T}\_{\text{R}} + \text{32}) + \text{1.24192} \times 10^{-4} \tag{3}$$

$$\times (\text{1.8T}\_{\text{R}} + \text{32})^2 - \text{716.9427/(1.8T}\_{\text{R}} + \text{32})$$

The limitation of reservoir temperature data used 35.8 °C < TR < 88.9°C. Suppose the minimum miscibility pressure (MMP) is less than the bubble point pressure (BP) for any sample. The bubble point pressure is taken as the minimum miscibility pressure (MMP) determined by the constant mass study test [38].

#### *2.2.4 Alstonetal et al. empirical correlation*

Alston et al. [33] presented an empirical correlation for minimum miscibility pressure (MMP) caused by gas solution in reservoir fluids. The minimum miscibility pressure empirical correlation that is in Eq.(4) was predicted based on carbon dioxide (CO2) composition stream, light oil fraction (CH4 + N2), reservoir temperature, pentane plus (C5 + ) molecular weight, and Intermediate oil fraction (C2 to C4, H2S, and CO2). So, they proposed an impurity factor for predicting minimum miscibility pressure empirical correlation (MMP) by contaminated or en-riched carbon dioxide (CO2) stream (Alston, Kokolis, and James, 1985).

$$p\_{CO2} = 1.25 \ast 10^{-\top} \left(1.8t - 460\right)^{1.06} \left(M\_{W\odot +}\right)^{1.78} \left(\frac{\varkappa\_{vol}}{\varkappa\_{int}}\right)^{0.136} \tag{4}$$

Also, suppose the minimum miscibility pressure (MMP) of volatile reservoir oil is fewer than the saturation pressure (BP). In that case, the saturation pressure act as the minimum miscibility pressure (MMP).

#### *2.2.5 Emera and Sarma empirical correlation*

Emera and Sarma (2005) presented genetic logarithm (GA)-depending on correlation to predicate minimum miscibility pressure (MMP) as shown in Eq.(5). The input data parameters that are based on this correlation are (C1 and N2) volatiles ratio, reservoir temperature, intermediates components (C2–C4, H2S, and CO2), pentane plus (C5 + ) molecular weight, and (C2–C4, H2S, and CO2) [34].

$$\text{MMP}\_{\text{pure}} = 0.003 \ast T^{0.544} \left(\text{MW}\_{\text{C}\_{\text{5}+}}\right)^{1.006} \left(Y\_{\text{VOL}} | Y\_{\text{INT}}\right)^{0.143} \tag{5}$$

#### *2.2.6 Liao et al. empirical correlation*

Liao et al. [35] offered minimum miscibility pressure (MMP) empirical correlation depending on (CH4 + N2) oil fraction, (C2 to C4, H2S, and CO2) intermediate oil fraction, pentane plus (C5 + ) molecular weight, and reservoir temperature, as shown in Eq.(6).

$$\text{MMP}\_{\text{pure}} = 0.003 \ast T^{0.544} \left(\text{MW}\_{\text{C}\_{\text{5}+}}\right)^{1.006} \left(Y\_{\text{VOL}} | Y\_{\text{INT}}\right)^{0.143} \tag{6}$$

This minimum miscibility pressure (MMP) empirical correlation was appropriate for low permeability reservoirs. The characteristics of oil reservoir low permeability must be (vol/yint>1), where the experimental and published data were used in this correlation [35].

#### *2.2.7 Mansour et al. empirical correlation*

Mansour et al. [36] proposed a new method for predicting (MMP) of a multicomponent volatile oil reservoir. This model used twenty-live crude oil samples to correlate this unique formula with new constants. The data range for using this equation API from 40.5 to 26 and in range temperature from 160 to 246°F. The developed (MMP) equation gives good results to reduce the previous correlations errors, where (Er) was found to be 0.627%, (Ea) 2.4%, (Er) 0.627%, (R2) 94.82% (S), and 2.7%. Consequently, this new model has better accuracy than previous literature correlations, as shown in Eq. (7) [36].

$$\text{Ln(MMP)} = \pounds\_0 + \pounds\_1(\text{LnT}) + \pounds\_2(\text{LnMWT}\_{\text{CS}}{^+}) + \pounds\_3(\text{yVol/yint}) \tag{7}$$

where β0, β1, β2, β<sup>3</sup> are the coefficient values and have the following values 11.222, �0.355, �0.2069, and 0.039, respectively.

#### **Nomenclature**


**16**

*Carbon Dioxide-Oil Minimum Miscibility Pressure Methods Overview DOI: http://dx.doi.org/10.5772/intechopen.106637*

#### **Subscript**


#### **Author details**

Eman Mohamed Ibrahim Mansour1,2

1 PVT Lab, Production Department, Egyptian Petroleum Research Institute, Cairo, Egypt

2 PVT Service Center, Egyptian Petroleum Research Institute, Cairo, Egypt

\*Address all correspondence to: emanmansour84@yahoo.com

© 2022 The Author(s). Licensee IntechOpen. 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.

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#### **Chapter 3**

## Miscible Displacement Oil Recovery

*Nasser Mohammed Al Hinai and Ali Saeedi*

#### **Abstract**

Miscible gas injection (MGI) is an effective enhanced oil recovery (EOR) method used worldwide often for light oil recovery. In the petroleum industry, many MGI processes typically involve injection of an associated gas (AG) mixture or CO2, which have both been recognised as excellent candidates for such processes. The initial part of this chapter provides a broad introduction and background to the EOR techniques used worldwide as well as those implemented in Oman oil fields and briefly discusses their critical importance. Oman is one of the most active countries in terms of successful MGI processes in the Middle East, hence the emphasis given in this chapter to such projects in this country. The second part covers the technical details of the MGI process and the potential problems and challenges associated with it, while the third part focuses mainly on the common techniques used to control gas mobility during gas flooding including MGI. The impediments and challenges for wider application of the mobility control techniques are also covered. The last section presents a sample feasibility evaluation for a real oil field around the implementation of mobility control techniques for an MGI process.

**Keywords:** miscible gas injection, enhanced oil recovery, gas mobility control

#### **1. Introduction**

Over the past few decades, the rate of the new substantial oil discoveries has been on the decline. As a result nowadays, many oil companies are trying to maximise oil production from their existing reserves and maintain oil flow rates at or above the economic level through production optimisation and the use of enhanced oil recovery (EOR) techniques [1]. Enhanced oil recovery refers to the methods of increasing or maintaining the ability of oil to flow through interconnected pores towards the production wells by changing the physical and/or chemical properties of the in-situ fluidrock system. Presently, the average recovery factor (RF) from mature oilfields under the primary and secondary recovery is only 20–40% [2]. Given the earlier mentioned lack of substantial new discoveries, increasing the RF from matures fields has become important to meet the growing energy demand in the years to come.

During the life cycle of an oil field, the oil extraction may occur typically in three recovery stages of primary, secondary and tertiary (i.e. EOR). Essentially, the petroleum product is produced from the reservoir initially by the natural reservoir energy such as the solution gas drive, gas cap drive and aquifer influx [3]. This is often termed as primary recovery, where the first wells drilled in the field are able to produce the oil from the reservoir without any intervention. In this stage primarily, the pressure gradient between the reservoir and surface controls the hydrocarbon flow into the well and then to surface. Over time, the reservoir pressure may decline reducing the pressure at the bottom hole which may then become closer to the hydrostatic head of the fluid column in a production well reducing the oil flow rate achievable from the well. Subsequently, secondary recovery methods may be applied, for example, by injecting water or gas via injection wells into the reservoir to maintain the reservoir pressure and eliminate or minimise the previously observed decline in oil flow. This type of recovery methods has its own technical and economic limitations as may be determined by the cost and availability of injection fluids and/or the issues that may arise during the development of the in-situ flooding. For instance, in both water and gas flooding, the difference in fluid properties between the displacing fluids and to be displaced in-situ oil can result in unstable displacement, leading to a large oil volume left behind due to poor displacement efficiency and early breakthrough. Therefore, the application of such techniques may typically add up to only 40–50% of eventual oil recovery.

When the oil in a reservoir can no longer be produced by natural reservoir pressure (i.e. primary recovery), or by water or immiscible gas injection (i.e. secondary, improved recovery methods (IOR) or pressure maintenance), EOR techniques may be considered. In general, as briefly referred to earlier, EOR techniques aim to stimulate oil flow by overcoming the physical, chemical and geologic factors that inhibit the production of the remaining hydrocarbons [4]. One of the most widely implemented EOR processes today is thermal recovery, which involves heating the oil bearing interval with steam or hot water to reduce the oil viscosity. Miscible gas injection (MGI) is another most widely used approach today, which is carried out by the injection of a high-pressure gas, such as carbon dioxide or hydrocarbon-associated gas, to sweep additional oil towards the wellbores by employing a number of in-situ mechanisms such as oil viscosity and IFT reductions. Chemical agents dissolved in water and injected into the reservoir can also improve the displacement properties during a water flood. Currently, various EOR projects executed around the world, as shown in **Figure 1**, account for only 3.5% (3 million barrels per day (MMbpd)) of the

**Figure 1.** *Worldwide EOR projects contribute to global oil production [5].*

#### *Miscible Displacement Oil Recovery DOI: http://dx.doi.org/10.5772/intechopen.105757*

**Figure 2.** *The contribution of current EOR projects implemented in Oman oil fields [7].*

total world oil production (96 MMbpd) [5]. However, further application of these technologies has the potential to increase oil recovery from existing fields and new discoveries and alleviate oil supply shortage in the future [5, 6].

The application of EOR techniques in Oman may be considered as a successful example of how such techniques may be used to boost oil production and achieve substantial enhancements in recovery. Over the past decade, a number of EOR projects in the Middle East (ME) have been executed. Among the ME countries, Oman leads the way mainly owing to its declining overall oil production rate [7] which has seen EOR to become a major strategy to meet target oil production from its existing fields [8]. In 2007, this country's oil production declined to an average of 700,000 bpd. However, with the aid of EOR methods, the field operators have been able to increase the country's overall oil production to its current level of nearly 1 million bpd. Miscible gas injection is one of the EOR techniques used in the country. The largest fields produced using EOR techniques in Oman and the indicative contributions made by such techniques in each field are depicted in **Figure 2**. The daily oil production rate from these fields with implanting EOR techniques varies between 40 and 80 thousand bpd (Mbpd). While without EOR, it was 3–45 Mbpd making such techniques the key driver of Oman's oil production nowadays [9].

### **2. Miscible gas injection (MGI)**

The MGI is one of the most effective EOR methods used to enhance the production of light crude oil in the petroleum industry [10]. This method is PVT driven in which the injected gas (CO2, associated gas (AG) or natural gas liquids (NGL)), in addition to helping with pressure maintenance, would mix with and alter the properties of the in-situ oil allowing the otherwise trapped oil to become mobile and easily displaced [11, 12]. During the miscible gas flooding, the injected gas would become miscible with the reservoir oil at or above the minimum miscibility pressure (MMP) of the reservoir oil (**Figure 3**). By definition, the MMP is the pressure at which the mass transfer and molecular interactions between the gas and oil intensify forcing the physical and chemical properties of the two phases to converge [14, 15]. In other

**Figure 3.**

*Development of miscibility of injected CO2 in oil at miscible and immiscible pressures [13].*

words, upon reaching MMP, the gas acts as a solvent for the oil towards forming a single fluid phase (liquid) in the reservoir with the potential of effectively reducing the saturation of the remaining oil to near zero under ideal conditions [4]. During this process, the improved displacement efficiency of the flood is realised via three main mechanisms including substantial reduction in IFT (i.e. elimination of the interface between the two fluids and reduction of capillary pressure to zero), reduction of oil viscosity and oil swelling [16, 17]. The value of MMP depends on the reservoir temperature as well as the compositions of the injected gas and in-situ oil [18, 19].

In general, the miscibility process of the crude oil-gas system may occur through two paths of multi-contact miscibility (MCM) and first-contact miscibility (FCM) [20]. The MCM would take place if the in-situ pressure is equal to MMP which, as discussed previously, is a critical property to be taken into account for designing an MGI process [21]. The MCM may develop gradually via a number of processes including vaporising gas drive, condensing gas drive and a combination of the two drives [15]. On the other hand, when the reservoir pressure is adequately high and well above MMP, FCM would take place in which the injected gas would develop miscibility with the in-situ oil at all proportions as soon as they are brought in contact. Since FCM would only occur at high enough pressures, depending on the type of injectant used, achieving this type of miscibility could be challenging.

The type of the injected gas used for MGI depends on the gas availability and reservoir conditions [2] with the common gases used around the world being CO2, hydrocarbon gas mixture (AG, NGL), flue gas and N2 [20, 22]. Carbon dioxide, which has been most widely used in the United State, Canada and China [23], can achieve miscibility at relatively low pressures (when compared with other gases) and has a relatively high density (can be similar to oil). The latter can help to reduce the severity of gravity segregation and override which can negatively affect the sweep efficiency.

The use of this gas for flooding can also help to reduce the global level of CO2 emissions. However, some of the main challenges for a successful CO2 flooding in general are the availability of CO2 and corrosion in wells and surface facilities, which can result in considerable cost increases, in particular, for remotely located fields.

In the Middle East, the available CO2 supply is limited to those associated with large industrial sources [24] which, when combined with the earlier mentioned issues associated with using this gas, has made its wide application limited. However, the hydrocarbon gas injection could be considered for MGI processes more widely for which the produced AG is usually readily available from the field itself or those close by. On the other hand, as mentioned earlier, unlike CO2, conducting MGI using AG, depending on the gas composition, requires a relatively high pressure to achieve miscibility. To date, there have been three MGI projects (at either pilot- or field-scale) in the Middle East as reported in the literature [25]. Two of the projects involve miscible CO2 injection and the other utilises AG injection. The Rumaitha Field in Abu Dhabi was the first pilot miscible CO2 injection implemented in the region [25–28]. The second pilot CO2-EOR project has been implemented in Minagish Oolite Reservoir in west Kuwait [29]. The third project has been implemented in Field A located in the Harwell Cluster in southern Oman in which the field's AG mixture (CH4 enriched with light and heavy hydrocarbon fractions found in natural gas as well as considerable amounts of sour gases (3–5 mol % H2S and 10–25 mol % CO2)) is used for reinjection [30, 31]. As will be discussed in further details later with field case for improving the MGI process in this field.

