ghiên cứu ứng dụng công nghệ bơm ép luân phiên nước khí hydrocacbon nhằm nâng cao hệ số thu dầu tại tầng miocene bể cửu long tt tiếng anh

MINISTRY OF EDUCATION AND TRAINING HANOI UNIVERSITY OF MINING AND GEOLOGY TRINH VIET THANG RESEARCH FOR APPLICATION OF WATER ALTERNATING GAS TO ENHANCED OIL RECOVERY IN THE MIOCENE RESERVOIR, CUU LONG BASIN Major: Petroleum Engineering Code: 9520604 SUMMARY OF TECHNICAL DOCTORAL THESIS HANOI – 2019 The dissertation is completed at the Department of Drilling and Production, Faculty of Petroleum, Hanoi Unniversity of Mining and Geology Scientific Supervisors: Assoc Prof., Dr Cao Ngoc Lam Dr Sc Phung Dinh Thuc Reviewer 1: Assoc Prof., Dr Nguyen The Vinh Reviewer 2: Dr Nguyen Hai An Reviewer 3: Dr Pham Xuan Toan The thesis will be defended before the Academic Reviewer Board at the University level at Hanoi University of Mining and Geology at … of date….month…., 2019 The thesis is available at the National Library of Vietnam or the Library of Hanoi University of Mining and Geology INTRODUCTION Research Objective Petroleum is an invaluable, unrenewable and fundamental resource for every country around the globe, especially so for developing countries In recent years, the amount of newly discovered oilfields, especially those that are significant in reserves, is declining, while many of the ones that are in production are reaching their final stages Therefore, around the world, Enhanced Oil Recovery (EOR) technologies are increasingly receiving attention and resources from countries and companies alike Vietnam is a country with moderate oil production; the majority of which are from the basement reservoirs within the Cuu Long basin The main reservoirs are the fractured granite basement and miocene, accounting for about 90% of the yearly oil production After primary production and secondary production (waterflooding), oil recovery factor for these reservoirs range from 20% to 32% More than two-third of the explored oil in place still remains untouched This is an opportunity for the application of EOR method(s) to unlock the remaining oil in place Application of EOR technologies for the producing reservoirs mentioned above is the main focus, critical for meeting the energy demand With the application of EOR method(s), a modest 1% to 2% increase in recovery factor for large reservoir is already comparable to a discover of a small reservoir Moreover, as production rate of the Miocene reservoir is already in decline, the need for researching an appropriate EOR method for this zone is even more imperative For these reasons, “Research for Application of Water-Alternating-Gas to Enhance Oil Recovery in the Miocene reservoir, Cuu Long Basin” is a crucial and prioritized research project with clear cut implications The main objectives of this work are to characterize in details the applicable condition associate with Miocene properties and to come up with the an effective EOR method as well as its application for this objective In order to successfully apply Water-Alternating-Gas (WAG) to enhance oil recovery for this reservoir within the Cuu Long basin, the authors need to focus on: ➢ Literature researching to study existing EOR methods and their successful applications around the world, to gauge their compatibility with the geological, rock, and fluid properties, as well as the production configurations, found in the Vietnamese reservoirs, especially for sedimentary reservoir ➢ Researching available methods to determine Minimum Miscibility Pressure (MMP), as well as the miscibility, near miscibility, and immisicbility mechanism for Vietnamese oil reservoirs ➢ Researching and evaluating the effects of reservoir properties on possible application of Water-Alternating-Gas injection to enhance oil recovery ➢ Researching and evaluating EOR effectiveness of Water-Alternating-Gas injection and comparing it to those of other EOR methods, using Miocene’s reservoir simulation model Research Procedure ➢ Data collection: collecting, classifying, and processing available data to assess the difficulties and complications affecting production ➢ Literature review: researching existing EOR methods already applied around the world and evaluating their applicability on Su Tu Den field Focusing on solving the miscible/nearmiscible/immiscible mechanism, as well as how changes in various factors such as pressure lead to changes in miscibility ratio or displacement within the Miocene reservoir ➢ Laboratory work: utilizing Slimtube experiment to determine the minimum miscibility pressure (MMP) of the in-situ oil sample native to the Mioxen reservoir ➢ Reservoir simulation: utilizing numerical simulation to find the MMP and compare it to the one determined from Slimtube experiment Simulate dynamics flows of fluids for the entire reservoir(s) of interest to evaluate and compare efficiency of different EOR methods, such as gas injection or alternating gas injection Research Subject Research application of Water-Alternating-Gas to enhance oil recovery for the Miocene reservoir, Su Tu Den field Scope of Study Mioxen reservoir of Su Tu Den field, Contract Block 15-1, Cuu Long basin, Vietnam, operating of Cuu Long Joint Operating Company (CSLJOC) Defending Conclusions Finding 1: By utilizing simulation model, the exactly MMP for the process of injecting Water-Alternating-Gas into Miocene reservoir was successfully predicted Finding 2: Based on different criteria, it was proven that Water-Alternating-Gas was the most appropriate EOR method for Su Tu Den field Scientific Significance The thesis researchs of mechanism and application of Water-Alternating-Gas