Environmental Impacts of Crude Oil Processes

## **Chapter 7** Gasoline Lubricity

*Panagiotis Arkoudeas*

#### **Abstract**

It is concluded that the lubricity of gasoline is the least well understood of all three fuels due largely to the lack of a reliable test method for measuring the lubricity of such a very volatile and contamination-sensitive material. To overcome this limitation, the development of a simple and easy methodology based on the general standard ASTM G-133 have been produced. This method is first used to investigate the lubricity of commercial gasolines to obtain some baseline data for further study. A comparison of the overall lubricity level of diesel fuel and gasoline fuel indicates that additive-free gasolines have significantly poorer lubricity than highly-refined, Swedish Class I diesel fuel, while commercial, detergent-containing gasolines range from slightly better to significantly poorer than a Swedish Class I diesel fuel. Especially LRP (lead replacement) gasolines developed a tests on refinery streams used to blend gasoline also show quite varied wear behaviour. Gasoline lubricity can be significantly improved by adding small amount of diesel lubricity additives. The results indicate that the type of fuel is a significant factor for discriminating the lubrication properties of each type of gasoline fuel and that lubricity is affected by bulk and trace composition characteristics of the fuel.

**Keywords:** gasoline lubricity, repeatability and reproducibility, new method for fuel tribology, elastohydromechanic film formation, boundary lubrication

#### **1. Introduction**

In the late 1980s and early 1990s, environmental concern about the toxic and harmful emissions from diesel and gasoline engines led to large reductions in the amounts of sulphur and the development of reformulated gasoline fuels.

The topic of gasoline lubricity has recently become more urgent with the possible introduction of direct-injection gasoline engines, which will necessitate highpressure gasoline injection pumps, a development that is most likely to place considerably more emphasis on the lubricating ability of gasoline, accelerating wear especially in rotary distributor fuel pumps. According to pump manufacturers this loss of lubricity may be the difference between fuels from a controlled laboratory environment and a cost-conscious production environment [1].

The stringent specifications for sulphur content in gasoline (from the year 2005, Euro 4 emissions specifications have defined the limit of 50 ppm S for the countries of E.U., and from the year 2008 have been 10 ppm) and may take off some of the fuel lubricating capability. The lubricity of aviation kerosene and diesel fuel appears to arise from very small quantities of polar, quite high boiling point components. It is realised that the overcoming increase in the severity of refinement of gasoline fuels makes very difficult to analyse these components and chemically identify them, as they vary greatly depending upon the origin of the fuel.

Fuel quality in recent years became increasingly important, not only for its role in the actual performance of the vehicles, but also for its impact on the emissions. However, the fuel pump at the service stations is the point at which the actual specifications of the fuels should be ascertained. This paper presents results of a survey of gasoline samples obtained from service stations in Athens area.

In Greece, three main types of gasoline are sold in the service stations: new super or LRP gasoline with a Research Octane Number of 96 (96 RON) for the noncatalytic cars, unleaded gasoline with a Research Octane Number of 95 (95 RON) and super unleaded gasoline with a Research Octane Number of 98 (98 RON) for newer cars equipped with a catalyst. Some service stations also sell super unleaded with a Research Octane Number of 99 or 100 (99+ RON) but the market share of this product is very limited. Unleaded gasoline is the cheapest gasoline and it is marked with quinizarine, while new super and super unleaded gasoline have similar prices (and they are quinizarine free). This price differential is the main motive to mix the cheaper with the more expensive fuel. Most gasoline adulteration cases involve the illegal mixing of the cheaper unleaded into the LRP or super unleaded gasoline. Less common is the mixing of much cheaper heating fuel into the gasoline. In such cases, the sulphur content can be used as a physical marker, which characterises the fuel quality [1]. Also, the viscosity of gasolines is 10 times less than diesel fuels and it is an indicator of adulteration, too.

Gasoline lubricity is a complex phenomenon, involving many complicated and intercorrecting factors, such as the presence of water, oxygenates, diolefins, aromatics, the effect of viscosity and the synergistic effect of different wear mechanisms. The lubricity mechanism of gasoline is quite different from that of diesel fuels that leads to severe adhesive wear. With low-sulphur fuels, adhesive wear is seen instead of corrosive and mild oxidative wear, and deposits build up on top land [1].

The emissions from motor vehicles contribute about 90% of airborne lead in urban areas. So, it was committed to phase out leaded petrol to reduce ambient lead concentrations as much as possible. On the other hand, valve seat recession (VSR) occurs when there is insufficient lubrication between the exhaust valve and seat. The mechanism of valve seat wear is a mixture of two major mechanisms. Iron oxide from the combustion chamber surfaces adheres to the valve face and becomes embedded. These hard particles then embed into the valve seat and cause abrasive wear or valve recession leading to early engine failure. For this reason, there are a number of anti-wear additives on the market that protect car's valve seats. Additives with active ingredients of either potassium, sodium, phosphorous or manganese have been shown to give protection to exhaust valve-seats. Although no additive is as effective as lead, it has been shown that correct dosing will provide adequate protection to exhaust valve-seats under normal driving conditions [1]. The new specifications in the Greek market determined as appropriate additive the potassium at the concentration level of 10–20 ppm (mg/kg). Because there is a small possibility that mixing of some anti-wear additives on the market could result in engine damage, the potassium additive was mixed from the refinery production [1].

#### **2. Commercial gasoline lubricity evaluation**

Examination of the gasoline lubricity has shown that the majority of the samples6were above the acceptance limit of diesel lubricity, the 460-μm limit (**Figure 1**). We cannot include the repeatability limit calculated according to Eq. (2) for diesel fuels because such an assumption is not scientific tested and experiments

**Figure 1.** *Lubricity values for the three gasoline types.*

must be carried out for the determination of the repeatability and reproducibility limit of gasoline fuels. This means that research studies must determine the effect of temperature and humidity on gasoline lubricity for wears greater than 600 μm. Regarding the effect of the test apparatus' modification, mentioned above, this limit must be restricted to lower values. This enhances even more the experimental observation of greater lubricity values for gasoline than that of a common diesel fuel.

$$r = 139 - (0.1688 \times \text{WS} \, 1.4), \quad 360 \le \text{WS} \, 1.4 \le 600 \tag{1}$$

On the contrary, most of the samples of new super gasoline were near the limit of 460-μm indicating that the presence of the potassium additive had a main effect on the lubricating properties of fuels. Adulterated new super gasolines with unleaded gasoline have poorer lubricating properties, as shown in **Figure 2**. The effect of sulphur content in gasoline lubricity is depicted in **Figure 3**. It is obvious that unleaded and super unleaded gasolines have much higher lubricity values than LRP gasolines. Especially, below the level of 50 ppm are observed extremely high lubricity values.

**Figure 2.** *Gasoline lubricity values vs. water pressure (from the humidity and temperature of the experiment).*

**Figure 3.** *LRP gasoline lubricity values and adulterated samples.*

There was no linear or other type of correlation between the concentration of potassium and the lubricity, but it seems that there is a limit of demanded potassium that may maintain a significant reduction of MWSD1.4 value near the limit of 460 μm. The factors most likely to cause the observed differences in lubricity are the bulk fuel composition, the use of additives and the use of oxygenates.

#### **3. Fuel comparison**

The adulterated fuel samples were isolated and two statistical computations were carried out each time, one with these samples and the other without.

The spread of the values can be depicted using boxplots. In **Figure 4** is shown the median, quartiles, and extreme values of lubricity for each type of gasoline fuel. In each box plot is displayed the 50% of samples' population in the square area, the 75% of them within the upper and lower limit and the extreme values which are cases with values more than three box lengths from the upper or lower edge of the box. It is shown that LRP gasolines have a much better representative sample population indicating good lubricating properties compared with the other two types of gasoline. One unleaded gasoline has shown extreme good lubricity value,

**Figure 4.** *Box plot analysis—First statistical graphic approach to the data.*

#### *Gasoline Lubricity DOI: http://dx.doi.org/10.5772/intechopen.101302*


#### **Table 1.**

*Data of descriptive analysis for gasoline lubricity.*

279 μm, but it is mainly caused by the use of special anti-wear or other additives. For the samples, which were not identified as adulterated, a descriptive analysis has been made. The results are shown in **Table 1**.

Because all the properties were not normally distributed for correlation analysis with Pearson correlation coefficient, were chosen the correlation coefficients of Spearman and Kendall's tau-b to be computed. The effect of the properties on the gasoline lubricity is different for each type of gasoline fuel. The chemical structure and the related individual physical properties seemed to interconnect in their effect on lubricity in different degree for each type of fuel. The results indicate that the type of fuel is a critical factor for discriminating the lubrication properties of each type of gasoline fuel.

More specifically, the statistically significant coefficients showed that unleaded gasolines seem to have lower values of wear as sulphur and nitrogen content, saturates and viscosity increased. On the contrary, unleaded gasolines seem to have greater values as toluene, oxygen, MTBE and vapour pressure increased.

LRP gasolines seem to have lower values of wear as sulphur and nitrogen content, conductivity (no-adulterated samples), saturates and viscosity increased. On the contrary, LRP gasolines seem to have greater values as the benzene, aromatics and xylene increased.

Finally, super unleaded gasolines seem to have lower values of wear as sulphur content, nitrogen content and olefins increased. On the contrary, super unleaded gasolines seem to have greater values as toluene, xylene, water, benzene, aromatics and oxygen increased.

The results above were extracted after bivariate correlation analysis to measure how variables are correlated and the values of the correlation coefficients are shown in **Table 2**.

This differentiation of the properties' effect on lubricity reinforce the idea of the complicated wear mechanism that take place under the specific conditions of the experiments and the important role of the compositional characteristics of the fuel. Oxygen content and MTBE seems to maintain or even increase unacceptable wear


*\*\*Correlation is significant at the 0.01 level (2-tailed).*

*\*Correlation is significant at the 0.05 level (2-tailed).*

#### **Table 2.**

*Data of correlation analysis between lubricity and physicochemical properties.*

diameters and a possible development of a uniform system for fuel quality monitoring, including the control of MTBE' content, should accept a lower upper limit of acceptance for this oxygenate.

#### **4. Viscosity and density effect**

Due to no specification limit of viscosity in gasoline, was decided to test all the samples at the temperature of 15°C. During the statistical process, was espied a linear correlation between the viscosity and density (*R*<sup>2</sup> = 0.76). In **Figure 5** is shown that correlation linearity for the total of gasolines and each fuel severally.

This is an obvious interconnecting factor as concerns the effect of density or/and viscosity on gasoline lubricity and each gasoline type separately. Both these properties are greatly influenced from the composition of the fuel, chlorine, nitrogen, sulphur and MTBE content. Organic chlorine content is connected with dioxin emissions but is anti-wear role is unknown. It was detected using SEM on the wear surface.

That enhances the opinion that the compositional characteristics of the fuel do influence the gasoline lubricity in considerable degree.

#### **5. Potassium content**

With confidence we can say that the potassium additive for valve recession plays an important role in the boundary-forming characteristics of LRP gasolines. As long

**Figure 5.** *Graphs indicating linear correlation between viscosity and density at 150°C.*

as a "minimum" is maintained, the lubricity of the fuel seems to be more acceptable than that of unleaded and super unleaded samples. It is not easily to determine this limit but as shown in **Figure 6**, we can expect good results even when the potassium concentrate is less than 4 ppm. The amount that is added to the fuel does not seem to affect the final result of WSD1.4 proportionally.

Also, conductivity of LRP gasolines was much greater than that of unleaded and super unleaded gasolines. The main effect on that is due to the organic salt of potassium, but there is not good linear correlation between conductivity and potassium content (*R*<sup>2</sup> = 0.51). In **Figure 7** could see the difference between the conductivity for each type of fuel.

**Figure 6.** *Potassium content and gasoline lubricity.*

**Figure 7.** *Conductivity values at 200°C for each type of gasoline fuel. Effect of the potassium concentration.*

Due to its incompatibility to modern catalytic converters, we could not use potassium additives—alkyl, aryl or alkoxy potassium compounds or other—as additives for gasoline lubricity.

#### **6. Model predicting the value of gasoline lubricity**

The model described below is based on the observed values of 106 samples of automotive gasoline fuels that were collected during the years 2001, 2002 and 2003.

All the measured gasoline fuel properties were used for the development of regression statistical analysis. In particular, it was found through trial and error that we must not exclude any variable from the input data in order the methodology to produce the smallest error in the validation data and to obtain as much greater *R*squared value as possible. Indeed, a 30 input–1 output network was set up using the above-mentioned variables as inputs and the lubricity as output. The predicted lubricity values by this linear regression analysis showed a standard error of 81.5 μm and the experimental values correspond to a correlation coefficient *R*<sup>2</sup> = 0.78. This model cannot be used as a predictor for gasoline lubricity. In **Figure 8** it is obvious the difference between observed and predicted gasoline lubricity values.

**Figure 8.** *Observed versus predicted gasoline lubricity values after linear regression analysis.*

#### *Gasoline Lubricity DOI: http://dx.doi.org/10.5772/intechopen.101302*

The information obtained through univariate analysis—where the effect of each input variable on the output was examined separately—show that the values of each input variable and the direction in which it affects the fuel lubricity cannot indicate an acceptable accuracy for the degree of wear totally. More in depth analysis of the compositional constituents and their effect on lubricity will have to be done. Especially, properties such as the acid value and a GC analysis of the content of diaromatics, diolefins and other compositional characteristics would provide better results in the direction of a model predicting the gasoline lubricity.

#### **7. Elastohydrodynamic (EHD) film formation**

#### **7.1 Introduction**

It is reasonable to expect that elastohydrodynamic (EHD) film formation by gasoline may also play an important role in gasoline pump lubrication. However, up to date there has been no published work, on gasoline, or indeed, diesel fuel EHD lubrication. In this chapter, EHD traction and optical film thickness measurements of gasolines and MTBE in point contacts are described and compared with those of diesel fuel and hexadecane.

Section 7.3 describes an experimental study of EHD film formation properties of gasolines and diesel fuels. Research is directed at understanding how thin the films formed by gasoline fuels will be, and the transition from elastohydrodynamic to boundary lubrication. It was found that at high speed, the EHD behaviour of gasolines, MTBE, and diesel fuels obeys Hamrock-Dowson theory. At low speed, gasolines give very thin films and show significant boundary film formation.

To make further progress in understanding gasoline EHD behaviour, mini traction machine (MTM) tests were carried out to measure friction/traction in both fixed slide-roll ratio and variable slide-roll ratio conditions. Results are described in Section 7.4. Diesel fuels exhibited EHD behaviour similar to hexadecane and other lubricants, but gasolines gave EHD Stribeck curves and traction curves significantly different from those of lubricants.

In Section 7.5 the EHD behaviour of gasolines and diesel fuels is further examined by cross-plotting test results as log (traction coefficient) versus log (film thickness). The lubrication regimes of gasolines and diesel fuels involved in current study can then be discussed in terms of lambda ratio. Results suggest that the Stribeck curves of gasolines and MTBE obtained in this study are incomplete. Due to their extremely low viscosity and the rolling speed limitation of the current MTM test device, it was not possible to enter the full fluid film regime.

Section 7.6 summarises the main conclusions drawn from these results.

#### **7.2 Test fuels**

The properties of test fuels are listed in **Table 3**. These are a subset of the fuels studied in HFRR work previous HFRR research.

#### **7.3 The film formation of diesel and gasoline fuels**

#### *7.3.1 Ultra-thin film interferometry (UTFI)*

The ultra-thin film interferometry technique provides a method of measuring the thickness of very thin lubricating films in rolling contact between a glass flat and a steel ball. In co-operation with traction measurements, film thickness


#### **Table 3.**

*The composition and properties of gasolines, MTBE and diesel fuels used in this study.*

measurements can provide valuable information concerning the rheological and friction behaviour of fuels at high pressures and high shear rates. A major limitation of conventional optical interferometry is that it cannot be used to measure films less than approximately one quarter the wavelength of the visible light used (approximately 75 nm), since this corresponds to the first destructive interference fringe of the shortest wavelength visible light. An ultra-thin EHD film thickness measurement technique was therefore developed by Johnson, Wayte and Spikes in the early 1990s to overcome this limitation [2].

This method used a transparent SiO2 or Al2O3 "spacer layer" coating, typically 430 nm thick, applied on the top of a semi-reflecting film on a transparent glass or sapphire flat. This coating enables interference fringes to be obtained even in the absence of an oil film. A schematic representation of EHD test device used in this study is shown in **Figure 9**.

A 19.05 mm in diameter steel ball is loaded against a rotating glass disk. The glass disc is driven by a motor and the disc drives the steel ball in nominally pure rolling. The rotating speed of the glass disc can be continually adjusted down to 0.0002 m/s to allow the measurement of very thin films formed by fuels.

**Figure 9.** *Schematic representation of EHD film thickness test device.*

#### *Gasoline Lubricity DOI: http://dx.doi.org/10.5772/intechopen.101302*

The underside surface of the glass disc is coated with a very thin, sputtered layer of chromium. A transparent silica layer, of thickness greater than half of the wavelength of visible light, is deposited on the top of the semi-reflecting chromium layer. White light is shone through the glass disc into the contact between the glass disc and the steel ball. Some light is reflected from the semi-reflecting chromium layer and some light passes through the fuel film and is reflected off the steel ball. Since the intensity of the two reflected beams is similar, constructive or destructive interference produces an interference pattern based on the thickness of fuel film. A spectrometer is used to determine the wavelength of maximum constructive interference. A menu-driven computer program is employed for image grabbing and analysis [3].

As shown in **Figure 9**, the test fuel is enclosed in a chamber to reduce evaporation during the test. All tests in the current study were carried out at 25 � 0.5°C. The load applied was 20 N, corresponding to a maximum Hertz pressure of 0.48 GPa in the contact and the composite roughness of the undeformed surfaces was 11 nm.

#### *7.3.2 Hamrock-Dowson Equation*

A number of equations have been developed for predicting EHD film thickness of lubricants. The most widely-used are the formulae proposed by Hamrock and Dowson in the 1970s (186), which can be employed with confidence for many material combinations including steel on steel up to maximum pressure of 3–4 GPa [4]. They were developed by regression-fitting numerical solutions of the EHD contact problem over a range of loads, speeds, geometries and materials. The Hamrock-Dowson equation for central film thickness *hc* is expressed by

$$\hbar\omega/R\_{\text{x}} = K \cdot U^{0.67} \mathbf{G}^{0.53} \mathbf{W}^{-0.067} \tag{2}$$

where

*U* = (*uη*0/*E*<sup>0</sup> *R*0 )—the non-dimensional speed parameter. *G* = (*αE*<sup>0</sup> )—the non-dimensional material parameter. *W* = (*w*/*E*<sup>0</sup> *R*02 )—the non-dimensional load parameter. *K* = 2.69 (1–0.61e � 0.73k). *k* = *a*/*b*—ellipticity parameter. *K* ≈ 1.0339 (*R*<sup>0</sup> *<sup>x</sup>*/*R*<sup>0</sup> *y*) 0.636. *Rx*, *Ry* reduced radii of curvature in the '*x*' and '*y*' directions, respectively. *η*0—the viscosity at atmospheric pressure of the lubricant (Pas). *E*0 –the reduced Young's modulus (Pa), 2/*E*<sup>0</sup> = (1 + *ν*<sup>1</sup> 2 )/*E*<sup>1</sup> + (1 � ν<sup>1</sup> 2 )/*E*2. *u*—the entraining surface speed (m/s) = (*u*<sup>1</sup> + *u*2)/2.

*Rx*—the reduced radius of curvature in the entrainment direction (m), 1/*Rx* = 1/*R*1*<sup>x</sup>* + 1/*R*2*x*.

*α*—the pressure-viscosity coefficient (m2 /N).

*w*—the contact load (N).

For a fixed lubricant, load and contact geometry, EHD film thickness is thus proportional to (*U*) 0.67, so that a log (film thickness) versus log (speed) plot for a given fluid at a given temperature should yield a straight line of gradient 0.67.

#### *7.3.3 Film thickness test results*

**Figure 10** shows the variation of film thickness with rolling speed for five fluids, two diesels, two gasolines and MTBE. The following main features can be seen (**Figure 11**).

**Figure 10.** *Film thickness of gasolines and diesel fuels.*

#### **Figure 11.**

*Film thickness of purified hexadecane compared with diesel fuels.*


The high lubricity diesel fuel obeys the EHD theory only down to about 17 nm. Below this, the film is thicker than predicted, probably due to boundary film formation. This can be explained by the fact that Shell Class 1 is much purer than high lubricity diesel. and impurities in high lubricity diesel fuel contribute to film thickness at low speed.