Harweel Fields consist of a cluster of reservoirs deep within the tight carbonate oilbearing rocks in the south of Oman in the Petroleum Development Oman (PDO) concession area, as shown in **Figure 4**. The figure also presents a geological cross section of the carbonate stringers, as encased in the Ara salt and the general geological setting of the area. The fields are expected to make a significant contribution to the Sultanate's oil production over the coming 30 years. The reservoir rocks in these fields are more than half a billion years old (where the hydrocarbon deposits are among the oldest in the world) located at a depth of about 5 km, making them PDO's deepest producing oil fields [33, 34]. As indicated earlier, the MGI in Field A, located in the cluster, has already begun in which the source of the injection gas is the Field's AG [30]. The produced AG mixture is reinjected into the reservoir at high pressures of up

#### **Figure 4.**

*Geological cross section of the carbonate stringers (left) and an aerial overview of Harweel Fields in southern Oman (right) [32].*

to 45 MPa during which the injected gas develops miscibility with the in-situ oil under the reservoir's high temperature (up to 377 K). The reservoir contains a light crude oil with a typical gravity of 42°API and a viscosity of 0.23 cP at reservoir conditions. It was initially estimated that up to 47% of the Field's original oil in place (OOIP) could be recovered with the MGI process [33]. However, it has been realised since then that the presumed RF might not be eventually achievable due to the technical and operational challenges faced in this field, e.g. premature gas breakthrough and high degree of reservoir heterogeneity. As mentioned earlier, this chapter will be mainly focusing on addressing some of the technical challenges experienced during MGI in Field A and similar fields by proposing and testing a novel mobility control technique applicable to such a high-pressure and temperature environment.

#### **3. Challenges associated with MGI process**

As with other EOR techniques, MGI can be economically expensive and technically challenging to implement [35]. For example, even when the injection gas is readily available on site (e.g. associated gas), gas processing, handling and compression as part of the expected gas recycling scheme can be costly [2, 36]. Full life cycle economics of a gas injection project, therefore, must be taken into account to justify its implementation. In addition, as an example, a technical challenge in achieving a profitable MGI is the instability of the oil displacement process in the reservoir mainly due to the expected unfavourable mobility ratio and possible gravity segregation whose effects may be intensified by the level of reservoir heterogeneity.

From a more general technical perspective, the efficiency of an MGI is controlled by the collective effects of several physical forces acting on the displacement front. These forces include the viscous forces that stem from viscosity contrast in the flood, gravity forces caused by fluid-fluid density differences, dispersive forces driven by the fluid concentration gradients and, finally, the capillary forces that have roots in the IFT between any immiscible fluids. The large differences in fluid viscosities can cause viscous fingers at the displacement front. If the vertical permeability in the reservoir is quite high, a pronounced density difference can cause gravity segregation. Both of the above have the potential to leave a large amount of oil unswept. The capillary and dispersive forces tend to enhance the fluid mixing but do not often overwhelm the viscous fingering [37, 38]. Therefore, the gravity and viscosity forces are the essential forces driving the instability of the oil displacement process during MGI [39]. Provided in the following two subsections are further details about the underlying mechanisms behind these two forces and how they may interfere with the performance of an MGI process. Possible mitigation strategies to lessen their effects will be outlined and adequately discussed in later sections of this chapter.

#### **3.1 Viscous fingering**

When a fluid is injected into a reservoir to displace another, there is almost never a collective perfect piston-like displacement across the entire reservoir interval. Especially in a gas flood, unstable displacement due to viscous fingering can lead to uneven or poor sweep, as depicted in **Figure 5** [40]. Viscous fingering is generally defined as a hydrodynamic instability that occurs between two fluids of differing mobility/

**Figure 5.**

*Effect of viscous fingering on the development of areal sweep efficiency against time (t) in a quarter of a five-spot flood pattern during gas flooding, (A) an unstable displacement with poor macroscopic sweep, (B) a stable displacement good with macroscopic sweep, ( ) an injection well and (O) a production well [40].*

viscosity in the porous media that could lead to reduced sweep efficiency and early breakthrough [39, 41, 42]. The terms mobility, mobility ratio and that in a gas flood mobility ratio may be interchangeably used with viscosity ratio would be defined and discussed shortly. In MGI, there are several parameters that affect the viscous instability at the fluid-fluid interface including fluid viscosities, degree of miscibility, gas dissolution and exsolution and reservoir heterogeneity [39, 42–44]. However, the viscosity contrast and permeability heterogeneity are the two that mainly control the dynamics of the fingering phenomenon [37, 45]. The importance of mobility/viscosity ratio may be further realised after defining the mobility ratio (M) as a widely used criterion to characterise and determine the occurrence and possible effects of viscous fingering.

As indicated by Eq. (1), the mobility of a fluid (λi) in a porous medium may be defined as the ratio of effective permeability (K*i*) and effective viscosity (μi) experienced by the fluid while flowing in the medium [40, 46, 47],

$$
\lambda\_i = \frac{\mathbf{K}\_i}{\mu\_i} \tag{1}
$$

Subsequently, for any fluid-fluid displacement, such as an MGI, the mobility ratio (M) can be simply defined as the mobility of the displacing fluid over that of the displaced fluid [40, 47]. For instance, Eq. (2) defines M for an MGI process where gas displaces the in-situ oil.

$$\mathbf{M} = \frac{\lambda\_{\text{gas}}}{\lambda\_{\text{oil}}} = \frac{\mathbf{K}\_{\text{pu}} /\_{\mu\_{\text{pu}}}}{\mathbf{K}\_{\text{oil}} /\_{\mu\_{\text{oil}}}} \tag{2}$$

Where μoil and μgas are the oil and injected gas viscosities, respectively. For a miscible displacement, where the gas solvent may displace the oil at irreducible water saturation and the effective permeability to both fluids may be considered to be the similar, Eq. (2) may be reduced to Eq. (3) [40]. Furthermore, during gas flooding, due to the large viscosity contrast between the gas and the in-situ oil, viscosity ratio may be considered adequate for qualitative evaluation of viscous

instability in the flood [40, 45, 48]. Therefore, for the purpose of qualitatively characterising the effect of viscous fingering on the performance of an MGI process, the viscosity ratio may be used interchangeably with the mobility ratio [40].

$$\mathbf{M} = \frac{\mu\_{\text{oil}}}{\mu\_{\text{gas}}} \tag{3}$$

During its development, the severity of viscous fingering increases with increase in the mobility/viscosity ratio of the fluid system. If M is larger than unity, the displacement becomes unstable resulting in the development of viscous fingers. Therefore, to achieve a stable displacement, where possible, the viscosity of the displacing fluid may be increased or its effective permeability reduced until the value of M approaches unity or less. For instance, if the injected gas viscosity is increased, the gas mobility may be suppressed. Hence, the severity of the viscous fingering and the chance of developing premature breakthrough can be reduced, resulting in improved displacment efficiency. **Figure 6** demonstrates the effect of mobility ratio on the area sweep efficiency of an MGI process as reported by Habermann [40]. As can be seen from the figure, when M ¼ 1, the ultimate areal sweep reaches as high as 99%, however, if M increases to 38.2, the areal sweep would decrease by more than 20%. The physical development of viscous fingers as the mobility ratio changes for the cases presented in **Figure 6** is demonstrated by the diagrams included in **Figure 7**. As can be seen in this figure, the displacement is characterised as stable if the value of M is one or lower. The effect of M as demonstrated through the above sweep values and **Figures 6** and **7** was for a homogeneous porous system. The presence of permeability heterogeneity would also make considerable contribution towards initiating and development of viscous fingering [41]. A high permeability layer would present a preferential flow path for the fingering of the injected gas causing early gas breakthrough and a low overall oil recovery factor [28, 29, 49].

#### **Figure 6.**

*Areal sweep efficiency as a function of mobility ratio and pore volumes of displacing phase injected for an MGI process [40].*

**Figure 7.**

*Viscous fingering growth for different mobility ratio and injected pore volume [40].*

#### **3.2 Gravity segregation**

As indicated earlier, another possible major technical challenge faced by an MGI process that influences the vertical sweep efficiency is the gravity segregation or gravity override. The injected gas (such as CO2 or hydrocarbon gas) is usually less dense than the in-situ oil which may lead the injected gas to flow upwards, rather than lateral, forming a gravity tongue [49, 50]. Such a behaviour, similar to unfavourable mobility ratio, would result in early gas breakthrough and reduced vertical sweep efficiency in horizontal MGI processes as depicted in **Figure 8**. The effect of gravitational force on an MGI process has been studied by Moissis et al. [51] using numerical simulation. They found two dimensionless parameters of relevance, the dimensional density difference (Δρ):

$$
\Delta \rho = \frac{\rho\_{\rm o} - \rho\_{\rm g}}{\rho\_{\rm g}} \tag{4}
$$

and the dimensionless gravity number (Ng):

$$\mathbf{N}\_{\rm g} = \frac{\left(\rho\_{\rm o} - \rho\_{\rm g}\right)\mathbf{g}\mathbf{K}\_{\rm e}}{\mathbf{q}\mu\_{\rm o}}\tag{5}$$

**Figure 8.**

*(A) Reservoir heterogeneity due to permeability variation versus depth in field a located in South of Oman, (B) example effect of possible gravity segregation on vertical sweep efficiency.*

where Ng represents the ratio of gravity forces to viscous forces, ρ<sup>o</sup> and ρ<sup>g</sup> are the oil and gas densities, respectively, Ke is equivalent permeability, μ<sup>o</sup> is the oil viscosity, q is the flow rate of the less viscous fluid in the porous medium of interest, and g is the gravitational acceleration. The simulation results obtained by Moissis et al. [51] show that the gravity force does not influence viscous fingering growth at small Ng values indicating the dominance of the viscous forces under such a condition [51]. As Ng increases to larger values, the gravity force begins to influence the growth rate of viscous fingering in the upper part of the porous medium. For sufficiently large Ng values, gravity override completely dominates the displacement where, eventhough the viscous fingering can still occur near the gravity tongue, it is suppressed in the bottom part leaving this part of the porous medium completely unswept. Overall, as may be expected, with increase in Ng the gas breakthrough occurs earlier reducing the overall oil recovery [51].

Further interplay between the gravity and viscous forces towards controlling the efficiency of a gas flood may be deduced by further scrutiny of Eq. (5). Controlled by the magnitude of Ng, the effect of the gravitational force is expected to be even larger at high flood viscous ratios because the gravity to viscous forces ratio is inversely proportional to the viscosity of the fluid available in the porous medium. At the beginning of the flood, as defined by Eq. (5), this ratio is equal to Ng. However, as the displacement proceeds and more of the less viscous gas enters the porous medium at constant flow rate, the gravity to viscous forces ratio begins to increase resulting in more sever gravity override. Such an effect would be more pronounced in the case of floods characterised by a high viscosity ratio [51].

Scott [50] has suggested to combat the gravity segregation by adjusting the density of the miscible gas injected as part of an MGI. For example, the pressure within the formation can be maintained high enough so that the density of the injected fluid

*Miscible Displacement Oil Recovery DOI: http://dx.doi.org/10.5772/intechopen.105757*

approaches that of the reservoir oil. However, for measurable outcomes in general, the density of the miscible fluid should be maintained within about 10% of the density of to be displaced in-situ oil [50]. Furthermore, this technique may be proven difficult and impractical if large injection volumes are required to maintain the reservoir pressure. Scott [50] has also indicated that the density adjustment may be obtained by injecting carbon dioxide or intermediate natural gas fractions (C2H6, C3H8 and C4H10). Carbon dioxide in its supercritical state is capable of exhibiting a density greater than that of the reservoir oil [50]. However, hydrocarbon gases alone may not normally achieve a density equal or close to that of the resident crude oil under typical reservoir conditions; therefore, sever gravity override could still occur. Another technique to increase the density of injected gas is the use of chemical additives; however, to date, suitable and viable chemical additives to be used for this purpose are yet to be developed [52]. As suggested in the literature, the mitigation of the gravity segregation can be possibly achieved by mobility or conformance control [52].

#### **4. Gas mobility control techniques**

As mentioned above, the major challenge with the ongoing MGI flooding in the oil field is the unfavourable mobility ratio. This challenge can be addressed by the implementation of several approaches as proposed in the literature (although mainly for CO2 flooding) including water alternating gas flooding (WAG) [53–55], foam flooding [56–62] and increasing the gas viscosity using the addition of polymers as thickening agents [52, 63–71]. The common main objective of these approaches would be to control the gas mobility effectively and, as a result, increase the sweep efficiency of the gas flooding [72]. Further technical details about each of the abovementioned techniques are provided in the upcoming subsections of this chapter.

#### **4.1 WAG process**

As an EOR method, the WAG process is defined as the injection of a gas (e.g. CO2 or hydrocarbon gases) and water alternately into an oil-bearing formation (**Figure 9**). The WAG injection scheme was initially proposed by Claudle and Dyes in 1958 [55] to improve sweep efficiency during gas flooding. Their study showed that this injection scheme would result in the reduction of the relative permeability to the gas phase and suppress its mobility. In other words, the WAG would improve the sweep efficiency of the injected gas by using water to control the gas mobility and stabilise the displacement front. In general, depending on the MMP of the in-situ oil, this technique can be classified into two categories of miscible and immiscible WAG displacements [73]; however, as reported in the literature, the majority (79%) of the historical WAG field applications fall into the miscible category [74, 75]. In some recent field applications, in an injection scheme similar to WAG, the produced gas has been reinjected through water injection wells to improve the oil recovery and help to provide pressure maintenance [76]. The majority of the WAG injection projects are found onshore (88%), and few others are reported to have been implemented in an offshore environment (12%) [75].

In general, there are a number of factors affecting the performance of the WAG process including the degree of reservoir heterogeneity, in-situ fluid properties, injection technique, miscibility conditions and other WAG parameters such as the individual gas and water slug sizes and their size ratio (WAG ratio), number of injection

#### **Figure 9.**

*A typical WAG injection process as an EOR method that involves the injection of gas and water alternatively into an oil reservoir.*

cycles and injection rates [77–79]. Similar to other EOR processes, the WAG flooding has a number of advantages and disadvantages that will be presented and discussed below.