for enhancing oil recovery was relatively new in Vietnam Through this work, the authors successfully explored the mechanism of fluid flow in formation with high degree of heterogeneity, of the gas-water-oil interactions, of the injected gas and in-situ oil miscibility, and of the macroscopic and microscopic displacement efficiency Furthermore, the author was also able to evaluate the degree of enhancing oil recovery on a particular subject when applying Water-Alternating-Gas injection, from there being able to make recommendation on application of EOR method on Vietnam’s oilfields Field Application This study provided substantial scientific reasonings to recommend employing Water- Alternating-Gas for enhancing oil recovery in Miocene, Cuu Long, and to go forward with piloting a Water-Alternating-Gas injection scheme in the South West area of Su Tu Den field Research Results This work stemmed from the pressing need of Vietnam’s oil producing climate Its results contributed to the improvement of oil recovery factors for many zones and reservoirs, especially Miocene ➢ The optimal procedure to predict the in-situ oil’s MMP, as well as such value for the target of interest in this work, was determined ➢ Successfully studied the influence of reservoir parameters, geological structure, geological properties, and previous production scheme(s), on the effective application of Water-Alternating-Gas for sedimentary formation ➢ Evaluated the effectiveness of applying Water-Alternating-Gas for enhancing oil recovery and compared it to other EOR methods, using reservoir simulation ➢ Results of this work were published and presented at the “International Conferences on Earth Sciences and Sustainable Geo-resources Development” conference Volume and Structure of this Manuscript This thesis consists of an introduction, four chapters outlining the research procedures, conclusions, recommendations, and references It is 133 - page long, with 16 tables, 103 graphs, figures, and 112 references CHAPTER 1: OVERVIEW Enhance Oil Recovery All EOR methods aim to improve the microscopic and/or macroscopic displacement efficiency, based on the viscous, capillary, and/or gravitational interactions of the injected fluid(s) and in-situ fluid(s) as followed: Figure 1.1: Interactions between Different Forces in EOR Enhancing oil recovery helps mobilizing the capillary-trapped oil or rock-surfacetrapped oil in oil-wet formations, ultimately reducing the residual oil saturation Displacement efficiency improvement heavily depends upon capillary force and gravity (figure 1.1) Moreover, EOR methods also improve the swept efficiency of the injected fluid(s), especially in zones that are little-affected/unaffected during traditional waterflooding Enhance oil recovery manages to push oil out of pores and out of un-swept zones by injecting fluid(s) or changing the in-situ oil properties These mechanisms of EOR are defined and classified into microscopic and macroscopic displacement Both microscopic and macroscopic displacement efficiencies are affected by pore structure, reservoir fluids properties, injected fluid(s) properties, and flow of fluids in porous media Flow in Porous Media Stalkup (1983) devised the following formula to calculate the mobility ratio for injection Water-Alternating-Gas in presence of water and oil in the formation: M= Chat −day Chat −bi −day  Kg Kw    + ( g + w )   g  w  Swavg = = (o + w )  K o K w    +   o  w  Sowavg In which: M: WAG mobility ratio 𝜆𝑐ℎ𝑎𝑡−𝑑𝑎𝑦 : water-gas mobility ratio 𝜆𝑐ℎ𝑎𝑡−𝑏𝑖−𝑑𝑎𝑦 : water-oil mobility ratio Kw, Kg, Ko: water, permeability (mD) gas, and 1.2) oil( 𝜇𝑤 , 𝜇𝑔 , 𝜇𝑜 : water, gas, and oil viscosity (cP) Macroscopic and Microscopic Displacement Efficiency The topic of EOR mechanisms and associating phenomenon will be discussed in detail These phenomena mostly depend upon the flow of fluid through porous media and the nearby solid/liquid has great effect on the flow velocity As all oil reservoirs have both water and oil, research in two-phase flow is crucial The complex interactions between these two during flow, as well as rock-fluid interactions, have great impact on the residual saturations and the change in fluid composition during production Different macroscopic oil recovery mechanisms include immiscible, partially-miscible and fully-miscible Capillary pressure has the most impact on the fluid-fluid interfaces and is mainly responsible for the macro phase and micro phase in the producing fluid Oil recovered from pores by being displaced by other fluid(s) is called microscopic displacement efficiency (ED) On the other hand, macroscopic displacement efficiency or volumetric swept efficiency is the volume of in-situ fluids swept out of the porous media by the injected fluid(s) Volumetric swept efficiency (EV) comprises of two factors: areal swept efficiency (EA) and vertical swept efficiency Soi – Sor Ed = EA = Ev x EI Soi Areal swept efficiency (EA) is the ratio of the area of contact between the insitu/injected fluids and the area of the entire reservoir Different EOR Methods Based on the results of thousands of EOR projects implemented around the world, the projects’ reservoir conditions, reservoir properties, and location (onshore/offshore), the authors conclude that gas injection and chemical EOR are particularly suitable to the geological conditions, rock properties, fluid properties, and producing settings in the Vietnamese oilfields Chemical EOR is mostly applied for sedimentary formations and onshore reservoirs One main drawback of this EOR method is its difficulties when carry out in deep reservoirs (under high