#### *7.3.4 Discussion of film thickness results*

#### *7.3.4.1 Thick film behaviour*

At high speeds, all fluids appeared to give behaviour consistent with EHD theory. **Table 4** lists the film thicknesses of all fuels at 2 m/s together with their viscosities at 25°C.

**Table 4** indicates the film formation of hexadecane and **Figure 12** compares the film thickness of hexadecane taken from reference [7] with the two diesel fuels. It can be seen that the latter give similar film thicknesses comparable to hexadecane. It is possible to use these film thickness results to obtain approximate value of pressureviscosity coefficient, or "*α*-value" of gasolines and diesel fuels [8]. Assuming that EHD behaviour is occurring, from the Hamrock and Dowson equation.

$$h = k \left( U \eta \right)^{0.67} a^{0.53} \tag{3}$$

By comparing two fluids at the same speed, load, solid geometry and materials.

$$h\_1/h\_2 = \left(\eta\_1/\eta\_2\right)^{0.67} \left(a\_1/a\_2\right)^{0.53} \tag{4}$$

The film thickness, viscosity, and α-value of mineral oil were used to determine the α-value of gasolines and diesel fuels in this experiment. The results are shown in **Table 5**.


**Table 4.**

*The EHD film thickness of test fluids and fuels at 2 m/s and their viscosity at 25°C. \* by extrapolation.*

#### **Figure 12.**

*The* α*-values versus temperature for some hydrocarbons (completed from references [5, 6]).*

The viscosity-pressure dependence of several hydrocarbons boiling in the gasoline-diesel fuel range has been studied previously. Bispo use a vibrating-wire viscometer to measure the viscosity of toluene and some C5–C10 normal alkanes in the pressure range of 0.1–300 MPa and temperature range 30–70°C. Ducoulombier et al. determined the viscosities of some alkyl benzenes and C10–C18 normal alkanes using a falling body viscometer. **Table 5** shows α-values of hydrocarbons in the gasoline-diesel boiling range which are derived from these data using the Barus isothermal viscosity pressure equation:

$$a = [\ln \left(\eta/\eta\_0\right)]/p \tag{5}$$

where *p* is the pressure.

*η*<sup>0</sup> is dynamic viscosity at *p* = 0 and at a constant temperature.

The effect of temperature on the *α*-values of these components is shown in **Figure 12**.

**Figure 12** shows how alpha value varies with temperature. It can be seen that for gasoline model compounds (C5–C10), the curves are almost flat, i.e. α-values are

#### *Gasoline Lubricity DOI: http://dx.doi.org/10.5772/intechopen.101302*


#### **Table 5.**

*The effective pressure-viscosity coefficient of gasolines and diesel fuels.*


#### **Table 6.**

#### *The* α*-values of some gasoline components and diesel components, derived from references [5, 6].*

independent on temperature in range of 30–70°C. In contrast, diesel model compounds (C12 C18) exhibit an obviously higher temperature gradient. Toluene gives the lowest α-value as compared with other hydrocarbons.

As shown in **Tables 4** and **6**, the values of pressure viscosity coefficient for gasolines (6.3–7.1 GPa<sup>1</sup> ) are comparable to those for C7–C10 aromatics (6.2– 8.4 GPa<sup>1</sup> ), and C5–C10 normal alkanes (7.6–8.3 GPa<sup>1</sup> ) if one bears in mind the difficulties associated with the EHD film determination of such volatile and extremely low viscosity liquids. MTBE gives a particularly low *α*-value of 2.5 GPa<sup>1</sup> . For diesel fuels similar phenomena are observed. The *α*-values of diesel fuels (8.0– 10.1 GPa<sup>1</sup> ) are lower but comparable to that for C10–C18 normal hydrocarbons (8.3–14.5 GPa<sup>1</sup> ). For gasolines the *α*-values are about 1 GPa<sup>1</sup> lower than the corresponding average *α*-values of their main hydrocarbon components (C5–C10 hydrocarbons) measured using viscometers. In case of diesel fuels, the *α*-values of C10–C18 hydrocarbons is 8.3–14.5 GPa<sup>1</sup> and diesel fuel *α*-values are in the range 8–10.1 GPa<sup>1</sup> and thus the difference is about 2 GPa<sup>1</sup> . In general, the *α*-values of gasoline and diesel fuel obtained using film thickness results are about 20% lower than corresponding average *α*-values of their main components, measured using conventional high pressure viscometry. This is consistent with previous findings (187) [9]. Baskerville and Moore have indicated that estimated *α*-values obtained using film thickness results were about 26% lower than those determined by conventional viscometry, irrespective of fluid type or temperature [9]. This was

explained by the response of lubricants to the severe conditions of shear or the systematic error in determining film thickness (187) [9].

#### *7.3.4.2 Discussion of boundary film behaviour*

It is clear from the results in **Figure 10** that the diesel fuels and one of the gasolines gave pronounced boundary film behaviour.

The boundary film formation properties of some hydrocarbons and synthetic fluids in rolling concentrated contacts have been investigated by Gao and Spikes [10]. It was found that a deviation from EHD theory can occur at between 1 and 10 nm for some base fluids. The enhancement of film thickness was ascribed to the formation of high viscosity layers, a few monolayers thick, on solid surfaces. This effect becomes significant when the film thickness generated is comparable to the thickness of the viscous layers, typically 1–10 nm. No measurable boundary film were found with hexadecane or other pure hydrocarbons.

The boundary film effect was further investigated by Gao et al. using binary mixtures of synthetic lubricants with different polarity and viscosity [11]. As shown in **Figure 13**, addition of 10% wt. of high viscosity ester into low viscosity polyalphaolefin produces a positive divergence from theoretical value, to approach the pure ester behaviour in very thin film region. When 10% wt. of low viscosity ester is added to the high viscosity polyalphaolefin, the trend is reversed and negative divergence is observed (**Figure 14**).

This phenomenon was interpreted in terms of the fractionation of base fluids due to Van der Waals forces very close to polar solid surfaces [12]. The thickness of EHD films formed in the very thin film region (<10 nm) is then controlled by the viscosity of the more polar component rather than the viscosity of the blend [12].

In the current research, a similar departure from EHD theoretical line was observed with most fuels in the 5–20 nm range: however only positive divergence was observed. Very pure fuels, such as gasoline E and MTBE, exhibited less deviation in this region (**Figure 10**). This phenomenon may be explained based on the boundary film formation of polar constituents in fuels. Two different effects are possible.

a. The adsorption of naturally-occurred polar impurities and gasoline oxidation products

As described, non-additised modern gasolines generally contain about a few tens of ppm wt. of sulphur (thiophenes, benzothiophenes and sulphides), about 10 ppm

**Figure 13.** *The effect of addition of 10% wt. high viscosity ester in low viscosity polyalphaolefin [11].*

**Figure 14.** *The effect of addition of 10% wt. low viscosity ester in high viscosity polyalphaolefin [11].*

of nitrogen (pyridines and isoquinolines), and trace amounts of oxygen-containing impurities (alkylphenols, alcohols and alkoxyalcohols). Although these polar impurities are only present in a very small quantity in gasolines, they are polar and, in general, would be more viscous than gasoline hydrocarbon constituents. For example, phenol has a viscosity of about 6 cP at 25°C, about 10 times that of gasoline. The oxidation of unstable components, mainly olefins and diolefins, in long-term storage will also increase the polar impurity content in gasoline. These polar impurities may play a part in thin film gasoline EHD lubrication, by surface adsorption.

#### b. The polymerisation of diolefin components in gasolines

The two gasolines had been stored in a tightly-closed vessel 1 year before tests. Both gasolines probably contained about 0.5% wt. diolefin which has very strong polymerisation tendency (**Table 4**). It is possible that a polymer film was formed by a chain reaction mechanism. Polymers in solution have been shown to form enhanced EHD film formation at low speeds [13]. As a polymer, detergent can have a considerable influence on the viscosity of gasoline fuels and thus on the consequent EHD film-forming properties.

Gasoline E exhibit less divergence probably related to the presence of MTBE. The free radicals produced during oxidation of MTBE (as an ether MTBE is more easily oxidised to peroxide than gasoline hydrocarbons) will interfere with gasoline autoxidation and gum forming tendency.

It is reasonable to expect that elastohydrodynamic (EHD) film formation by gasoline may also play an important role.

#### **Conflict of interest**

The author declare no conflict of interest on the information delivered in this chapter.

*Crude Oil - New Technologies and Recent Approaches*

#### **Author details**

Panagiotis Arkoudeas School of Chemical Engineering, National Technical University of Athens (NTUA), Athens, Greece

\*Address all correspondence to: potis.arkoudeas@hotmail.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.

### **References**

[1] Arkoudeas P. Lubricity of middle and light distillates of petroleum [dissertation thesis]. NTUA; 2009

[2] Wei DP, Spikes H, Koreck S. The lubricity of gasoline. Tribology Transactions. 1999;**52**(4):813-823

[3] Spikes HA, Ratoi M. Ultra-thin film interferometry manual. Tribology Series. 2000

[4] Stachowiak GW, Batchelor AW. Engineering Tribology. 1st ed. Amsterdam, New York: Elsevier; 1993

[5] Oliveira CMBP. Viscosity of liquid hydrocarbons at high pressure [PhD thesis]. London: Imperial College (University of London); 1991

[6] Zhou H, Lagourette B, Alliez J, Xans P, Montel F. Development and application of simha equation of state to calculation of the density of certain alkanes and their mixtures. Fluid Phase Equilibria. 1989;**47**(2-3):153-169

[7] Guangteng G, Spikes HA. Boundary film formation by lubricant base fluids. Tribology Transactions. 1996;**39**(2): 448-454. DOI: 10.1080/104020 09608983551

[8] Stachowiak GW, Batchelor W. Engineering Tribology. Series 24. Amsterdam: Elsevier; 1993. p. 586

[9] Baskerville FM, Moore AJ. Film thickness anomalies in very thin elastohydrodynamic oil films. Tribology Series. 1997;**32**:147-157

[10] Guangteng G, Spikes HA. Behaviour of lubricants in the mixed elastohydrodynamic regime. Tribology Series. 1995;**30**:479-485

[11] Guangteng G, Spikes H. Fractionation of liquid lubricants at solid surfaces. Wear. 1996;**200**(1-2): 336-345

[12] Guangteng G, Spikes H. The control of friction by molecular fractionation of base fluid mixtures at metal surfaces. Tribology Transactions. 1997;**40**(3): 461-469. DOI: 10.1080/1040200970 8983681

[13] Smeeth M, Spikes H, Gounsel S. Boundary film formation by viscosity index improvers. Tribology Transactions. 1996;**39**(3):726-734. DOI: 10.1080/10402009608983590

**Chapter 8**

## Oil Losses Problem in Oil and Gas Industries

*Yulius Deddy Hermawan, Dedy Kristanto and Hariyadi*

#### **Abstract**

Oil losses is a problem that often arises in oil and gas industries either in onshore or offshore area. There is a loss discrepancy between total quantities from shippers and measurement in the storage tanks; the total sending volume is lower than the measured volume in the mixing tank in a gathering station; this is known as oil losses. When this occurs, an agreement to determine a fair share of the losses must be made. There are two categories of oil losses, they are individual and group losses. Individual loss occurs when oil from one shipper has not been mixed yet with other oils. This includes emulsion and evaporative losses. Group loss occurs during mixing oils in the same storage tank or pipeline. Furthermore, by knowing the causes of oil losses, a way to minimize oil losses can be determined.

**Keywords:** Emulsion, Flash, Offset, Oil losses, Proportional, Shrinkage, Stratified

#### **1. Introduction**

Oil losses problem often arises in oil and gas industries either in onshore or offshore area. There is a loss discrepancy between total quantities from shippers and measurement in the storage tanks; the total sending volume is lower than the measured volume in the mixing tank; this is known as oil losses. When this occurs, an agreement to determine a fair share of the losses must be made. Hermawan et al. [1] have classified oil losses into two categories, they are (1) individual and (2) group losses.

#### **1.1 Individual loss**

Individual loss occurs when oil from one shipper has not been mixed yet with other oils. This includes emulsion and evaporative losses. In order to determine emulsion loss, basic sediment and water (BS and W) of oil should be measured. The net standard volume (NSV) excludes sediment, water, and free water. Evaporative loss occurs when light components are released from oil in the storage tank. This happens when the oil temperature in tank is higher than its bubble point.

#### **1.2 Group loss**

**Figure 1** shows typical pipeline system and storage tank for oil gathering activity. The use of the same pipeline to transport the crude oil to a storage tank and oil mixing process either in the same temporary or final storage tank could come up the problem of oil losses. Group loss occurs during mixing oils in the same storage tank

**Figure 1.**

*Pipeline system and storage tank for oil gathering activity. (a) Pipeline System. (b) Storage Tank.*

#### **Figure 2.**

*Typical oil mixing phenomena in gathering station.*

or pipeline. Typical oil mixing phenomena in the gathering station is illustrated in **Figure 2**.

The specific characteristic which has a great effect on group loss is the specific gravity (SG) or API gravity. Petroleum can be classified based on its characteristics, for example density i.e., SG or API, (which indicates heavy oil or light oil), normal boiling point (which indicates the ease with which the oil evaporates), and viscosity (which indicates the ease with which the oil flows). There are five categories of the petroleum fluid, they are dry gas, wet gas, gas condensate, volatile oil, and black oil [2, 3]. The properties of petroleum fluids will change when they mix together in the same tank. In this case, the oil volume shrinkage occurs when two or more oils are mixed in the same storage tank. As shown in **Figure 2**, Shipper A and B undergo the mixing process 3 times, i.e., mixing in the Station-1, Station-2, and Station-3. This means that Shipper A and B will experience 3 times the volume depreciation. Shipper C and D experience the mixing phenomena twice and once, respectively. When compared to other Shippers, the volume of shrinkage for Shipper D will be less because it only experiences one mixing phenomena.

The group loss can also occur in the use of the same 3-phase-separator to separate the well stream into three phases of oil, gas, and water, as shown in **Figure 3**. The 3-phase-separator is often used in both onshore and offshore areas. In separators, gas is flashed from the liquids and free water is separated from the oil. These steps remove enough light hydrocarbons to produce a stable crude oil [4]. On the other

*Oil Losses Problem in Oil and Gas Industries DOI: http://dx.doi.org/10.5772/intechopen.97553*

**Figure 3.** *Typical 3-phase-separator in the oil and gas gathering station.*

hand, setting and controlling of the interface level in 3-phase-separator must be seriously done in order to avoid oil losses due to the offset phenomena. In this case, offset means that water can overflow the weir and follow with oil to the oil storage tank, and vice versa, underflowing oil with the water stream [5].

#### **2. Procedure of sharing oil losess**

The typical block diagram of oil distribution and mixing phenomena as shown in **Figure 4** would be used as a case study of oil losses problem in the oil and gas industries. In this case, shippers are defined as the petroleum companies, both government and private companies that are members of the cooperation contract contractor. In general, the criteria for shippers are based on the type of oil produced from the oilfield for examples, heavy oil, light oil, and condensate.

When this study was carried out, the weather conditions are as follows: the air temperature varied from 26.7 to 28.7°C, and humidity varied from 71 to 82%. Climate data (from the Juanda Meteorological Station, Surabaya, Indonesia) shows an annual average rainfall of 1.969 mm/year. The ratio of the dry to wet months is

**Figure 4.**

*The typical block diagram of oil distribution and mixing phenomena.*

0.5109 or 51.09%. The climate in the study location is relatively wet because the number of dry months is relatively the same as the number of wet months.

In this case, shipper A and B will have 3 times mixing in TANK-1, TANK-2, and TANK-3, respectively; Shipper C will have twice mixing in TANK-2 and TANK-3; while Shipper D has only once mixing in TANK-3. The tank criteria used in this case is the welded steel tank for storing petroleum at the atmospheric pressure accordance with PTK-013/PTK/II/2007, BPMIGAS, February 12, 2007, Decree of the Head of BPMIGAS: Operation and Maintenance of Petroleum Storage Tanks. Oil tank capacity depends on its production rate. In addition, the tank capacity also depends on its function, whether for temporary or final storage. TANK-1 and TANK-2 are the temporary storage tank with capacity @30,000 barrels, and Tank-3 is the final storage tank with capacity 900,000 barrels. Calculation of sharing oil losses can be determined with the following procedures.

#### **2.1 Required data**

The data required in the calculation of sharing oil losses are the gross production rate in barrel fluid per day (BFPD), the water cut (WC, %-volume), the tank's conditions (pressure and temperature), the oil specific gravity (SGo), the formation water specific gravity (SGw), basic sediment and water (BS&W, %-volume), and hydro carbon composition (%-mole). The required data for calculating of sharing oil losses are listed in **Tables 1** and **2**.

As shown in **Table 1**, all shippers produce fluid with different characteristic, water cut and BS&W. Shipper D produces condensate with water cut and BS&W equal to zero. All fluids are stored in the atmospheric storage tank (pressure of about 1 atm and temperature of about 30°C. Water cut is a parameter that shows the water content that is easily separated naturally from oil. While BS&W shows the amount of water and based sediment in the oil which is difficult to separate naturally. In other words, the BS&W separation can only be carried out with the aid of a separator such as a centrifuge.

Based on the water cut data, the oil rate of each shipper can be calculated. The oil rates after being separated from free water for shippers A, B, and C are 600, 1800, and 950 BOPD (barrel oil per day), respectively. But these rates are still the gross rate due to basic sediment and water content. The net standard volume (NSV) excludes sediment, water, and free water. The NSV is obtained from the gross volume minus free water and BS&W volume. In order to calculate the total sharing oil losses, the individual losses such as emulsion and evaporative losses must first be calculated.


*\* Shipper D produces condensate, BFPD: Barrel Fluid Per Day, WC: Water Cut in %-Vol, SGo: Specific Gravity of oil, SGw: Specific Gravity of formation water, BS&W: Basic sediment and water in %-Vol.*

#### **Table 1.**

*The required data: production rate, tank's condition, properties.*


#### *Oil Losses Problem in Oil and Gas Industries DOI: http://dx.doi.org/10.5772/intechopen.97553*

**Table 2.**

*The required data: hydrocarbon composition (%-mole).*

#### **2.2 Calculation of emulsion correction factor**

BS&W is required to calculate the emulsion losses. In this case, BS&W in oils shipper A, B, and C are taken the same 0.25%-vol (**Table 1**). The BS&W in oil of shipper D is zero since this oil is a typical condensate.

For calculation emulsion losses, the empiric emulsion equations for all shippers must be determined. The emulsion parameters (*a*1, *b*1, *a*2, *b*2) for each shipper are

shown in **Table 3**. The empiric emulsion equations and emulsion loss can be determined with following procedure:

a. First, we make a curve of percentage of the addition of the volume of formation water (in %vol) versus the calculated SG. The first curve produces linear equation:

$$Y\_1 = a\_1 X\_1 + b\_1 \tag{1}$$

where *X*<sup>1</sup> is the percentage of the addition of the volume of formation water (in %vol), *Y*<sup>1</sup> is the calculated SG, *a*<sup>1</sup> and *b*<sup>1</sup> are constants. The calculated SG is:

$$\text{SG}\_{\text{calculated}} = (\mathbf{1} - X\_w)\mathbf{S}\mathbf{G}\_\mathbf{o} + X\_w \mathbf{S}\mathbf{G}\_\mathbf{w} \tag{2}$$

where *Xw* is water volume fraction in oil, SGw is specific gravity of formation water, and SGo is specific gravity of oil. The correlation between the calculated SG and the percentage of the addition of the volume of formation water for shippers A, B, and C is shown in **Figure 5**.


**Table 3.** *Emulsion parameters.*

**Figure 5.** *Emulsion profile of Shippers A, B, and C.*


$$Y\_2 = a\_2 X\_2 + b\_2 \tag{3}$$

where *X*<sup>2</sup> is the measured BS&W, *Y*<sup>2</sup> is the measured SG, *a*<sup>2</sup> and *b*<sup>2</sup> are constants. The correlation between the measured SG and measured BS&W for shippers A, B, and C is shown in **Figure 5**


$$\text{ECF} = \mathbf{X}\_1 - \mathbf{X}\_2 \tag{4}$$

The resulted ECF for all shippers are listed in **Table 3**. The constants of *a*1*, b*1*, a*2*,* and *b*2*,* are taken from **Figure 5**.