#### *4.1.1 The mechanisms and factors influencing WAG flooding*

During WAG injection, the improved recovery is not often achieved through modifying the fluid properties of each of the injected phases, it rather tends to combine the advantages of each of the continuous gas or continuous water floods through creating a synergism between the in-situ flow properties of the two phases if injected on their own. Overall, when WAG injection is applied in an oil reservoir, it may yield favourable outcomes through several mechanisms [80]. Firstly, the injection process may help to maintain the reservoir pressure above the MMP of the oil resulting the achievement of the more desirable miscible flood. Secondly, the injected gas mobility is reduced by supressing the gas relative permeability in any existing preferential flow channels. This is achieved by the increase in water saturation in these zones and therefore reduction in gas saturation suppressing the possibility of gas channelling and viscous fingering [52, 81, 82]. Thirdly, in the case of a miscible flood, the excellent microscopic displacement efficiency of the miscible gas flooding is put into use across a larger portion of the reservoir by the mobility control and conformance control provided by the water phase, leading to higher oil recovery. Lastly, compared with a continuous gas injection process (e.g. continuous MGI), the WAG flooding decreases the amount of the gas needed for injection leading to possible

#### *Miscible Displacement Oil Recovery DOI: http://dx.doi.org/10.5772/intechopen.105757*

improvement in the economics of the overall flooding process. Considering the collective advantages mentioned here, the WAG injection process may become a viable option for some fields around the world.

Laboratory experiments have been used to study the effect of various parameters such as WAG slug size, WAG ratio (tapering), number of WAG cycle and injection flow rate on the performance of WAG [53, 54, 73, 83–89]. In general, these parameters show strong effects on the oil recovery trends of a WAG injection. It has been found that, in general, decreasing slug size and WAG ratio and increasing the number of WAG cycles would lead to a higher oil recovery [53, 80]. However, the optimum WAG ratio often depends on the wettability of reservoir rock, in-situ fluid properties and the type of gas being used as well as economic evaluations [53]. The optimum WAG ratio is considered as a key parameter for the successful implementation of a WAG injection process. A high WAG ratio may lead to an excessive water injection into the reservoir giving rise to the water blocking effect where the water phase would surround the trapped oil at low permeable zones and reduce accessibility by the injected gas decreasing the overall oil recovery. On the other hand, if the ratio is too low, the conformance control of the WAG flood would be lost and the injected gas would penetrate through the reservoir very fast under the effect of unfavourable mobility ratio and lead to early breakthrough. Overall, the experimental results have demonstrated that the WAG process may help to suppress viscous fingering and lead to increased oil recovery in gas flooding [74, 75].

#### *4.1.2 Challenges of WAG flooding*

The WAG injection has been successfully applied in several oilfields worldwide demonstrating that it could result in considerable incremental oil recovery at the field scale (5–10% of oil initially in place (OIIP)) [90]. However, some published literature also indicates that some of the field-scale WAG processes have not reached their expected target recovery factors, especially in naturally fractured, highly permeable and highly heterogeneous reservoirs [75]. Furthermore, the field-scale implementation of this technique has also helped to identify a number of challenges that may be faced by the field operators. Such challenges are presented and discussed below by first dividing them into the two categories of operational challenges versus those of subsurface reservoir related.

#### *4.1.2.1 Operational issues*

A numbers of operational related issues have been reported in the literature including [74, 75, 90].

#### *4.1.2.2 Reduced injectivity*

The ability to inject the required amounts of gas and water through the injection wells is critical towards achieving the desirable WAG performance. Reduced injectivity can result in a pressure reduction in the reservoir, which may impact on, for example, miscibility, performance of the displacement and the eventual production yield. This issue may be caused by changes in the phase relative permeabilities and/or near wellbore formation damage. In general, the field trials have shown that the reduced injectivity may be experienced for the water injection rather than the gas injection stage during the alternating injection of the two phases [75, 90].

#### *4.1.2.3 Corrosion*

Corrosion problems have been reported in many projects that have involved WAG injection. Often such issues have been encountered because the pre-existing injection and production facilities were not initially designed to handle the WAG injection process. Six fields are reported to have experienced corrosion problems, mainly on the injection facilities. The existing case studies indicate that in most cases, such problems could be adequately addressed by using corrosion-resistant materials in the manufacture of equipment, coating the flow-lines and chemical treatments [75, 90].

#### *4.1.2.4 Asphaltene, scale and hydrate formation*

Asphaltene and scale precipitation and hydrate formation are among other problems that have been experienced in various WAG field trials. These problems would lead to production disturbance and even flowlines blockage which may increase the operating costs of a WAG process. Three fields (East Vacuum, Wertz Tensleep, Mitsue) have experienced asphaltene precipitation, and two fields (Ekofisk and Wasson Denver) have reported the formation of hydrate in the injection wells due to the low temperature in the injectors or cold weather at the wellhead. Some of these problems could be resolved by chemical treatments [75, 90].

#### *4.1.2.5 Subsurface reservoir issues*

Besides the operational problems discussed above, there are also a number of issues related specifically to the subsurface and fluid flow in the bulk of the reservoir presenting challenges for the WAG implementation:

#### *4.1.2.6 Premature gas breakthrough*

Unexpected early gas breakthrough has been reported in several WAG field applications despite the fact that WAG is often implemented to combat this issue in particular. The main cause for this problem has often been inadequate characterisation of the reservoir, poor design of the WAG process or limitations imposed by the existing versus required infrastructure (e.g. limited number of injection/production wells). Regardless of the cause, early gas breakthrough would often occur due to gas channelling through highly permeable layers or gravity override [91, 92]. The early gas breakthrough leads to loss of reservoir pressure and lost miscibility in a miscible WAG project [93, 94]. As reported in the literature, five oil fields (University Block 9, Juravlevsko-Stepanovskoye, Lick Creek, Caroline and Snorre) have experienced this problem because of gas channelling [93, 95–98]. Unfortunately, this problem is hard to resolve as once occurred, its root causes (as mentioned at the beginning of this paragraph) are difficult to address. However, adequate reservoir characterisation before the implementation of this mobility control technique can be helpful in avoiding unexpected early gas breakthrough [75].

#### *4.1.2.7 Oil trapping*

Several studies have demonstrated the occurence of oil trapping by water in the WAG flooding [99–102]. This phenomenon is also referred to as water blocking [102]. During the WAG injection, the injected mobile water traps/encases the residual oil

#### *Miscible Displacement Oil Recovery DOI: http://dx.doi.org/10.5772/intechopen.105757*

which then becomes difficult for the gas phase to access and mobilise. Therefore, a high residual oil saturation may be left behind in the reservoir even after WAG flooding. It has been determined that rock wettability and WAG ratio can strongly affect the oil trapping with being more sever in the case of water-wet rock formations or high WAG ratios [80, 99, 100, 103].

#### *4.1.2.8 High water production*

The injection of large amounts of the water into the reservoir (i.e. high WAG ratio) can cause high water saturation [104] leading to excessive water production and, hence, reduced oil recovery [105]. In addition, the excessive water production would require additional water treatment capacity that brings about additional costs impacting on the project economics [103].

#### **4.2 Gas foam flooding process**

#### *4.2.1 Gas-foam generation and foaming agents*

Gas-foam injection is another approach to combat the conformance and mobility limitations encountered in an MGI process. Furthermore, this technique may also bring about some of the advantages of the chemical EOR due to the chemical additives required for foam stabilisation and generally better foam generation. The foam flooding was first introduced by Bond and Halbrook in 1958 to show that the foam generated by the injection of an aqueous surfactant solution and miscible/immiscible gas could increase sweep efficiency [106]. With the favourable results obtained from the above study in the subsequent years, it was proposed to use foam injection as a means of gas mobility control. However, the concept did not become widely known and immediately adopted due to the lack of understanding of mobility control mechanisms behind the foam flooding [107].

In the context of fluid flow in porous media, a foam is generally defined as a gasliquid mixture where the liquid phase exists as a continuous wetting phase in the rock, whereas all or parts of the gas form the discontinuous phase surrounded by a thin liquid film or Lamellae [60]. According to the literature, the research conducted in the area of gas foam flooding mostly relates to CO2-EOR because the required chemicals are much easier to dissolve in CO2 towards the generation of a CO2 foam at reservoir conditions [72]. A gas foam may be stabilised by the addition of effective surfactants, which contain a hydrophobic and hydrophilic segment [72]. Surfactants then can be either water-soluble or CO2-soluble [60, 108, 109]. The selection of surfactant depends on the reservoir conditions. If the reservoir condition is suitable for a surfactant to be soluble in the injected gas, then injection of water with the surfactant can be eliminated [110]. Numerous CO2 soluble surfactants have been experimentally identified [56, 109, 110]. For example, the hydrocarbon-based ethoxylates surfactant has been suggested by Scheievelbein et al. as a CO2 foam agent instead of using a water-soluble surfactant [110]. The other reported surfactant products include Tergitol TMN-6, oligo (vinyl acetate), poly(ethylene glycol) 2,6,8-trimethyl-4-nonyl ethers, and ethoxylated amine surfactant [111–115]. For miscible hydrocarbon gas flooding, only water-soluble surfactants can be used as the foaming agent because no effective surfactant directly soluble in hydrocarbon gases for gas-foam generation has been reported in the literature [57]. Nine water-soluble surfactants have been identified for foam generation with hydrocarbon solvents,

including alkanolamides, amine oxides, betaine derivatives, ethoxylated and propoxylated alcohols and alkylphenols, ethoxylated and propoxylated fatty acids, ethoxylated fatty amines, fatty acid esters, fluorocarbon-based surfactants and sulfate and sulfonate derivatives [57]. As the temperature increases, most of the watersoluble surfactants become less soluble in water. Therefore, it may be necessary to evaluate the surfactant solubility in either CO2 or water for application in hightemperature reservoirs [72, 116].

The foam used for gas foam flooding may be generated in several ways as discussed in the literature. It may be formed within the target porous media by alternating injection or co-injection of a suitable surfactant and gas (CO2 or hydrocarbon gas mixture). In the case of CO2 foam flooding, the foam can be formed when a surfactant is dissolved into CO2 (usually in supercritical state) and then injected into the porous media, without requiring the injection of a liquid slug [59]. The foam can also be generated at the wellhead by the simultaneous injection of the gas and surfactant solution. Then, as the foam leaves the wellbore, it could be re-formed and strengthened as it enters the micropores of the reservoir rock [72].

As a gas foam enters a rock formation, it would need to propagate through the entire formation suppressing the high gas mobility for the whole duration of the flood. However, the injected foam is not often thermodynamically stable under in-situ conditions, and therefore, the two-phase foam system may collapse with time. On the other hand, as mentioned earlier, the passage of the fluids through the porous rock formation could result in the regeneration of the foam due to shearing effects applied by the micron-sized tortuous pores and pore channels [117]. Therefore, in order to have an effective foam for mobility control, the rate of in-situ foam generation would need to be equal to or greater than the rate of its decay [72]. In general, the foam propagation at the large reservoir scale and the foam stability are the main challenges faced by the gas foam flooding technique.

#### *4.2.2 Main mechanisms of gas-foam flooding*

A gas foam may be used as part of an EOR scheme for two purposes [57]. Firstly, it can be designed to reduce the gas mobility to a level that is comparable to or even less than that of the displaced oil so that the gas viscous fingering and channelling can be effectively suppressed. Thereby the areal sweep efficiency could be improved considerably. However, it is worth noting that the reduction level in the foam mobility has to be optimised and controlled to avoid the prohibitive pressure drop in the reservoir caused by extremely low foam mobility. Therefore as a compromise, a weak and modest foam may be generated by varying the surfactant concentration in a gas-foam injection [118]. The second possible purpose of using a gas foam is for conformance control or blocking of a thief gas channel to divert the injection fluids away from it and into other unswept lower permeability oil-rich zones to mobilise the otherwise bypassed oil [72, 109]. Typically, this can be achieved by the alternating injection of an aqueous solution with a high concentration of a surfactant [57]. The high concentration of surfactant then generates a strong foam that would flow in the highly permeable or thief zone [118] resulting in the diversion of the gas flow into the lower permeability zones.

The enhanced recovery of a gas foam injection is usually achieved through a number of different mechanisms as summarised and briefly discussed below.

#### *4.2.2.1 Stabilising the displacement front*

The efficiency of a fluid-fluid displacement in a porous medium is in general controlled by the three gravity, viscous and capillary forces [60, 119]. Therefore, the manipulation of these forces can result in enhanced recovery. Concerning the application of a gas foam during a gas flooding process such as MGI, the mobility control and, therefore, stabilisation of the flood front may be achieved by the higher viscosity and reduced relative permeability of the gas foam both relative to the case of injecting the gas on its own. Typically, these effects may be achieved through two mechanisms [60]. The first mechanism is related to the movment and re-arrangement of bubbles due to the local gradient in the surfactant concentration and, therefore, the interfacial tension. The surfactant movement within the liquid film (Lamellae) lowers the surface tension between the two phases (liquid and gas) that slows down the bubble motion and causes an increase in the gas phase effective viscosity [120–122]. The second mechanism that reduces the gas-foam mobility is gas trapping [123, 124]. As the foam injected and/or formed in a porous medium, as also indicated earlier, it prefers to flow through highly permeable and porous zones, while the low permeability areas with small pores remain occupied by the wetting phase [125] (**Figure 10**). Thus, the gas bubbles may enter and become trapped in the intermediate size pores, where a large fraction of foam bubbles are immobilised due to the high enough capillary pressure [59]. Nguyen et al. [126] found that the amount of trapped gas in this form is governed by several factors, such as the foam texture, pore geometry and pressure gradients. The blocked intermediate size pores decrease the pore volume available for the gas foam to flow through, thus the reduced relative permeability and suppressed gas-foam mobility [60].

A gas foam can help to combat gravity segregation too [60]. **Figure 11** demonstrates the effectiveness of a CO2 foam towards stabilising the displacement front in the X-ray CT scanned core-flooding experiments conducted by Wellington and Vinegar [127]. As can be seen from the left-hand side images, the researchers found that CO2 injection alone would lead to the formation of a gravity tongue, whereas the

#### **Figure 10.**

*A micro-pore illustration of foam flow and gas trapping in the porous media. The cross-hatched spaces represent the solid grains, and the dotted spaces indicate the wetting liquid [60, 117].*

#### **Figure 11.**

*X-ray CT scan images for (A) a CO2 miscible flood (blue) in a core saturated with oil (red) and residual brine (yellow) and (B) CO2-foam flooding (blue) in a core saturated with oil (red) and a surfactant solution (yellow) [72, 127].*

right-hand side images show that the CO2-foam injection prevented the gravity and viscous instabilities towards the uniform displacement of the in-situ oil.

Overall, based on the discussion presented so far, a gas foam would not change the gas phase density but exhibit its effectiveness by suppressing the gravity and viscous forces, leading to stabilisation of the displacement front.