pressure, high temperature condition) or in offshore reservoirs This is due to the difficulties in manufacturing chemicals that can withstand temperature above 80oC and the chemical affinity of seawater/formation water Therefore, gas EOR, particularly the Water-Alternating-Gas method, is deemed to be most fitting Theoretical Background of Gas Injection in Oil Reservoirs In order to determine the right miscibility mechanism, the first concepts of miscibility condition(s) and main miscibility mechanisms need to be understood Figure 1.2 explains briefly how MMP is determined The author finds it appropriate to stay close to the real reservoir conditions and fluid properties often found in Vietnam throughout this research Fluid compositions vary with depth and reservoir pressures is usually higher than bubble point Therefore, MMP also changes with depth, resulting from fluid composition and pressure changes with depth Different injection gases also result in initial MMP, how it varies with depth, as well as the mechanism of miscibility Figure 1.2: Miscibility and Immiscibility Mechanics At this point, the injected gas help improve oil recovery by: oil vaporization, decrease oil viscosity, increase dissolved gas when pressure goes down, and decrease interfacial tension between phases The effectiveness of these mechanisms can be quantified through monitoring the dissolve of injected gas in reservoir oil, oil swelling coefficient, and decrease in oil viscosity There are several methods of determining MMP: through Slimtube experiment in the laboratory (based on recovery factor), or through numerical simulation packages Conclusions The laboratory setup to estimate MMP was built to simulate the temperature and pressure condition in the reservoir However, throughout the entire experiment, fluids inside the Slimtube were only subjected to unchanging reservoir conditions This setup was unable to simulate the changes in miscibility and immiscibility along the lateral and longitudinal direction The Slimtube experiment simply estimated MMP through closely monitoring the recovery factor as the experiment went on and the amount of oil/gas that did and did not underwent miscibility Fluid composition was also unchanged throughout the experiment, which was unrepresentative of what happens on the field To address these issues, the authors built a procedure to simulate and estimate the MMP using numerical method, one that could give a more accurate result to the sedimentary reservoirs found in Cuu Long basin Based on the statistics of EOR projects around the world and the analysis on the factors affecting these projects, Water-Alternating-Gas was found to be the most fitting method for the reservoirs of interest, given the rock, fluid, reservoir properties and their offshore condition To fill in the gaps in preceding works, both in Vietnam and on the world, the authors set the following research targets: ➢ Researching and selecting the best EOR method for Miocene reservoir, Su Tu Den field, Cuu Long basin ➢ Researching and building simulation models to accurately predict the MMP for gas injection EOR and comparing it to the predicted MMP from Slimtube experiment These models would also have a PVT and Slimtube displacement simulation ➢ Researching, evaluating, and selecting the optimal gas composition for injection in the Water-Alternating-Gas scheme ➢ Developing a reservoir simulation model and utilizing it to evaluate miscibility/nearmiscibility/immiscibility at reservoir conditions with factors like reservoir heterogeneity, saturation of oil/gas/water inside the reservoir, changes in pressure and temperature during production, changes in fluid composition during production and execution of the EOR project ➢ Exploring different EOR project options, optimizing and comparing economical gains between Water-Alternating-Gas injection scheme and other gas injection schemes ➢ Evaluating and proving that miscible/near-miscible gas injection was suitable for Miocene, given its geological structure, reservoir fluid properties, and rock properties ➢ Validating the capability of Water-Alternating-Gas injection project to maximize the additional oil recovery and the economic gains, using reservoir simulation CHAPTER 2: SELECTING THE OPTIMAL EOR METHOD FOR MIOCENE SU TU DEN Miocene Geological Properties The STD Oil field consists of three main objectives, that including: Fractured granite basement, Miocene (with pay zones B10, B9, B15) and Oligocene (C30) In which, pay zone B9 of miocene resevoir includes thin thickness, grain size from fine to medium, depositional environments range from distribulary channels to bay head delta deposits with associated crevasse splay and overbank deposits (Figure 2.1) B10 Miocene reservoir was discovered in wells SD - 1X, SD - 2X, SD -3X, SD - 4X, SD - 5X, SD - 6X The B10 interval is a 10-16m, and confirmed from results of log interpretation and results of welltest B10 is most potential in STD lower miocene for oil production Figure 2.1: Structural Map of B10 Miocen, Su Tu Den Figure 2.2: Oil-Water Relative Permeability Curves for Miocene Rock and Fluid Properties 2.2.1 Rock Properties of Lower Miocene Laboratory results for wettability, water/oil relative permeability, and rock compressibility showed overall good rock properties (porosity was about 30%, and average permeability was about 7,000 mD) Wettability was 0.18 and 0.28 for well SD-2X and SD3X, respectively Rock compressibility was gathered and measured from 23 samples Laboratory analysis showed typical compressibility value felt between 4.5 and 11.9 E-06 (psi-1) Relative permeability curves