#### **2.3 Calculation of evaporative correction factor**

The flash calculation is usually used in the application of Vapor–Liquid-Equilibrium (VLE). Just like the name, a liquid will "flashes" or partially evaporates

**Figure 6.** *Flash Calculation algorithm [1].*


#### **Table 4.**

*Antoine parameters for hydrocarbon:* T *in K;* P *in kPa.*

at a system pressure, when the liquid temperature is higher than its bubble temperature, producing a two-phase system of vapor and liquid in equilibrium [6]. Flash calculation is an integral part of process engineering calculations. Someone uses the flash calculation in order to determine the amounts (in moles) of hydrocarbon liquid and gas coexisting in a vessel at a given pressure and temperature. The flash calculation is also accomplished to determine the composition of the existing hydrocarbon phases [7].

*Oil Losses Problem in Oil and Gas Industries DOI: http://dx.doi.org/10.5772/intechopen.97553*


#### **Table 5.**

*Calculation procedure of bubble point* Tb *[1].*


#### **Table 6.**

*Calculation procedure of dew point* Td *[1].*

Flash calculation method is used to calculate evaporative loss. The three important parameters used in the flash calculation are pressure (*P*), temperature (*T*), and vapor fraction (*nv*). Evaporation is indicated by the value of vapor fraction [7]. The value of vapor fraction (*nv*) ranges in between 0 to 1. If *the* vapor fraction equals 0, the fluid is in liquid phase, if it equals 1, the fluid is in gas phase. Elseif it is in between 0 and 1 (0<*nv*<1), the fluid is in mixed-liquid–vapor phase; in other words, part of light component in fluid evaporates; this causes oil loss due to flash phenomena [1].

**Figure 6** shows the flash calculation algorithm. The data required in the flash calculation are hydrocarbon composition (*zi*), pressure (*Pi*), and temperature (*Ti*) of each shipper fluid. The intended pressure (*Pi*) in this case is the fluid pressure in a storage tank. The fluids of all shippers are stored in atmospheric tanks with temperatures about 30°C (**Table 1**). The Antoine equation which is used to calculate flash correction factor (FCF, in %Vol) is taken from the equation "Anto5" in UniSim Design R451 Honeywell [8], and written as follows:

$$P\_{nap\ j} = \exp\left(a\_j + \frac{b\_j}{(T + c\_j)} + d\_j \ln\left(T\right) + e\_j T^{f\_j}\right) \tag{5}$$


**Table 7.**

*Calculation procedure of vapor fraction* nv *[1].*


#### **Table 8.**

*Normal bubble and dew points of crude oils.*

where *Pvap j* is vapor pressure of component *j* (in kPa),*T* is temperature of system (in K), and *aj*, *bj*, *cj*, *dj*, *ej*, *fj* are Antoine parameters for each component *j* and listed in **Table 4**.

The flash correction factor (FCF), in %Vol, must be calculated in order to know the oil losses due to flash phenomena. The FCF can be determined with following procedure:


#### *Oil Losses Problem in Oil and Gas Industries DOI: http://dx.doi.org/10.5772/intechopen.97553*


#### **Table 9.**

*Total individual losses.*


*The constants of* a, b, c *are referenced from PSME of UPN "Veteran" Yogyakarta collaborated with LEMIGAS Jakarta [9].*

#### **Table 10.**

*Parameters* a*,* b*,* c *in API 12.3 equations.*


#### **Table 11.**

*Calculation procedure of shrinkage volume in tanks.\**

$$\text{FCF} = n\_v \ge \mathbf{100\%} \tag{6}$$

where FCF is in %Vol.

The calculation results of *Tb* and *Td* for all shippers are listed in **Table 8**. Since the fluid storage temperatures in tanks for all shippers are lower than their bubble points, all fluids are in liquid phase. There are no evaporative losses.

#### **2.4 Calculation of individual loss**

Individual loss consists of emulsion and evaporative losses. Individual loss for each shipper is listed in **Table 9**. Shipper B produces the biggest individual loss, i.e., 201.13 barrel, due to its high water cut and BS&W. The total individual loss (TIL) is 252.69 barrel. Finally, the net standard volume (NSV) that excludes sediment, water, and free water is 3747.31 barrel. The NSV is then used to calculate the shrinkage volume factor in the group losses.

#### **2.5 Calculation of shrinkage correction factor**

A shrinkage loss is a group loss in oils mixing. The modified equation of API 12.3 is used for calculating of shrinkage losses and defined as follows:

$$\mathcal{S}\_h(\mathfrak{M}) = a \, L\_c (\mathbf{100} - L\_c)^b (\Delta^o \mathbf{A} \mathbf{P} \mathbf{I})^c \tag{7}$$

where *a*, *b*, and *c* are constants of modified API 12.3 as listed in **Table 10**, *Lc* is % light component, Δ<sup>o</sup> API is <sup>o</sup> API difference between <sup>o</sup> API of shipper one and other, and *Sh* is shrinkage volume percentage (in %Vol).

As written in McCain [10], the API gravity for each shipper is defined as follows:

$$^\circ \text{API}\_i = \frac{141.5}{\text{SG}\_i} - 131.5 \tag{8}$$

where <sup>o</sup> API*<sup>i</sup>* is API gravity of shipper *i*, and *SGi* is specific gravity (60o /60<sup>o</sup> ) of shipper *i*. Calculation procedure of shrinkage volume in tanks is shown in **Tables 11** and **12**.

#### **2.6 Determination of sharing oil losses**

Sharing oil losses can be determined with 2 methods, they are Proportional Method, and Stratified Method [1].


**Table 12.**

*The oil mixing stratification in each tank.*


*NSV: Net Standard Volume (barrel); SG: Specific Gravity;* x*: volume fraction; SCF: Shrinkage Correction Factor (%Vol).*

#### **Table 13.**

*Proportional sharing losses results.*

**Figure 7.**

*Shrinkage volume illustration from mixing phenomenon of light and heavy oils [1].*

#### **2.7 Proportional method**

In oil and gas industries, the proportional method is frequently utilized to determine sharing oil losses. The operator measures the total received volume of oil in TANK-3 at the last station (see **Figure 2**). This measured volume value represents the net corrected volume (NCV) which does not take into account the mixing event at the previous station.


*Oil Losses Problem in Oil and Gas Industries DOI: http://dx.doi.org/10.5772/intechopen.97553*

> **Table 14.**

*Stratified sharing losses results.*

The total shrinkage volume (*Vsh*-prop) is the difference volume between the total volume sent from all shippers and the net corrected volume as written below:

$$V\_{sh-\text{prop}} = \sum\_{i=1}^{n} V\_i - V\_{nc\text{ (TANK-3)}} \tag{9}$$

where *Vi* is net standard volume of shipper *i*, and *Vnc* (TANK-3) is the netcorrected-volume in TANK-3. The proportional shrinkage volume for each shipper (*ξ*prop*<sup>i</sup>* ) can be calculated as follows:

$$\xi\_{\text{prop}\_i} = \frac{\varkappa\_i \left( \mathbb{1}\_{\text{SG}\_i} \right)}{\sum\_{i=1}^n \varkappa\_i \left( \mathbb{1}\_{\text{SG}\_i} \right)} V\_{sh-\text{prop}} \tag{10}$$

where *xi* is volume fraction of shipper *i* as defined below:

$$\mathbf{x}\_{i} = \frac{\mathbf{V}\_{i}}{\sum\_{i=1}^{n} \mathbf{V}\_{i}} \tag{11}$$

The proportional shrinkage correction factor (SCFprop*<sup>i</sup>* in %Vol) for each shipper can then be calculated as follows:

$$\text{SCF}\_{\text{prop}\_i} = \frac{\xi\_{prop\_i}}{V\_i} \ge 100\% \tag{12}$$

The shrinkage correction factors (SCF) with proportional method are listed in **Table 13**. The total shrinkage loss is 4.49 barrel. The SCF for each shipper is almost the same, i.e., 0,12%-Vol. When compared with other shippers, the shipper D has the highest value of SCF, i.e., 0.13%-Vol, because the oil of shipper D is categorized as condensate. Condensate which is also known as a light oil or gas oil has different characteristics with the heavy oil. The light oil has a low density with small molecular size. The molecular size of light oil is smaller than heavy oil, so it is understandable that when they mix together, shrinkage will occur geometrically as shown in **Figure 7**. This phenomenon is in accordance with the observations of Erno et al. [11], James [12], Shanshool et al. [13], and Hermawan et al. [1]. The proportional method is considered unfair since the last shipper who experienced a few mixing processes also bears losses of other upstream shippers.


#### **Table 15.**

*Comparison between proportional and stratified results.*

#### **2.8 Stratified Method**

The stratified method is the new method proposed by Hermawan et al. [1] where the net corrected volume (NCV) is calculated stratify from tank to tank as shown in **Tables 11** and **12**. The shrinkage volume is calculated for every mixing in the tank. Therefore, more often oil mixes with others; its volume will be more decreased.

The shrinkage volume for shippers A and B in TANK-1 is written as follows:

$$\xi\_{\rm st-li} = \frac{\varkappa\_i \left( \mathbb{1}\_{\rm SG} \right)}{\sum\_{i=1}^n \varkappa\_i \left( \mathbb{1}\_{\rm SG} \right)} V\_{\rm slg-1} \tag{13}$$

where *ξ*st�I*<sup>i</sup>* is shrinkage volume for shipper *i* (A, B) in TANK-1, and *Vshg-*<sup>I</sup> is the group shrinkage volume in TANK-1. The shrinkage volume for shipper C and TANK-1 (mix A-B) in TANK-2 can be calculated with the following equation:

$$\xi\_{\rm st-IIi} = \frac{\varkappa\_i \left( \mathbb{1} \langle \mathsf{S}\_{\rm G} \rangle \right)}{\sum\_{i=1}^{n} \varkappa\_i \left( \mathbb{1} \langle \mathsf{S}\_{\rm G} \rangle \right)} \, \mathsf{V}\_{\rm shg-II} \tag{14}$$


**Table 16.** *Daily join report.*

where *ξ*st�II*<sup>i</sup>* is shrinkage volume for shipper *i* (C, and mix A-B) in TANK-2, and *Vshg-*II is the group shrinkage volume in TANK-2. Finally, the shrinkage volume for shipper D and TANK-2 (mix A-B-C) in TANK-3 can be determined as follows:

$$\xi\_{\rm st-III\_i} = \frac{\varkappa\_i \left(1\_{\rm SG\_i}\right)}{\sum\_{i=1}^n \varkappa\_i \left(1\_{\rm SG\_i}\right)} V\_{\rm shg-III} \tag{15}$$

where *ξ*st�III*<sup>i</sup>* is shrinkage volume for shipper *i* (D, and mix A-B-C) in TANK-3, and *Vshg-*III is the group shrinkage volume in TANK-3.

The total stratified shrinkage volume (*ξ*st�tot*i*) for shippers A and B are the summation of its shrinkage volume in TANK-1, TANK-2, and TANK-3, for shipper C is those in TANK-2 and TANK-3; while for shipper D is only once in the last tank of TANK-3.

$$
\xi\_{\rm st-toti} = \xi\_{\rm st-li} + \xi\_{\rm st-IIIi} + \xi\_{\rm st-IIIi} \tag{16}
$$

where for shipper C*ξ*st�I*<sup>i</sup>* ¼ 0, and for shipper D*ξ*st�I*<sup>i</sup>* ¼ *ξ*st�II*<sup>i</sup>* ¼ 0 .

The stratified shrinkage correction factor (SCFst*<sup>i</sup>* in %Vol) for each shipper can then be determined with the following equation:

$$\text{SCF}\_{\text{st}\_i} = \frac{\xi\_{\text{st-tot}}}{V\_i} \ge 100\% \tag{17}$$

**Table 14** shows the stratified sharing losses results. The subtotal oil losses in TANK-1, TANK-2, and TANK-3 are 0.89, 2.88, and 0.72 barrels, respectively. The stratified method produces the total oil loss of 4.49 barrels. This result is the same with the proportional result. The SCFs in TANK-1, TANK-2, and TANK-3 for each shipper are almost the same, i.e., 0.04%-Vol, 0.09%-Vol, and 0.02%-Vol, respectively. If compared with other shippers, the total SCF of shippers A and B are the biggest one, i.e., 0.14%Vol. The total SCF of shipper C is 0.10%Vol. While the total SCF of shipper D is the smallest one, i.e., 0.02%Vol.

Comparison between proportional and stratified results is shown in **Table 15**. More often oil mixes with others; its volume will be more decreased. The stratified method is therefore considered fair, since the oil volume shrinkage of each shipper is calculated according to the amount of the mixing phenomena.

#### **3. Daily join report**

A Joint Report is created when several Cooperation Contract Contractors or Shippers use shared facilities, so that a distribution mechanism for oil losses due to evaporation, emulsion, and shrinkage is required [14, 15]. Daily join report needs to be compiled to find out the distribution of oil losses for each shipper. The stratified method is chosen to determine sharing oil losses since this method gives the fair results. The daily join report for all shippers is shown in **Table 16**.

#### **4. Sources of oil losses**

Causes of oil losses that can be minimized are as follows:

• Limited number of tanks in the field (both storage and handover tanks), so this will limit the *settling time* for separation of water and sediment.


Inevitable oil losses are as follows:


#### **5. Conclusion**

A case study on oil losses in the oil and gas industries has been discussed for some shippers namely, shipper A, B, C, and D with typical diagram of oil distribution and mixing process. The individual loss includes loss due to water cut, emulsion and evaporation phenomena. The parameters of water cut (%-vol) and BS&W (%-Vol) need to be identified to calculate the net volume free of water and sediment. However, shipper D does not contribute emulsion loss because its oil is typically condensate with BS&W=0. All shippers do not produce evaporative loss, because the oil temperatures in tanks are lower than its bubble temperature.

The group loss happens during mixing oil in the same storage tank. The parameter of oil specific gravity must be determined to calculated the group loss. The oil volume will shrink when two or more oils mix together in the same storage tank. In this case, the proportional and stratified methods have been utilized to calculate the sharing oil losses. The proportional method gives almost the same of shrinkage correction factor (SCF) for all shippers. However, the proportional method is considered unfair, since the downstream shipper, e.g., shipper D, bear the losses of the upstream shippers (shippers A, B, and C). Therefore, the stratified method is considered fair for determining the sharing oil losses, since the oil loss of each shipper is calculated based on the amount of the mixing event.

According to the analysis of oil losses case study with typical oil distribution flow diagram in the oil and gas industries, the considered several ways to prevent oil losses include the following:

• Provide the adequate tanks in the field (both storage and handover tanks), so this will give enough settling time for separation of water and sediment. The

available tank should meet predetermined criteria such as material and good welding so as not to leak.


#### **List of abbreviation**


*Oil Losses Problem in Oil and Gas Industries DOI: http://dx.doi.org/10.5772/intechopen.97553*

#### **Author details**

Yulius Deddy Hermawan<sup>1</sup> \*, Dedy Kristanto<sup>2</sup> \* and Hariyadi<sup>2</sup>

1 Department of Chemical Engineering, Faculty of Industrial Engineering, Universitas Pembangunan Nasional "Veteran" Yogyakarta, Yogyakarta, Indonesia

2 Department of Petroleum Engineering, Faculty of Mineral Technology, Universitas Pembangunan Nasional "Veteran" Yogyakarta, Yogyakarta, Indonesia

\*Address all correspondence to: ydhermawan@upnyk.ac.id and dedikristanto@upnyk.ac.id

© 2021 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.

### **References**

[1] Hermawan YD, Kristanto D, Hariyadi, Wibowo (2019) Determination of sharing oil losses using proportional and stratified methods in Krisna field, Journal of Petroleum Exploration and Production Technology, https://doi.org/10.1007/ s13202-019-0724-8

[2] McCain WD Jr. (1990.a), Component of Naturally Occuring Petroleum Fluids, in The Properties of Petroleum Fluids, Pennwell Books, PennWell Publishing Company, 2nd ed., Tulsa, Oklahama, pp. 1-45.

[3] Whitson CH, Brule MR (2000), Volumetric and Phase Behavior of Oil dan Gas Systems, in Phase Behavior, Henry L. Doherty Memorial Fund of AIME, Society of Petroleum Engineers Inc. Richardson, Texas, pp. 1-13.

[4] Arnold K, Stewart M (1999) Surface production operations: design of oilhandling system and facilities, 2nd edn Vol. 1, Gulf Publishing Company, Houston, TX, p. 1-25.

[5] PSP MIGAS (*Study Center of Oil and Gas Development*) of UPN "Veteran" Yogyakarta collaborated with LEMIGAS Jakarta (2019) Oil losses study of oil distribution from Central Gathering Station to Floating Storage and Offloading (*in Indonesian*).

[6] Smith JM, Van Ness HC, Abbott MM (2001), *Introduction to Chemical Engineering Thermodynamics*, 6th ed. in SI Unit, McGraw Hill, New York, p. 314-351.

[7] Ahmed T, 2007, *Equations of State and PVT Analysis: Applications for Improved Reservoir Modeling*, Gulf Publishing Company, Houston, Texas, p. 331-365.

[8] UniSim Design R451 Thermo Reference Guide, (2017), Honeywell

[9] PSME (*Study Center of Mineral and Energy*) of UPN "Veteran" Yogyakarta collaborated with LEMIGAS Jakarta (2017), Oil Losses Study of Oil Distribution in "P" Field (*in Indonesian*).

[10] McCainWD Jr (1990.b), Properties of Black Oils-Definition, in The Properties of Petroleum Fluids, Pennwell Books, PennWell Publishing Company, 2nd ed., Tulsa, Oklahama, pp. 224-225.

[11] Erno BP, Chriest J, Given R (1994), Equation Predicts Shrinkage of Heavy Oil/Condensate Blend, *Oil & Gas Journal*, May 12, 1994.

[12] James H (2014), Shrinkage Loses Resulting from Liquid Hydrocarbon Blending, iMEC Cooperation.

[13] Shanshool J, Habobi N, Kareem S (2011), Volumetric Behavior of Mixtures of Different Oil Stock, *Petroleum & Coal Journal*, 53 (3), August 2011, pp. 223-228.

[14] PTK-013/PTK/II/2007, BPMIGAS, February 12, 2007, Decree of the Head of BPMIGAS: Operation and Maintenance of Petroleum Storage Tanks (*Pengoperasian dan Pemeliharaan Tangki Penyimpanan Minyak Bumi*).

[15] PTK-062/SKKO0000/2016/S0, SKKMIGAS, December 13, 2016, Decree of the Head of SKKMIGAS: Guidelines for the Management of Oil and Gas Production (*Pedoman Tata Kerja Manajemen Produksi Minyak dan Gas Bumi*).

[16] Kokal S (2005), "Crude Oil Emulsions: A State of the Art Review", SPE 77497.

Section 4 Case Studies

#### **Chapter 9**

## Improving Reserves and Well Productivity Using Modern Technologies

*Haq Minhas*

#### **Abstract**

The oil trapped in a reservoir rock through geological processes over millions of years is called the Original Oil in Place (OOIP). Oil recovery factor (RF) represents the recoverable fraction of OOIP. We do not have any control on the quantity of OOIP. However, the volume that we can recover is partly in our control. Through proper well placement, engineering, and production technologies, we can recover anywhere from 5 to 70% of OOIP. Exactly how much we will recover depends on the techniques employed and the nature of the reservoir. The economically recoverable oil is called the *reserves*. In this chapter, we will talk about various oil field technologies that can be employed to maximize petroleum reserves. We will explore some emerging technologies and processes that have helped some fields achieve 70% recovery factor while others are trailing behind, stuck at an average of 35% recovery factor, some as low as 10%. Despite all the hype, and many decades of research, Enhanced Oil Recovery (EOR) is contributing just about 4% of total world production, and most of it is from thermal EOR. We need a profound shift in the EOR technology application required to make it simple and widely applicable.

