Proper handling of sour gas produced is crucial to the development of sour reservoirs. Over years of research and practice, many methods of sour gas processing have been developed from the solid storage of sulfur to reinjecting the sour gas back into producing or depleted light oil reservoir for miscible flooding enhanced oil recovery. This paper seeks to investigate the use of sour gas to enhance oil recovery and its associated phase behavior problems.

In designing a miscible gas flooding project, the minimum miscibility pressure (MMP) is the key parameter that determines the impact on gas and oil mixing phase behavior. The MMP is the lowest pressure at which the displacement process becomes miscible upon contact with the reservoir fluid. There are various methods to determine the MMP. A laboratory experiment is the most accurate but time consuming and subject to fluid sample quality; while the Equation of State is poor in characterizing polar molecules like H2S. For this study, empirical correlations are used to determine the MMP because the study focuses more on the general trend of how methane concentration affects the MMP of the process.

In this study, a sour gas injection model is developed using a compositional simulator with the aim to determine mechanistically how sour gas enhances oil recovery. This model is used to evaluate the effect of some important parameters such as acid gas concentration, injection pressure and injection rates on oil recovery efficiency.

The result of MMP study shows that methane concentration has a significant impact on the MMP of the process. As methane concentration increases in the injection gas, the MMP of the process also increases. From this study, it was observed that increasing acid gas concentration decreases the MMP of the process as a result of an increase in gas viscosity, consequently extending the plateau period resulting in late gas breakthrough and increasing the overall recovery of the process. It is also seen that this increase in viscosity increases the

volumetric sweep efficiency of the process which is an improvement to most gas injection enhance oil recovery (EOR).










Research aim2

Research objectives2

Research Layout2



Hydrocarbon Recovery3

Displacement of Fluid in a Reservoir5

Mechanism of Gas Flooding in EOR8

Determination of Minimum Miscibility Pressure (MMP)16

Sour gas Injection26



Comparative Study for MMP using Correlations35

Base Case Description41

3.1.4 Reservoir Initialization 43



Compositional Variation of Acid gas in the Injection Gas 48

Effect of gas injection rate 51

3.2.3 Injection Pressure Effect 53


Conclusion and Recommendation 56







Figure 1:Comparison of Model With Experimental Non-wetting Phase Residual Saturation (Pope 2007) 7

Figure 2: Conditions for different types of oil displacement by solvents(Lake L. W., 1989). 11 Figure 3:First Contact Miscibility in Pseudo-ternary Diagram (Stalkup 1987) 12

Figure 4:Phase Behaviour Consideration For first Contact Miscibility (Stalkup 1987) 13

Figure 5: Gas Injection Scenarios (Al-Hadhrami et al. 2007) 16

Figure 6: Schematics diagram of Slim-tube apparatus (Yellig and Metcalfe 1980) 17

Figure 7: Schematic diagram of rising bubble apparatus (Eakin and Mitch 1988) 19

Figure 8: Ternary diagram at a specific temperature and pressure 24

Figure 9: Vaporizing-gas drive mechanism (Stalkup, 1987) 25

Figure 10: Condensing-gas drive mechanism (Stalkup, 1987) 26

Figure 11: Phase Envelope For H2S and CO2 Mixture (Bierlein and Kay, 1953) 31

Figure 12: Model Diagram 37

Figure 13:Comparision: The effect of acid gas composition on oil recovery efficiency 37

Figure 14:Comparison: The effect of Acid Gas Composition on Oil Production Rate 39

Figure 15 Comparison: The effect of Acid Gas Composition on Gas Production Rate 39

Figure 16: Effect of Acid Gas Composition on Gas Viscosity in the Production Block 41

Figure 17:Comparison: Effect gas injection rate on oil Production Rate 41

Figure 18: Gas injection rate vs time 42

Figure 19: Cumulative gas Injected vs Oil Recovery efficiency 48

Figure 20: Effect of gas injection pressure on oil recovery efficiency 49

Figure 21: Effect of gas injection Pressure on Oil Production rate 50

Figure 22: Effect of gas injection pressure on injection rate 50

Figure 23: Scenario 1 MMP Change with C1 Composition Using Glaso Correlation 52

Figure 24: Scenario 1 MMP Change with C1 Composition Using Yuan et al Correlation 52

Figure 25: Scenario 2 MMP Change with C1 composition using Glaso Correlation 53

Figure 26 Scenario 2 MMP Change with C1 composition using Yuan et al Correlation 54


Table 1: Properties of H2S and CO2 (Carroll, 2010) 30

Table 2: Injection Fluid Composition 42

Table 3: Reservoir Fluid Composition 43

Table 4: Reservoir Model Input parameters 44

Table 5: NA phase binary interaction parameters for the components contained in the oil mixture 46

Table 6:Oil, Water and Gas Saturation Functions 46

Table 7: Different Scenarios for MMP studies 35

Table 8: Result of MMP Studies for Scenario one 36

Table 9: Result of MMP Studies for Scenario Two 38

Table 10: Result of MMP Studies for Scenario Three 40


One of the major problems of developing a sour reservoir is how to handle the produced sour/acid gas. The gases produced from a sour reservoir are sweetened to selectively separate the gases using different methods . Among these methods, amine extraction  is  the most commonly used in petroleum industries. The separation process results in the production of a waste stream containing CO2 and H2S, and this mixture is referred to as acid gas. There is a need for an environmentally-friendly and cost-effective method for dealing with this acid gas stream.