#### *4.2.2.2 Reducing the capillary force*

Capillary pressure is usually held responsible for the bulk of the entrapped oil (often non-wetting phase) in rock formations. That is why Zhang et al. [128] point out that the removal of the trapped crude from a reservoir rock needs ultra-low interfacial tension through an emulsification mechanism. The capillary number as set out in Eq. (6) defines the ratio between viscous and capillary forces acting on a displacement. The lower the interfacial tension (low capillary forces), the higher the capillary number and, therefore, the more dominant would be the viscous forces resulting in higher recoveries.

$$\mathbf{N}\_{\mathbf{c}} = \frac{\mathbf{K} \Delta \mathbf{P}}{\sigma \mathbf{L} \cos \theta} \tag{6}$$

Where Nc: capillary number, dimensionless, K: absolute permeability of the porous medium, ΔP: pressure drop along the porous medium, σ: the interfacial tension between the two fluids, L: length of the porous medium, and θ: contact angle.

Once during foam injection, the surfactant in the injected slugs proceeds through the porous rock, different interactions occur at oil, foam and rock interface [129] leading to ultra-reduction of the interfacial tension between the oil and water resulting in the formation of an oil-in-water emulsion. Accordingly, the capillary force reduces to near zero allowing the emulsion to move through the pore throats (**Figure 12**) resulting in enhanced recovery [60].

**Figure 12.**

*(A) A high interfacial tension results in large capillary force, which prevents an oil droplet from crossing through the downstream pore throat, (B) ultra-low interfacial tension leads to near zero capillary force, which allows the oil droplet to flow through the pore throat and be produced [59].*

#### *4.2.2.3 Altering the rock wettability*

The wettability of a porous rock formation is an essential factor to be taken into account in its characterisation because of its impact on the bond between oil and rock, the multiphase flow behaviour and distribution of fluid saturations in the reservoir [108]. Wettability alteration may occur in the foam flooding process due to the interactions between the surfactants used and the rock surface [59]. According to Eq. (6), the capillary number can also be increased by changing the contact angle, which means altering the rock wettability. As mentioned before, increasing the capillary number can result in lower residually trapped oil [59]. The importance of wettability alteration is not often considered in both experimental and simulation work, because of the erroneous assumption that all rocks remain water-wet during foam injection, and it is difficult to quantify the reservoir wettability in a meaningful and repeatable manner [130]. Although Charanjit and Bernard [131] do not agree that wettability may change due to a foaming agent, in a number of other studies, wettability alteration due the surfactant adsorption has been reported to change porous rocks from oil-wet to water-wet [131–133].

Overall, the foam injection process can enhance the oil recovery by mobility control in combination with ultra-low IFT and possible alteration of the rock wettability due to the presence of surfactant in the foam.

#### *4.2.3 Challenges and field application for gas-foam EOR*

The application of the gas-foam process in oil fields for mobility control has shown to be technically and economically challenging. This is because the effectiveness of a gas foam flooding highly depends on several parameters such as oil type, oil and water saturation, brine salinity and pH, surfactant formulation and concentration, reservoir heterogeneity, capillary pressure and gas flow rate [134, 135]. For example, a high oil saturation and low water saturation in the presence of light oil may cause the foam to decay and collapse [136]. As a consequence, before applying a foam EOR process, it is extremely important to gain a comprehensive understanding of the physical aspects of the process and how the foam may flow and behave once injected through a porous rock formation. The two main broad technical and operational difficulties in applying foam EOR at the large field scale are described below.

#### *4.2.3.1 Foam stability and propagation*

According to the numerous studies conducted to date, it may be difficult to achieve a stable and reliable foam generation under the harsh reservoir condition (high temperature and high salinity) often encountered and also control the propagation of the foam over large distances in the reservoir scale. Under high salinity and high temperature, the gas foam cannot be stabilised with the surfactant, because under such conditions the surfactant solubility in water or CO2 would be reduced resulting in its precipitation onto the rock surface [115, 137]. In addition, with the loss of the surfactant, the necessary ultra-low IFT may not be achievable [138, 139]. The levels of oil and water saturations are other parameters that affect foam stability. Mayberry and Kam [140] examined the foam strength at different oil and water saturations. Their experimental results indicate that the apparent foam viscosity is significantly reduced at oil saturations greater or lower than a critical oil saturation. The presence of the oil in the formation has a strong effect on the foam rupture and breakdown due to the interactions occurring between the foam lamellae and the oil phase [141]. Law et al. [142] also found that foam is degraded if the oil saturation exceeds critical foaming oil saturation of the surfactant. It is also shown that the light and less viscous oils are more destructive to foam stability than heavy oils [136]. Moreover, the reservoir water saturation is crucial for the foam stability. When a foam is injected at water saturations below a critical value, which corresponds to a limiting capillary pressure, the foam may begin to coalesce and dry out. It should be noted that below the critical water saturation and above the critical oil saturation, the foam is eliminated [56, 136].

#### *4.2.3.2 Scale-up from pilot to full field application*

There have been several CO2-foam trials performed since 1990 mainly in the United States [143–145]. Some of these, such as that performed in Joffre Viking oil field, were unsuccessful, because of the foam propagation control failure [146]. On the other hand, a few of the pilot tests have been successful, including that conducted in the Rock Creek Field [147] and Northward-Estes Field. In Northward-Estes Field, it was observed that the foam injection led to reduced CO2 injectivity by 40–85% [143]. Several other pilot studies were conducted using CO2 foam in East Vacuum Grayberg/ San Andreas Unit [148] and SACROC Field in West Texas [149, 150], all of which proved that CO2 mobility could be reduced and oil production increased. However, a transition from pilot scale to a wider field application has not been implemented due to various challenges such as issues associated with chemical supply and transportation, processing and separation of the produced fluids, offshore supply and also safety concern [151–154].

#### **4.3 Direct gas thickeners**

The use of direct gas thickeners is another method that brings together the combined possible advantages of using chemical additives and MGI. This technique has been recognised as a "game-changing technology" for mobility control, which was first reported in late 1960 [68, 69, 72, 155]. Since then, the interest in synthesising and designing affordable gas thickeners has been carrying on steadily. However, until now the term "gas thickener" has been used in laboratory investigations only, and its effectiveness has not yet been verified in any field-scale applications around the

world. In general, this technique involves increasing the injected gas viscosity by directly adding chemicals that exhibit good solubility in common supercritical fluids (SCF) used for EOR such as CO2 or hydrocarbon solvents. Chemicals that may increase the viscosity of an SCF include entrainers, conventional oligomers and polymers and small associating compounds [156]. In an ideal situation, chemical compounds need to be readily soluble in the dense CO2 or hydrocarbons solvents and insoluble in both crude oil and brine at reservoir conditions [52]. It should be noted that the thickening level of the gas is not expected to affect its injectivity because this solution would exhibit a shear-thinning behaviour near the wellbore which facilitates the mobility of the thickened gas in this area but, the mobility ratio of the gas flood would be improved in the bulk of the rock formation leading to enhanced recovery (**Figure 13**). In addition, the thickened gas would uniformly flow into different zones, allowing the gas to also mobilise the trapped oil in the low permeable zones. In other words, this technique can be applied as a way of improving the flood conformance and mobility control as illustrated in **Figure 13**.

Two fundamental strategies have been introduced in the literature to increase the injected gas viscosity [157].

**Direct dissolution of polymers**: In this strategy, a gas thickener is typically a synthesised or identified polymer or oligomer that promotes attractive interactions and dissolution with gas molecules. However, it has been recognised that the use of polymers with extraordinary molecular weight for the above purpose would be quite challenging since most of the SCF fluids are very stable and weak solvents due to the very low dielectric constant, no dipole momentum and sometimes low density. The

**Figure 13.** *Simplified illustration of a thickened gas flooding.*

intermolecular attractions between the polymer molecules are typically strong enough at ambient temperature so that even stirring them would be insufficient to attain dissolution. Therefore, they may only dissolve in a gas solvent at elevated pressure and temperature because such conditions give rise to the intermolecular forces between the solvent-polymer segments or solvent-solvent or polymer segment-segment pairs in the solution given by difference on the free volume between the polymer and gas solvent and the free energy [158]. In addition, heat may be required to weaken intermolecular interactions between the polymer molecules (e.g. hydrogen bond) [158]. Another approach for obtaining high solubility of the polymer in solvents is to introduce associating or functional groups in the polymer's molecular chains, for example to become CO2 philic, and therefore assist the polymer dissolution in the solvent [159, 160]. Some examples of the associated polymers include polyvinyl acetate (PVAc), oligo (3-acetoxy oxetane), poly [(1-O-(vinyloxy) ethyl-2, 3, 4, 6-tetra-O-acetyl-β-D-glucopyranoside)] and amorphous polylactic acid [161, 162]. Once the molecules of the polymer are dissolved in the solvent, the intermolecular/intramolecular association may occur which would result in an increased solution viscosity. Some of the polymers can increase the solvent viscosity significantly by simply changing the thickener concentration or by twining their molecular structure like a hair between different polymer chains [163].

**Dissolution of small molecules (self-assembling and associating compound)**: The second strategy is focusing on the design of small-molecules material that contains a self-assembling and associating compound to form a viscosity-enhancing supramolecular network structure in the solution. Such a material contains an associating group composed of a solvent philic segment that facilitates dissolution and one or more solvent-phobic segments that would induce the intramolecular association with neighbouring molecules, thereby molecular association establishing a viscosity enhancement for the solution, but its impact on viscosity could be minimal [72]. The small-molecules thickeners have shown little success to thicken CO2 and light alkane solvents primarily because these are regarded as weak solvents for the ionic and polar associating compounds that are commonly composed into the small-molecules thickeners [71, 157].

Overall, a polymeric or small-molecules compound thickener capable of dissolving into CO2 or light hydrocarbon solvents has to be identified to increase the solution viscosity under typical field conditions. The ideal chemical additives are those that can effectively increase the viscosity of the injected gas very close to that of the crude oil. Furthermore, a viscosified gas used for EOR has to be transparent and single phase rather than opaque viscous solution in order to be capable of flowing through micro-pore throats in rock formations [157]. A viscosified gas with the above-described desirable characteristics used for an MGI process can suppress the gas mobility in the reservoir reducing the severity of viscous fingering and the chance of developing premature gas breakthrough and high production gas oil ratio (GOR). As a result, the sweep efficiency would be improved for the gas flood. Various studies conducted over the past several decades have resulted in successful laboratory-scale progress in thickening of CO2 and NGL (natural gas liquefied). The successful CO2 thickeners include the fluoroacrylate-styrene copolymer polyFAST and poly(dimethylsiloxane)-toluene solutions [160]. These two thickeners have been found to be capable of increasing the CO2 viscosity by approximately 10 and 4 fold, respectively, at dilute concentrations [160]. A drag-reducing agent (DRA) poly(α-olefin) was presented as the most significant thickener that can increase the viscosity of the NGL [164].

#### *4.3.1 Challenges and opportunity for gas thickeners*

The use of gas thickeners has the potential to eliminate many of the earlier mentioned challenges and difficulties associated with WAG and gas-foam injections. However, the discovery of inexpensive polymers or small-molecules materials soluble in CO2 or alkane solvents has so far been a major challenge. Furthermore, the performance of none of the identified or synthesised thickeners has been verified in even a field pilot test yet.

In general, the following challenges have hindered the identification of effective thickeners that could be used for a gas flood:

**Thickener solubility**: The attainment of adequate solubility has been the primary obstacle in finding viable thickeners because most of the designed and identified polymers for the CO2 and hydrocarbon gases exhibit extremely low solubility unless a large volume of a co-solvent (e.g., 10–15 wt% toluene) is added. The reason behind this problem is that CO2 and alkane gases are poor solvents for extremely high molecular weight, polar and ionic-associated groups that are composed in small-molecules thickeners. The alkane gases (methane and ethane) do not have dipole or quadruple moments, so the dispersion interactions are dominant with these solvents. Thereby, alkane gases would not be suitable SCF solvents unless the density of these solvents is increased considerably by increasing the system pressure. Unlike alkane gases, CO2 has a substantial quadrupole moment that induces quadruple interaction as the temperature is low [158]. In addition, CO2 acts as a Lewis acid for the polymers containing oxygen [165]. In general, as mentioned before, a polymeric CO2 thickener needs to contain a CO2-philic function group that facilitates the polymer solubility and CO2-phobic function group that promotes intermolecular associations to enhance the viscosity [166]. To date, solubility remains a key major challenge in the identification of an inexpensive thickener for CO2 and hydrocarbon solvents.

**Cost and environmental persistence**: The high price and environmental issues are other challenges that impede the use of the identified or developed thickeners to date in field applications. In fact, most of such thickeners are unaffordable and/or unavailable in large enough quantities. The requirment of an organic co-solvent to obtain the necessary dissolution levels further adds to the cost. Moreover, some of the developed thickeners, such as fluoroacrylate-styrene copolymers (polyFAST) and semi-fluorinated trialkyltin fluorides, are fluorinated compounds that contain Fluorine. These thickeners have been identified as the best thickeners for CO2 and NGL, respectively. However, the fluorine in these thickeners would bring about potential negative effects on the environment making them unsuitable for EOR applications [52, 72, 157, 160].

#### **5. Mobility control: feasibility evaluation field A**

Overall, from the discussions presented so far, it is clear that each of the proposed mobility control methods, as applicable to an MGI process, has its own challenges and deficiencies. The possible field-scale implementation of each method often depends primarily on the in-situ conditions and specific characteristics of the field of interest. The objective of this section of the chapter is to present an evaluation of the applicability of each of the techniques discussed earlier in Field A given its specific conditions and characteristics.

#### **5.1 WAG technique**

As mentioned earlier, in field applications, the WAG process has been applied successfully in a number of oil fields around the world [74, 75]. A total of 72 field-scale miscible and immiscible WAG projects were reviewed by Skauge et al. that have utilised hydrocarbon or non-hydrocarbon gases. Majority of these projects have been successful resulting in incremental oil recoveries in the range of 5–10% of OIIP. For successful projects, the WAG process consistently yielded better oil recovery than that could be achieved with continuous gas injection even though, often, a large amount of oil (35–65% of OIIP) would still be left behind [52]. Some of reviewed projects have also been unsuccessful due to operational and/or reservoir related difficulties such gas gravity segregation, extreme reservoir heterogeneity, excessive water production, corrosion, scale and/or hydrate formation, etc. [74] In the case of Field A, in-situ water saturation is very low (<10%) and, therefore, the field surface facilities and well completions are not designed to inject or handle large amounts of water. Therefore, the WAG strategy is not the best choice to implement in this field.