**Keywords:** enhanced oil recovery (EOR), improved oil recovery (IOR). Water flooding, upstream technology, recovery factor, field development planning

#### **1. Introduction**

Achieving highest recovery factor is perhaps an implicit success metric for any oil company. It not only improves the financial value of the company but also reflects its technical prowess. Yet the industry is hovering around a dismal average of 30% recovery factor. In this document, we will explore the blocks and block busters to reach high recovery factors in the range of 50–70%. Improving recovery factor is a two-step process, a good understanding of and the ability to control the recovery mechanisms involved. The first part needs a good reservoir characterization using the modern reservoir evaluation technologies and modeling. The second part requires deploying various technologies to economically maximize hydrocarbon recovery through a sound Field Development Plan (FDP). The FDP is perhaps the most important event in the life of an oil field. An FDP lays the foundation of whether the field will achieve a high recovery factor or remain an average recovery factor field. We cannot overemphasize the importance of FDP and therefore start this chapter with a review of FDP process and highlight some of the best practices. Reservoir management, also a component of FDP, is perhaps the second most important intangible technology having the greatest impact on recovery factor. As part of reservoir management, a periodic review of the full field after a period of production may uncover many new opportunities even in the old fields [1].

There are several enabling technologies that have large influence on recovery factors including 3D/4D-seismic, horizontal drilling, geosteering, hydraulic fracturing, intelligent completions, digital coring, machine learning, and digitalization. Enhanced Oil Recovery (EOR) is one technology that has not delivered to its promise yet. Several fields have achieved recovery factors in the range of 60–70% even without EOR [2]. There is an emerging realization to morph EOR technology to a workable tool. The long cycle of EOR projects from lab to field can be shortened and EOR should be integrated with initial field development plan rather than an afterthought as tertiary recovery. We will explore the key characteristics of various fields with high and low recovery factor to understand if it is the nature of the reservoir, fluid properties, field size, technology application, development strategy, or the team behind the field that has the biggest influence on recovery factor. Several benchmarking studies have given new insights as what really matters in recovery factors.

Shale revolution in the US is perhaps the best example of what technology can do. The combination of hydraulic fracturing and horizontal drilling with high-rate fluid injection has added billions of barrels of oil reserves from low-permeability geological formations that were considered uneconomical just 20 years ago. Today, the shale formations in the US are producing some 8 million barrel per day of oil, thanks to the technology. Still very low recovery factor of less than 10% in shale oil is a major challenge and perhaps a limiting factor to the growth and the future of shale oil and shale gas. Such low recovery factors mean more drilling to maintain production, excessive costs, and a large footprint of shale development. Achieving high recovery factors in shale oil could become a new resource of hydrocarbon, perhaps bigger than the original shale oil.

The recent EIA recommendations to ban all new exploration activities to achieve net-zero carbon emissions by 2050, the world economy recovering fast from COVID-19, rapidly rising oil price, giant discoveries becoming rare, and energy transition to renewables, is a rare combination of rising oil demand with a reduction of oil exploration. It is no brainer that adding reserves and production from existing oil fields is the only option to mitigate a looming oil crisis. It is quite doable when we look at some historical numbers summarized in **Table 1**.

With more focus, investments, and application of new technology, we can squeeze even more from the existing fields and keep up with the desired growth in reserves. This is the main theme of this chapter. How can technologies help in extracting more petroleum reserves?


**Table 1.**

*Historical reserve addition—new discoveries VS improvements from existing fields.*

*Improving Reserves and Well Productivity Using Modern Technologies DOI: http://dx.doi.org/10.5772/intechopen.102897*

We have structured this chapter to start with the field development planning, the basic concepts of oil recovery and well productivity, enabling technologies for conventional reservoirs and shale oil, and a discussion on enhanced oil recovery. We can either push the oil toward the producing wells or we can reach the oil that otherwise cannot reach the producing well due to restricted flow paths. Or we use a combination of both techniques, pushing the oil and reaching the oil. Water flooding and most enhanced oil recovery techniques are examples of pushing the oil. On the other hand, complex wells, multilaterals, hydraulic fracturing, and various stimulation techniques are examples of reaching the oil. Reservoir permeability is a key criterion in the selection of appropriate technique.

This chapter will provide a high-level discussion of key technologies together with a focus on reservoir to increase oil recovery and well productivity. In a nutshell, with detailed knowledge of subsurface geology and fluid movements, if we can position the producing and injection wells at optimum location equipped with adequate completion jewelry, we are well on the way to high recoveries.

#### **2. Field development plan: the blueprint of the reservoir**

The fundamental job of a reservoir engineer is to engineer and maximize oil recovery and the economics of the reservoir. We use an approach as in **Figure 1** for life cycle field optimization. Understanding or characterizing the reservoir is the first step in building a reservoir model. We simply cannot model something that we do not understand is a classic quote from L. P. Dake. The reservoir model is used to make an optimum field development plan (FDP). All possible development options are considered and the one with the highest financial returns and recovery is selected. Monitoring of the reservoir behavior during drilling and production is critical to ensure our reservoir models and the reservoir understanding was correct and the field is behaving as expected. In case of any surprises, we may re-engineer our FDP to still get the highest value for our investment. For example, if the oil water contact is found lower than expected, then the depth of water injection wells can be adjusted accordingly. We may need to update our models and FDP frequently based on drilling, formation evaluation, and early production data.

The advancements in technology have improved this process in many ways. Many new formation evaluation techniques such as nuclear magnetic resonance, deep-investigating shear wave, deep-reading resistivity, wellbore imaging, digital rock physics, 3D seismic, and sequence stratigraphy have greatly enhanced our reservoir understanding. With the advances in well placement technologies, we can place the wells at optimum locations to maximize recovery. Modeling and reservoir

**Figure 1.** *Continuous optimization of NPV during field life.*

#### *Crude Oil - New Technologies and Recent Approaches*

simulation with high-speed computers has not only increased our response time to quickly update the models but also reduced the amount of upscaling that we had to do in the past and added more reliability in out models. The real-time data combined with data analytics is opening another avenue of opportunities and reservoir modeling. These technologies may even discover some treasures hidden in the heaps of old data.

Different stages of field development process are shown in **Figure 2** and explained below


#### **Figure 2.**

*Stage of field development for conventional reservoirs. Our focus changes over time from information collection to optimized development to minimizing costs.*

cost, and schedule estimates for every option considered. It usually starts with ruling out the options that are technically not feasible.

	- Objective of the development
	- Details of geoscience and petroleum engineering data used for the modeling
	- Production forecasts of the models including low, median, and high case
	- Description of engineering facilities
	- Cost estimates
	- Operating, maintenance, and reservoir monitoring protocols
	- Project planning
	- Project economics
	- Budget proposal

#### **Figure 3.**

*Execution of field development plan.*

reservoir management uses a life cycle approach as shown in **Figure 1**. Continuous monitoring and periodic adjustment of the reservoir models ensures optimum reservoir performance and update to the field development plans if needed. Quite often, we update the models and adjust the field development plan many times during the life of a field as shown in **Figure 2** labeled FDP-1, FDP-2, FDP-x. While FDP-1 is green field development, FDP-2 and the later FDPs are part of the brown field development.

• **Changing focus during different phases.** During different stages of development, the importance or focus changes from maximizing information at appraisal stage to optimization during early development to cost saving during development. The curious and questioning mind set of "do what is right" changes to an executor mind set of "do the things right." Some companies use the analogy of thinking hats. The project team uses three different hats: a) information gathering hat, b) do the right development hat, and c) do the development right hat. However, there is often some overlap. We may get new information even during development and production stage that is crucial to reservoir understanding. Likewise at the appraisal phase, we have some idea of the ultimate development and collect the relevant information.

Smart fields are a further enhancement to above approach shown in **Figure 1**. In this case, flow rate from each well and if possible, from each segment of horizontal wells or each zone can be adjusted to ensure uniform production from the entire reservoir and achieve a uniform injection. This results in large gains in recovery.

#### **2.1 Assurance review of FDP: a cold-eye review**

Assurance review process or value assurance review, a routine practice in most companies is a proven process that can add substantial value to any project. Essentially, a team of experts will review the project in detail to identify any gaps or improvements before the project goes to the management for funding. However, in

#### *Improving Reserves and Well Productivity Using Modern Technologies DOI: http://dx.doi.org/10.5772/intechopen.102897*

some cases the process may become a formality with little value addition. There are two versions of assurance review—a power point review and a consultation review. In a power point review, the project team presents the final project to the review team in a presentation session. Such review may uncover some key shortcoming in the project but not everything. In a consultation review, the review team will spend few days with the project team to go through every detail and suggest any improvement or alternatives if needed. Such a session can significantly improve the skills of the project team as a by-product of project review.

The review team could be internal or external. Internal teams may have the advantage of having the background knowledge of local geology but may have biases toward the project or conflict of interest if there are mutual reviews. Review by external teams, the so-called cold-eye review, could be more effective especially by industry experts who have reviewed hundreds of other projects and carry with them decades of knowledge.

#### **2.2 Giving the old fields a new life**

There are many examples where a field may not have started with an optimum development plan. This happens mostly with old fields. A full-field review of such underperforming fields can often uncover many new opportunities to improve production and recovery. Usually, the past costs are considered sunk costs and forward economics is used for any investment decisions in these projects. **Figure 4** shows an example of a field revival from Venezuela. In 1995, the production had declined to one fourth of initial levels and it appeared as if there is little left in the field. But a new reservoir understanding following an integrated study and application of new technologies revived the field again. The literature is rife with such examples where many oil fields got a new life after a study and a dose of new technology.

#### **Figure 4.**

*Better reservoir understanding followed with additional wells and recompletion of existing wells resulted in large production increase—example from Venezuela (Hamilton 2002).*

There are several reasons to revisit old fields to extract the remaining oil:


#### **2.3 The role of new technology in field development**

Several new technologies have been developed that have significantly transformed field development planning. This includes new measurements for formation evaluation, advances in computing power and modeling, advances in drilling technology, well placement, completion, and instrumentation.

#### *2.3.1 New measurements for formation evaluation: Deeper and clearer*

There are several technologies that have radically improved formation evaluation and help in better reservoir characterization.


*Improving Reserves and Well Productivity Using Modern Technologies DOI: http://dx.doi.org/10.5772/intechopen.102897*

flow in porous media. Such pore scale modeling has wide applications in recovery process. It can be used to obtain relative permeability data for every rock type and with a turnaround time of weeks what used to take several months from the lab measurements. This can significantly improve the quality of reservoir models and speed up the development.

4. Several wireline measurements can now be made with while-drilling technology. This real-time formation evaluation is the backbone of geosteering that allows the well to track the reservoir at optimum location through well placement technology.

#### **3. The elements of well productivity**

The fluid flow from reservoir to wellbore through porous media is described in Eq. (1) below. This is a solution of diffusivity equation for an ideal homogeneous reservoir.

$$q = \frac{kh\left(p\_r - p\_{wf}\right)}{141.2 B\_o \mu\_o \left(\ln\frac{r\_c}{r\_w} - \frac{1}{2} + S\right)}\tag{1}$$

In this equation, q is flow rate, k is reservoir horizontal permeability, pr is the reservoir pressure, pwf is the flowing bottom hole pressure, Bo is oil formation factor which is the ratio of reservoir volume to surface volume of oil, μ<sup>o</sup> is oil viscosity, re is the reservoir radius, rw is the wellbore radius, S is the wellbore skin that indicates the connectivity of wellbore to the reservoir, a positive value shows a poor connectivity or flow restriction in the near wellbore region such as damage wellbore, a negative value on the other hand suggests improved flow paths in the near wellbore region typically created by stimulation or hydraulic fracturing.

We will use aforesaid equation to explore how we can use various well technologies to maximize flow rate. In a later section, we will consider how to maximize total recovery from the reservoir. The flow rate q (bbl/d) in Eq. (1) is controlled by the following parameters.

1.Reservoir Pressure, Pr, the higher it is the higher the flow rate will be. At the time of the reservoir discovery, we find the initial reservoir pressure (pi), later it will reduce or deplete with production. The production will start declining as the reservoir pressure Pr reduces as in Eq. (1). We often try to maintain the well production by gradual reduction of surface pressure, by increasing the choke size, and produce the well at constant rate before the inevitable decline in well production when the surface pressure has reached its minimum. To avoid this production decline, we often try to maintain reservoir pressure through pressure maintenance by injecting water or gas. The ratio of injected volume to produced volume is called voidage replacement ratio (VRR), which is monitored in any water flood project to ensure adequate injection. Water or gas injection has another more important function as well. It displaces oil in addition to providing pressure support. Water injection through vertical wells is not very efficient as it creates localized regions of high-pressure and high-water saturation resulting in water breakthrough and poor reservoir sweep. New technologies such as horizontal wells equipped with inflow control devices, or diversion

technologies, allow a more uniform water injection and production through long-distributed length of horizontal wellbore rather than a single-point injection and production from vertical wells. We can manipulate reservoir pressure and fluid displacement through several waterflood technologies.

	- a. Flow rate will be high in a high permeability and large reservoir thickness. In case of low-permeability reservoirs, we can use hydraulic fracturing to get reasonable flow rates and make the marginal wells more profitable. In the extreme case of nano-Darcy reservoirs such as shale reservoirs, the well may not flow at all without hydraulic fracturing. As shown in **Figure 5**, fractures in low-permeability reservoirs can increase the overall system permeability many times compared with the unfractured matrix permeability (100 or 1000 times or even more depending on the matrix permeability). Hydraulic fracturing creates system permeability in two ways. It creates new hydraulic fractures, parallel to maximum horizontal stress that can be preserved through proppant or sand placement in the fractures.

#### **Figure 5.**

*Fold of increase in the overall system permeability due to the presence of fractures. These fractures could be natural fractures or man made through the process of hydraulic fracturing (ref. [4]).*

*Improving Reserves and Well Productivity Using Modern Technologies DOI: http://dx.doi.org/10.5772/intechopen.102897*

#### **Figure 6.**

*Shear movement in existing natural fractures creates conductivity in natural fractures, which can be otherwise closed. After movement, the fracture face leaves a small opening that provides a conductive path for fluid to flow.*

> Conventional wisdom is that these hydraulically created fractures parallel to maximum stress are easier to open and easier to remain open and these are the ones responsible for increase in production in lowpermeability reservoirs. However, hydraulic fracturing also activates and makes conductive the existing natural fractures in shale or tight formations, especially the critically stressed fractures that are aligned at small angles from maximum stress orientation, typically +/ 30o to maximum horizontal stress. This happens by small shear movement in the fractures as shown in **Figure 6** [5]. This also explains why slick water, with no proppant, has been working so well in many shale formations. It also explains a frequently observed mismatch between production logs and the occurrence of natural fractures. Mostly, the fractures aligned with critical stress orientation are seen to dominate the production. This concept is motivating shale drillers to orient wells to target the critically stressed natural fractures. Fracturing then is the obvious choice in low-permeability reservoirs as it will increase the overall or the system permeability.


Although in the aforesaid discussion improvement in well productivity was the focus, in most cases both the well productivity and the fluid recovery are linked

together. Water flooding improves well productivity by maintaining reservoir pressure, and improves recovery by prolonging well life and mostly by fluid displacement. Hydraulic fracturing is historically used to increase well productivity by reducing the wellbore skin. This also reduces the abandonment pressure and thus improves the fluid recovery. In very tight formations to shale reservoirs, the wells may not produce economically without hydraulic fracturing. In this case, hydraulic fracturing will increase both the well productivity and the reserves.

#### **4. Low oil recovery factor: still a challenge for petroleum industry**

A global average 30% Recovery Factor in oil reservoirs is a major challenge for petroleum industry as identified by SPE in its six grand challenges [6]. Such low recovery factors also make us one of the least efficient industries in terms of input to output ratio. Can we do any better? Yes, it is indeed doable as proven by many oil companies that have raised the bar of recovery factor to 50% or more with water flooding in combination with new technologies. Even a 70% recovery factor is not out of reach. Saudi Aramco's has launched a plan to raise its recovery factor of major producing fields from current 50–70% [7]. A study of 730 sandstone reservoirs was carried out [8] to understand what drove some reservoirs to achieve very high recovery factors. Key traits of high recovery reservoirs include homogeneous and good-quality reservoirs with strong water drive. Important observations of this study are highlighted below:


In short, we can achieve high recovery factor by following the best practices of reservoir management.

#### **4.1 Fundamentals of oil recovery**

Natural depletion of reservoir pressure, called the primary recovery, uses only the natural reservoir pressure support. This support could come from expansion of oil above bubble point pressure, release of solution gas below bubble point pressure, influx of gas from gas cap, or influx of water from possible connected aquifer. Often such natural pressure supports are either weak or absent and may result in very low recovery factor, except in very strong water aquifer. Recovery factor from primary recovery is less than 20% in most cases. In some countries, the regulators do not allow producing some oil field purely in primary recovery phase to achieve maximum recovery.

#### **4.2 Secondary recovery**

The secondary recovery using water or gas injection is used in majority of the fields. Globally, the combined recovery factors from primary and secondary

*Improving Reserves and Well Productivity Using Modern Technologies DOI: http://dx.doi.org/10.5772/intechopen.102897*

recovery range between 35 and 45% [9] or an additional 15–25% recovery attributed to water injection. The purpose of water injection is to provide pressure support and displace oil with water. The injection will be more effective when the injected water can push the oil like a piston. However, it rarely happens. The injection water often fingers through oil due to its lower viscosity, wettability effects, and reservoir heterogeneities. Significant quantity of oil is left behind after water flooding. Even without any Enhanced Oil Recovery techniques, water flood projects can achieve an additional 10–30% recovery factor as proven by several high recovery water floods. This was achieved by a combination of new technology and reservoir management. Recovery factor from water flooding or gas flooding is approximately given by the following relation,

$$\mathbf{RF} = \mathbf{E\_{PS}} \times \mathbf{E\_S} \times \mathbf{E\_D} \tag{2}$$


#### **Figure 7.**

*Microscopically bypassed oil during water flood in a water wet reservoir (Eps). The oil is in red, grains in yellow and water in blue color. The figure on the left shows the original oil and water saturations before water flooding. The figure on the right shows the saturations during water flooding (ref. [2]). In water wet reservoirs, the water moves around the grains and small pore throats leaving some oil trapped in the larger pores.*

#### **Figure 8.**

*Macroscopically bypassed oil (Es). Water flood from left flows through higher permeability, by passing oil in the lower right in a 6-m-thick layer (ref. [2]).*

#### **Figure 9.**

*Improved sweep efficiency of water after adding polymer due to lowering of water mobility (ref. [10]).*

conformance. Various near wellbore and deep-reservoir diversion techniques are used to improve water conformance and the resulting Es. **Figure 9** illustrates how the addition of polymer to water can improve its sweep efficiency by making the water more viscous and sweep the oil in a more piston like manner.

• Ed is the fraction of the reservoir volume connected to any well. Ed is adversely affected in reservoir with vertical or horizontal barriers, or compartmentalized reservoirs. Reservoir understanding combined with horizontal or multi-lateral wells or infill wells has helped the industry greatly increasing Ed.

The different components of recovery mechanism as depicted in Eq. (2) suggest that we must understand and then control recovery process from pore to reservoir scales (**Figure 10**).

As shown in **Figure 1**, the reservoir understanding starts even before drilling the first well, and the field appraisal is done to improve reservoir understanding and reduce the reservoir uncertainties. A field development plan is then formulated based on the best reservoir understanding at that time. The field production and monitoring provide the dynamic reservoir information when the fluid movement

**Figure 10.** *Example of oil left in isolated compartments (Ed).*

*Improving Reserves and Well Productivity Using Modern Technologies DOI: http://dx.doi.org/10.5772/intechopen.102897*

takes place in the reservoir. Despite all these data collection activities, our reservoir understanding is often far from perfect, especially in complex geologies. Often the reservoir data are fragmented among different disciplines. Integration of every piece of data is the first step behind reservoir understanding. Complex geological models are a great tool to pull all these data together. Reservoir simulation is then used to evaluate different development and production options and select the most optimum one to build a field development plan. History matching the model with production data provides another dimension of reservoir characterization, which is based on reservoir performance. It helps in understanding the reservoir compartments, communication with aquifer or gas cap, and reservoir heterogeneities. These models can then help in predicting the performance of different water flood techniques to select the most optimum option.

#### **4.3 Formation evaluation**

Our journey to reservoir understanding starts with an initial geological model, which is built using surface acquired seismic, gravity, or magnetic surveys. Well drilling provides the first source of direct measurements in the subsurface. Well logs in the form of gamma ray, density, resistivity, neutron, sonic, caliper, nuclear magnetic resonance combined with rock, and fluid sampling have been used for many decades. A whole science of understanding rock and fluid distribution in the near-wellbore formations is based on these well logs, which is collectively called formation evaluation. Reservoir dynamics involve the measurement of reservoir pressure during fluid movements in the rocks few centimeters or few hundred of meters away from the wellbore using formation testers or transient well testing. The objectives of formation evaluation can be classified as below:


In the past, aforesaid measurements were made with wireline tools after drilling the well. The downhole data are transmitted to surface using electrical cables called wireline. With advances in technology, most of these measurements are now possible while drilling a well and the data transmitted to surface in real time using mud pulses or measurement while drilling technology. The logging while drilling or LWD provides data for formation evaluation as soon as or soon after the drilling bit penetrates the rocks. LWD has become essential for placing the well or steering the bit at optimum location in the reservoir in geosteering systems.

