In Situ Co2 EOR Mechanism and Co2-Oil Phase Behavior

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In Situ Co2 EOR Mechanism and Co2-Oil Phase Behavior

ABSTRACT

Numerical reservoir simulators are employed to obtain meaningful and reliable solutions for an actual case due to extreme complexity of the reservoirs systems. Wilcox formation is a reservoir in the gulf of Mexico with various development challenges, to better maximize the resources in the reservoir, simulation studies is needed to make better informed decision. For this study, a compositional simulator model is developed for comparing CO2 injection in different API oil reservoir. The fluid samples were characterized using PVT simulator and so also is the swelling factor and the viscosity reduction test. The E300 eclipse simulator was used for determining the MMP by developing a 1-D slimtube experiment model and a CO2 injection model for the case studied. The estimated MMP of 6500 psia is less than the reservoir pressure so a miscible flooding was achieved. Four API oil samples (22o, 29o, 38o and 45o) was simulated and compared considering different scenarios. The viscosity reduces with increasing injection rate for the light oil samples and from the swelling test, increasing CO2 injected will increase the oil swelling capability. Furthermore, sensitivity analysis was performed to investigate which of the samples is best candidate for CO2 flooding and results shows that light oil reservoirs are better candidate for CO2 flooding.

TABLE OF CONTENTS

CHAPTER ONE …………………………………………………………………………………………………………………………….. 1
1.1 Background Study ………………………………………………………………………………………………………………. 1
1.2 OBJECTIVE OF RESEARCH …………………………………………………………………………………………………….. 3
1.3 Aims and Objective …………………………………………………………………………………………………………….. 3
1.4 The outlay of the Thesis ………………………………………………………………………………………………………. 4
CHAPTER TWO ……………………………………………………………………………………………………………………………. 5
Literature Review ………………………………………………………………………………………………………………………… 5
2.1 Geology of deep water Wilcox Formation ……………………………………………………………………………… 5
2.1.1 Turbidite Elements ……………………………………………………………………………………………………….. 5
2.1.2 Paleogene (Wilcox) Deposition ………………………………………………………………………………………. 6
2.2 Reservoir Characterization and Development Challenges of Wilcox Formation ………………………….. 7
2.2.1 Reservoir Characterization …………………………………………………………………………………………….. 7
2.2.2 Obstacles to Exploration and Development GoM Wilcox Formation …………………………………. 11
2.3 Immiscible CO2 Processes ………………………………………………………………………………………………….. 11
2.4 IN SITU CO2 GENERATION ………………………………………………………………………………………………….. 13
2.4.1 Ammonium Carbamate as a gas generating agent ………………………………………………………….. 14
2.5 Kinetics and Mechanism of the Reversible Dissociation of Ammonium Carbamate …………………… 19
2.5.2 Urea as a gas generating agent …………………………………………………………………………………….. 27
2.6 TRANSPORT AND STORAGE OF CO2 …………………………………………………………………………………….. 28
2.6.1 CO2 flooding ………………………………………………………………………………………………………………. 28
2.6.2 Molecular Diffusion Governed Mass Transport ………………………………………………………………. 29
2.7 Mass Transfer of CO2-Crude Oil Systems ……………………………………………………………………………… 30
2.7.1 Mass Transfer without Reaction (Physical Absorption) ……………………………………………………. 34
2.7.1.1 Film Theory …………………………………………………………………………………………………………….. 34
2.7.2 Mass Transfer with Chemical Reaction ………………………………………………………………………….. 37
2.7.1 Prediction of Diffusion Coefficient ………………………………………………………………………………… 39
CHAPTER THREE ………………………………………………………………………………………………………………………… 40
RESERVOIR SIMULATION MODELING …………………………………………………………………………………………… 40
3.1 INTRODUCTION TO ECLIPSE 300 …………………………………………………………………………………………. 40
3.2 Data description and Model used ……………………………………………………………………………………….. 40
3.2.1 The phase behavior of the fluid composition …………………………………………………………………. 41
3.2.2 3-parameter Peng-Robinson Equation of State Model…………………………………………………….. 41
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3.3 Estimating Minimum Miscibility Pressure (MMP) …………………………………………………………………. 43
3.4 Urea Reaction and CO2 Generation Kinetics …………………………………………………………………………. 44
3.5 CO2 Swelling Factor …………………………………………………………………………………………………………… 46
3.5.1 CO2 swelling factor for different API oil …………………………………………………………………………. 46
3.6 CO2-Oil Viscosity Reduction ……………………………………………………………………………………………….. 47
3.7 Lohrenz, Bray and Clark Viscosity Reduction Correlation ……………………………………………………….. 48
3.8 Reservoir Model and Rock Properties …………………………………………………………………………………. 49
3.8.1 Grid System ……………………………………………………………………………………………………………….. 49
3.8.2 Computational Process ……………………………………………………………………………………………….. 50
3.8.3 Simulation Model …………………………………………………………………………………………………………… 50
CHAPTER FOUR …………………………………………………………………………………………………………………………. 52
RESULTS AND DISCUSSION………………………………………………………………………………………………………….. 52
4.1 Grid sensitivity Analysis. ……………………………………………………………………………………………………. 52
4.2 Simulation Result and Discussion ……………………………………………………………………………………….. 54
4.3 Sensitivity Analysis ……………………………………………………………………………………………………………. 67
CHAPTER FIVE …………………………………………………………………………………………………………………………… 72
CONCLUSIONS AND RECOMMENDATIONS ……………………………………………………………………………………. 72
5.2 Recommendations ……………………………………………………………………………………………………………. 73
REFERENCES ……………………………………………………………………………………………………………………………… 80