#### *5.1.1 Gas foam technique*

It was previously discussed that the gas foam injection process has been tried at the pilot scale in some fields in the United States and Canada. However, this technique has never been performed in any field in the Middle East due to the difficulties of finding a suitable surfactant (water soluble) or due to the harsh reservoir conditions encountered including high salinity and high temperature. Although, there has been a number laboratory-scale studies done to date evaluating the application the technique under conditions encountered in this region. For example, in a recent study conducted by Sumaiti et al. [56, 111], the foamability and mobility of CO2-ethoxylated amine in carbonate cores were investigated at a salinity of 220,000 ppm and temperature of 393 K. The foamability of Ethomeen (C12) and apparent foam viscosity increase were confirmed at these conditions. In addition, CO2-foam core flooding obtained 8.89% of additional oil recovery. However, the availability of CO2 is very limited in the Middle East. Concerning Field A, the reservoir presents a harsh environment with a formation brine salinity of 275,000 ppm and a reservoir temperature of 377 K with low in-situ water saturation and a very light oil (42° API). It is extremely difficult to find a surfactant, especially water-soluble, which can work under these conditions. For the CO2-foam process, there is a lack of adequate CO2 availability in Oman. As a result, it is expected that achieving adequate foam stability would be a major challenge to implement a gas-foam process in Field A.

#### **5.2 Direct thickened technique**

As discussed earlier, several laboratory-scale studies have been conducted to date to find and/or develop direct thickeners for CO2 and NGL. However, the cost and environmental issues associated with these thickeners have prevented their application beyond the laboratory scale [167]. As outlined earlier, this technique has several distinct advantages compared with the other two mobility/conformance control techniques of WAG and gas-foam injection. Firstly, a screened thickener additive would be thermodynamically stable and chemically inert (with no or minimal interaction with reservoir sediments), making it ideal for application in harsh reservoir conditions *Miscible Displacement Oil Recovery DOI: http://dx.doi.org/10.5772/intechopen.105757*

(i.e. high formation salinity and temperature). Secondly, the gas viscosity increase achievable by a thickener does not dependent on rock characteristics, properties and saturations of other fluids in the reservoir and injection flow rates. Thirdly, it eliminates the need for water co-injection which minimises the chance of excessive water production and treatment requirements substantially and eliminates the water blocking effect too. Lastly, it has been demonstrated at the laboratory scale that this technique can increase the sweep efficiency considerably because of delayed gas breakthrough and improved gas mobility. Hence, it is believed that CO2 or AG mixture thickening may be the only viable technique for Field A to counteract unfavourable mobility conditions present in the Field and further enhance the oil recovery of the current ongoing MGI.

#### **6. Conclusion and recommendations**

This chapter presents the process of miscible gas injection (MGI) and the implementation of MGI in the petroleum industry especially for the recovery of light oil. It briefly discussed the challenges associated with the MGI flooding, and several solutions proposed in the literature to overcome these challenges include: water alternating gas flooding (WAG), foam flooding and the use of thickening agents. Despite many efforts made to date to identify a viable approach to counteract unfavourable mobility conditions and improve sweep efficiency. These approaches are not applicable in the fields as means of mobility control at field scale. Therefore, a further work requires that can improve the industry's confidence in employing these approaches at the field scale using numerical simulation followed by economic analysis to investigate and verify the feasibility of these techniques for field applications.

#### **Author details**

Nasser Mohammed Al Hinai<sup>1</sup> \* and Ali Saeedi<sup>2</sup>

1 Petroleum Development Oman, Petroleum Engineering, Sultanate of Oman

2 Department of Mining Engineering, Curtin University, Australia

\*Address all correspondence to: nasser.alhinai5@gmail.com

© 2022 The Author(s). Licensee IntechOpen. 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.

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#### **Chapter 4**

## Minimum Miscibility Pressure, Miscible Displacement, CO2 Capture, and Injection

*Julio Gonzalo A. Herbas Pizarro*

#### **Abstract**

The Minimum Miscibility Displacement Pressure, and the strategies to maintain the reservoir pressure above the minimum miscibility pressure are the most important elements for a successful EOR Dry Gas, CO2, or N2 Miscible injection project. The Miscibility behaviour needs to be understood early after the reservoir discovery to establish if a miscible displacement is economically attractive. The difference of a miscible gas displacement with an immiscible displacement is of such importance because a miscible displacement could achieve a recovery factor as high as 75% to 90% of the contacted oil compared to 30–40% recovery factor for an immiscible displacement process. In some field cases, the MMP is determined in the mid or late field life when the reservoir pressure, temperature and fluids distribution might limit the time left to design and implement a miscible gas displacement; in other, the operators possess the technology to design and implement Miscible Gas Displacement and the ability to articulate the project economy allowing time on decisions to implement, operate, and materialize the incremental recovery from a miscible displacement; therefore, it is recommended to determine the miscibility pressure, as soon the field is identified as candidates for EOR.

**Keywords:** EOR, CO2, miscible displacement, CCS

#### **1. Introduction**

This chapter discuss the concepts and elements that drive a Miscible Displacement, some practical strategies for project design, implementation and evaluation, field experiences from the Minimum Miscibility Pressure concept, application, and influence in field cases of Miscible Gas Injection projects performance, including natural gas, Dioxide Carbonate (CO2), Nitrogen (N2) and Flue. Some field cases of EOR Miscible Displacements injecting dry gas and CO2 are also discussed in the context of EOR operations.

Historically it is more common to deal with immiscible gas injection projects, compared with the cases of miscible gas injection projects possibly because the

opportunities for implementation of miscible displacement have not been identified in early stages, the high costs of compression to achieve miscibility and the access to the know-how.

There have been cases where the implemented reservoir management strategy was focused to let the reservoir pressure to deplete below the bubble gas pressure to create a secondary gas cap to use the gas cap expansion as production mechanism. This strategy might be considered reasonable and economic; however the cases that we have seen have recoveries in the range of 35–45% of the original oil in place at the time when the GOR has increased to extremely high values that suggest the injected gas is being recycled. The recovery factor in those cases might had been in order of 60–70% if a miscible gas injection process would have been implemented at early stage of the field life cycle.

The determination of the MMP can be estimated with reasonable accuracy if there is available a compositional analysis of the reservoir oil and a representative PVT analysis, which can be used to build a representative one-dimension compositional simulations for various types of gases that might be available for injection. Usually it is important a survey of potential gas sources in the area. Once the MMP has been estimated by compositional reservoir simulation, the next step is to verify the model work with laboratory experiments applying methods such as slim tube tests, rising bubble, zero interfacial tension, these last two are more recent developments in determination of MMP.

The typical candidate gases for injection are dry or wet natural gases, Nitrogen, CO2 and flue gas, a product from natural gas combustion; from those gases, the CO2 has been identified as the more efficient miscible agent based in its property to dissolve the oil.

The current trend of Carbon Capture and Storage (CCS) objectives pursued by the industry to reduce the green house effects can be levered with the implementation of more CO2 miscible injection projects elsewhere the CO2 is available, as there are several oil fields that have not developed because the hight CO2 content.

An early evaluation of the economic feasibility to achieve a miscible displacement is of paramount importance which should be followed with the formulation of a doable strategic implementation plan for the project construction to materialize the incremental recovery factor and the incremental production, that in turn is dependent of a sound reservoir management conscious of the project objectives, that works with open communication between and with participation of all the company players from top management to field engineers and operators.

#### **2. Generalities of gas injection miscible displacement process**

The crestal gas injection is one of the more efficient traditional displacements processes, it works by the gravity segregation drive mechanism displacing the oil downward toward the producer wells placed down in the structure. A miscible displacement is if not the most efficient, one of the more efficient displacement processes because the injectant fluid dissolves the oil as the injectant at displacement front gets in contact with the oil in the reservoir zones, once it gets in contact; therefore, the displacement front not only displaces the movable oil saturation but also dissolves the residual oil saturation that is typically left behind in an immiscible gas injection process. Therefore, the oil saturation behind the displacement front in a Miscible Displacement can be as very low virtually zero.

#### **3. What is miscibility**

Miscibility is the mixture of two fluids, one fluid dissolves a second fluid either at first contact or in multiple consecutive stages as the injectant fluid contact and displace the second fluid. First, contact miscibility is driven by the fluid s composition and the thermodynamic conditions: pressure and temperature.

An important feature of the Miscible Gas injection Displacement is the solubility effect of the gas displacing miscible oil which eliminates the gas oil relative permeabilities effect, which is a consequence of the dissolution of the displacing fluid into de displaced fluid, that convert the displacement as one uniform front moving at the interface of gas displacing oil.

The **Figure 1** shows gas (CO2) miscible displacement of trapped oil in a porous media, the CO2 gas mix with the oil, swells the oil molecules, and extract light components from the oil as it moves into the reservoir, creating a virtual wash of the porous media.

Other characteristics of a miscible gas displacement:


**Figure 1.** *CO2 injection miscible displacement in pore scale [1].*


Miscible displacement processes can be implemented in absence of structural dip as it is shown in **Figure 2**. In dipping reservoirs, the gravity segregation will favour a stable displacement as described in the Field case. Early Identification of Multiple Contact Miscibility injecting Dry Gas El Furrial Field, a Case of Multiple Contact Miscible Gas Injection combined with Low-Salt Water Injection.

### **4. Types of miscible process and mechanisms**

There are two basic types of miscibility:

#### **4.1 First contact miscibility**

Occurs when the injectant dissolves the oil as soon it gets in contact with the reservoir, it usually occurs with solvents as gasolines, and very rich gases.

**Figure 2.** *Miscible gas injection in absence of structural dip.*

#### **4.2 Multiple contact miscibility (MCM)**

A multi contact miscibility starts as an immiscible displacement, then the thermodynamic conditions (Pressure and Temperature) allow a continuous transfer of molecules of hydrocarbon from the displaced oil to the injectant (displacing phase), in a condensing and vaporising process, that enrich continuously the injected gas, until it becomes miscible with the displaced oil. The mechanic of miscibility injecting a dry gas is defined as Vaporizing Drive, it is controlled by the oil composition, the pressure, and the temperature.

The miscibility achieved through multiple contacts between the injection gas and the oil in-place occurs after the injection gas at the displacement front progressively contact the oil in the reservoir. As the displacement front moves into the reservoir the gas takes more heavier components until the miscibility is achieved. In presence of viscous fingering or permeability heterogeneity, the minimum distance to accomplish miscibility increases because of dispersion at the displacement front. The total recovery in a MCM process is the sum of the recovery obtained while injection gas travels the immiscible portion of the porous media plus the recovery obtained when the gas displaces the miscible portion.

In a phase envelope **Figure 3** the first contact miscibility pressure usually occurs above the bubble point pressure. The Cricondenbar is the maximum pressure that gas phase cannot be formed any more regardless of its temperature, its temperature is called cricondenbar temperature.

The Cricondentherm is the maximum temperature that liquid cannot be formed regardless of pressure and its pressure is called cricondentherm pressure.

At temperatures higher than Cricondentherm, only one phase occurs at any pressure, the corresponding pressure is called Cricondenbar that is the maximum pressure above which no gas can be formed regardless of the temperature.

The chart Pressure Temperature phase diagram for an oil system illustrates the position of the cricondenbar pressure, the bubble point line and the two phases liquid and gas envelop; the area above the bubble point line and below the cricondenbar pressure defines the region where the multiple contact miscibility might take place.

#### **5. Ternary diagrams**

Ternary diagrams are used to represent the phase behaviour of hydrocarbon systems, the mixture of components of the fluids with more than three components is divided into three pseudo components, such as light, intermediate, and heavy components of a hydrocarbon phase. The ternary diagrams are developed based on compositional equations of state (EOS) developed to replicate the phase behaviour of hydrocarbon systems, are useful to represent the phase behaviour of a mixture of pure hydrocarbons. The composition of the 3 points in ternary diagrams is defined based on the oil composition and the injection fluid composition., and the diagrams are generated with specialized commercial software as Eclipse 300, GEM, etc. The grouping of components is usually a convention defined by the user


As for example in **Figure 4**, a gas composition 50% C1 and 50% C2–C4 will lie in the midpoint of the C1 and C2–4 corners.

The composition of an Oil sample in the centre of the triangle represents a mixture of:


The green area represents the mixture of 3 groups C1, C2–4 and C7+ result in 2 phases gas and liquid.

The Triangular Diagrams in **Figure 5** represents a system with C1 at the top corner, C2–C4 at the bottom right corner and C7+ at the left corner. A point between two corners represents a composition proportional to the corners, as example a midpoint between C1 and C4 represent a mixture 50% C1 and 50% C2–4; similarly the midpoint *Minimum Miscibility Pressure, Miscible Displacement, CO2 Capture, and Injection DOI: http://dx.doi.org/10.5772/intechopen.106945*

#### **Figure 4.**

*Typical Ternary phase diagram, hydrocarbon system: the limiting tie line passes through the oil composition at minimum miscibility pressure (MMP) [1].*

#### **Figure 5.**

*Ternary diagrams system with limited miscibility [3].*

between C4–C2 and C7+ represent 50% of each corner. For this composition, the blue areas correspond to the mixtures that result in 2 phases oil and gas. The miscibility occurs when a gas composition gets in contact with an oil composition without crossing the two phases area.

A multiple contact miscible process MMP with dry gas is illustrated in 4 steps in the phase diagram in **Figure 6**.


**Figure 6.** *Three phases' diagrams condensing gas drive miscibility [3].*

4.The reservoir oil becomes enriched with these materials, until the miscibility occurs between the injection gas that has already extracted high Molecular weight components from the residual oil and the enriched oil at the displacement front.

The plait point is a critical point at which the liquid and vapor phases are identical**.** The miscibility occurrence is a function of the solvent concentration, (C4). The injectant composed by pure C4 and high C4 concentration achieve first contact miscibility. As the proportion of the solvent C–4 reduces, there will be a composition where there is not first contact miscibility, and miscibility might occurs by multiple contact, then as the C4 proportion reduces the miscibility is lower until a point where there is no miscibility at all, as shown in **Figure 7**.

#### **6. Condensing—Gas mechanism sequence**


As the pressure increases the two-phase region becomes smaller. At some pressure the injected gas is to the right of the limiting tie line and MCM develops. This process is known as condensing vaporizing multiple contact miscible drive.

*Minimum Miscibility Pressure, Miscible Displacement, CO2 Capture, and Injection DOI: http://dx.doi.org/10.5772/intechopen.106945*

**Figure 7.**

*Three phases diagrams showing gas composition with multiple MCM and gas composition with first contact miscibility FCM [4].*

#### **7. Vaporizing gas mechanism**

Intermediate hydrocarbon components in the oil vaporize to enrich the gas. As the leading edge of the gas slug becomes sufficiently enriched, it becomes miscible with the reservoir oil.