#### **5. Oil recovery from tight matrix in fractured reservoir**

Naturally fractured reservoir with tight matrix is perhaps the most difficult reservoir to achieve a decent recovery factor. Any water injection scheme will quickly flood the fractures, leaving most of the oil untouched in the matrix. In primary recovery phase, in the absence of any pressure support, the oil filled in the open fractures will be produced as flush production. The pressure inside the fractures will reduce over a short period of time as recharge from tight matrix to the fractures is very slow. In case of depletion drive, the tight matrix will continue recharging the fractures, though very slowly, resulting in a long tail of low production after the initial flash production. In case of strong connected aquifer, the fracture could quickly result in high water cut. The result is traditionally very low recovery factor in such reservoirs in both primary and secondary recovery phases. The shale reservoirs are even worse in terms of recovery factors and much more challenging since the matrix permeability is extremely low. Injecting any fluid into matrix in the presence of high-permeability fractures is a challenge. Several CO2 EOR huff-n-puff trials have shown some promising results in shale oil. These EOR technologies combined with controlled hydraulic fracturing and flow diversion technologies may give a new life to conventional fractured reservoirs with tight matrix as well. In many shale formations, the natural fractures are often closed and non-productive. In several studies, modeling, and micro-seismic during hydraulic fracturing have shown that fracturing with high-rate slick water can potentially make these close fractures conductive through shear movement, especially those aligned with present day stress. This is earlier shown in **Figure 6**.

#### **5.1 The complex wells: Taking the well to the reservoir**

The drilling technology together with measurement while drilling has become so advanced that we can drill wells almost along any trajectory that is optimum for reservoir management. Maximizing well to reservoir contact has greatly improved both the production per well and the recovery factor as well. Vertical wells are drilled with rotary drilling rig where the bit turns using a turntable at surface connected to the bit through hollow drill pipes. Horizontal drilling was traditionally done with mud turbine where the bit turns by the flow of mud. In this case, the pipe does not rotate. The pipe just slides as the bit is cutting through the rock. The more advanced Rotary Steerable System (RSS) uses a combination of downhole motor and pipe rotation. This system in combination with geosteering system can make the well track very complex geologies.

#### **6. The smart wells: Taking the chokes downhole**

Non-uniform production and injection from horizontal wells had been a major challenge for production engineer. An early excitement about long horizontal wells died after realization that productivity from horizontal wells was much less than expected considering the length of the well. Many production logs and well modeling revealed that higher pressure drops at the heel of the well resulted in higher production at the heel compared with the toe of the well. The result was less production from the toe of the well and often water or gas breakthrough near the well heel. Reservoir heterogeneities along the wellbore multiplied the problem of non-uniform production from horizontal wells.

*Improving Reserves and Well Productivity Using Modern Technologies DOI: http://dx.doi.org/10.5772/intechopen.102897*

An obvious solution was to introduce multiple downhole chokes called inflow control devices (ICD). Model-based flow restriction, ICD's is placed along the well length together with isolation packers that would result in more or less uniform production or injection along the well length. A more advanced version of flow control allows the adjustment of choking from surface. Such flow controls devices are called Inflow Control Valves. Downhole measurements of rate, pressure, and temperature can also be added. With surface control system and data transmission to a central location—this now becomes a smart well—part of a smart or intelligent field. Production or reservoir engineers from their offices can not only monitor but also control well production or even production from any section of the well. This has provided a huge boost to both production and recovery factors.

#### **7. Technologies for tight and shale reservoirs**

Hydraulic fracturing has been around for nearly 70 years. There had been a million fracturing jobs from 1940 to 2000. Another 6 million treatments were added from 2000 till now. More than half of the US production is attributed to hydraulic fracturing. Perhaps, hydraulic fracturing is the second most important technology after drilling. In addition, hydraulic fracturing is a very forgiving technique. We can often get away with good production increase even from an imperfect job. The success of this technology was its own enemy. For long time, there were no new developments in hydraulic fracturing. In many companies, it was called pressure pumping. Most fracture models were assumed as planner fractures in solid material, ignoring the presence of porosity, natural fractures, and other heterogeneities. The success of shale gas from early 2000 and later shale oil from 2007 motivated the service industry to come up with several new frac fluids, proppants, and the equipment. Efficiency of frac operations, cost reductions using pad drilling, horizontal well placement, slick water, and zipper fracs were the other major improvements. Realtime fracture monitoring using micro-seismic, downhole pressure monitoring, analysis of treating pressure, and experience of millions of treatments has tremendously increased our understanding of hydraulic fracturing in tight formations. Realization that natural fractures may re-activate during pumping as shown in **Figure 6** clearly negated he earlier assumptions of planner hydraulic fractures. All these developments in multiple technologies resulted in nearly 8 million bbl/d of shale oil. **Figure 11** below shows how the production from multi-stage fracturing in horizontal wells has impacted the overall US oil production.

#### **8. Enhanced oil recovery (EOR): the pinnacle of reservoir engineering**

Enhanced oil recovery (EOR) is oil recovery by the injection of materials not normally present in petroleum reservoirs. Despite lot of research EOR has not delivered in traditional applications in the form of tertiary recovery after water-flooding. Recently, many new concepts have emerged where EOR is being considered from early on rather than a late stage or tertiary form of recovery. Several successful polymer flooding together with the initial water flooding has been very successful. Low salinity water flooding is another promising technique that can significantly improve recovery without any new facilities. Despite a long history of EOR, a strong need of improving recovery factor, and lot of research on EOR, the total EOR contribution is just about 4 million bbl/d for the whole world. What is the reason of such dismal performance of EOR technology, and can we change EOR strategy to make it a success?

#### **Figure 11.**

*US oil production historical chart. Without shale oil, the US oil production would have been around 4000 bopd. Shale oil production reached to nearly 9000 bopd. It stands again nearly 8000 bopd, after the slowdown from COVID-19.*


The aforesaid does not mean a gloomy future for EOR. Going back to Eq. (2), the multilateral smart wells may increase macroscopic sweep efficiently Es and connected volume efficiency Ed, but the microscopic efficiency factor Eps can only be altered by some EOR technique. EOR may also increase Es beyond what smart well technology can do. The smart well technology could become an enabler of EOR. With advancements in computing power, the simulation models can incorporate the full physics and chemistry of EOR process now. Once calibrated with lab experiments, we may not need pilot testing for every EOR project. The fear of EOR should gradually go away once EOR becomes easy and more docile rather than frightening for the management. There are some field developments where EOR was considered from day one of field development such as polymer flooding or flooding with smart water. Perhaps, the term EOR should disappear completely and get integrated with secondary recovery. EOR, as is defined today, is not the only and the best route to high ultimate recovery.

#### **8.1 Recovery factor in shale oil: still a challenge**

While producing oil from dense shale rocks that had been discarded for many decades was a great achievement that has revolutionized the oil outlook in US and the rest of the world, an average recovery factor of less than 10% is a major challenge. Improving this recovery factor could unleash a huge new resource of oil. In Bakken alone, the in-place volume of shale oil is around 900 billion barrel. Projected recovery factor for Bakken is only 7%. Increasing this number by 5 or 10% can give hundreds of billions of barrels of additional oil. There is a huge prize if any of the ongoing EOR trials become successful. The reason of low recovery factor in shale rocks is very low matrix permeability in the range of micro- to nano-Darcy resembling concrete or even granite. It takes a long time for fluid to move from tight matrix to the fractures. With multistage horizontal wells, we create a stimulated volume of rock around the wellbore, which is a network of fractures or re-activated natural fractures. After fracturing, the oil from the fractures flows into the wellbore but the production quickly declines as the total volume capacity of the fractures is very small. The oil now moves very slowly from matrix to the fractures, and the well continues flowing at a very low rate for many years. Depletion drive with no pressure support is the other reason of low recovery factor. Even in a conventional reservoir depletion drive recovery factor would be around 15% in a low-permeability reservoir.

Several EOR techniques are being investigated that include miscible gases, surfactant, and low-salinity water flooding.

#### **9. A journey toward 70% recovery factor**

Achieving 70% recovery factor is not a destination but a journey. The closer we get to high recovery factor, the more difficult and expensive it will become to improve it further. Identification of potential oil traps from early reservoir studies is extremely important. For example, in a good permeability homogeneous formation, viscous fingering and fluid by-passed at pore level needs attention by controlling mobility ratio of injection fluid. In multi-layered system, the oil in low-permeability layers is likely to

#### **Figure 12.**

*Path to getting highest recovery factor. Get the low-hanging fruits first. Maximum value comes from initial development plan.*

remain undrained without diversion technologies. In random reservoir heterogeneities such as in some carbonate reservoirs, deep-reservoir diversion technologies could be more effective. In tight matrix-fractured reservoir, fluid will drain quickly from fractures, and any water injection will quickly flood the fractures leading to extremely high water cut, while bulk of the oil in matrix will remain unproduced. Unlocking matrix oil is the key in this case. In short, there is no magic bullet to reach the high recovery factor. It is a journey where we should target the big and the easy oil first—which is often the low hanging fruit. As in **Figure 11**, maximizing ED should be the top priority. If the oil is stranded in some compartments and we use expensive EOR chemicals to improve pore scale recovery factor, it will be a blunder. Next improving sweep control is the most important. If water is unable to reach any part of the reservoir, it is unlikely for expensive chemicals to reach there either. Addressing pore-level displacement is most difficult and often the last shot. As a quick check, in a situation of very low recovery factor in the range of 20–30%, it is probably reservoir connectivity (ED) or reservoir sweep (ES) that needs attention (**Figure 12**).

#### **10. Conclusion**

**Figure 13** summarizes the key parameters or activities that have greatest influence on recovery factor of conventional reservoirs. For heavy oil, the efficiency of Cyclic Steam Stimulation (CSS) or steam flooding and well spacing will be more important.

A strategy to high Recovery Factor is described in this paper based on the authors personal experience and recent benchmarking studies,

1.A good reservoir understanding is the starting point. New higher resolution and deeper measurements together with 4D seismic can radically improve reservoir characterization from micrometer to hundreds of meters.

**Figure 13.** *Key influencers in recovery factor.*

*Improving Reserves and Well Productivity Using Modern Technologies DOI: http://dx.doi.org/10.5772/intechopen.102897*


### **Author details**

Haq Minhas Director Reservoir Technology, Eternal Energy, Dubai, UAE

\*Address all correspondence to: haqminhas@me.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.

### **References**

[1] Shepherd M. Oil Field Production Geology

[2] Muggeridge A, Cockin A, Webb K, Frampton H, Collins I, Moulds T, et al. Recovery rates, enhanced oil recovery and technological limits. Recovery rates, enhanced oil recovery and technological limits (nih.gov)

[3] Cohen D. On the Likelihood of peak oil. Available from: https://www.resilie nce.org/stories/2007-05-31/likelihoodpeak-oil/

[4] Jennifer L. Miskimins, Hydraulic Fracturing Fundamentals and Advances. SPE Monograph Series

[5] Dusseault M, McLennan J. Massive Multi-Stage Hydraulic Fracturing: Where are We? (open article) Review\_ Massive\_Multi-Stage\_Hydraulic\_Frac turing\_Where\_are\_We.pdf (spbstu.ru) [Accessed on 24 Feb 2022]

[6] Meehan N. The Six Grand Challenges. JPT; 2015. Available from: https://jpt.spe.org/grand-challengeseng ineering

[7] Henni A. Saudi Aramco Boosts R&D Efforts to Increase Oil Recovery. JPT; 2015

[8] Lu X, Sun S, Dodds R. Toward 70% Recovery Factor: Knowledge of Reservoir Characteristics and IOR/EOR Methods from Global Analogs. Presented at SPE Improved Oil Recovery Conference held in Tulsa, Oklahoma, USA; 11-13 April 2016. SPE-179586

[9] Zitha P, Felder R, Zornes D, Brown K, Mohanty K. Increasing Hydrocarbon Recovery Factor. Increasing Hydrocarbon Recovery Factors (spe.org)

[10] Thomas A. Polymer Flooding. Rijeka: IntechOpen; 2016

#### **Chapter 10**

## Connect Two Crude Oil Distillation Units with One Crude Oil De-Salter in Dewania Refinery

*Omar Mahmoud Waheeb*

#### **Abstract**

Crude oil, which exported to refineries, already contains salt, water, and fouling crude oil received with salt content not less than 50 ppm. Dewania refinery with a capacity of 20,000 BPSD, which serves with two crude distillation units, each unit with a capacity of 10,000 BPSD, which operate without crude desalter. In an aim to reduce the effects of salts, water and, fouling associated with crude oil, two crude distillation units connected with one crude oil desalter with a capacity of 20,000 BPSD (one desalter). crude oil desalter transferred from (Daura Refinery) to Dewania refinery, in aim to reduce salt content from 50ppm to 5 ppm and mitigate water and other fouling. Crude oil desalter installed in the middle distance between two crude distillations units (90 m from each unit isometric piping). Crude oil, which is pumped by a charge pump to preheated in crude oil distillation unit with a train of heat exchangers. When the pipeline size increased from 4″ to 6″, which reduces the pressure dropped from 0.946 to 0.15 bar for each transfer pipeline and in consequence, the total pressure drop reduces from 11.011 to 10.215 bar for the whole unit. In an aim to reduce the heat dissipated from surface of transfer pipeline. Each transfer pipeline insulated with calcium silicate insulator, the thickness of insulator increased from 38mm to 50mm in an aim to reduce heat loss from 101.56 watts/m to 84.282 watts/m, which reduced temperature difference between the surface pipeline and environment from 13 to 10°C.

**Keywords:** Crude oil, Distillation, Desalter, Connect two crude distillation units.

#### **1. Introduction**

Crude oil, is extracted from the deep earth [1], and consist of a mixture of hydrocarbons also contains many associated materials like salt, water, metals, and fouling [1]. These associated materials can be considered harmful materials for the downstream process equipment; heat exchangers and heating furnaces [1, 2]. The Salts can be considered the main source of corrosion issue due to the hydrolysis reactions of sodium chloride, magnesium chloride, and calcium chloride salts [1, 3, 4], hydrochloric acid which initiated [1, 3, 4] can corrode the equipment (head and trays of distillation column, and heat exchangers) [4].

Salts, water, and fouling can be reduced by many methods such as: electrical desalting, electrical – chemical desalting, gravitational [2, 5], electrical chemical desalting can be considered the most effective method [6].

Crude oil desalter (COD) already available at upstream processes like (crude oil field), which reduces the salt content from 100 to 50 PPM, it also available at the downstream process like (crude distillation unit) (CDU). COD reduces salt content from 50 to 5 PPM [1], de – emulsifier and, water injected to the crude oil streamline after preheated by heat exchangers train to at least 120° C [2, 3], and then enter to COD, heat reduces the viscosity of crude oil in aim to simplify water removal.

Water added to crude oil at the same temperature is used mainly to wash the crude oil, and dissolve the salts associated with the crude oil [7]. The de-mulsifier material, which already added to crude oil to reduce interfacial tension of water droplets interface initiated inside crude oil (breaks droplet film), that facilitate coalescence process of water droplets with each other and in final result reduces the salt content in the crude oil [7, 8].

Applied pressure in the COD not less than 10bar (g), in aim, to avoid crude oil evaporation [1, 2]. The crude oil, de – emulsifier, and water mixed with mixing valve or static mixer [9], mixture enter the bottom of COD vessel through distributer, a vessel equipped with high voltage electrical transformer, that transformer converts AC to DC with two electrical grids, electrical voltages applied in crude oil desalting process varies from 15kv to 21kv DC voltage [10, 11]. In order to charge water drops suspended in heated crude oil, water drops charged with positive charges (+) and negative () charges, the drops then attract to each other's coalescence of water drops occur in aim to enlarge the size of water drops, which in consequence will raise the weight of water drops, water drops then fall by gravity. Crude oil exits from the top through the perforated pipe, effluent water exits from the bottom [11, 12].

#### **2. Connecting two CDUs with one COD**

Two CDUs were connected to COD at Dewania refinery with a capacity of 10,000 BPSD each, which makes the total capacity of 20,000 BPSD where the COD with a capacity of 20,000 BPSD. Dewania refinery, which receives Basrah Medium crude oil with API gravity of 30.4 with specifications as in **Table 1**, the location of COD installed between the two CDUs, It was in the middle 90 m from each unit isometric piping.

Two CDUs connected to COD with connection was through a common header with the size of 8″ SCH-40. Each supply pipeline from CDU with the size of 6″ SCH-40, and the same size for return pipeline (from COD to CDUs) is the same as the supply pipe with the value of 6″.



#### *Connect Two Crude Oil Distillation Units with One Crude Oil De-Salter in Dewania Refinery DOI: http://dx.doi.org/10.5772/intechopen.98182*

#### **Table 1.**

*Basrah Medium Crude Oil Specifications.*

#### **3. Materials and methods**

#### **3.1 Pressure drop**

The Connection of the two CDUs with one COD with the pipeline will make a pressure drop in the system. The pressure drop happens due to the flow of crude oil through the pipeline along the distance between the two connection points [13].

Pressure drop of the whole system includes the following: further factors that influence and caused pressure drop in the system, as will discuss herein below and takes consideration of the following factors.

If the pipeline size is 4″ used as in the original connection in the unit, the pressure drop calculation will be as following:

• The Pressure drop of the 4″ SCH-40 pipeline evaluated according to Darcy'<sup>s</sup> Eq. (1) [13]. The pressure drop is 0.946 bar for each supply and return

system pipeline. The velocity value of the crossing from the CDU to COD is 2.4464 m/sec.

$$
\Delta P = \lambda. \frac{\sum Le}{De}. \frac{V^2}{2}. \rho \tag{1}
$$

Pressure drop of each piece of equipment in the COD system as following:


The total pressure drop of one CDU with a capacity of 10,000 BPSD, which connected, to the COD capacity of 20,000 BPSD equal to 11.896 bar (calculated).

Therefore, if two CDUs connected to COD the capacity would be 20,000 BPSD. Hence total pressure drop for each unit is equal to 11.011 bar.

Differential pressure of charge pump is equal to 12.131 bar [14].

If the pipeline size 4″ replaced with pipeline size of 6″ in an aim to supply crude oil to COD and return to CDUs.

A pressure drop of 6″ SCH-40 was evaluated according to Darcy's Eq. (1) [13]. The pressure drop is 0.15 bar, for each supply and return system pipeline. The velocity value is 1.085 m/sec, so the total pressure drop if only one 10,000 BPSD CDU connected to 20,000 BPSD COD equals 11.11 bar.

If two CDUs each one of capacity 10,000 BPSD connected with COD of capacity 20,000 BPSD, the total pressure drop for each unit is equal to 10.215 bar.

#### **3.2 Heat loss**

Crude oil, which received in CDU pumped by charge pump to train of heat exchangers E-211A�C, E-216, E-215, in an aim to preheat crude oil up to 130°C out at the point out of exchanger E-211 B, crude oil exported to COD in an aim to reduce salt content. COD is already outside the battery limit with a distance not less than 90 m in terms of length, the temperature of crude oil should not be less than 110°C [2, 3, 15]. In an aim to reduce heat loss from the outer surface of 6″ pipeline, and reduces the pipe surface temperature within the required range, the pipe should be insulated with suitable insulation material in aim to reduce the heat loss to the atmosphere and in consequence, reduce the fuel consumption in the furnace.

It should note that all parts of the unit with a temperature more than 60°C insulated with calcium silicate (insulation material) [10], with specification as shown in **Table 2** in different thickness and wrap with an aluminum sheet with a


**Table 2.** *Specifications of Calcium Silicate Insulator.*

*Connect Two Crude Oil Distillation Units with One Crude Oil De-Salter in Dewania Refinery DOI: http://dx.doi.org/10.5772/intechopen.98182*

thickness of gage 24 and according to the temperature of the surface and the service.