and oil saturation curve showed this was a good target for water injection (Figure 2.2) 2.2.2 Fluid Properties of Lower Miocene During the DST testing, reservoir fluid in one phase was taken from well SD-1x, SD2X, and SD-3X along with the oil and gas samples taken from the separators The main oil properties in the Lower Miocene were shown in table 2.1: Table 2.1: Oil Properties at Reservoir Condition Properties API Gravity Bubble Point (psia) GOR (scf/stb) Oil Formation Volume Factor Bo at Reservoir Pressure Pr = 2.500 psi Oil Viscosity at Reservoir Condition (cP) SD-1X 34,7 1.155 364 SD-2X 35,5 1.275 364 SD-3X 35,4 1.060 314 1,24 1,27 1,23 0,907 0,825 0,88 Oil in Place and Reserves Evaluation of reserves and oil in place and classification of reserve was done through volumetric calculation coupled with Monte-Carlo simulation 11 Reservoir Temperature (C) Depth (m) Oil Viscosity (cP) Oil Saturation (%) Permeability (mD) Reservoir Structure Production System 100 > 32 1.700-1.745 0,75-0,77 30 7.000 Closed Separation and treatment for gas > 650 > 0,1 > 25 >5 Closed Separation and treatment for gas Passed Passed Passed Passed Passed Passed Passed Su Tu Den’s rock and reservoir properties were also imported into specialized software to assess their impacts and contributions to the selection of the optimal EOR method The software’s recommendation is shown in figure 2.5 and figure 2.6 below Results pointed out that both chemical EOR and gas injection were suitable methods Immiscible gas injection had up to 83% success rate and chemical EOR (Surfactant, ASP, Micellar) had up to almost 100% success rate However, as pointed out earlier in this report, chemical methods would be subjected to many challenges when executing in Miocene’s conditions, given the high pressure, temperature, and chemical affinity of reservoir brine/injected water These factors would increase the project’s cost and risk, as chemicals might degrade rapidly From figure 2.6, it was also apparent that with reservoir temperature above 200oF (93oC), chemical injection was relatively risky In the case of Miocene Su Tu Den, average reservoir temperature was already 184oF (84oC), with zones of almost 200oF in temperature due to substantial thickness (almost 40m) Moreover, Su Tu Den was an offshore field, so the logistical complications of transporting chemicals for injection would also be a difficult problem to solve, especially when injecting polymer/surfactant needed to be continuous for an extended time Figure 2.5: EOR Screening Results from Specialized Software for Miocene Figure 2.6: EOR Selection Criteria from Specialized Software for Miocene Water-Alternating-Gas remained the most suitable EOR method for Miocene reservoir, Su Tu Den, at this time The injected gas would be sourced from producing gas of the same oil field One big advantage of Water-Alternating-Gas was that there existed an abundant supply of producing gas and natural gas in Su Tu Den and Su Tu Trang The 12 production network between these fields was all operated by the same operator, CLJOC, making it easy to divert and distribute the needed gas for Water-Alternating-Gas injection in Miocene CHAPTER 3: BUILDING A SIMULATION MODEL FOR PREDICTING AND OPTIMIZING WATER-ALTERNATING-GAS PERFORMANCE IN MIOCENE RESEVOUR, SU TU DEN Analyze and Evaluate MMP Experiment for Miocene Oil and Gas Sample Production gas from well SDSW and Slimtube experiment was designed as followed: - Sand pack length (m): 12.19; - Inner diameter (mm): 3.68; - Packing material: Quartz; Slimtube porosity: 37.10%; - Slimtube pore volume (PV, cm3): 80.41; - Slimtube permeability (mD): 6,000 - Injecting Pressure (psia): 8,000; 7,000; 6,000; 5,000; 4,000; 3,000 - Total volume of injected gas is 1.4 PV Figure 3.1: MMP Estimation Experimental Result with Different Injection Pressure Experimental results showed that miscibility could be achieved with injection pressure above 5,300 psia; below this point is near-miscibility and immiscibility This experiment setup could not simulate changes in miscibility/near- miscibility/immiscibility along the longitudinal or the cross-sectional direction of the Slimtube Fluid composition inside the Slimtube was also unchanged, which was not presentative of what would happen on the field The flow of fluid inside the Slimtube was also different from how it was inside the reservoir Permeability and porosity of the Slimtube setup, which was built from Quartz particles, were not of similar values to those found in the reservoir of interest, making the estimated MMP inaccurate In order to address these problems, the authors developed a numerical simulation model that could predict the MMP to a higher degree of accuracy, then applied it to the reservoirs of Cuu Long basin Built a PVT model for the reservoir fluids and injection gas of well SD-2X; Utilized the equations of state (EOS) and phase diagram of the reservoir fluids and injection gas of well SD-2X to estimate the MMP using specialized software; Developed a Slimtube numerical simulation for Miocene Su Tu den; Made necessary changes to optimize this MMP determination model for the best accuracy possible; 13 Validated the numerical model by cross-checking its estimated MMP from with that from Slimtube experiment; Utilized the Slimtube model and PVT model to evaluate different MMP of different injection gases at various pressures; Picked the optimal gas composition for injection and injection pressure and evaluate its efficiency on Miocene model Reservoir Fluids PVT Model and MMP Prediction Model 3.2.1 Reservoir Fluids PVT Model for Well SD-2X The PVT model reproduced