#### **7.1 What happens in the simulation when miscibility is achieved?**

When the miscibility is achieved into the reservoir, the displacement will be very efficient and virtually all the oil in the reservoir will be removed and displaced toward the producer wells, the characteristic of miscible displacement projects is the high recovery factors in order of 60–75% of the oil in place; higher figures of the recovery factor are not commonly reported, limited by the operational pressure in the field, or lack of gas injection continuity, reservoir heterogeneities, etc.

Experiments show that final recovery increases by increasing the slim tube length for any injection rate.

#### **8. Challenges in miscible gas injection projects**

One difficulty in a Miscible Gas Displacement project is to keep all the reservoir porous media above the minimum displacement pressure. Several pressures levels can coexist in the reservoir because of the pressure gradient and the flow dynamics in a heterogeneous reservoir as sedimentary environments composed typically by river channels, plains, sandstones, bars, splays, etc. or in carbonate reservoirs with several facies within the reservoir unit; if there is not a well-defined safety margin above the MMP, there might be areas with pressures below the minimum miscibility pressure.

It is common to receive management requirements to produce at maximum potential which might not correspond to the injection rates designed to maintain the

**Figure 8.** *Fingering in a miscible displacement [2].*

reservoir pressure above the MMP, this is a challenge in a MMP project that might cause detrimental effects to the recovery factor.

In the last decades of past century and early times of this century, the oil and gas operators realized the importance of understanding the fluid behaviour and its characterization with application of fluid phase envelops and its use as a reservoir management tool. In many cases, the feasibility to increase dramatically the recovery factors was recognized after understanding the reservoir the reservoir dynamic, in some cases a late implementation of a MMP EOR project was hampered by the high cost of repressurizing the reservoir at levels adequate for a MMP displacement; this type of issues has avoided a more extended implementation of EOR Miscible gas injection projects.

Gravity stable injection of gases into high relief oil reservoirs can result in substantial incremental oil recovery, depending on the densities of the gases at reservoir conditions, the gases should be injected at the crest or bottom of the reservoir, while miscible displacement scan be in low relief of flat reservoirs, however the process will be more challenging because no gravity effects.

Viscous fingering is another challenge that can result in poor vertical and horizontal sweep efficiency (**Figure 8**).

Other challenges are the potential corrosion, affecting the well and the production facilities as also nonhydrocarbon gases must be separated from saleable gas.

#### **9. Typical gases that can be used as injectants**

The more common gases for injection are the associated gas produced with the oil, dry gases, or gases available in the nearby of the field's candidate for miscible injection, and other gases as CO2, N2, and Flue gas. Flue gas is a mixture of air with combustion gases, with the advantage that the volume of gas used in the combustion is multiplied by several orders of magnitude. Cleaning requirement of impurities in the flue gas will be depending in each case. The miscibility displacement with flue gas usually requires much higher reservoir pressures sometimes to impractical levels.

Usually, it is important to execute a source of injectant fluid study covering for example 100 kilometres around the project location with the purpose to investigate the potential sources of gases for injection. It should be done in a short period by personal of the operators familiar with this type of process. From the gas's availability study, it should be generated the different types of gases to be used in the determination of the optimum injectant for a particular EOR miscible gas injection project.

#### **10. Screening parameters for a miscible project**

The typical parameters for a favourable miscible process are shown below, it has been defined in several known publications, as "Updated EOR screening, JJ Taber, F.D. Martin, SPE, and R.S. Seright, SPE, New Mexico Petroleum Recovery Research Center SPE 1997 [5], and Aladasani, Ahmad, "Updated EOR screening criteria and modeling the impacts of water salinity changes on oil recovery" (2012). Doctoral Dissertations [6].

However, every field case should be studied individually considering all factors inherent to the field as reservoir size, reserves, available fluids for injection, markets, among others.


The average reservoir permeability is the arithmetic or geometric, weighted average of the permeabilities defined from electrical logs and cores used to populate a reservoir grid. Transmissibility is a term to express the reservoir ability to move fluids as function of relative permeabilities, fluid viscosity, formation volume factor, and geometric parameters.

#### **11. Experimental determination of the minimum miscibility pressure (MMP)**

There are several experimental methods to determine the MPP, the more known are the Slim Tube Tests, the Raising Bubble, the Zero Interfacial Tension; en addition there are other methods to estimate the MPP as compositional reservoir simulations and correlations.

Before initiation of the experimental laboratory work, it is recommendable to preliminary estimate the MMP by means of compositional reservoir simulations, this can be done building a simple one-dimensional reservoir simulation model based in the compositional fluid characterization, representative rock properties pressures and temperatures, then displace the oil using various injectants and various reservoir pressures; the obtained results can be used to evaluate the process under several pressures and to determine the conditions required to achieve a miscible displacement.

The one-dimension compositional modelling is recommended to be the first task to be done as soon as the compositional description and the PVT data is available, these will guide the laboratory experiments, and the preparation of full field compositional reservoir simulations studies.

#### **12. Slim tube tests**

The slim tube test is an apparatus laboratory test used to estimate the minimum miscibility pressure (MMP) or minimum miscibility concentration (MMC) of a given injection solvent and reservoir oil. It allows to create a porous media saturated with the reservoir fluid at representative pressure and temperature to establish the original conditions prevalent in the reservoir, which will be used to test the injectant as dry gas, wet gas, separator gases, CO2, Nitrogen, or Flue Gas.

The slim tube **Figure 9** is a narrow long-coiled stainless-steel tube. It is filled with sand of a specific mesh size like the reservoir porous media. To model the displacement process in the reservoir, the tube is saturated with reservoir oil at a reservoir temperature, then the Gas injection is performed at several test predefined pressures, or at the field reservoir pressure if this is a undersaturated reservoir and the

**Figure 9.** *Slim tube test apparatus schematic [3].*

*Minimum Miscibility Pressure, Miscible Displacement, CO2 Capture, and Injection DOI: http://dx.doi.org/10.5772/intechopen.106945*

investigation is done aiming to investigate the process at that operational pressure. The produced effluents, density and composition are measured as functions of the injected volume.

A slim tube internal diameter (ID) is typically about 5/16 inches, with length from 5 to 40 meters. The tube is filled up with glass beads or sand of a specific mesh size, the ratio of particle size to tubing diameter is sufficiently small, less than 1/10, to neglect wall effects, it can be idealized as a one-dimensional element of the reservoir.

When gas is injected in the sand packed slim tube apparatus will take place multiple equilibrium contacts, at the end of the experiment the recovery factor is calculated to identify the type of displacement, a miscible displacement will be concluded at recovery factor close to 95% or more. The slim-tube tests result should not be indicative of ultimate recovery to be achieved in actual reservoir, because the Slim Tube is not including factors sweep efficiency, transition zone length, etc. The experiment should be done at constant reservoir temperature.

The experimental procedure requires an initial calibrating of the apparatus with known fully miscible fluids. To determine the MMP, the slim tube is saturated with crude oil and several consecutive displacements are executed at various reservoir pressures.

The oil recovery after injection of a specific number of pore volumes (PV) such as 1.2 PV of solvent is the test criterion for miscibility. The recovery factors for the different pressures are plotted versus pore pressure for the several slim-tube tests, typically at low pressures recoveries will be low, and will increase as the pore pressure increases, when the slop of the first line exhibit a noticeable change, it is indicative of the multiple contact miscible pressure, further higher pressures should reach higher recoveries, **Figure 10**.

**Figure 10.** *Plotting results from the slim tube test experiments.*

The slim tube test usually considers consecutive displacements at different pressures, starting from the estimated from the MMP compositional simulation, the obtained results for the several pressures are plotted and the tests are repeated until reaching a near 95% recovery factor. The 2 lower plots in **Figure 10** show the MMP determination injecting soltrol (an isoparaffinic solvent) in slim tube saturated with synthetic oil. The experiments can be done with different solvent concentrations to evaluate the solvent minimum requirements.

Different strategies for the determination of the MMP can be designed, as for example, reducing the number displacements to at least four pore pressures, if the results show two trends, the point of intersection of the trends is considered the estimated MMP for the given oil-solvent system. In other cases, a particular reservoir pressure might have been defined as the target operation reservoir pressure to operate the reservoir with specific purpose as to avoid crossing the asphaltene flocculation onset, in that case it is a practice to run the slim tube tests a that specific operational pressure with the objective to understand the process, a particular case where this strategy was successfully applied is described in the field experiences section.

In any strategy that is used, the results obtained from a slim tube test must be used as input to fine-tune an equation of state for reservoir simulation, that will be applied in the full field compositional simulation required to estimate the field recovery factor; the accuracy of the predictions is function of the data representativeness.

The displacement from the reservoir is affected by various mechanisms that causing dispersion, such as gravity override and viscous fingering caused by unfavourable viscosity ratio. The porosity heterogeneity if present will also cause dispersion of the front. The slim tube provides a one-dimensional dispersion free displacement of oil; therefore, the dispersion effects must be studied with a three-dimension multi geocellular model representative of the reservoir. At field condition, the MMP and the final recovery are function of the thermodynamic behaviour in the system, the gravity effects, reservoir heterogeneities, etc.

#### **12.1 Micro slim tube test**

Interface Fluidics has created a novel method to estimate miscibility using a microfluidic chip capable of measuring MMP with greater precision and confidence than the standard slim tube method. The slim-tube standard apparatus estimates MMP by constructing a linear regression around a few critical data points, Micro Slim Tube use Interface's analogue a data-driven approach to yield results with greater

**Figure 11.** *Micro slim testing by interface fluidics oil.*

*Minimum Miscibility Pressure, Miscible Displacement, CO2 Capture, and Injection DOI: http://dx.doi.org/10.5772/intechopen.106945*

accuracy. Each chip run collects anywhere from 25 to 75 values per gas-oil system, resulting in high-resolution data plots that can be used to determine MMP directly.

The Micro Slim Tube **Figure 11**, is a miniature of the slim-tube method via microfluidic technology, for rapid and cost-efficient determination of MMP using smaller sample volumes to conduct initial tests. This allows to analyse several reservoirs samples and conditions for the MMP investigation. Changes in oil and gas composition can dramatically impact MMP values, accurately capturing this variable allows to cover a wider spectrum of condition for reservoir simulation models and detailed planning of miscible gas flooding processes.

It can reduce cost for miscibility measurements, and execution of minimum miscibility enrichment (MME) studies, to optimize the gas injection strategy. Requirement of lower sample volumes impact favourably the economy and health/ environmental risks associated with sampling from wells.

#### **12.2 Raising bubble method**

This s a more recent development laboratory method to indicate miscibility between the reservoir oil and injection gas at specific conditions of pressure and temperature.


Testing at several pressures helps to determine the MMP between the gas and oil. The rising-bubble test represents a forward-contacting miscibility process and therefore may not accurately to estimate the MMP for a backward or combined contact mechanism [7].

#### **12.3 Rising bubble apparatus by core laboratories**

The Rising bubble apparatus (RBA) offered by Core laboratories provides a fast, accurate, cost-effective measurement of minimum miscibility pressure. The essential feature of the apparatus is a flat glass tube mounted vertically in a high-pressure sight gauge in a temperature-controlled oven.

The glass tube, its **Figure 12** approximately 20 cm long, facilitates the examination of bubbles rising in opaque oils. The glass tube is back lit for visual observation of the tube contents. A hollow needle is mounted at the bottom of the of the sight gauge and protrudes into the rounded portion of the glass tube.

The Raising Bubble Apparatus has a needle that is set and kept about 3–5 centimetres below the flat portion of the tube. The sight gauge and glass tube are prefilled with deionised water at the initial test pressure and reservoir temperature., the reservoir oil is then injected downwards into the flat glass tube, displacing the water until only the lower circular portion of the glass tube contains any water.

**Figure 12.** *Raising bubble apparatus by core lab [8].*

A small gas bubble must be placed at the tip of the hollow needle and liberated into the tube, it will rise through the water, through the water/oil interface and up through the column of oil. After two or three bubbles have risen through the oil the water oil interface, then it is replaced with a fresh reservoir oil.

All the process of the gas bubble raising is monitored using a motion tracking optical system with a video camera mounted on a rail parallel to the path of the rising bubble. A magnified view of the bubble can be observed on screen and recorded as a small movie clip (mpeg). The time of the raising process for each injected gas bubble is calculated for each test pressure and use this data to interpolate the MMP.

#### **12.4 Zero interfacial tension (VIT vanished interfacial tension)**

At the Miscible Pressure, no interface exists between crude oil and injection fluid, i.e., interfacial tension approaches zero **Figure 13**. The VIT method measures the interfacial tension between the two phases, the measurements are done in a high-

**Figure 13.** *Vanishing interfacial method to estimate the MMP.*

*Minimum Miscibility Pressure, Miscible Displacement, CO2 Capture, and Injection DOI: http://dx.doi.org/10.5772/intechopen.106945*

pressure cell with an optical tensiometer, the oil is introduced as a drop phase into the chamber filled with the injection fluid [9].

The interfacial tension is measured with the Pendant Drop Shape analysis. It is measured at 5–10 different pressures at reservoir temperature after which the line is extrapolated to zero IFT. When the interface between two phases vanishes in all proportions, that is first contact miscibility. In a field CO2 project, it is always multi contact miscible, never first contact miscible.

Although it has been established that VIT is NOT a rigorous measurement of MMP, it provides a good approximation. The measurement of MMPs in a high-Pressure Temperature Tensiometer apparatus **Figure 14** it can be done in two weeks for 20 ft columns and less than a month for 6-point, 80-foot columns [9].

#### **12.5 Correlations to estimate the miscibility pressure**

Stalkup, JR [10] presented his Correlation to estimate the MMP (1983-4) developed from 9 different miscible process displacing oil of different compositions with gas composed by more than 80% mol methane, it correlates MPP as function of the oil composition and saturation pressure. The correlation results exhibited average deviation of 260 psi, and maximum deviation of 640 psi; however, the correlation exhibited large errors for displacements with gases with methane content lower than 80 mole percent [11].

#### **12.6 When is the best time to determine the minimum miscibility pressure?**

The time when to determine the Minimum miscibility pressure is the nearest time to the reservoir discovery date, as soon as a PVT sample is available and analysed, other parameters need to be considered, as the reservoir dimensions, volumes of initial oil in places, the reservoir pressure, the reservoir conditions either undersaturated or saturated reservoir, recovery factors, among others.

A MMP process is not applicable for a saturated reservoir because saturated reservoirs are characterized for having initial pressure below the bubble point pressure evidenced by a primary gas cap.