According to Baker, How [14]. The economical thickness of this type of insulation is 38 mm, heat loss and outer surface temperature estimated according to heat transfer calculations as follows:

#### **4. Calcium silicate insulation thickness of 38 mm**

Heat transfer by conduction, convection calculation as in Eqs. (2)-(6) [16] in aim to estimate heat loss and out surface temperature.

The heat transfer rate is �101.56 w/m and the temperature distribution of the pipe section as shown in **Figure 1** will be as follows:

The pipe internal temperature is 130°C; the surface temperature of the calcium silicate insulation will be 43.18°C, the metal surface temperature is 43°C if the ambient temperature is 30°C.

$$Q = UA\,\Delta T\,\tag{2}$$

$$\frac{1}{U} = \frac{R4}{hi\,R4} + \frac{1}{ho} + \frac{R4\ln\frac{R2}{R1}}{K1} + \frac{R4\ln\frac{R3}{R2}}{K2} + \frac{R4\ln\frac{R4}{R3}}{K3} \tag{3}$$

$$Nu = \frac{hidi}{kf} = 0.023. Re^{0.8}. Pr^{0.333}. \left(\frac{\mu}{\mu w}\right)^{0.14} \tag{4}$$

$$Re = \frac{\rho \,\nu \,di}{\mu} \tag{5}$$

$$Pr = \frac{cp\,\mu}{k} \tag{6}$$

**Figure 1.** *Temperature distribution through 38 mm insulation layer.*

#### **5. Calcium silicate insulation thickness of 50 mm**

In an aim to reduce the heat dissipated, insulation thickness increased to 50 mm instead of 38 mm. In consequence, the Heat loss reduced to �84.478 w/m, and the temperature distribution of the pipe section as in **Figure 2** will be as follows: internal temperature is 130°C, insulation and metal wrap surface temperature is 40.1°C and 40°C respectively.

**Figure 2.** *Temperature distribution through 50 mm (calcium silicate) insulation layers.*

#### **6. Control system**

Connection of two CDUs with one COD process flow diagram as shown in **Figure 3**, control system philosophy modified in aim to cover the addition of COD, the capacity of the unit would have controlled as before by FIC-101, the (valve Coefficient) C.V of control valve checked with this modification i.e. the pressure drop added to the system. This can be checked by evaluation of C.V as in Eq. (7) [17] the C. V value is 23.55 and the C.V value of FIC-101 is 90, which means FIC-101 is valid to be used even with the new addition of equipment.

$$C.V = 1.16.Q.\sqrt{\frac{\text{Sp.Gr}}{\Delta P}}\tag{7}$$

Control the COD with Two CDUs connected has many scenarios and as follows.


*Connect Two Crude Oil Distillation Units with One Crude Oil De-Salter in Dewania Refinery DOI: http://dx.doi.org/10.5772/intechopen.98182*

**Figure 3.** *Process Flow Diagram of Connection of Two CDUs with One COD.*

completed; if one unit is drop (switched off) for any reason (for example emergency case), when both units are in service, simple control system installed as shown in **Figure 3** and as following:

Check valve of (6″ X 300#) swing type and pressure switch, with rang (0–16 bar), were installed at the export line (supply line of crude oil to desalter). 3″ X 300# control valve with C.V equal to 90 normally closed, air to open installed at import line (pipeline back from desalter) work as an on–off controller connected to the pressure switch.

**Mechanism of the system:** When one of two units is dropped, then no signal passes from the pressure switch (signal off). The electrical relay would open, the solenoid valve would close which already installed at the air supply line to the control valve, and the control valve type is normally closed air to open, if no air supply, then the valve would shut. Only one unit would be in the service, crude oil would not pass to the other unit.

#### **7. Water injection**

Crude oil, which contains salts. The process water was used to dissolve associated salt. The amount of process water required varies from 5 to 7 vol % [15]. When two units in service the total amount of water would be used of 5 vol %, this is the

minimum recommended amount of water to be used, if any drop (CDU switched off) to any unit the amount of water will be within the maximum required amount for one unit.

### **8. Conclusions**


#### **Acknowledgements**

I would like to thank Head department of Dewania refinery: Mr. Kareem Toama, and Exterior refineries board coordinator: Mr. Emad M. Areeby.

### **Symbols**

### **Abbreviations**


*Connect Two Crude Oil Distillation Units with One Crude Oil De-Salter in Dewania Refinery DOI: http://dx.doi.org/10.5772/intechopen.98182*

#### **Greeks**


#### **Letters**


Q volumetric flow rate m<sup>3</sup> /h

### **Author details**

Omar Mahmoud Waheeb Chief of Engineers at Technical and Engineering Board, Daura Refinery, Midland Refineries Co., Iraq

\*Address all correspondence to: omsuch@gmail.com

© 2021 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.

#### **References**

[1] Juan Pereira, Ingrid Velasquez, Ronald Blanco, Meraldo Sanchez, César Pernalete and Carlos Canelón. 2015. "Crude Oil De – salting Process." *Intechopen.* 67-84.

[2] Juan Pereira, Ingrid Velasquez, Ronald Blanco, Meraldo Sanchez, César Pernalete and Carlos Canelón. 2015. "Crude Oil De – salting Process." *Intechopen.* 67-84.

[3] Sellami MH, Naam R and Temmar M. 2016. "Optimization of Operating Parameters of Oil Desalting in Southern Treatment Unit (HMD/Algeria)." *Journal of petroleum and environmental biotechnology ISSN: 2157-7463 JPEB* 1-6.

[4] Hussein K Abdel-Aal1, Khaled Zohdy and Maha Abdelkreem,. 2018. "Waste Management in Crude Oil Processing: Crude Oil Dehydration and Desalting." *International Journal of Waste Resources. 10.4172/2252-5211.1000326. Volume 8 • Issue 1 • 1000326* 1-4.

[5] Saeed Nasehi, Mohammad Javad Sarraf, Alireza Ilkhani, Mohammad Ali Mohammad mirzaie, Mohammad Hasan Fazaelipoor. 2008. "Study of Crude Oil Desalting Process in Refinery." *J Biochem Tech Special Issue (2): 29-33 ISSN: 0974-2328* 29-33.

[6] Christine Noïk, Jiaqing Chen, and Christine Dalmazzone. 2006. "Electrostatic Demulsification on Crude Oil: A State-Of-The-Art Review." Society of Petroleum Engineers 1-12.

[7] Xinru Xu, Jingyi Yang, and Jinshen Gao. 2006. "Effects of Demulsifier Structure on Desalting Efficiency of Crude Oils,." *Petroleum Science and Technology, 24:673–688, 2006 Taylor & Francis Group, LLC, ISSN: 1091-6466 print* 673-688.

[8] M. A. Saad, Mohammed Kamil , N. H. Abdurahman, Rosli Mohd Yunus and Omar I. Awad. 2019. "An Overview of

Recent Advances in State-of-the-Art Techniques in the Demulsification of Crude Oil Emulsions, Processes." *processes* 1-29.

[9] J. FORERO, J. DUQUE, J. DIAZ, A. NUÑEZ, F. GUARIN, F. CARVAJAL. 2001. "NEW CONTACT SYSTEM." *CT&F Ciencia,Tecnología y Futuro Vol. 2 Núμ. 2* 81-91.

[10] Abdollahi, Hadi. 2015. "Examining and Analyzing Desalters from Viewpoint Of Electric Field For Desalination Of Crude Oil." *International Journal of Biology, Pharmacy and Applied Science (IJBPAS)* 5680-5693.

[11] Ilkhaani, Shahrokh. 2009. *Modeling and Optimization of Crude Oil Desalting (MS.c Thesis).* Waterloo, Ontario, Canada: University of Waterloo.

[12] Farzad Mohammadi, Mehdi Mohammadi, Behrouz Nonahal. 2019. "Comprehensive of Electrical Model for The Electrostatic Desalting Process of Crude oil." *Petroleum and Coal, Pet Coal* 738-749.

[13] E. Shashi Menon, P.E. 2005. *Piping Calculation Manual.* New york : McGraw - Hill ISBN: 9780071440905.

[14] Baker, How. 1975. *Engineering manual, 10,000 BPSD crude distillation unit.* Oklahoma: How Baker Engineering.

[15] Hughes, Baker. 1998. *Engineering Manual, 25,000 BPSD crude oil desalter.* Amestrdam : Baker Hughes Engineering.

[16] Cao, Eduardo. 2010. *Heat transfer in Process Engineering.* New york: McGraw – Hill ISBN 9780071624084.

[17] Emerson Process Management, Fisher. 2005. *Control Valve Handbook fourth edition.* ASIN: B000JWBGNE, Fisher.

#### **Chapter 11**

## Green Technology for Crude Oil Processed Water Treatment: A Practical Approach for Nigeria Petroleum Industry

*Hassana Ibrahim Mustapha*

### **Abstract**

Cleaner production is the key to environmental sustainability. Conversion of crude oil to various beneficial products is responsible for the contamination of air, water, and soil which are harmful to human, plants, animals, public health and the environment. Adequately treating produced water is beneficial for irrigation, wildlife consumption, industrial water and for domestic purposes. Therefore, green technology for treatment of crude oil processed water would provide the environmental friendliness needed for prolong utilization of our natural resources. Hence, the aim of this book chapter is to investigate the potentials of constructed wetland as a promising, effective and environmentally friendly alternative for secondary petroleum refinery wastewater treatment. Planted and unplanted mesocosm scale experiment with real secondary refinery wastewater was used for the purpose of the study. The parameters investigated were temperature, pH, dissolved oxygen, electrical conductivity, total suspended solids, carbon oxygen demand, total petroleum hydrocarbon and oil and grease. The results revealed that *Typha latifolia* planted VSSF CWs effectively treated organic contaminants in secondary refinery wastewater with a better performance than the unplanted control VSSF CWs. The chromatographs for wastewater and *T. latifolia* samples showed a hydrocarbon distribution between n-C9 to n-C24 indicating abundance of lower weight hydrocarbon contamination.

**Keywords:** Approach, Crude oil, Green Technology, Processed Water, Nigeria, Treatment

#### **1. Introduction**

#### **1.1 Importance of crude oil to the Nigeria economy**

Crude oil is Nigerian's main source of revenue. The Federal Government of Nigeria derive about 90% of its revenue and 35% of its Gross Domestic Products from petroleum industry [1]. Nigeria has four refineries located in Kaduna, Warri and two in Port Harcourt with capacity of 438, 750 billion b/d along with 21 depots and about 5001 km of product pipelines [2]. The Federal Government of Nigeria has absolute ownership of its oil and gas resources, thus, exercises its rights through concessions, joint venture, production sharing contracts and service contracts [3]. The Organization of Petroleum Exporting Countries (OPEC) ranked Nigeria as the sixth largest producer of oil [1]. Crude oil is essential for modern life for it provision of fuel and raw materials for an immense variety of useful products, from plastics to fertilizers, to pesticides, and medicines that facilitated unprecedented economic growth and improved human health around the world in the 20th century [4, 5]. Also, Globally, it is the most important source of power [5, 6], it represents about 40% of world total energy use [6]. Several nations are excessively reliant on petroleum for their main source of electricity and transportation fuel [7].

Olujobi et al. [1] described the Nigeria oil industry as consisting of three main streams: upstream petroleum sector (exploration, and production), downstream (crude oil refining for domestic consumption, marketing, and transportation) and the midstream (natural gas). The activities of the upstream and downstream sectors are interconnected and interdependent which is done through the establishment of an adequate regulatory framework consisting of laws and regulations setting out rights, obligations, procedures and standards, and regulatory institutions charged with responsibility for monitoring compliance as explained by Ambituuni et al. [2]. Nigeria has gained in economic and technological advancement through upstream and downstream activities and have posed human health, safety, and environmental risks [2]. Aside the gains of petroleum industry to the Nigeria economy, it is also faced with products theft, pipelines vandalism and cross-border smuggling, lack of capacity storage depots and substandard jetties [8]. Furthermore, Niger delta of Nigeria is a wetland consisting of mangroves, freshwater swamps, lowlands rainforest, salt water marshes and derived savanna vegetation covering about 12% (111, 020 km<sup>2</sup> ) of Nigeria's surface area, however, due to oil and gas exploration and development, Niger Delta is undergoing critical environmental threat, biodiversity extinction, and speedily growing human population [9]. It is important to be able to balance the derived economic and social merits from crude oil and the detrimental outcomes associated with ecotoxicological effects on soil and water environments [6].

#### **1.2 Significant of crude oil processed water on the environment**

Petroleum industries are a major source of environmental pollution. Conversion of crude oil to various beneficial products is responsible for the contamination of air, water, and soil. One of the major effects of oil exploration and exploitation activities is air pollution with the resultant negative effect of health such as exposure to ambient air levels of CO may result into the formation of carboxyhemoglobin and inhaled particles would increase blood viscousity which may hinder oxygen movement to the tissues [7]. The negative impact of contamination of the aquatic ecosystem on fishes was reported in a review on phytoremediation of crude oil spills by Yavari et al. [10] as abnormal neurone development, genetic damage, physical deformities, as well as changes in biological activities such as feeding, reproduction, and migration. Also, oil spills can suffocate aquatic life and renders water unfit for communal and domestic purposes [11]. Other resultant consequences as highlighted by Ite et al. [12] are atmospheric pollution associated with flaring and venting of natural gas, this act can contribute to global climate change, pollution of marine environment which often result in adverse impacts on wildlife and negative impact on tourism, and fishing and other businesses as well as water and soil pollution.

Produced water is a byproduct of oil and gas production and it is the largest wastewater produced by the petroleum industry [13]. Igunnu and Chen [14] estimated that about 250 million barrels of it is generated daily from oil and gas fields worldwide with 40% of it discharged into the environment. Similarly, Allison

#### *Green Technology for Crude Oil Processed Water Treatment: A Practical Approach for Nigeria… DOI: http://dx.doi.org/10.5772/intechopen.98770*

and Mandler [4] stated that on the average, 10 barrels of wastewater is generated for each barrel of crude oil processed. These large volumes of wastewater produced during petroleum production is either discharged into the sea or re-injected into production or disposal reservoirs [15] or for reuse purposes. The contaminants in the produced water are harmful to human, plants, animals [16] as well as public health and the environment are threatened by its presence [17]. However, if produced water is adequately treated, it can be put to beneficial uses such as irrigation, wildlife consumption, industrial water and for domestic purposes [14].

Produced waters contain varying levels of organic and inorganic contaminants that can pose serious hazard to the environment when discharged untreated [18]. Accordingly, organic contaminants are classified as toxic, teratogenic, and carcinogenic [19]. The toxicity of petroleum wastewater depends on several factors including quantity, volume, and variability of discharge [20]. Thus, the effects of produced water on the environment cannot be overemphasized. Soil, an important medium for crop cultivation and habitat for living organisms is the most affected by the discharge of produced water [21]. The potential effects of produced water on soil quality and plants were reported by Pichtel [17] as low permeability of soil to air and water due to excessive sodicity, high accumulation of salts in soil causing plants to desiccate and die, and replacement of existing plant species by new species because of chemical changes in the soil. Contamination of soil by hydrocarbon can affect the physical, chemical and biological characteristics of the soil [10]. Also, reduction of dissolved oxygen in waterbodies as mentioned by Abbas [22] which is considered as detrimental to the aquatic ecosystem. Health hazards due to contaminants from petroleum wastewater may have short term (death at high concentrations of hydrogen sulphide gas) or long-term effects (cancer from benzene) [4].

The quality of produced water varies from region to region depending on the type of extracted hydrocarbons, extraction methods and the minerals present in geologic formation [13, 14]. Lin et al. [13] also stated that produced wastewater is characterized by high TDS, oil and grease, benzene, toluene, ethylbenzene, and xylenes (BTEX), polycyclic aromatic hydrocarbons (PAHs); organic acids; and waxes as well as heavy metals, ammonia and hydrogen sulfide. Abbas et al. [22] reported the characteristics of produced water in varied ranges composing of 1220–2600 mg/L COD, 2–565 mg/L O&G, 0.026–778.51 mg/L BTEX, 1.2–1000 mg/L TSS, and metals ranging from 0 to 150, 000 mg/L. They however, stated that the composition was highly depended on the crude oil quality, origin of wastewater contaminants and operating conditions of the refineries. Similarly, Mustapha [23], characterized secondary refinery wastewater and found that the wastewater was composed of organic and inorganic compounds including salts, suspended solids and metals varying from 12.2 ± 0.3 to 253.0 ± 0.7 NTU, 146.7 ± 0.1 to 446.0 ± 0.4 mg/L TDS, 161.7 to 782.5 mg/L TS, 10.4 to 283.1 mg/L BOD, 40.2 to 520.8 mg/L COD, 0.01 to 3.4 mg/L Cr, 0.01 to 0.06 mg/L Pb0.01 to 1.16 mg/L phenol and 0.7 to 14.2 mg/L O&G, suggesting that the secondary wastewater can adequately be treated with CWs for reuse purposes or safely discharge into the environment. Consequently, Lin et al. reported that about 45% of produced water from onshore activities is reused for conventional oil and gas operations.

#### **1.3 Green technology for wastewater treatment**

Natural resources are valuable resources of the world. They represent vital resources for a variety of human activities and also provide a living environment for a range of aquatic organisms. The deterioration of our environment due to pollution is most pronounced in developing countries. This has become a persistent

problem that needs to be given priority attention. Thus, prolong utilization of water and soil resources would necessitate the application of sustainable techniques such as green technology. Green technology is a natural process that provide high quality outcomes without compromising on environmental sustainability [24]. They serve as alternative method for the treatment of wastewater. Several types of green technologies have been applied for the remediation of polluted sites. Examples include but not limited to phytoremediation, bioremediation, biostimulation, bioaugmentation, natural attenuation, constructed wetlands, vermifiltration, nanotechnology, membrane filtration, and microbial fuel cells [19, 21, 24–27]. Phytoremediation is a cost-effective, plant-based technique of environmental remediation that uses the ability of plants and indigenous microorganisms in the rhizosphere to treat different types of contaminants [26]. More advantages of phytoremediation include public acceptance and ability to simultaneously treat organic and inorganic contaminants [28].

Constructed wetlands (CWs) are man-made wastewater treatment facilities duplicating the processes occurring in natural wetlands. They consist of shallow ponds or channels, which have been planted with aquatic plants and rely on natural microbial, biological, physical and chemical processes to treat wastewater [23]. This process is a complex, integrated system in which water, plants, animals, and microorganisms and natural elements interact to improve water quality [29]. CWs are a promising green technology that can decrease the adverse effect brought about by anthropologic activities. This technology has been used extensively for petroleum wastewater treatment. They have however has been largely ignored in developing countries where effective; low-cost wastewater treatment strategies are critically needed. CWs are lower in energy consumption, cost of investment, cost of operation and maintenance [18]. They are also known for their effective treatment, simplicity, low sludge production, high nutrient absorption capacity, process stability and its potential for creating biodiversity [18, 30]. Constructed wetlands are used for all types of wastewater treatment around the world. If they are correctly built, operated, and maintained [23] they can effectively restore sites of a wide variety of contaminants ranging from BOD, suspended solids, nitrogen, phosphorus, heavy metals, volatile organics, semi-volatile organics, petroleum hydrocarbons, pesticides and herbicides, PAHs, chlorinated solvents, to non-chlorinated solvents in storm water or municipal, agricultural and industrial wastewaters. Paz-Alberto et al. [31] mentioned that the effectiveness of a green technology such as CW is dependent on sufficient biomass production and contaminant accumulations into its tissues. In addition, effective treatment is based on the characteristics of the wastewater and treatment methods [32]. Additionally, effectiveness of remediation is usually judged by the level of reduction of contaminants and degradation of organic contaminants [6]. Also, the use of CWs for wastewater treatment can revitalize the environment, generate a water source or restore a marsh habitat during the course of treatment [32].

There are several studies on the use of different types of CWs for petroleum wastewater in developed countries with few reported researches in the developing countries. These researches are focused on constituents and effective treatment of petroleum contaminated wastewater. For instance, Stefanakis et al. [33] used horizontal subsurface flow CWs to effectively treat groundwater containing influent quality of 0.009 ± 0.004 mg/L methyl *tert*-butyl ether (MTBE), 10.2 ± 3.8 mg/L benzene and 27.1 ± 8.0 mg/L ammonia. Alsghayer et al. [29] also used horizontal subsurface flow CWs to treat wastewater containing high concentrations of polycyclic aromatic hydrocarbons (PAHs) (Phenanthrene, Pyrene, and Benzo[a]Pyrene) with high removal efficiencies. Effective treatment of petroleum contaminated wastewater with VSSF CWs was also reported by Mustapha [25].

