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Results
Abstract Habur Project will be the second fractured carbonate reservoir using Thermally Assisted Gas Oil Gravity Drainage (TAGOGD) recovery mechanism in Northern Oman. ESPs are selected to provide artificial lift ahead of gas lift to reduce Capex, lower power consumption and to increase well lifting potential. This paper summarizes the approach used to mitigate risks in the deployment of thermal ESPs in potentially extreme corrosive (high H2S and CO2) operating conditions. The ESP operating environment is predicted to be challenging due to a unique combination of conditions: i) high temperature (> 150degC), ii) high free gas/steam production, iii) corrosive with high H2S/CO2. These challenges pose a risk that the pumps are not able to achieve required functionality and/or have a short lifespan. Front-end integrated mitigation plan of the above has been constructed based on i) internal and external ESP performance benchmarking, ii) early detailed "bespoke" thermal ESP design options, iii) initial operating procedures and iv) troubleshooting guidance. Additionally, the project economic robustness was tested against different ESP run life scenarios. Thermal ESPs are a mature artificial lift method with local and global deployment in hot environments such as Steam Assisted Gravity Drainage (SAGD) systems. If steam breakthrough is not appropriately managed, it can result in low pump efficiency or gas lock in some cases which has a negative impact on production. Experience from SAGD in Canada indicates that with proper ESP design and appropriate trouble shooting procedures, risks related to gas and steam breakthrough can be managed. Corrosion can lead to premature ESP failure. Habur Project is predicted to become sour as the rock and reservoir fluids heat up releasing significant CO2 and H2S. However, the risk of corrosion can be mitigated by appropriate material selection of ESP components. Expensive metallurgy raises the cost of pump deployment, but economic analysis shows the project to be robust even in the scenario of short ESP lifespans. This project demonstrates how through benchmarking, multidiscipline integration and early collaboration with ESP service providers supported maturation of a robust ESP design to support project Final Investment Decision. Importantly this work expands the operating conditions of thermal ESPs beyond typical clastic SAGD such as Canada to more corrosive environments expected in carbonate steam developments. Novel workflows described in this paper can be adapted to other challenging high temperature and corrosive fields using TAGOGD or other thermal recovery methods.
- Asia > Middle East > Oman (1.00)
- North America > Canada > Alberta > Athabasca Oil Sands (0.47)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government (0.46)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Surmont Field (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Orion Oil Sands Project (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Leismer Oil Sands Project (0.99)
- (5 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
Steam Trap Management Re(de)fined
Palani, Ilayaraja (Saudi Aramco, Jazan, Western Province, Saudi Arabia) | Wassly, Abdulrahman Q (Saudi Aramco, Jazan, Western Province, Saudi Arabia) | Alnashry, Faris A (Saudi Aramco, Jazan, Western Province, Saudi Arabia) | Sharahely, Fayez H (Saudi Aramco, Jazan, Western Province, Saudi Arabia) | Alruzayhi, Turki F (Saudi Aramco, Jazan, Western Province, Saudi Arabia)
Body steam trap management is one of the key programs in energy management. Considerable amount of steam as energy and water as condensate is lost through failed traps. In a well-maintained steam distribution system distribution loss of 5% is acceptable and losses increase drastically to 10 to 15 % in a poorly maintained system. Trap population is a mix of different types of traps such as thermodynamic or disc type, bimetallic, inverted bucket, float, and thermostatic. Though the professional fraternity as well as management agrees that significant contribution of losses is due to failure of thermodynamics traps where failure rates are as high as 40%, only few companies acted to adopt alternate trap types and reduce the failure rate. Very few have leveraged technology to detect failure as well as diagnose type of failure. Millions of dollars need to be invested in online trap management systems and fear of uncertainty overwhelmed sound engineering judgement to adopt alternate traps over conventional thermodynamic traps. This prevented addressing the perennial issue of steam loss through traps. 10% loss has become the acceptable norm. This paper discusses current conditions at field based on survey, alternates to disc traps, failure rate reduction after replacing disc traps, strategy to manage traps, and overall net benefits. Steam trap management program was revisited using extensive field survey data, analyzing types of traps based on application and steam pressure levels. Trap failure rate matrix was developed based on type and pressure levels. Condensate recovery was used to measure or determine the effectiveness of disc type trap replacement. A strategy was developed to maximize condensate recovery with optimized investment. This helped to prioritize areas where disc type traps are to be replaced with suitable alternate types and yield desired results. Actual failure rate comparison was made before and after disc type trap replacement. Condensate recovery improved from 85 to over 92%. It is expected to reach 97%, if all disc type traps are replaced. Failure rate of traps are expected to maintain around 3%.