To achieve a miscibility displacement in a saturated reservoir, it would be required to re-pressure the reservoir to above the bubble point pressure, which could be achieved injecting a considerable volume of gases or water while the reservoir is closed to producing, this situation is very improbable to happen because the prohibitive cost that represent injecting fluids without hydrocarbon production.

Under the current trends of switching the energy supply from fossil to renewable cleaner energies might be opportunities where the Carbon Capture and Storage (CCS) activities might supply the opportunities to use depleted oil reservoirs with low recovery factors for CO2 storage. In those cases, dedicated geosciences and reservoir engineering studies will be required to mature every particular field case with two folds objectives, first to storage the CO2, second to investigate how the remaining oil in the depleted structure will be affected by the injected CO2.

For a subsaturated reservoir, the situation is different because there is higher probability to implement a miscible process with the purpose to increase the oil recovery factor and the reserves; the suggested procedure is:


This process must be based on numerical reservoir simulations using calibrated reservoir simulation models.

The MMP process are viable only when the incremental production generates enough revenue to cover the project cost implementation and generate revenues for the operator and the shareholders. In the field history cases we describe a case of multiple contact miscibility with dry gas in a subsaturated reservoir.

*Minimum Miscibility Pressure, Miscible Displacement, CO2 Capture, and Injection DOI: http://dx.doi.org/10.5772/intechopen.106945*

#### **13. Field case: early identification of multiple contact miscibility injecting dry gas el furrial field, a case of multiple contact miscible gas injection combined with low-salt water injection EOR projects**

El Furrial field is a giant structure discovered in 1986 by Lagoven s.a affiliated of PDVSA with the perforation of the Ful-1X well in Eastern Venezuela **Figure 15**, it encountered 854 m gross interval with 366 m net oil sandstone **Figure 16**, it was the more important discovery in South America in over 25 years, achieved 10 years after the nationalization in 1976, at a time when national production had declined to its lowest point since 1950; this field become the highest producing oil field in Venezuela, reaching a peak of 480,000 bbl/day in 1998. Secondary and Tertiary recovery studies to maximize the oil recovery were initiated in 1990 (**Figure 17**).

The discovery of this giant near 7.9 billion barrels of oil in place was a tremendous success of the exploration campaign undertaken by Lagoven s.a. [12] in an area where international operators exploited shallower oil reservoirs before the 1976 nationalization leaving unnoticed deeper structures containing a trend of giant light oil reservoirs.

Initially, a water injection project to inject 200,000 barrels of fresh water was designed to maintain the reservoir pressure at or above 6500 psi at reservoir datum, with the purpose to have a safety margin above the asphaltenes flocculation onset that was extensively measured to start at about 1500 psi above the bubble point pressure 4500 psi.

**Figure 15.** *El Furrial field location.*

#### **Figure 16.** *Regional structural setting El Furrial field.*

Immediately after the sanction of the water injection project, it was identified the feasibility of a Multiple Contact Miscible (MCM) process injecting Dry Gas [13]; the feasibility was identified from one-dimension compositional simulations, followed by experimental studies that concluded with the implementation of a project to inject

*Minimum Miscibility Pressure, Miscible Displacement, CO2 Capture, and Injection DOI: http://dx.doi.org/10.5772/intechopen.106945*

**Figure 18.** *Water and gas injection project and oil production wells map (IAGF project).*

600 mmscf/d of dry gas to develop a MCM project in parallel to an increase of the water injection to 450,000 barrels/day to significantly increase the final recovery factor (**Figure 18**).

The two projects water injection and MCM gas injection were designed, planned and implemented to operate simultaneously. The gas injection in 5–6 wells located at the crest of the anticline and the water injection in near 36 water injection wells positioned at the flanks in two independent rows one for each main reservoir unit (**Figure 18**).

The projects were designed to achieve a combined recovery factor in range from 55 to 60%. Both projects were timely implemented and successfully operated since inception to mid project life. By end of 2021, 36 years after the field discovery the recovery factor achieved is estimated in range of 44.5% that is near 10–15% below the initial predictions; this implies that a range from 845 to 1240 million barrels were not produced.

The procedure applied to determine the Multiple Contact Miscibility displacement is summarized below:


In this specific case, the slim tube tests were performed at 6500 psi to verify the occurrence of miscibility previously calculated in the one-dimension compositional simulations.

Afterwards the MMC miscible gas injection project known as IAGF (Injection de Agua y Gas Furrial) was sanctioned and implemented along with an increase in the water injection capacity; the gas injection started in 1998. The performance of the two projects is discussed below:

#### **13.1 Field case IAGF gas injection combined with low-salt water injection El furrial production performance**

The field production history of the IAGF project described in the previous section is shown in the **Figure 19**, the pressure history is presented in the **Figure 20**. The field production targets for the field were planned with the premise to maintain the reservoir pressure in range of 6500–7000 psia to ensure the gas displacement under the miscibility process and to avoid the asphaltene deposition around the wellbore of the producer wells, plugging the perforations in the well completions and damaging the formation in the wellbore zones. The asphaltene flocculation onset pressure was measured as function of the asphaltene in around 6000 psia.

The **Figure 20** shows pressure performance, it is observed the reservoir management activity to maintain the reservoir pressure in the predefined range 6500–7000 psia was consistent since the inception of the project until approximately the year 2008, when a drastic pressure decline occurred as a result of lack of continuity in the gas and water injection operations, that occurred in parallel with an intensive infill drilling campaign implemented in the lapse 2008–2010; such drilling campaign resulted in an increase of the production however the reservoir voidage was not maintained causing a drastic reduction of the reservoir pressure to levels below 6500 psia the operation pressure that preceded a dramatic fall in the production rates observed in the years 2013–14.

The analysis of the historic performance suggests this reservoir was capable to produce at rates higher than predicted for a longer period (after 2004), if the reservoir pressure would be maintained above 6500 psi.

**Figure 19.** *Production forecast plot IAGF project.*

#### **Figure 20.**

*Pressure performance plot IAGF project.*

The project management seems to have been disattended in the last 10 to 12 years because of the nationalization of the injection facilities, politization of the project management, and other detrimental practices of century 21 socialism regime, as a

result the reservoir pressure declined to 4600 psi in 2013, below the asphaltenes flocculation onset.

At current standards of the technology with the application of best reservoir management practices the final recovery for this project should have been close to 70– 75%; however, several events that affected the continuity of the gas and the water injection affected adversely its performance. Analysis of the results of the two consecutive EOR projects, are discussed below to illustrate the impact of early EOR gas and water injection studies.

The first project, a Low Salinity Water injection was designed in 1990–1991 to maintain the reservoir pressure at 6500 psi, the water injection was initiated in 1992 with a pilot test followed by the construction of the facility to inject 450,000 bbls/day of water to recover an estimate of 1277 million barrels of incremental oil (20 % recovery above the primary recovery factor estimated in 16%), it was named the Resor project. The water injection operations were initiated at reservoir pressure of near 8000 psia at 14,000 feet deep, fresh water of 1000 ppm from shallow aquifers was selected after screening all available sources which put this project as a Low Salinity Water Injection displacement process.

Immediately after the RESOR project was sanctioned in 1992, the gas injection feasibility studies were initiated, the experimental and engineering work were executed in 2 years, and the obtained results concluded the dry gas injection would add an important increase in the recovery, therefore it was recommended to initiate a dry gas injection with pure methane at rates of 550 mmscf/day in the crest of the structure to increase the final recovery to around 55–60%. The Miscible Displacement Injecting Dry Gas studies were done with TCA Reservoir Engineering Services a company based in Durango Colorado with cooperation from the EOR department of the Texas University and the Research Institute Intevep S.A. affiliated of PDVSA; the simulation work included the one-dimension and full field compositional simulations that demonstrated a multiple contact miscible displacement injecting pure methane, this process was corroborated with slim tube experiments executed at Intevep the Technological branch of PDVSA, and verified in Core Lab and Westport Laboratories in Houston Texas, giving the bases for the Miscible Gas Injection EOR project initiated in 1998 (IAGF).

The Miscible Gas Injection project was designed in 1994 [13] to inject 550 million standard cubic feet per day of dry gas together with an expansion of the water injection to 550,000 bbls per day, with the objective to generate reserve of 684 million barrels of incremental oil, additional to the base water injection estimated reserve in 1277 million bbls; the gas injection project was named IAGF and initiated in 1998. The project aimed to achieve a multiple contact miscible displacement injecting dry gas at 6500 psia at the top of the reservoir, with the objective to remove and displace the residual oil toward the producer wells acting in combination with the water injection at the flanks of the structure, it implied the conversion of five-six producer crestal wells to gas injectors sacrificing a substantial oil production rate (**Figure 21**).

The cross section of the compositional simulations shows the effect of the miscible gas displacement in the reservoir reducing the oil saturation to near zero in the surrounding zones to the gas injection wells, as it was observed in the slim tube tests and predicted in one-dimension compositional models.

#### **13.2 IAGF water and gas injection project, performance review**

In this section, it is described an analysis of the actual reservoir response under water and gas injection versus the predicted forecasts, to illustrate the value of the

#### *Minimum Miscibility Pressure, Miscible Displacement, CO2 Capture, and Injection DOI: http://dx.doi.org/10.5772/intechopen.106945*

**Figure 21.**

*Cross section compositional simulation, showing near zero oil saturation in zones affected by the miscible displacement injecting dry gas.*

early identification and implementation of the feasibility of a MCM process, for this analysis, data from various sources was used to generate an overview of the project performance.

Both injection projects are classified as Enhanced Oil Recovery, because their intrinsic characteristics:


To evaluate the results of both projects, it was accessed the original working files and the numerical simulation models build in 1990–1997 built in house using commercial simulators with data generated in laboratories of Intevep s.a., Core Laboratories Inc, Schlumberger, and other international laboratories, as compatibility tests performed in Serk Baker labs in United Kingdom. We also used the universities Simon Bolivar and Universidad Los Andes in Venezuela, Bristol University in UK and Texas A&M University in Houston Tx. Before the project sanction, all the tests were verified by international laboratories in Houston and Dallas Texas USA.

The analysis of the production performance is based in the production forecast, actuals production profiles obtained from public domain literature, personal experiences, notes, and testimony of some of the main players.

The simulation profiles generated for the sanction of the two analysed projects were plotted along with a natural depletion case, and the actual historic production performance plots, shown in **Figure 19**, it shows the natural depletion and three consecutive cases corresponding to: injection water 450,000 bbls/day base case (blue dotted line), water expansion to inject 550,000 bbls/day of water (green dotted line) and the miscible gas injection of 550 mmscf/day combined with 550,000 of water injection.

The solid black line represents the actual historic production, the orange line starting at 2007 represents the PDVSA Plan at that year; the STOIIP at this year was increased to order of 7.9 B bbls.

A reservoir pressure review to the available data in the **Figure 20**, shows observed pressures in the first 1–2 years after the gas injection started in 1997, the actual oil rate was lower than predicted, it declines to 400,000 bbls/d and is maintained until the year 2012, then a dramatic decline started to reach the actual rate 60,000 bbls/d in the year 2020–21.

The overall actual production performance is superior to the forecast because of intensive infill drilling; however, the dramatic production decline started in 2012 is result of a progressive discontinuity of the gas and water injection operations.

The main conclusion is the water and gas injection operations affected favourably the production overachieving the initial forecast and generating more than planned reserves, however a more careful analysis shows the achieved actual recovery factor just reach around 45% of the updated STOIIP (7.9 MMbbl) which is near 10% bello the recovery factor obtained in the initial predictions; this deficit is a result of discontinuation of the gas and water injection operations and the over-production above the established production levels, noticeably the dramatic production decline occurred in 2012, coincides with the pressure depletion below the operational maintenance pressure defined for the reservoirs in the implementation studies in 6500–7000 psi at datum.

Currently the gas flare is common in this giant field, which is a result of the inefficient operation in the compression and injection system; the field reservoir pressure was well managed until 2012, however after 2013 the decline in the reservoir pressure coinciding with the low oil production rates reflect its effects of well productivity deterioration (**Figure 22**).

### **14. CO2 injection as EOR process**

EOR CO2 flooding consists of injecting large quantities of CO2 in the reservoir to form a miscible flood, the injected CO2 volume is determined from experimental and

**Figure 22.** *Press Note of Gas Flaring in El Furrial Field Monagas State, March 2020.*

compositional studies can be from 15% or more up to 1.5 hydrocarbon pore volumes. When the CO2 gets in contact with the oil in the reservoir, if the pressure is high enough, there will be a kind of "vaporizing gas drive" recovery mechanism:


The CO2 is an efficient miscible displacement solvent, it requires lower pressures to achieve miscibility compared to other gases as hydrocarbon gases, Nitrogen and flue gas, the CO2 injection as EOR method in the oil industry is well known and has been applied in many fields.

Conversely in some fields with high CO2 content, meaning the CO2 is available, the CO2 reinjection has not been implemented, the produced CO2 is vented, or the wells have been shut in, in contrast with other fields and reservoirs where the CO2 is not available and the required volumes for CO2 injection for EOR purposes, had been purchased and transported from other sources. Those fields with high CO2 content that have been under exploited because its high CO2 content can be an excellent fit of the technology to produce the hydrocarbons with high CO2, separate it and reinject in the reservoir displacing the total usable hydrocarbons and leaving the CO2 reinjected volumes in the reservoir, finally used as the CO2 captured recipient.

The **Figure 23**, is a schematic of a CO2 EOR process followed by a waterflooding displacement to chase the CO2 slug.

The Screening Parameters for a CO2 EOR are listed below:


#### **14.1 EOR and CCS**

Since the 1950s, the oil and gas industry has spent many billions of dollars on CO2 EOR technologies, commercial projects, and developing operational knowledge. Most of this activity has been in land-based oil and gas fields. The first patent for CO2 EOR was granted in 1952, the Texas Railroad Commission reports the first three projects were initiated in Osage County, Oklahoma between 1958 and 1962. These CO2 EOR

**Figure 23.** *Schematic of a CO2 EOR Displacement Followed by a Waterflood.*

projects have steadily increased over the years based on the growing availability of CO2 and technology advances.

In 2012 the Oil & Gas Journal EOR survey, reported the CO2 flooding in the USA was producing more oil than EOR by Steam Injection (308,564 bbls/day vs. 300,762 bbls/day) with 41% of the output from all types of EOR. The active CO2 EOR projects in the USA were increased to 120, representing 89% of the total 135 CO2 EOR project globally. Furthermore, in the past years, as sources of CO2 offshore and deep-water technology has become available new EOR CO2 injection projects were initiated, as in the giant Lula field located deep-water in Brazil, which is the pointy end of a very long and successful industry history of CO2 EOR.