*Green Technology for Crude Oil Processed Water Treatment: A Practical Approach for Nigeria… DOI: http://dx.doi.org/10.5772/intechopen.98770*

The objectives of the study in this book chapter are to showcase constructed wetland as a promising, effective and environmentally friendly alternative for petroleum refinery wastewater treatment, investigate the contaminant pathways using mass balance approach. The outcomes of the study can prove to be beneficial to petroleum industry especially for Nigeria, water resources departments, environmental managers and researchers in the field of environmental Engineering and management. The application of the study will ensure reduction of hazardous constituents into water bodies and soil and assure improved water quality by the discharge of treated wastewater into the environment. The adequately treated wastewater from constructed wetland systems can be reused and/or safely discharged into water bodies, this can drastically reduce the cost of production of potable water. Additionally, health problems and diseases associated with the discharge of untreated or inadequately treated wastewater can be minimized and treated water can also be reused. Thus, field experiment using mesocosm scale experiment with real refinery effluent collected from the effluent discharged point of the Kaduna refinery and petrochemical industry was conducted for the purpose of the study.

#### **2. Practical approach for petroleum wastewater treatment**

#### **2.1 Materials and methods**

#### *2.1.1 Description of the study area*

This study was conducted offsite of the refinery (Minna, Nigeria) about 150 km from the Kaduna Refinery and Petrochemical Company which lies between latitude 10°31′35″ N and Longitude 7°26′19″ E and Minna is within 9° 36′ 54″ N and 6° 33′ 51″ E within the Northern guinea savannah ecological zone of Nigeria. Kaduna and Minna (Nigeria) have a tropical climatic condition with temperature ranging between 13 and 35°C and average accumulated rainfall of 306 mm and Minna with average high temperature of 34°C and low of 22°C with total rain accumulation of 256 mm (NIMET 2010). The Kaduna refinery and petrochemical (KRPC), Kaduna is the third largest refinery Nigeria with a capacity of 110, 000 barrels per stream day (BPSD). The type of crude oil processed by the refinery are Escravos light crude and Ughelli Quality Control Centre (UQCC) crude oil [25]. The refinery uses large volume of water for processing crude oil into its finished products and it discharges large quantities of wastewater into the environment. It discharges approximately 100, 000 m3 /day of secondary treated wastewater [23]. The discharged effluent is composed of oil and grease, hydrocarbons, phenols, nutrients, and heavy metals [34]. The refinery treats its effluents by chemical addition, clarification, oxidation, oil skimming, filtration and evaporation before being discharged via drainages into the Romi stream. More details on the process and characteristics of the petroleum refinery effluent are given in Mustapha et al. (2015).

#### *2.1.2 Experimental setup of vertical subsurface flow constructed wetlands*

The mesocosm-scaled subsurface flow constructed wetland (SSF) systems were composed of four VSSF constructed wetlands connected in parallel to each other. The VSSF wetlands were cylindrical in shape and made of plastic material (44 cm diameter and 88 cm height). The media type used for the VSSF CWs was gravel with coarse sand. Coarse size gravel of 25–36 mm was used near the middle and outlet of the VSSF CW cells and the inlet parts were filled with 6–10 mm gravel to support the plant roots. The bottom of the VSSF CWs were fitted with perforated

PVC pipes of diameter 50 mm about 10 cm above the media connected to the collection chamber. The VSSF wetland cells had an effective volume of 123 L with a porosity of 0.40. It has a designed flow rate of 0.0048 m3 /h, hydraulic loading rate of 0.0032 m3 /m2 h and a theoretical hydraulic retention time of 48 hours. The VSSF CWs were planted with *T. latifolia* 10 cm below the media and the other two unplanted VSSF CWs served as the control to assess the performance of *T. latifolia*. The *T. latifolia* used in this study was collected from a swampy area outside the refinery. Refinery wastewater was discharged into a 5 m3 collection tank, which subsequently flows gradually by gravity into the VSSF CW cells while the treated effluent was collected at the outlet. Influent and treated samples from the outlet of the wetland cells were collected every 2 weeks for both field and laboratory analysis to determine the performance of the *T. latifolia* in the remediation processes of electrical conductivity (EC), total suspended solids (TSS), carbon oxygen demand (COD), total petroleum hydrocarbon (TPH) and O&G. The temperature, pH and dissolved oxygen (DO) of the samples were also measured immediately on the site using handheld equipment (WTW Ph 340i, HM TDS-3 9001, WTW Cond, 3310 and OXi 340i). The analytical procedures used for influent and effluent samples were based on the Standard Methods for Examination of Water and Wastewater (2002). The method used for TPH determination was Gas Chromatography–Flame Ionization Detector (GC-FID) and Hexane Extractable Gravimetric method for O&G. The experiments were duplicated under the same conditions.

#### *2.1.3* Typha latifolia, *an ideal wetland treatment plant*

*Typha spp*. is an aquatic, emergent monocotyledon plant species with linearly erect leaves and green stems extending well above the surface of the water as well as with an extensive rhizomes and roots systems, it also has a well-developed vascular system and supporting tissues [35]. This plant can be beneficial or nuisance in aquatic systems depending on the defined uses of the aquatic systems. There are reported researches on the beneficial uses of *Typha spp*. in constructed wetland treatment processes. Accordingly, Belmont et al. [36] testified on the effective performance of *Typha* spp. in wastewater improvement. Thus, *T. latifolia* was chosen for this study for its moisture tolerance, abundance, efficiency, fast growth and management.

The experiment started up by first counting and weighing *T. latifolia* before transplanting into the wetland cells. The plant height and number of live shoots of *T. latifolia* were recorded at the time of the transplant and subsequently every month after the transplant consecutively for a period of six months to monitor the growth rate of the *T. latifolia* in secondary treated refinery wastewater. The biomass was sorted into leaf, root and stem, washed under running tap and then rinsed with deionized water in order to remove any soil particles attached to the plant surface and their wet weight were determined, then oved dried at 105°C for 24 hours. The oven dried samples were grounded into powder, these were digested and analyzed for TPH and O&G determination.

#### *2.1.4 Statistical analysis*

Statistical analysis was performed using the IBM SPSS 20 (IBM SPSS Inc.). All experiments were performed in replicates. One way analysis of variance (ANOVA) at 95% (p < 0.05) was used to determine the significance of the data, multiple comparisons of means of the experimental parameters for the planted and unplanted VSSF CWs using Duncan multiple range test and Tukey honest significant difference. The treatment efficiency of the VSSF CWs were calculated as the percent of the contaminant removal, R and mass removal percent, M as presented below:

*Green Technology for Crude Oil Processed Water Treatment: A Practical Approach for Nigeria… DOI: http://dx.doi.org/10.5772/intechopen.98770*

$$R = \frac{\mathbf{C}\_i - \mathbf{C}\_o}{\mathbf{C}\_i} \times \mathbf{100} \tag{1}$$

$$M = \frac{C\_i V\_i - C\_o V\_o}{C\_i V\_i} \times 100\tag{2}$$

Where R and M are contaminant removal percent and mass removal percent, Ci and Co are influent and effluent concentrations and Vi and Vo are influent and effluent volumes of the *T. latifolia* planted and unplanted VSSF CWs.

#### **3. Results and discussions**

#### **3.1 Presentation of results**

Constructed wetlands are a promising and suitable technology for wastewater treatment. This is evident from the results collated from the field analysis conducted in a 184-day experiment using secondary refinery wastewater from Kaduna refinery, Nigeria. Thus, **Table 1** present the qualities of secondary refinery wastewater before and after treatment with vertical subsurface flow constructed wetlands (VSSF CWs). The secondary refinery wastewater, the treated wastewater (*Typha latifolia* planted VSSF CWs) and the effluent from the control (unplanted VSSF CWs) were characterized with varied concentrations of physicochemical and organic parameters. The water temperatures ranged from 31.08 ± 3.41 to 27.13 ± 1.71°C with an observed significance difference (P > 0.05) among the variables. The pH values for both effluents from the *Typha latifolia* planted and unplanted VSSF CWs showed no significance difference among them. Similarly, there were no significant difference in the oily content and total suspended solids (TSS) from both effluents though the effluents were significantly different from the influent concentrations. In contrast, electrical conductivity (EC) and carbon oxygen demand (COD) contents of the influent and effluent samples showed high significant differences among themselves. Comparing the effluent values to allowable


*Mean ± standard deviation. Values are means of two replicates (n = 2). Values on the same row with different superscript are significantly different (P ≤ 0.05) while those with the same superscript are not significantly different (P ≥ 0.05) as assessed by Tukey (HSD) and Duncan's Multiple Range Test.*

#### **Table 1.**

*One-way ANOVA for influent and effluent constituent of* Typha latifolia *planted vertical subsurface flow constructed wetlands treating secondary refinery wastewater.*

#### **Figure 1.**

*Performance evaluation of* T. latifolia *planted and control (unplanted) VSSF CWs.*

standards, temperature, pH, dissolved oxygen (DO), total petroleum hydrocarbon (TPH) and Oil and Grease (O&G) were within the limits of discharged while the effluents from *Typha latifolia* planted VSSF CWs met the discharge limits for EC, TSS and COD and the unplanted VSSF CWs had values above the allowable limits.

The treatment performance of *Typha latifolia* planted VSSF CWs for secondary treated refinery wastewater is presented in **Figure 1**. The removal efficiencies were determined for EC, TSS, COD, TPH and O&G contents. The *Typha latifolia* planted VSSF CWs showed a better performance than the unplanted VSSF CWs indicating that macrophytes have a significant role to play in constructed wetlands treatment process. The removal performance ranged from 25.71 ± 5.73 to 76.72 ± 12.51% and 11.94 ± 9.31 to 42.81 ± 15.71%, respectively for *Typha latifolia* planted and unplanted VSSF CWs. The *Typha latifolia* planted VSSF CWs showed highest removal efficiency for COD and the lowest for EC content while TPH content was most removed and similarly EC content the least removed in the unplanted VSSF CWs.

Constructed wetlands uses natural processes in plants, soil, and organisms for the removal of contaminants in wastewater [32]. It is composed of complex biogeochemical mechanisms and the removal processes of the different types of CWs varies and could be attributed to the difference in loading rate, nutrient species and abiotic environment [32]. Hence, in order to determine the removal pathways for the contaminants removal in VSSF CW treatment system mass balance approach was used. CWs can identify the potential sources and sinks of contaminants through the transfer and transformation of the contaminants in the


#### **Table 2.** *Mass balance approach for input parameters in mg.*

*Green Technology for Crude Oil Processed Water Treatment: A Practical Approach for Nigeria… DOI: http://dx.doi.org/10.5772/intechopen.98770*


**Table 3.**

*Mass balance approach for output parameters in mg.*

wetland cells [32]. **Tables 2** and **3** present the fate of TPH and O&G in water, plants and sediment loads. **Table 2** showed the input variables and **Table 3** showed the output variables and mass removal percentage of the CW treatment systems. The input variables ranged from 1874.16 (O&G) to 568.84 (TPH) mg. The tissues of *T. latifolia* were segregated into root, stem and leaf parts, results showing that the root and leaf of *T. latifolia* accounted for the highest and least accumulation of TPH and O&G contents. However, higher contents were retained in the soil. Generally, the mass removal performance was high for both the planted and unplanted VSSF CWs although the planted (86.04 and 92.89%) showed a higher removal than the unplanted (79.98 and 80.58%).

The contaminant removal pathways were segregated into plant parts, sediment and other sources. The results are presented in **Table 4**. The plant contribution to the removal process was approximately 8 and 2% TPH and O&G and sediment exhibited the highest percent. Removal pathways by other sources that were not determined in the experiment also showed high removal performance.

The health of the plants used in constructed wetlands is reflected in its growth. The *T*. *latifolia* used for this study showed a continuous growth in height and increased canopy. The average results recorded from the startup of the experiment, from transplant (day 0) to the termination of the experiment are presented in **Figure 2**. The plant average canopy height ranged from 15 to 165 cm and density ranged from 25 planted *T*. *latifolia* to over 140 live stands of *T. latifolia* each in the two planted VSSF CW cells.

The environment will continuously be polluted with TPHs and the content will depend on the source of contamination be it crude oil itself or it finished or byproducts. **Figures 3** and **4** presents the chromatographic profile of TPHs content in the secondary refinery wastewater used for the field experiment. The chromatography for wastewater sample showed a hydrocarbon distribution between n-C9 to n-C24 with a hump between n-C19 and n-C24 (**Figure 3**). **Figure 4** presents the chromatograph for root sample of *T. latifolia* used for secondary refinery wastewater treatment. The hydrocarbon content of the root sample contained n-C9 to n-C22


#### **Table 4.**

*Removal pathways for contaminants in vertical flow constructed wetlands.*

**Figure 2.** *Plant stem and canopy height for* Typha latifolia *planted constructed wetlands.*

with a hump between n-C20 and n-C22, the hydrocarbon content in the leaf sample ranged from n-C12 and n-C22 and stem sample contained ranged of n-C9 to n-C20 (**Figure 4**) hydrocarbons.

#### **3.2 Discussion of results**

#### *3.2.1 Physio-chemical properties of wastewater in treatment wetland*

Physical, chemical and biological processes are used in subsurface flow CW treatment systems. Garcia et al. [37] mentioned physical factors as filtration and sedimentation, chemical factors include oxidation and sorption to organic matter while biological mechanisms include oxygen release and bacterial activity in the rhizosphere [37]. The planted system showed a high mean treatment performance for all the measured parameters (COD, TPH, O&G, TSS and EC) (**Figure 1**). Wastewater treatment occurs as the water flows gradually through the wetlands, consequently, temperature was reduced by 4°C, pH by 0.29 units, DO increased by 1.4 mg/L and EC decreased by 352 μs/cm for the *Typha latifolia* planted CWs and 2°C, 16 units, 0.57 mg/L and 174 μs/cm, respectively by the unplanted CWs. The observed oxygen in the CW treatment system may be attributed to water flowing vertically into the system, through the plant into the sediment and transfer through atmosphere to the water surface [32, 38]. Additionally, oxygenation of the treatment wetlands by continuous flow of water through the wetlands was supported by [39], favored by sedimentation, precipitation, absorption of soil particles, assimilation for the plant tissues and microbial transformations. Also, a reduction in the concentrations of the contaminants in the wastewater can increase the aerobic condition of VSSF CWs. This finding is in agreement with Al-Mansoory et al. [26]who observed higher gasoline concentrations with lower DO concentrations. Furthermore, increased DO in the *T. latifolia* planted VSSF CWs can aid biological pathway for removal of organic contaminants in secondary petroleum refinery wastewater. In this study, low removal of suspended solids was observed for both the planted and the unplanted VSSF CWs (**Figure 1**). This is in contrast to other studies. For instance, Mustapha [23] reported 60% TSS removal efficiency by VSSF CWs planted with *Cyperus alternifolius* and *Cynondon dactylon* and attributed

*Green Technology for Crude Oil Processed Water Treatment: A Practical Approach for Nigeria… DOI: http://dx.doi.org/10.5772/intechopen.98770*

physical processes as the main pathway for the removal of suspended solids. Skrzypiec and Gajewska [40] reported 59 to 99% TSS removal in a VSSF CWs, stating that the decomposition of organic matter in CWs is by aerobic and anaerobic microbial processes and physical processes of sedimentation and filtration of particulate organic matter. Rios and Aizaki [39] and Wagner et al. [41] described the significant effects of salinity on plant growth with higher levels affecting the development of the plants. In this present study, *T*. *latifolia* was able to tolerant the EC values of the secondary refinery wastewater with its growth rate response (**Figure 2**).

Organic contaminants such as COD, TPH and O&G removal are favored by VSSF CWs due to it aerobic conditions. These contaminants were effectively removed in this study (**Figure 1**), suggesting aerobic biodegradation as a removal

**Figure 4.** *Chromatographic profile of leaf (a) and stem (b) of* T. latifolia *for TPH contents.*

pathway [37]. High COD removal in this study (**Figure 1**) is similar to the results reported by Mustapha [23] for *T*. *latifolia* planted VSSF and those reported by Kulshrestha and Khalil [42] for COD 77.28% and Skrzypiec and Gajewska [40] for TPH (97%) and COD (51 and 49%) in VSSF CWs and a COD removal of 39 to 69% in HSSF CWs was reported by [43]. They attributed removal mechanisms to filtration and sedimentation of suspended solids, organic matter mineralization within the wetlands and microbial degradation. Furthermore, Skrzypiec and Gajewska [40] reported that degradation of organic contaminants in CWs were dependent on pH, temperature, DO, hydraulic load, feeding mode, hydraulic retention time, depth of bed, plant species and harvesting.

Machado et al. [44] explained that substrate types can affect removal efficiency of a CW. A gravel substrate CW achieved 95.5% COD removal while a gravel-sand

#### *Green Technology for Crude Oil Processed Water Treatment: A Practical Approach for Nigeria… DOI: http://dx.doi.org/10.5772/intechopen.98770*

substrate achieved a 99% in a VSSF CW planted with *Zizaniopsis bonarienses*. Li et al. [45] also reported the efficiency of organic contaminant removal in CW was highly dependent on oxygen concentration within the matrix in the bed and wetland design. They achieved a COD removal of >80% in horizontal subsurface flow CWs suggesting that the supplied artificial aeration may have enhanced the treatment process.

#### *3.2.2 Functions of* T. latifolia *in the processes of remediation*

Wetland plants are the most conspicuous component in the wetlands [18]. They have been reported to significantly contribute to the treatment processes. Al-Mansoory et al. [26] identified two major ways for effective treatment by plants namely creating favorable conditions for complex interactions involving rhizobacteria and root exudates to degrade contaminants in the soil. Also, Moubasher et al. [46] have attributed effective remediation to plants, its fibrous root system and rhizosphere. Hence, both plant and microorganisms have key role to play in phytotechnological processes of contaminant removal although, the rhizosphere is the most influential [28]. In this present study, the significant role of *T*. *latifolia* and its associated microorganisms was illustrated in reduction of the TPH and O&G in the planted VSSF CWs as compared to the unplanted control VSSF CWs (**Figure 1**). The significance of plants and microorganisms in the degradation of petroleum hydrocarbons was investigated by Moubasher et al. [46] who explained that presence of plants may greatly enrich the rhizosphere microbial flora by providing exudates, enzymes, and oxygen through its roots.

However, the plant contribution as shown by the theoretical mass removal percent were observed to be low for TPH and O&G compared to contribution by sediment and other sources (**Table 4**). The likely pathway removal of TPH and O&G in the unplanted VSSF CWs be explained by the processes of volatilization, eluviation and photolysis as suggested by Al-Mansoory et al. [26]. This is also in agreement with the findings by [46], as they also added the activity of its original microflora. In that case, the indigenous microorganisms in the soil of the VSSF CWs maybe responsible for the high contaminant degradation as presented in **Table 4**. In support of this argument, Alsghayer et al. [29] reported that microbial activities are increased in the soil as plant roots provide readily degradable carbon resulting into higher organic contaminant degradation through direct metabolism or a combined metabolism. In addition, Imfeld et al. [38] stated that the removal of toxic organic compounds in CWs are microbially mediated through aerobic and anaerobic microbial degradation processes. TPH are considered as water soluble compounds that display a sorption potential, generally more easily degraded and more readily mineralized under aerobic conditions [38]. This characteristics of TPH may explain its high removal rate in *Typha latifolia* planted VSSF CWs. In this study, TPH had a 93% mass removal rate, 8 and 43% are by plant uptake and sorption in soil and 42% assigned to volatilization and microbial degradation. In comparison to the study conducted by Ekperusi et al. [11] who assessed the transport and fate of hydrocarbons in *Lemna paucicostata* observed a < 1% (6.49 ± 0.66 mg/kg) accumulation in its tissues and 97.74% biodegradation of TPH, while *T*. *latifolia* accumulated higher percent (8%) in its tissues. The treatment of organic compounds by plants includes accumulation, sequestration, degradation, and metabolism of contaminants [11]. This is also supported by Azubuike et al. [47] who reported that the major removal pathway for organic contaminants is by degradation, rhizoremediation, stabilization, volatilization and mineralization in the presence of plants. This is in agreement with Eke et al. [48] stating that removal pathway in CWs is by volatilization, aerobic degradation and metabolic activity of microorganisms.