Over the years a lot of strategies have been developed to handle acid gas mixture, and  most of them are primarily concerned with the reduction of the toxic hydrogen sulfide to an inert/non-toxic reactive product. The most common technique is the Claus reaction process where gases containing H2S are catalytically converted to elemental sulfur (Bennion et al. 1999)Another method used to manage the acid gas mixture is to inject a compressed acid gas mixture into a subsurface reservoir for storage.

In this research, I studied the re-injection of the rich waste acid gas stream directly back into the producing or depleted light oil reservoir for the purpose of miscible flooding enhanced oil recovery through characterizing its phase behavior and numerical simulation. Sour gas injection for enhanced oil recovery (EOR) presents a cost-effective and environmentally-friendly solution for managing a sour reservoir. It eliminates current  taxation or future liability associated with emission or surface storage of sulfur. This study will focus on mechanisms of miscible gas injection using sour gas. Sour gas is a blend of natural gas with hydrogen sulfide (H2S) and carbon dioxide (CO2)

Research aim

The main goal of this research is to develop a miscible gas flooding EOR with sour gas using a  compositional simulator with the aim to study the mechanism of how sour/acid gas enhances oil recovery and to understand how hydrocarbon composition in sour gas affects miscibility development and the minimum miscibility pressure.

Research objectives

To conduct minimum miscibility pressure (MMP) studies with a compositional variation of methane in the injected sour gas to determine how methane concentration affects the MMP of sour gas and its phase behavior.

Develop a compositional simulation model for the sour gas injection process and conduct sensitivity studies to determine the effect of some parameters on oil recovery efficiency.

Research Layout

This research is organized into four chapters. A brief introduction to the problem, objectives, and scope of the work are presented in Chapter One. Chapter Two contains a review of the published literature and a summary of related previous studies. This chapter also focuses on the miscible gas flooding EOR process, different gases used for gas flooding, miscibility development and methods used in determining minimum miscibility pressure and work done on sour gas injection. Chapter Three the base case model is presented. Chapter Four discusses the results obtained from the simulations, sensitivity studies, and comparative MMP studies, as well as the summary of the analysis of results obtained. Finally, conclusions, and recommendations, are presented in Chapter Five.



Hydrocarbon Recovery

Hydrocarbon development is usually divided into three stages: Primary depletion, secondary recovery, and tertiary recovery. Primary depletion refers to the volume of hydrocarbon produced by the natural energy prevailing in the reservoir. Secondary recovery is usually used after reservoir pressure, and rate start declining, while tertiary recovery or enhanced oil recovery (EOR) is applied after secondary recovery has become uneconomical. The objective of EOR processes is to recover the remaining oil after the primary and/or secondary recovery mechanism.

Primary Recovery

Primary recovery process techniques use the reservoir natural energy to force hydrocarbons out of the reservoir. The recovery efficiency of primary depletion depends mainly on existing reservoir drive mechanisms. These forces in the reservoir either can act simultaneously or sequentially (Ogienagbon et al. 2016)

Primary recovery from oil reservoirs is influenced by reservoir rock properties, fluid properties, and geological heterogeneities. The primary oil recovery factors range from less than 10% to 40% or higher, while the remainder of the hydrocarbon is left behind in the reservoir (Satter, Iqbal, and Buchwalter 2008)

Secondary Recovery

Secondary recovery involves the introduction of artificial energy into the reservoir via one wellbore and production of oil and/or gas from another wellbore (Romero-Zeron 2012)Usually, secondary recovery includes the immiscible processes of water flooding and gas injection or gas-water combination floods, known as water alternating gas injection

(WAG), where slugs of water and gas are injected sequentially. Simultaneous injection of water and gas (SWAG) is also practiced, however the most common fluid injected is water because of its availability, low cost, and high specific gravity which facilitates injection (Satter, Iqbal, and Buchwalter 2008)

Tertiary Processes

Tertiary recovery processes refer to the application of methods that aim to  recover  oil beyond primary and secondary recovery. During tertiary oil recovery, other than conventional water, immiscible gas is injected into the formation to effectively boost oil production (Green and Willhite 1998)EOR is a broader idea that refers to the injection of fluids or energy not normally present in an oil reservoir to improve oil recovery that can be applied at any phase of oil recovery including primary, secondary, and tertiary recovery (Romero-Zeron, 2012).

Thus, EOR can be implemented as a tertiary process if it follows a water flooding or an immiscible gas injection. It may also be a secondary process if it follows primary recovery directly (Satter, Iqbal, and Buchwalter 2008)EOR refers to the recovery of oil through the injection of fluid sand energy not normally present in the reservoir (Lake 1989)(Green and Willhite 1998)

The ultimate goal of EOR processes is to increase the overall oil displacement efficiency, which is a function of microscopic and macroscopic displacement efficiency (Romero-Zeron, 2012). One of the mechanisms limiting primary and secondary recovery from completely sweeping the reservoir is trapping of oil on the pore scale (microscopic). Hydrocarbon trapping increases as oil saturation decreases due to an increase in capillary forces. This trapping is best expressed as a competition between viscous forces, which mobilize the oil, and capillary forces, which trap the oil (Larry Lake,1989).




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