Conversely, some onshore fields with large volumes of liquid CO2, has not been fully developed because the high CO2 content, which might have been produced and used to recover the hydrocarbons and leave the CO2 storage in the reservoir.

### **15. Challenges and solutions injecting CO2 for EOR**

Some of the challenges for the EOR CO2 project implementation are:


Over the last 25 years, a small number of offshore saline aquifers and oil and gas reservoirs have successfully used many of the technologies developed through the last 58 years of land-based CO2 EOR experience. It is possible that CO2 is a viable means to increase hydrocarbon output from many depleted offshore reservoirs that are marginal or no longer productive; most operators are not using this technique on their reservoirs because they do not have an economical supply of CO2, other operators because do not own the CO2 technology. However, cost-effective supplies of CO for many of these offshore fields may become available as carbon capture from nearby electric power plants and other large, stationary sources of CO emissions becomes more common (**Figure 24**).

In the last years, it has been detected some onshore light waxy oil fields containing large amounts of CO2, one of those fields located in Europe and another one in South America, both were not fully developed because the high CO2 and wax content has somehow affected the wells productivity, so that their achieved recovery factor has been very low near 1% of the initial oil in place; their production operations were affected by other factors as pressure depletion, while having a large volume of liquid CO2 dissolved in the gas cap, those CO2 volumes instead being flared, might be compressed and injected back into the reservoir.

Challenges for offshore EOR CO2 injection and CCS projects are more stringent because the higher development costs, the offshore surface facility space, weight and power limitations, the lack of sufficient and economical CO2 supplies, and fewer existing wells that are more widely spaced. All these factors are added complexity that contribute to uncertain EOR performance and require longer time periods for CO2

**Figure 24.** *Schematic CO2 capture and injection offshore.*

placement to displace oil and gas and achieve adequate sweep efficiency. However, EOR is currently being considered for several offshore developments. The prognosis is better when successful secondary recovery methods have been employed through water and natural gas injection, which make CCS and CO2 EOR methods much more feasible and less costly to apply.

Some of the key challenges and solutions for offshore CO2 injection for EOR and CCS projects, include the use of CCS tanker ships and barges to ensure CO2 supplies and to provide service facilities until the construction of pipelines and construction of permanent facilities is justified. Horizontal well designs may be needed to offset a lower well density and achieve a more uniform sweep and displacement.

Transport of CO2 from onshore sources to offshore oil and gas fields has been successfully done at several CO EOR projects using pipelines and barges. Tanker ships have successfully and safely transported CO2 for over twenty years, are best suited for the small volumes needed for pilot CO2 injection tests; tanker ships that deliver LNG


**Figure 25.** *CO2 transport in LNG tankers.*

**Figure 26.** *LNG Tanker ships for CO2 Delivery Offshore EOR projects (OTC 21984).*

*Minimum Miscibility Pressure, Miscible Displacement, CO2 Capture, and Injection DOI: http://dx.doi.org/10.5772/intechopen.106945*

to ports with supplies could carry CO2 it on their return voyages to economically supply EOR projects (**Figures 25** and **26**).

Some CO2 activities that are happening in the world are the CO2 pipeline projects in planning or in construction in several continents, as:


There are at least three CO2 EOR and enhanced gas recovery (EGR) projects around the world, as:

1.Gas injection in the Bay St. Elaine oil field in the Louisiana marshlands,

2.Dulang field WAG project in Malaysia's east coast in the South China Sea.,

3.Lula CO2 offshore Brazil

#### **16. CO2 capture and injection, costs, and technology**

A critical element of a CO2 capture and storage project is obtaining the CO2, the technology for separating it from a flue gas, and the business model of who pays, it has been surprising to hear discussions about where the CO2 is going to come from for capture and storage purposes, and its associated costs, the oil operators being obliged to do carbon capture and storage will look for the cheapest way to obtain CO2 which would otherwise be vented to the atmosphere. I obvious should be to reinject the captured CO2 into the depleted oil reservoirs, which should increase the reservoir pressure and in cases helps to increase the oil production and final recovery factors [14, 15].

For the natural CO2 subsurface reservoirs, the CO2 is already in the ground, it is not sensible to produce it to storage unless a reasonable use is determined, that can be EOR to increase the oil recovery. Gas wells with high CO2 should be studied, although they would normally not be produced at all, an option can be to capture the CO2 and reinject it to enhance the oil recovery and after extracting it, use the reservoir to storage the CO2.

Flue gases from power stations and energy intensive industries, particularly concrete, steel and oil refining are potential sources. The original assumption for carbon capture and storage was targeted to coal power station flue gases. This proposition in the UK and Netherlands now have the expectation to stop using coal power, which will reduce an important source of CO emission. The UK anticipates continuing to use gas power, the Netherlands anticipates all power generation coming from renewables [16].

The focus to flue gases from energy intensive industries with typically 20 per cent CO2, that needs to be separated from the 80 per cent of other gases, the amine technology separates the amine molecule attaches to the CO2 in one column, and the amine is separated from the CO2 in a second column, cost estimated were reported in range \$35 to \$69 per tonne of CO2 captured from a coal power flue gas in India by 2019 [17].

The key measures to report cost of the CCS defined by the Global CCS Institute in 2017 update, defines it as the life cycle unit cost of production and cost per tonne of avoided CO2. The cost per tonne of CO2 avoided is a measure that enables comparison across various technology in terms of their value reducing greenhouse gas emissions. The costs for USA reported in 2017 show for flue gas from cement in cost in range 58 to101 US\$/tonne; for Iron and steel the cost is reported in 95 to 370 US\$/tonne [17].

There have been many efforts over the past 10 years or so to find ways to reduce these costs. One idea is for fuel to be combusted in pure oxygen, with an air separation upstream of the combustion unit, a mature technology, then the flue gas is near entirely CO2, this option has been studied by Occidental (OXY) (**Figure 27**).

A great deal of research is going into carbon capture technology, particularly with new solvents. An example is the advances from Occidental Petroleum (OXY) to direct capture and storage CO2 from the air (DAC): [18].

In 2019, OXY Low Carbon Ventures (OLCV) released a first look of design of the plant to capture up 500 Kt of CO2 annually directly from air to be used in EOR projects and subsequently stored underground permanently in the Permian Basin, expected to expand to include multiple DAC plants, each capable of capturing one megaton of atmospheric CO2 annually. If the initial plant is approved by Occidental and Carbon Engineering, construction is expected to begin in 2021, with the plant becoming operational within approximately two years.

On March 28, 2022, Oxy subsidiary (OLCV) and Weyerhaeuser Company (WY) announced an agreement for the evaluation and potential development of a carbon capture and sequestration project in Livingston Parish, Louisiana. The agreement provides OLCV with exclusive rights to develop and operate a carbon sequestration hub on more than 30,000 acres of subsurface pore space controlled by Weyerhaeuser. OLCV will use the land to permanently sequester industrial carbon dioxide (CO2) in underground geologic formations not associated with oil and gas production, while Weyerhaeuser continues to manage the aboveground acreage as a working forest [18] (**Figure 28**).

**Figure 27.** *Tanker Transporting Oil Cargos a Sources of CO Discharge to the atmosphere.*

*Minimum Miscibility Pressure, Miscible Displacement, CO2 Capture, and Injection DOI: http://dx.doi.org/10.5772/intechopen.106945*

#### **Figure 28.**

*DAC direct air capture CCA oxy plant.*

The agreement, is a pivotal step in OLCV subsidiary 1PointFive's strategic vision to develop a series of carbon capture and sequestration hubs within the U.S.:


#### **17. Who pays the CO2 capture costs?**

The question of how to cover the costs of CCS are being discussed for several years, one idea has been the CO2 utilization using electricity to make hydrogen and using this hydrogen for CO2 activation towards methanol or methane.

In Europe, emitters of CO2 are being hit by ever increasing regulatory pressure and costs to dis-incentivize emitting CO2 to the atmosphere, the costs of CO2 separation from flue gases would be paid for by emitters. This is the plan of the Rotterdam PORTHOS project, which envisages that energy intensive industries in the Port of Rotterdam would pay themselves for CO2 capture and storage.

In Europe, the emissions trading scheme covers all land-based emissions (not shipping and aviation), the cost of emitting is not yet close to the cost of CO2 capture and storage, and is not a stable price, so does not provide enough incentive by itself. The Netherlands and UK Governments are looking provide a subsidy or additional tax, between the carbon price and the cost of carbon capture.

#### **18. CO2 to enhance the oil production**

Research work conducted in slim tube test experiments to investigate the recovery with injection of various gases, such as CO2, N2, CH4, or flue gas, have demonstrated the CO2 gas injection results in the highest oil recovery factor compared with injection of the other gases.

In water flood secondary recovery projects, after long periods of water injection, a significant amount of oil remains in the reservoir due to the capillary pressure between water and oil. In these cases, the oil recovery can significantly be improved by gas injection in such a way that the gas/oil front moves gravity stable through the reservoir.

If the injected gas and the displaced fluids are moving in gravity stable displacement, substantial incremental oil can be produced; the factors driving the incremental oil production are, reduced interfacial tension for miscible or near miscible displacements at reservoir conditions, gravity drainage for injection of non-miscible gases and improved sweep efficiency for attic oil with stable front moving vertically through the reservoir.

Several gases can be injected in the reservoirs, for a case when methane, CO2 and N2 are available, the choice of what gas will be injected depends on the prices of the gases, costs of injection and incremental oil recovery by the respective gas.

#### **18.1 Outlook and growth potential**

The current world energy market trend driving the transition to clean energies to replace fossil energies and reduce the CO2 emissions, implies a progressive reduction of the oil and gas production; at this point some industry observers believe the EOR methods may help offset the predicted decline in oil production over the next twenty years, and the CO2 EOR may be a substantial portion of the future EOR growth. A key factor for this growth is a sustainable economic supply of technologies and CO2 for injection where the CCS initiatives might be an important factor.

#### **19. CO2 EOR field cases Lula Project Brazil**

The Lula field is a supergiant ultra-deep water offshore field located in the Santos basin southeast of Brazil, it is the most significant CCS project in Brazil. And Latin America, it is a pre-salt carbonate reservoir in the Santos Basin located below a thick, 2000 m salt column trapping a light, 28–30° API oil with high solution gas ratio (200– 300 m<sup>3</sup> /m<sup>3</sup> and variable CO2 content between 1 to 15%, with neighboured areas with up to 80% of CO2. The Lula field was developed in phases in the prospective areas of the field defined with extended well tests, production pilots followed by large scale production developments. The pilots provided data to calibrate simulation models, select strategies to maximize recovery and profitability, for the development of other fields in the Santos basin pre-salt blocks.

Early studies showed the oil recovery factor could be greatly improved with secondary and tertiary recovery by implementing a Water-alternating-gas (WAG) injection EOR project chosen because of the availability of seawater, produced gas, and the reservoir conditions particularly suited to miscible methods mixing water and gas. The project that began in 2009 with the arrival of a floating, production, storage, and

*Minimum Miscibility Pressure, Miscible Displacement, CO2 Capture, and Injection DOI: http://dx.doi.org/10.5772/intechopen.106945*

**Figure 29.**

*CO2 Concentration in the Eastern Bank of Brazil's Exploration Areas. Source: EPE Empresa de Pesquisa Energetica January 2020.*

offloading vessel, followed by the WAG pilot project with three producer wells with one gas injector at about 1.0 million m<sup>3</sup> /day initiated in April 2011, the facility began exporting some gas to shore and the injection wells began to inject mostly CO2 at rates of about 35000 m<sup>3</sup> /day. The pilot was monitored with permanent downhole pressure gauges, and gas injection tracers.

The first results were presented in the SPE155665, concluding the injection of WAG using CO2 separated from the associated gas in the pilot project as a suitable strategy to increase the oil recovery; the 2012 production and pressure data monitoring of the WAG installation was translated into EOR expansion at the field scale. By December 2018, there were nine production systems (FPSOs) at Santos Basin, with natural gas pre-treatment and CO2 separation systems using membranes. Since 2013, up to end 2018 around 9.8 million metric tons of CO2 has been injected, and the projects continue in operation.

This CO2 pilot project made the Lula field a pioneer in Deepwater CO EOR, Petrobras may set the record as the first company to successfully combine CCS and CO2 EOR for large-scale, sustained oil production in deep-water (**Figure 29**).

#### **20. Conclusions**


#### **Acknowledgements**

#### **Credits for the RESOR and IAGF water and miscible gas injection projects**

The implementation of the RESOR water Injection project was initiative of Mss' Juana Albornoz (deceased) supported by Dr J.P. Chalot and other Lagoven's professionals, the RESOR team was composed by: Orlando Dumont, Jesus Nunez, Richard Alvarez, Magno Romero, Pascual Marques and Jesus Tineo, the Reservoir Engineering Team was composed by Raul Mengual, Antonio Russo, Luis Ruiz, Jose Gil, Nidia Pinto, Pablo Saavedra, and other professional. In the construction of the simulation models, it was notable the contribution of Dr Pepe Bashbush, and Richard Smith from Intera SRL.

The discovery of the multiple contact miscible injecting dry gas in El Furrial Field was done by Dr Elmond Claridge (deceased) Head of EOR Dept at the University of Houston, Dr Michael Todd and Dr Curtis Chase (deceased) both from TCA reservoir engineering services; the direction of the research project by Julio Herbas, supported by an extended team composed by geoscientist and engineers from Lagoven and Intevep s.a., and audited by a BP Exploration team: Ian Roberts, Dr Shen Tai Lee (deceased), Dr Mike Christie (fluids behaviour), Dr Neville Jones (Geoscientist), Mike Levitan (reservoir simulation), Andy Johnston (Compression Design), and Leon Miura from Lagoven s.a. in charge of the project implementation.

*Minimum Miscibility Pressure, Miscible Displacement, CO2 Capture, and Injection DOI: http://dx.doi.org/10.5772/intechopen.106945*

#### **Conflict of interest**

The authors wish to confirm that there are no known conflicts of interests associated with this publication and there has been no financial support for this work that could have influenced its outcome.

#### **Acronyms and abbreviations**


*Enhanced Oil Recovery - Selected Topics*

### **Author details**

Julio Gonzalo A. Herbas Pizarro Mineaoil Limited, London, United Kingdom

\*Address all correspondence to: jherbas@mineaoil.com; julioherbas@btinternet.com

© 2022 The Author(s). Licensee IntechOpen. 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.

*Minimum Miscibility Pressure, Miscible Displacement, CO2 Capture, and Injection DOI: http://dx.doi.org/10.5772/intechopen.106945*

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