experimental results under field pressure, temperature, and volume This process used equations of state to calculate and adjust the physical and chemical properties to match results from experiment 3.2.2 Utilizing EOS to Estimate MMP for Different Injection Gas Composition The miscibility mechanism of two phases is divided into the displacement part and the mixing part The condition for miscibility could be determined through a three-phase diagram with the assumption that properties of all three pseudo-component remained completely unchanged during mixing This assumption was one of the biggest weaknesses of basing our analysis on the three-phase diagram (figure 3.3) Figure 3.3: Three-Phase Diagram Figure 3.4 : STD Three-Phase Diagram Utilizing Miocene’s reservoir fluids and injection gas’ PVT model, equations of state, and phase diagram, MMP, FCM (First Contact Miscible), and MCM (Multiple Contact Miscible) were determined Figure 3.4 shows the three-phase diagram of Miocene oil with the dots being current temperature and pressure in the reservoir ➢ Scenario 1: using dry gas or commercial gas, simulation model showed FCM to be 7,340 psia and MCM to be 7,305 psia ➢ Scenario 2: using second stage separator gas, simulation model showed FCM to be 5,838 psia and MCM to be 5,542 psia ➢ Scenario 3: using first stage separator gas, simulation model showed FCM to be 4,758 14 psia and MCM to be 4,510 psia ➢ Scenario 4: using gas before entering the separator, simulation model showed FCM to be 3,991 psia and MCM to be 2,004 psia ➢ Scenario 5: using inert gases such as N2 or CO2, simulation model showed miscibility could not be achieved 3.2.3 Developing a Slimtube Simulation Model for Miocene Su Tu Den This Slimtube model was built in the form of grid blocks to simulate the injection of gas into the oil reservoir This model was designed to have its configurations and properties similar to those of the Slimtube in laboratory described above Initial condition for all grid blocks were set to reservoir pressure and temperature condition The oil and gas mixture in the first block would move and change its composition It would continue move to the next block and mix with the original oil there, before repeating the moving and mixing process again This would taken place repeatedly and continuously from the injector to the producer This model was able to address the drawbacks of the Slimtube experiment described earlier and to give a more accurate MMP prediction for Miocene oil and reservoir conditions, with different injection gases Slimtube simulation results Injection simulations were run at 184oF and pressure between 1,000 and 7,000 psia ➢ Case 1: using dry gas or commercial gas as injection gas, the simulation model predicted the oil recovery factor and MMP of approximately 6,000 psia ➢ Case 2: using second stage separator gas, the simulation model predicted the oil recovery factor and MMP of approximately 4,500 psia ➢ Case 3: using gas before entering the first stage of the separator, the simulation model predicted the oil recovery factor and MMP of approximately 2,500 psia This MMP value was quite similar to the reservoir pressure Figure 3.5: Oil Recovery from Slimtube Simulation for MMP Estimation of Case Figure 3.6: Oil Recovery from Slimtube Simulation for MMP Estimation of Case Figure 3.7: Oil Recovery from Slimtube Simulation for MMP Estimation of Case 15 The Slimtube simulation was able to distinguish between miscibility and nearmiscibility, from which an accurate MMP estimation in presence of flow and compositional changes could be achieved At the end of the displacement process, it was observed that after the mixing and displacing, the residual oil saturation inside the Slimtube was almost zero (0) For the displacement process without miscibility, residual oil saturation was about 0.2 ➢ Case 4: using inert gas such as N2 or CO2 as injection gas, simulation result showed no miscibility taken place at any pressure N2 injection into the reservoir would be an immiscible process Compare MMP from Different Prediction Methods Experimental MMP Table 3.1 Variation in MMP Estimation PVT Model MMP 1-D Slimtube Model MMP 5.300 psia Difference 7.350 psia 38.6 % 6.000 psia 13.2 % Estimation made utilizing laboratory Slimtube with porosity of 37.8% and reservoir oil and injection gas taken from well SDSW23P Error due to equation of state at static contact between the two phases Estimation made using oil and gas representative of the reservoir of interest (SD-2X) Variation due to changes made to porosity to a more consistent value with the actual reservoir, averaging about 30% Estimation made using oil and gas representative of the reservoir of interest (SD-2X) Results above proved that using simulation model to simulate Slimetube yielded accurate MMP estimation at reservoir conditions They also proved the effectiveness of miscible injection over near miscible or immiscible injection These results also pointed out the limitations of calculating MMP using only the PVT model More importantly, this work was able to validate the development and application of the numerical simulation model for the Slimtube, giving accurate MMP estimation for oil reservoirs with different injection gases, and fully applicable for Miocene Su Tu Den Selection of the Gas Source and Gas Injection Scheme for Miocene Su Tu Den From Slimtube simulation model runs, optimal usage of gas for injection was determined Based on Miocene’s pressure gradient with depth, porosity and permeability distribution, and MMP estimation from Slimtube model, the authors concluded that injecting hydrocarbon gas