*T. latifolia* is a good phytoremediator since it was found growing freely in polluted site. This ideal was based on the report by Azubuike et al. [47] in their review on bioremediation techniques that most plants growing in polluted site can be considered as good phytoremediator. For instance, in this present study *T*. *latifolia* was able to tolerate the secondary refinery wastewater they were fed with in the course of the experiment. Thus, the increased density and canopy height is an indication of its ability to tolerate organic contaminants in the wastewater. This is in agreement with studies conducted by Alsghayer et al. [29] who used *Phragmites* and *Vetiver* to treat PAHs. They reported that increasing plant growth indicates increased plant biomass, shoot elongation and its adaptive characteristics. The presence of plants in CWs are reported to produce higher contaminant removal efficiency of planted systems and their ability to promote biodegradation [33]. It was also observed that the *T*. *latifolia* planted VSSF CWs had less residual TPH and O&G compared to the content in the unplanted control VSSF CWs. This study is also a confirmation of the positive role of plants in CWs. Increased treatment rate is observed in planted system due to presence of root, shoot biomass and microorganisms enhancing the rhizosphere effects [29]. Furthermore, overtime, there was increase in removal of contaminants in the secondary refinery wastewater, this increase may be related to plant growth and plant growth also results into increased root length which is expected to increase microbial degradation of organic compounds giving raise to effective biodegradation process [26]. Effects of plant root growth on microbial growth and corresponding increase in biodegradation of organic contaminants is also supported by Moubasher et al. [46]. They explained that microbes can secrete compounds that favors oil-degraders, restore the function of microbial community and increase phytoremediation efficiency.

Sediment or substrates compartment of CWs also have special role in its treatment processes. This could be through precipitation, filtration of suspended solids, sorption of heavy metals and organic matter as well as adhesion of microorganisms and support to root system [49]. The mechanisms for petroleum hydrocarbons in sediment include volatilization, photodegradation, leaching, plant uptake, biodegradation, and abiotic losses according to Al-Mansoory et al. [26]. Supply of oxygen into the substrates favor ideal conditions for the development of important microorganisms that plays vital role in the process of contaminant removal [50]. From the results of the mass balance, TPH and O&G were largely retained in the substrates of both the *T. latifolia* planted and unplanted control VSSF CWs suggesting that the mass removal pathway for these organics is as suggested by Hussain et al. [49]. Tropical climatic temperatures can play a significant role in biodegradation of hydrocarbons. The temperatures for the *T. latifolia* planted and the unplanted VSSF CWs were within the optimum temperature (20-30°C) required for biodegradation of hydrocarbons [26]. Therefore, significant mass removal of TPH occurred in the unplanted control VSSF CWs (**Table 2**). The high temperature in unplanted control VSSF CWs (**Table 1**), may have aided in the high treatment rate (**Tables 2**–**4**). Since temperature can determine the nature and extent of microbial hydrocarbon metabolism that affect biodegradation rate and physio-chemical behavior of oil hydrocarbons (viscousity, diffusion and volatilization) [51]. Coulon et al. [51] observed in their study that temperature had significant effect on TPH biodegradation regardless of bioaugmentation, although, the addition of nitrogen and phosphorus enhanced the biodegradation rate at 20°C. The functions of microbial species in sediment compartment are to metabolize organic contaminants to carbon dioxide and water [11].

#### *3.2.3 Chains of hydrocarbon in secondary refinery wastewater*

The hydrocarbon chains (C9 – C24) of this present study is similar to those identified by Ekperusi et al. [11] in their study (C8 – C40) which is consistent

*Green Technology for Crude Oil Processed Water Treatment: A Practical Approach for Nigeria… DOI: http://dx.doi.org/10.5772/intechopen.98770*

with the hydrocarbons chain present in light crude oil associated with the Niger Delta oil fields, Nigeria. The wastewater, leaf, stem and root samples showed higher rate of lower molecular weight hydrocarbons (<n-C23), this is an indication that all the samples contained light crude oil or by-product of gasoline diesel or jet fuel as suggested by Cortes et al. [52]. Similarly, Khudur et al. [6] also reported diesel as relatively low molecular weight hydrocarbons with typical carbon number of C8 – C28 and they are readily degraded by microorganism. Additionally, the presence of low molecular weight hydrocarbons in the plant tissues of *T*. *latifolia* is an indication of its translocation from the soil. This finding is in agreement with Al-Mansoory et al. [26] who stated that lower molecular weight hydrocarbons can be transported across plant membranes from the soil and released through the process of phytovolatilization [26]. In addition, lower molecular weight aromatic hydrocarbons known to be easily taken up by plants roots [46]. Khudur et al. [27] stated that readily uptake of lower molecular weight hydrogen compounds may indicate its toxicity. The suggested high toxicity of lower molecular weight hydrocarbon may not be applicable to *T*. *latifolia* growth rate and performance (**Figure 2**) in VSSF CWs. Again, toxicity may depend on several factors including quantity, concentrations, and bioavailability of contaminants [20]. The translocation of TPH into part tissues indicates the contribution of *T*. *latifolia* (plants) to contaminant removal processes in CWs.

#### **4. Conclusions**

The role of green technology for petroleum wastewater treatment specifically for Nigeria Petroleum industry was investigated and presented in this book chapter. Constructed wetlands served as the green technological approach for petroleum wastewater treatment. In conclusion,


#### **Acknowledgements**

The author acknowledges the management of Kaduna Refinery and Petrochemical Company, Kaduna. Nigeria for the opportunity to conduct the field study.

### **Conflict of interest**

The author declares no conflict of interest.

### **Thanks**

The author also acknowledges Aisha Onkwo Ibrahim with thanks for her encouragement despite my ill health in bringing the work to reality.

#### **List of abbreviations**


#### **Author details**

Hassana Ibrahim Mustapha Department of Agricultural and Bioresources Engineering, Federal University of Technology, Minna, Nigeria

\*Address all correspondence to: h.i.mustapha@futminna.edu.ng

© 2021 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.

*Green Technology for Crude Oil Processed Water Treatment: A Practical Approach for Nigeria… DOI: http://dx.doi.org/10.5772/intechopen.98770*

#### **References**

[1] O. J. Olujobi, O. M. Olujobi and D. E. Ufua, "A Critical Appraisal of Legal Framework on Deregulation of the Downstream Sector of the Nigerian Petroleum Industry," *International Journal of Management,* vol. 11, no. 6, pp. 252-268, 2020.

[2] A. Ambituuni, J. Amezaga and E. Emeseh, "Analysis of safety and environmental regulations for downstream petroleum industry operations in Nigeria: Problems and prospects," *Environmental Development,* vol. 9, pp. 43-60, 2014.

[3] A. Ingelson and C. Nwapi, "Environmental Impact Assessment Process for Oil, Gas and Mining Projects in Nigeria: A Critical Analysis," *Law, Environment and Development Journal,* vol. 10, no. 1, pp. 37-56, 2014.

[4] E. Allison and B. Mandler, "Petroleum and the Environment," American Geosciences Institute, 2018.

[5] T. A. Oyejide and A. O. Adewuyi, "Enhancing linkages of oil and gas industry in the Nigerian economy," Cape Town, 2011.

[6] L. S. Khudur, E. Shahsavari, A. F. Miranda, P. D. Morrison, D. Nugegoda and A. S. Ball, "Evaluating the efficacy of bioremediating a dieselcontaminated soil using ecotoxicological and bacterial community indices," *Environmental Science and Pollution Research,* vol. 22, p. 14809-14819, 2015.

[7] J. K. Nduka, V. N. Okafor and I. O. Odiba, "Impact of Oil and Gas Activities on Acidity of Rain and Surface Water of Niger Delta, Nigeria: An Environmental and Public Health Review," *Journal of Environmental Protection,* vol. 7, pp. 566-581, 2016.

[8] E. Collins and A. A. Azunwo, "Oil Politics and Its Marketing Strategies of the 21st Century in Nigeria: A Practical Approach," *IIARD International Journal of Economics and Business Management,* vol. 4, no. 7, pp. 49-58, 2018.

[9] P. O. Phil-Eze and I. C. Okoro, "Sustainable biodiversity conservation in the Niger Delta: a practical approach to conservation site selection," *Biodiversity Conservation,* vol. 18, p. 1247-1257, 2009.

[10] S. Yavari, A. Malakahmad and N. B. Sapari, "A Review on Phytoremediation of Crude Oil Spills," *Water Air and Soil Pollution,* vol. 226, pp. 279-297, 2015.

[11] A. O. Ekperusi, E. Nwachukwu and F. D. Sikoki, *scientific Reports,* vol. 10, pp. 8489-8498, 2020.

[12] A. E. Ite, U. F. Ufot, M. U. Ite, I. O. Isaac and U. J. Ibok, "Petroleum Industry in Nigeria: Environmental Issues, National Environmental Legislation and Implementation of International Environmental Law," *American Journal of Environmental Protection,* vol. 4, no. 1, pp. 21-37, 2016.

[13] L. Lin, W. Jiang, L. Chen, P. Xu and H. Wang, "Treatment of Produced Water with Photocatalysis: Recent Advances, Affecting Factors and Future Research Prospects," *Catalysts,* vol. 10, pp. 924-42, 2020.

[14] E. T. Igunnu and G. Z. Chen, "Produced water treatment technologies," *International Journal of Low-Carbon Technologies,* vol. 9, pp. 157-177, 2014.

[15] M. Dudek, H. S. Ullaland, A. Wehrle and G. Øye, "Microfluidic testing of flocculants for produced water treatment: Comparison with other methodologies," *Water Research X,* vol. 9, p. 100073, 2020.

[16] T. Abdel-Moghny, R. S. A. Mohamed, E. El-Sayed, S. M. Aly and M. G. Snousy, "Effect of Soil Texture on Remediation of Hydrocarbons-Contaminated Soil at El-Minia District, Upper Egypt," *ISRN Chemical Engineering,* vol. 2012, pp. 1-13, 2012.

[17] J. Pichtel, "Oil and Gas Production Wastewater: Soil Contamination and Pollution Prevention," *Applied and Environmental Soil Science,* vol. 2016, pp. 1-24, 2016.

[18] H. I. Mustapha and P. N. L. Lens, "Constructed wetlands to treat petroleum wastewater," in *Approaches in Bioremediation. The New Era of Environmental Microbiology and Nanobiotechnology*, R. Prasad and E. Aranda, Eds., Sringer Nature, 2018, pp. 199-237.

[19] S. Ismail, "Phytoremediation: a green technology," *Iranian Journal of Plant Physiology,* vol. 3, no. 1, pp. 567 - 576, 2012.

[20] C. E. Nwanyanwu and G. O. Abu, "In vitro effects of petroleum refinery wastewater on dehydrogenase activity in marine bacterial strains," *Ambiente & Água - An Interdisciplinary Journal of Applied,* vol. 5, no. 2, pp. 21-29, 2010.

[21] P. Agamuthu, Y. S. Tan and S. H. Fauziah, "Bioremediation of hydrocarbon contaminated soil using selected organic wastes," *Procedia Environmental Sciences,* vol. 18, p. 694 – 702, 2013.

[22] A. J. Abbas, H. A. Gzar and M. N. Rahi, "Oilfield-produced water characteristics and treatment technologies: a mini review," *IOP Conf. Series: Materials Science and Engineering,* vol. 1058, pp. 1-10, 2021.

[23] H. I. Mustapha, "Treatment of petroleum refinery wastewater with constructed wetlands," Taylor & Francis, Delft, 2018.

[24] S. Arora and S. Saraswat, "Vermifiltration as a natural, sustainable and green technology for environmental remediation: A new paradigm for wastewater treatment process," *Current Research in Green and Sustainable Chemistry,* vol. 4, p. 100061, 2021.

[25] H. I. Mustapha, H. J. J. A. van Bruggen and P. N. L. Lens, "Vertical subsurface flow constructed wetlands for the removal of petroleum contaminants from secondary refinery effluent at the Kaduna refining plant (Kaduna, Nigeria)," *Environmental Science and Pollution Research,* vol. 25, p. 30451-30462, 2018.

[26] A. F. Al-Mansoory, M. Idris, S. R. S. Abdullah and N. Anuar, "Phytoremediation of contaminated soils containing gasoline using *Ludwigia octovalvis* (Jacq.) in greenhouse pots," *Environmental Science and Pollution,* vol. 24, p. 11998-12008, 2017.

[27] L. S. Khudur, E. Shahsavari, A. F. Miranda, P. D. Morrison, D. Nugegoda and A. S. Ball, "Evaluating the efficacy of bioremediating a dieselcontaminated soil using ecotoxicological and bacterial community indices," *Environmental Science and Pollution Research,* vol. 22, p. 14809-14819, 2015.

[28] E. Wolejko, U. Wydro and T. Loboda, "The ways to increase efficiency of soil bioremediation," *Ecology of Chemical Engineering Study,* vol. 23, no. 1, pp. 155-174, 2016.

[29] R. Alsghayer, A. Salmiaton, T. Mohammad, A. Idris and C. F. Ishak, "Removal Efficiencies of Constructed Wetland Planted with Phragmites and Vetiver in Treating Synthetic Wastewater Contaminated with High Concentration of PAHs," *Sustainability,* vol. 12, no. 8, pp. 3357-3375, 2020.

[30] S. H. Chek Rani, M. F. Md. Din, B. Mohd. Yusof and S. Chelliapan, "Overview of subsurface constructed wetlands application in tropical climates," *Universal Journal of* 

*Green Technology for Crude Oil Processed Water Treatment: A Practical Approach for Nigeria… DOI: http://dx.doi.org/10.5772/intechopen.98770*

*Environmental Research and Technology,* vol. 1, no. 2, pp. 103-114, 2011.

[31] A. M. Paz-Alberto and G. C. Sigua, "Phytoremediation: A Green Technology to Remove Environmental Pollutants," *American Journal of Climate Change,* vol. 2, pp. 71-86, 2013.

[32] R. K. Chakrabort and J. S. Bays, "Natural Treatment of High-Strength Reverse Osmosis Concentrate by Constructed Wetlands for Reclaimed Water Use," *Water,* vol. 12, pp. 158- 188, 2020.

[33] A. Stefanakis, E. Seegera, C. Dorer, A. Sinke and M. Thullner, "Performance of pilot-scale horizontal subsurface flow constructed wetlands treating groundwater contaminated with phenols and petroleum derivatives," *Ecological Engineering,* vol. 95, pp. 514-526, 2016.

[34] P. M. Nacheva, "Water Management in the Petroleum Refining Industry," in *Water Conservation*, Croatia, INTECH, 2011, pp. 1-26.

[35] H. I. Mustapha, "Invasion, management and alternative uses of Typha latifolia: A brief review.," in *National Conference and Annual General Meeting of the Nigeria Institute of Agricultural Engineering,* Minna, 2016.

[36] M. A. Belmont, E. Cantellano, S. Thompson, M. Williamson, A. Sanchez and C. D. Metcalfe, "Treatment of domestic wastewater in a pilot-scale natural treatment system in central Mexico," *Ecological Engineering,* vol. 23, no. 4-5, pp. 299-311, 2004.

[37] J. García, D. P. L. Rousseau, J. Morató, E. Lesage, V. Matamoros and J. M. Bayona, "Contaminant Removal Processes in Subsurface-Flow Constructed Wetlands: A Review," *Critical Reviews in Environmental Science and Technology,* vol. 40, no. 1, pp. 561-661, 2010.

[38] G. Imfeld, M. Braeckevelt, P. Kuschk and H. H. Richnow, "Monitoring and assessing processes of organic chemicals removal in constructed wetlands," *Chemosphere,* vol. 74, p. 349-362, 2009.

[39] C. Ríos, L. Gutiérrez and M. Aizaki, "A case study on the use of constructed wetlands for the treatment of wastewater as an alternative for petroleum industry," *Bistua: Revista de la Facultad de Ciencias Básicas,* vol. 5, no. 2, pp. 25-41, 2007.

[40] K. Skrzypiec and M. H. Gajewska, "The use of constructed wetlands for the treatment of industrial wastewater," *Journal of Water and Land Development,* no. 34(VII–IX), p. 233-240, 2017.

[41] T. V. Wagner, F. Al-Manji, J. Xue, K. Wetser, V. de Wilde, J. R. Parsons, H. H. M. Rijnaarts and A. A. M. Langenhoff, "Effects of salinity on the treatment of synthetic petroleum-industry wastewater in pilot vertical flow constructed wetlands under simulated hot arid climatic conditions," *Environmental Science and Pollution Research,* vol. 28, p. 2172-2181, 2021.

[42] K. kulshrestha and N. Khalil, "Treatment of domestic waste water in Pilot Vertical Flow Constructed wetland with recycle and with Tidal Flow constructed wetland in India," Aligarh, India, 2019.

[43] G. Baskar, V. T. Deeptha and R. Annadurai, "Comparison of Treatment Performance between Constructed Wetlands with Different Substrates," *International Journal of Research in Engineering & Advanced Technology,* vol. 2, no. 3, pp. 1-6, 2014.

[44] A. I. Machado, M. Beretta, R. Fragoso and E. Duarte, "Overview of the state of the art of constructed wetlands for decentralized wastewater management in Brazil," *Journal of Environmental Management,* vol. 187, pp. 560-570, 2017.

[45] F. Li, L. Lu, X. Zheng, H. H. Ngo, S. Liang, W. Guo and X. Zhang, "Enhanced nitrogen removal in constructed wetlands: effects of dissolved oxygen and step-feeding," *Bioresource Technology,* vol. 169, pp. 395-402, 2014.

[46] H. A. Moubasher, A. K. Hegazy, N. H. Mohamed, Y. M. Moustafa, H. F. Kabiel and H. H. Hamad, "Phytoremediation of soils polluted with crude petroleum oil using Bassia scoparia and its associated rhizosphere microorganisms," *International Biodeterioration & Biodegradation,* vol. 98, pp. 113-120, 2015.

[47] C. C. Azubuike, C. B. Chikere and G. C. Okpokwasili, "Bioremediation techniques–classification based on site of application: principles, advantages, limitations and prospects," *World J Microbiol Biotechnol,* vol. 32, pp. 179- 197, 2016.

[48] P. E. Eke, M. Scholz and S. D. Wallace, "Constructed Treatment Wetlands: Innovative Technology for Petroleum Industry," in *SPE Annual Technical Conference and Exhibition*, Anaheim, California, 2007.

[49] F. Hussain, G. Mustafa, F. Ali, M. Matloob, H. Shah, A. Raza and J. Irfan, "Constructed Wetlands and their Role in Remediation of Industrial Effluents via Plant-Microbe Interaction–A Mini Review," *Journal of Bioremediation & Biodegradation,* vol. 9, no. 4, pp. 447- 453, 2018.

[50] M. Rossmann, A. T. de Matos, E. C. Abreu, F. F. Silva and A. C. Borges, "Performance of constructed wetlands in the treatment of aerated coffee processing wastewater: Removal of nutrients and phenolic compounds," *Ecological Engineering,* vol. 49, pp. 264-269, 2012.

[51] F. Coulon, B. A. McKew, A. M. Osborn and T. J. T. K. N. McGenity, "Effects of temperature and

biostimulation on oil-degrading microbial communities in temperate estuarine waters," *Environmental Microbiology,* vol. 9, no. 1, pp. 177- 186, 2007.

[52] J. E. Cortes, A. Suspes, S. Roa, C. González and H. E. Castro, "Total Petroleum Hydrocarbons by gas chromatography in Colombian waters and soil," *American Journal of Environmental Science,* vol. 8, no. 4, pp. 396-402, 2012.

*Edited by Manar Elsayed Abdel-Raouf and Mohamed Hasan El-Keshawy*

Petroleum crude oil is the main energy source worldwide. However, global fossil fuel resources and reservoirs are rapidly and disturbingly being depleted. Thus, it is particularly important to shed light on new techniques developed for economic production and better utilization of crude oil. In addition, the processes involved in the production, refining, and transportation of crude oil are environmentally hazardous. It is essential to develop cleaner technologies and to find innovative solutions to overcome these problems. Over four sections, this book discusses materials used in cracking crude oil and improving its specifications, methods for reducing or eliminating the hazardous effects of petroleum pollution, and the environmental effects of crude oil, as well as presents case studies from different countries.

Published in London, UK © 2022 IntechOpen © Malekas85 / iStock

Crude Oil - New Technologies and Recent Approaches

Crude Oil

New Technologies and Recent Approaches

*Edited by Manar Elsayed Abdel-Raouf* 

*and Mohamed Hasan El-Keshawy*