CHAPTER ONE

1.1 Background Study

Only some fraction about (10%) of the initial hydrocarbon in place in a petroleum reservoir can be recovered by primary production using the reservoir’s natural energy drive. In the turbidite system in the deepwater Wilcox formation of the Northwest Gulf of Mexico, there is a potential of 15Bbbl that covers over 34,000 mi2 (54,740 km2) (Meyer, Zarra, Rains, Meltz, & Hall, 2005). This formation is characterized by high pressure and high temperature and a water depth of 3000-7000 feet, and the formation has an average permeability of about 15mD. Furthermore, the porosity is about 18%, crude gravity of 250 API, and viscosity of 6cP. The majority of the remaining oil is trapped by capillary forces, bypassed due to reservoir heterogeneity and mobility of the injected fluid to displace reservoir oil. Therefore, a significant fraction of the remnant oil is available as a target for Enhanced Oil Recovery (EOR) processes. This oil can be an energy source for years to come. However, as of date, there are new EOR technologies for producing the resource which includes Chemical, Water, Polymer, thermal flooding, and Gas Injection. Large research expenditure and efforts are being directed towards enhancing the recovery of this oil but with limited success. Although the complete recovery of all the trapped oil is difficult, the target resource base is very large. Of the major contending processes for this trapped resource, gas injection appears to be an ideal choice. CO2 injection is one of the most frequently used gas injection EOR methods and its application grows very fast because of its abundance, greenhouse effect and so forth. Secondary and tertiary recovery process based on gas injection can represent a very interesting solution to extend the life of the reservoirs and maximize the recovery. However, the injection strategy need to be carefully studied in order to optimize the overall sweep efficiency. The common challenges with CO2 injection include CO2 supply limitation, transportation, cost investment, and corrosion. For an offshore application, the critical challenge could be related to an extremely remote and significant increase in project cost. Different approaches have been employed to study the performance of CO2 in increasing oil production including miscible/immiscible injection carbonated water injection (CWI) and CO2 injection into the aquifer. In these methods, different parameters can effect such as minimum miscible pressure (MMP), injection rate and so forth.

In situ CO2 EOR (ICE) is a novel way of generating CO2 in subsurface for flooding to increase oil recovery in hydrocarbon reservoirs. The process involves dissolving ammonium carbamate or urea in a brine solution as a gas generating agent. This chemical solution at reservoir condition liberates CO2 and ammonia is generated as a by-product. CO2 will reduce the viscosity of the crude oil resulting in oil swelling while the ammonia will benefit in terms of wettability alteration. These methods requires minimal capital investment upfront compared to supercritical CO2 flooding. It reduces fingering because of the absence of free CO2 phase and this makes it a potential tertiary oil recovery mechanism for both onshore and offshore fields.

Chemical solvents methods have been widely studied and generally are recognized as the most effective technologies for CO2 capture and separation (Bai & Yeh, 1997; Bonenfant, Mimeault, & Hausler, 2003; Chakma, 1995; McCann, Maeder, & Attalla, 2008; Wolsky, Daniels, & Jody, 1994).

CO2 is absorbed in a chemical such solvent as amines to form bicarbonates (Khatri, Chuang, Soong, & Gray, 2006). In situ CO2 generation has been studied for Enhanced Oil Recovery and it has been recognized that ammonium carbamate at a high temperature above 80oC will generate CO2. Studies have shown that when this ammonium carbamate at high temperature produced CO2 in a sand pack column, it results in a decrease of oil viscosity and improve in oil recovery (Gumersky, Dzhafarov, Shakhverdiev, & Mamedov, 2000; Lei, Yang, Zu, Wang, & Li, 2016; Shiau, Hsu, Roberts, & Harwell, 2010; Wang, Kadhum, Chen, Shiau, & Harwell, 2017). Additionally, the mass transfer of CO2 between water and hydrocarbon phase controls displacement efficiency and not MMP (Dong, Huang, & Srivastava, 2001). Molecular diffusion of the CO2 from the aqueous phase to the oil phase plays a key role in oil recovery processes. Modeling of the molecular diffusion becomes important in simulation of the reservoir for EOR. Two mechanisms are associated with the mass transfer of components: molecular diffusion and convective bulk flow. The accurate prediction or measurement of the diffusion coefficient D is very crucial in determination of the diffusion flux.

1.2 OBJECTIVE OF RESEARCH

Another novel technique of injecting CO2 for EOR is to inject it indirectly into the subsurface formation by injecting a solvent which is a CO2 generating species. Solvents like concentrated ammonium carbamate solution and urea are commercially available. The solvent when injected subsurface liberates CO2 and NH3 under reservoir condition. The CO2 liberated help reduce the interfacial tension, lowers the viscosity of the oil which results in oil swelling. The ammonia produced at high concentration leads to sand wettability reversal. The self-reaction ignition properties of the urea and ammonium carbamate make the single fluid injection possible and reduce the complexity of the injection system. Because of their CO2 producing capacity and reasonable cost-benefit, they appear to be a promising candidate for delivering CO2 to increase oil recovery. This work study the technical challenges for EOR of tight and viscous oil recovery of Wilcox formation, review in-situ CO2 generation and flooding and compare CO2 injection in different API crude through numerical simulation. Sensitivity study was also be carried out.

1.3 Aims and Objective

This numerical study is directed towards studying of CO2 flooding for deepwater Wilcox formation. The aim is to investigate the technical limit for EOR of tight and viscous oil recovery using in-situ CO2 generation and flooding through numerical simulation and sensitivity study.

In order to accomplish the proposed objectives;

 The development challenges of the Wilcox formation will be studied.

 Review work on the development of in-situ hybrid CO2 for EOR.

 Develop a model to study CO2 injection in different API oil using a compositional simulator.

 Carry out sensitivity analysis on the study.

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