such as dry gas or enriched gas would not achieve miscibility, only nearmiscibility In order to improve the efficiency of gas injection for Miocene, WaterAlternating-Gas needed to be applied Water-Alternating-Gas would increase the downhole pressure of injection wells, bringing the reservoir oil and injection gas closer to miscible point Moreover, injecting water before and after injecting gas also hinders the rapid flow of gas, due to its low mobility factor, improving the swept efficiency of the injection process 16 Conclusions In this work, the authors explored and analyzed the difference in experimentally determined MMP, MMP calculated from analyzing PVT model, and MMP estimated by utilizing numerical simulation The advantages and disadvantage of estimating MMP experimentally were discussed in detail Factors negatively influenced its outcome included invariability of reservoir fluid composition and injection gas composition and Slimtube’s fluid composition Results showed that using Slimtube simulation model yielded more accurate MMP estimation, under the reservoir properties and conditions This simulation model was also validated and was ready to be applied to determine the MMP for various oil reservoirs in Vietnam with various injection gas compositions CHAPTER 4: APPLY WATER - ALTERNATING - GAS INJECTION FOR MIOCENE SU TU DEN SIMULATION MODEL Updating Simulation Model and History Matching Miocene reservoir simulation model had 114,626 grid blocks in total, and was last updated on 01/01/2015 Examining Miocene’s simulation model, the authors found it successfully met the criteria needed for utilization in this research History matching results for Miocene, Su Tu Den was shown in figure 4.1 Figure 4.1: Oil Saturation Distribution and History Matching Result This model was ready and reliable for converting to a compositional model for evaluation of different Water-Alternating-Gas injection schemes Converting from Black Oil Model to Compositional Model Black oil model was not able to simulate changes in fluid composition from this grid black to the next along the path from the injection well to the production well However, changes in reservoir fluid and injection gas composition would determine miscibility, near miscibility or immiscibility Compositional model could handle compositional and phase changes of reservoir oil and injection gas from which more accurately reflected the fluid mixture properties and fluid flow History matching results was shown above and 17 difference in volume of oil in place between black oil model and compositional model is less than 3% Analyzing Different Gas Injection Schemes and Sensitivity Analysis Based on current field status, well SD-16I was in the most optimal position among the injection wells to test gas injection and assess increase in oil recovery In order to evaluate how miscibility, near-miscibility, immiscibility, effectiveness of gas injection, effect of reservoir fluid properties, injection well location affect oil recovery, different injection and optimization schemes needed to be come up with and tested These different schemes are shown below in table 4.1 18 Table 4.1: Different Gas Injection Schemes and Sensitivity Analysis Water Injection Well Water injection case: injection water in well 27I and 16I Gas Injection Injection time Well 27I 16I Injecting Injecting Injecting Injecting Injecting Injecting Below Enriched Water CO2 N2 Dry Gas OWC Gas Pressure Injection Volume 2023 Reservoir 14000 bbl/day X X Scenario Gas injection case: inject gas in well 27I and water in well 16I Scenario Water-Alternating-Gas (WAG) injection case: inject water in well 27I inject gas-water alternatively in well 16I 27I 16I 2023 Reservoir 5MMscf/day X X X 27I 16I 2023 Reservoir 5MMscf/day X X X Scenario WAG injection at MMscf/d case at well 16I, water at well 27I WAG injection at 10 MMscf/d case at well 16I, water at well 27I WAG injection at 15 MMscf/d case at well 16I, water at well 27I 27I 16I years Reservoir 5MMscf/day X X X 27I 16I years Reservoir 10MMscf/day X X X 27I 16I years Reservoir 15MMscf/day X X X 27I 16I years Reservoir X X X Scenario WAG injection for years (5 MMscf/d) case at well 16I, water at well 27I 5MMscf/day 19 WAG injection for years (5 MMscf/d) case at well 16I, water at well 27I 27I 16I years Reservoir 5MMscf/day X X Water-Alternating-CO2 injection at MMscf/d case at well 16I, water at well 27I 27I 16I years Reservoir 5MMscf/day X X Water-Alternating-N2 injection at MMscf/d case at well 16I, water at well 27I 27I 16I years Reservoir 5MMscf/day X X Water-Alternating-Dry-Gas injection at MMscf/d case at well 16I, water at well 27I 27I 16I years Reservoir 5MMscf/day X X Water-Alternating-EnrichedGas injection at MMscf/d case at well 16I, water at well 27I 27I 16I years Reservoir 5MMscf/day X X X Scenario X X Scenario X X 20 4.3.1 Evaluation of Water Injection, Gas Injection, and Water-Alternating-Gas Injection - Base case water injection: inject water to maintain reservoir pressure for well SD-16I and SD-27I with injection rate of 14,000 barrels/day - Scenario 1: inject gas for the entire life of well SD-16I with injection rate of MMscf/day - Scenario 2: Inject gas and water alternatively in well SD-16I with months of gas injection (5 MMscf/day) alternating with months of water injection (40,000 barrels/day) Simulation models showed scenario yielded better incremental oil recovered, followed by gas injection then base case water injection Figure 4.2: Field Oil Recovery for Base Case, Case 1, Case Figure 4.3: Field Gas Production and Gas Cumulative Production for Case 3a, Case 3b, Case 3c 4.3.2 Evaluating and Selecting Optimal Gas and Water Injection Rate - Scenario 3a: WAG injection with gas rate at MMscf/day; - Scenario 3b: WAG injection with gas rate at 10 MMscf/day; - Scenario 3c: WAG injection with gas rate at 15 MMscf/day; Simulation results showed that highest oil recovery was achieved when injecting dry gas at MMscf/day, even though the amount of gas injected was the least This was due to WAG injection being near-miscibility, rendering higher gas injection rate (10 MMscf/day or 15 MMscf/day) unfavorable due to not enough time for the injected gas to come into contact and mix with oil Gas breakthrough was apparent, with gas production rate at the producer increased significantly at every gas injection cycle Under the MMscf/day gas injection scenario, it took one year for the gas to reach the production well, a part of which already mixed with the in-situ oil improving miscibility efficiency and ultimately oil recovery 4.3.3 Evaluating Water-Alternating-Gas Efficiency at Different Injection Time - Scenario 4a: WAG injection with gas rate of MMscf/day and 2-year injection time 21 - Scenario 4b: WAG injection with gas rate of MMscf/day and 3-year injection time Simulation results showed that the longer the injection time, the better the improved in ultimate oil recovery factor Scenario 4b was effective and should be applied for well SD16I Figure 4.4: Field Oil Production Rate and Cumulative Production for Case 4a, Case 4b Figure 4.5: Field Oil Production Rate and Cumulative Production for Case 5a, Case 5b, Case 5c 4.3.4 Evaluating Gas Injection at Miscibility/Near-Miscibility/Immiscibility - Scenario 5a: WAG injection using dry hydrocarbon gas; - Scenario 5b: WAG injection using CO2; - Scenario 5c: WAG injection using N2; Simulation results, shown in figure 4.7, showed injecting dry gas to be most effective, while injecting N2 or CO2 were quite similar in EOR performance Immiscibility of injecting N2 was clearly reflected in its EOR performance 4.3.5 Comparing Effectiveness of Injection Schemes with Different Injection Gases - Scenario 6a: WAG injection using dry hydrocarbon gas at rate of MMscf/day; - Scenario 6b: WAG injection using enriched gas at rate of MMscf/day; Simulation results showed injecting enriched gas yielded higher oil recovery compared to when injecting dry gas It was also observed that displacement efficiency of enriched gas was better than that of dry gas, given the same reservoir fluids and conditions Although both scenarios were injection under MMP, efficiency still differed 22 Figure 4.6: Field Gas Production Rate and Cumulative Gas Production for Case 6a, Case 6b Conclusions 12 sensitive cases, evaluating the effectiveness of Water-Alternating-Gas, gas injection at different rate or different composition methods were compared to each other and to traditional water injection Water injection would give relatively good ultimate oil recovery at 34.4% (at 02/2014, water injection recovered 26.5% of oil in place) and good swept efficiency Examining Miocene simulation model proved that it was favorable to apply miscible/near-miscible gas injection for EOR and that Water-Alternating-Gas was highly suitable to the reservoir/rock structure, properties and fluid properties of Miocene Su Tu Den Water-Alternating-Gas had the highest EOR potential, increasing ultimate oil recovery factor to about 36%, 2% to 5% higher than that of traditional water injection, and increasing total oil produced to about – MMbbl (depending on original oil in place) Moreover, this EOR scheme would also reduce water cut of production wells due to interruptive water injection and reduce the risk of abandon well due to high water cut One of the factors hindering EOR performance of gas injection and Water-AlternatingGas injection when applying to Miocene was the current injection wells In order to enhance oil recovery for Miocene Su Tu Den, one of the production wells needed to be converted to Water-Alternating-Gas injection well or one additional smart well needed to be drilled Numerical simulation results on Miocene Su Tu Den proved the effectiveness of partial-miscibility of gas injection into reservoir at pressure below MMP Results of optimizing Water-Alternating-Gas injection rate showed that best EOR performance could be achieved at MMscf/d Simulation model analyzing and evaluation verified that WaterAlternating-Gas was the most suitable EOR method for Miocene, Su Tu Den, both economically and technologically 23 CONCLUSIONS This research explored and evaluated the application of Water-Alternating-Gas injection for the reservoirs at Su Tu Den at near-miscibility It analyzed the different mechanisms of enhancing oil recovery and proved that Water-Alternating-Gas was the most suitable EOR method for the reservoir of interest and was capable of achieving from 2% to 5% incremental oil recovered compared to traditional waterflooding From the results presented above, the authors came to the following conclusions: Experimental setup and results to estimate MMP in laboratory setting was assessed The authors also addressed the limitations of MMP estimation in laboratory environment and by phase diagram by developing simulation model to calculate and estimate MMP numerically in a way that reflected as accurately as possible the field conditions found in Cuu Long basin This work pointed out the difference in MMP estimated through laboratory experiment, by using PVT model, and by utilizing Slimtube numerical simulation model Results proved that the simulation model worked as intended and was able to accurately predict MMP for oil reservoir and different injection gases, at reservoir conditions and properties This method also reduced the calculation error compared to that when using equation of state and phase diagram to predict MMP In this work, the authors evaluated the effects of geological structure, reservoir depth, reservoir temperature-pressure, reservoir fluid properties, injection gas properties, flow of fluid through the reservoir, optimization of injection process and injection gas composition, etc… on the effectiveness of EOR process This is coupled with evaluating the field condition and production history of Miocene, Su Tu Den Results showed that gas injection, especially Water-Alternating-Gas, to be the most fitting EOR method for Miocene, Su Tu Den Based on the evaluation and analytic of EOR projects around the world, the authors selected main criteria for Miocene to evaluate and select Water-Alternating-Gas as the EOR method of choice Both reservoir properties and production history of Miocene were in accordance with the criteria for a successful application of Water-Alternating-Gas The authors also built a compositional model to explore miscibility/near- miscibility/immiscibility of dry gas, enriched gas, CO2, and N2 injection Using this model, it was proven that Water-Alternating-Gas was the most optimal method and gave the most increase in ultimate oil recovery 12 cases of gas injection, Water-Alternating-Gas injection, or gas injection at different rates and different gas compositions were compared to each other and to traditional 24 waterflooding Results from Miocene simulation model study proved that: ➢ Application of Water-Alternating-Gas EOR method at near-miscible condition was appropriate given the reservoir structure and reservoir fluid/rock properties of Miocene, Su Tu Den at this stage Water-Alternating-Gas yielded the highest amount of incremental oil recovered, 2% higher than waterflooding, MMbbl of incremental oil, and reduced water cut for production wells during the reservoir’s final stages ➢ Improving ultimate recovery factor for Miocene with Water-Alternating-Gas required the conversion of an existing production well to an injection well or drilling of a new smart well into the central area of the reservoir Under this scenario, incremental oil recovery could be up to 3% – 7% higher than traditional waterflooding or only Water-Alternating-Gas injection through well SD-16I ➢ The effectiveness of partially-miscible gas injection with reservoir pressure under MMP was proven Results from optimization of injection rate using reservoir simulation model revealed gas injection rate of MMscf/d to be most optimal ➢ Injection of dry gas, N2, CO2, or enriched gas all gave better ultimate oil recovery than waterflooding did ➢ Simulation model study for Miocene reservoir showed Water-Alternating-Gas injection as EOR project for Miocene, Su Tu Den, was both economically and technically successful At the same time, results from this work could also be applied to other sedimentary target of similar conditions within the area 25 LIST OF PUBLISHED WORKS Trịnh Việt Thắng (1999) “Nghiên cứu áp dụng hệ dung dịch khoan gốc dầu cho mở vỉa sản phẩm mỏ Bạch Hổ” Giải khuyến khích – Vifotec, Tuyển tập Báo cáo - Quỹ tài trẻ Trịnh Việt Thắng, Nguyễn Mạnh Tuấn, (2008), “Ultradril - Hệ dung dịch khoan ức chế sét hiệu cao, nâng cao tốc độ khoan đạt hiệu kinh tế môi trường”, Tuyển tập báo cáo hội nghị KHCN Viện Dầu Khí Việt Nam: 30 năm Phát triển Hội nhập, tr 663-668 Trịnh Việt Thắng, Lê Xuân Lân (2011), “Đánh giá sơ khả áp dụng bơm ép khí nhằm gia tăng hệ số thu hồi dầu thềm lục địa Việt Nam”, Tạp chí Khoa học Kỹ thuật Mỏ Địa chất, Số 34/4/2011, tr 28-33 Trịnh Việt Thắng, Đoàn Văn Thuần nnk (2015), "Xây dựng sở liệu phần mềm quản lý hợp đồng dầu khí nước", Tạp chí dầu khí, số 5/2015, tr 66-72 Cơng trình đề nghị Giải thưởng khoa học cơng nghệ Dầu khí 2015: “Ứng dụng giải pháp khoa học công nghệ tiên tiến để nâng cao hiệu phát triển khai thác kết hợp với thăm dò mở rộng dự án Đại Hùng, Lô 05-1a, bể Nam Côn Sơn, thềm lục địa Việt Nam” Nhóm tác giả Triệu Hùng Trường, Trịnh Việt Thắng tác giả, “Nghiên cứu hoàn thiện công nghệ khoan thân nhánh giếng khai thác đường kính nhỏ bể Cửu Long nhằm tăng cường thu hồi dầu” Đề tài cấp Nhà nước mã số 14/HĐ-T.14.13/ĐMCNKK, Bộ Công Thương năm 2016 Trịnh Việt Thắng, Đỗ Thành Sỹ “Water Flooding Optimmization Using the Augmented Largrangian Method With Stocchastic Gardients” International Conference on Earth Sciences and Sustainable Geo-resources Development, ESASGD 2016 Đoàn Văn Thuần, Trịnh Việt Thắng nnk (2017), "Hệ thống tiêu chí đánh giá hoạt động nhà thầu/người điều hành Petronas số khuyến nghị quản lý hoạt động thăm dò khai thác dầu khí Việt Nam”, Tạp chí dầu khí, số 07/2018, tr 50-58 Trịnh Việt Thắng, Lê Thế Hùng, Đinh Đức Huy "Nghiên cứu ứng dụng công nghệ bơm ép luân phiên nước-khí nhằm nâng cao hệ số thu hồi dầu cho tầng chứa cát kết Mioxen hạ mỏ Sư Tử Đen Tây Nam, bể Cửu Long, thềm lục địa Việt Nam” Hội nghị toàn quốc Khoa học trái đất tài nguyên bền vững 2018 ... Tạp chí dầu khí, số 07/2018, tr 50-58 Trịnh Việt Thắng, Lê Thế Hùng, Đinh Đức Huy "Nghiên cứu ứng dụng cơng nghệ bơm ép ln phiên nước- khí nhằm nâng cao hệ số thu hồi dầu cho tầng chứa cát kết... hợp đồng dầu khí nước" , Tạp chí dầu khí, số 5/2015, tr 66-72 Cơng trình đề nghị Giải thưởng khoa học cơng nghệ Dầu khí 2015: Ứng dụng giải pháp khoa học công nghệ tiên tiến để nâng cao hiệu... “Đánh giá sơ khả áp dụng bơm ép khí nhằm gia tăng hệ số thu hồi dầu thềm lục địa Việt Nam”, Tạp chí Khoa học Kỹ thu t Mỏ Địa chất, Số 34/4/2011, tr 28-33 Trịnh Việt Thắng, Đoàn Văn Thu n nnk (2015),