- Management (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
Sensitivity Analysis of Diffusion-Based Hydrocarbon Gas Huff-n-Puff Injection in Eagle Ford Shale
Fu, Q. (Chemical and Petroleum Engineering, University of Kansas, Lawrence, Kansas, United States) | Tsau, J. S. (Chemical and Petroleum Engineering, University of Kansas, Lawrence, Kansas, United States) | Mohrbacher, D. (Chemical and Petroleum Engineering, University of Kansas, Lawrence, Kansas, United States) | Zaghloul, J. (Continental Resources, Oklahoma City, Oklahoma, United States) | Baldwin, A. (Devon Energy, Oklahoma City, Oklahoma, United States) | Alhajeri, M. (Public Authority for Applied Education and Training PAAET, Al Asimah, Kuwait) | Barati, R. (Chemical and Petroleum Engineering, University of Kansas, Lawrence, Kansas, United States)
Abstract The utilization of hydrocarbon gas in enhanced oil recovery (EOR) processes offers two significant advantages: an increase in the recovery factor and a reduction in net emissions. Through core-scale experimental and numerical investigations, effective diffusion coefficients for single-phase and cross-phase behavior were determined by Fu et al. (2021), enabling their application in larger-scale predictions. [1] The primary objectives of this study are to 1) better understand the impact of upscaling from core-scale to field-scale simulations; 2) verify the effect of diffusion mechanism during huff-n-puff by history matching a model for a single well pilot; and 3) conduct a comprehensive sensitivity analysis and optimization of the recovery factor for huff-n-puff schedule, taking into account fracture spacing and injection-production patterns in both the dead and live oil windows of the Eagle Ford formation. The fluids in place in the Eagle Ford shale show a wide range of GORs, with hydrocarbon maturities ranging from black oil to lean gas condensates, [2] therefore, both live and dead oil regions are investigated in this study. Two compositional models, incorporating dual porosity and dual permeability characteristics, were constructed using the Petrel software. The first model replicated a huff-n-puff field pilot study reported by Orozco et al. (2020) in the Eagle Ford [3] and consisted of one well with the well length of 6,240 ft and 26 hydraulic fracture stages. The second model encompassed a single stage of eleven horizontal wells, designed according to the field blueprint reported by Baldwin et al. (2020). [4] Within this model, six wells were allocated for injection and production during the huff-n-puff cycles, four were used as containment wells, and one functioned as a monitoring well at the center of all eleven wells. The well spacing was set at 1000 ft, with the first stage of each well measuring 220 ft in length, and each well containing 10 hydraulic fractures. These fractures were spaced 20 ft apart (cluster spacing), with a height of 100 ft, and a half-length of 500 ft. Once the pilot well's primary and huff-n-puff oil production rate was history matched, the same reservoir properties, including matrix and natural-fracture porosity, permeability, natural fracture spacing, and relative permeability, were applied to the eleven-well model. Both models employed history-matched effective diffusion coefficients and a tuned equation of state fluid model to fluid samples collected and analyzed for the Eagle Ford formation. [5, 1] Results show that models including the diffusion mechanism had a 2.2% higher oil recovery factor compared to those that did not include diffusion after five cycles of huff-n-puff. The sensitivity analysis on hydraulic fracture spacing showed that smaller fracture spacing creates larger contact surface area between the matrix and fracture, promoting the diffusion mechanism and facilitating higher oil recoveries. The sensitivity analysis also revealed that depletion level on the producer before starting Huff n Puff also had an impact on recovery efficiency. Producing a well on primary production for 6 years and then implementing huff-n-puff yielded the most oil cumulative produced. If the huff-n-puff cycle was delayed to 10 years after initial production, cumulative values were lower than at the 6-year mark due to depletion effects and difficulties in re-pressurizing the formation. The sensitivity analysis on the "puff" production period suggested that longer production times delayed the speed of oil production, but resulted in higher oil production after completing six cycles of huff-n-puff. Further sensitivity analysis on the length of the soaking period suggested that longer soaking times delayed oil production and did not contribute significantly to oil production. These parametersโ effects on cumulative oil production and reservoir pressure were analyzed to determine the optimal approach for field application. Investigations on using different injection gases such as CO2, y-grade, and lean gas for dead oil and live oil systems rank the best injectants for maximizing oil production in the following order: y-grade > CO2 โ hydrocarbon gas > lean gas. The findings of this study provide a deeper understanding of upscaling considerations and offer recommendations for huff-n-puff pilot designs in the Eagle Ford formation.
- North America > United States > Texas (1.00)
- Europe > United Kingdom > North Sea > Central North Sea (0.24)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.73)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (5 more...)
Perspectives of Hydrogen Peroxide Injection to the Carbonate Reservoir for ISC Initiation
Askarova, A. G. (LLC, LABADVANCE, Moscow, Russia) | Maerle, K. V. (Center for Petroleum Science and Engineering, Skolkovo Institute of Science and Technology, Moscow, Russia) | Popov, E. Y. (Center for Petroleum Science and Engineering, Skolkovo Institute of Science and Technology, Moscow, Russia) | Malaniy, S. E. (LLC, Lukoil Engineering, Moscow, Russia) | Grishin, P. A. (Center for Petroleum Science and Engineering, Skolkovo Institute of Science and Technology, Moscow, Russia) | Slavkina, O. V. (LLC, Lukoil Engineering, Moscow, Russia) | Cheremisin, A. N. (Surgut State University, Surgut, Russia)
Abstract As part of laboratory and numerical investigations, an assessment of hydrogen peroxide (H2O2) injection efficiency was performed to estimate the ability of H2O2 to increase the productivity of heavy oil field development. The combined effect can be observed, including heat release due to H2O2 decomposition and oxidative reactions with oil during the in situ combustion (ISC) process and increased oil mobility due to CO2 dissolution. Laboratory experiments were performed on an autoclave to study the decomposition of peroxide in conditions close to the reservoir (pressure and temperature) and obtain experimental values of the kinetic parameters of the H2O2 decomposition reaction. Further, these values and experimental parameters were integrated into a homogenous numerical model representing the target oil reservoir. Also, during the laboratory experiment, the optimal value of the H2O2 concentration was determined for subsequent sensitivity analysis. The numerical model was then used to build a Tornado diagram and to estimate the effects of preheating, operational parameters, reservoir properties and kinetic parameters with or without catalysts in the system. According to the results of the hydrodynamic modeling, efficient heating of the formation to high temperatures (over 100ยฐC) during the injection and decomposition of H2O2 is possible only in the presence of a catalyst. The bottomhole formation zone temperature with a catalyst can reach up to 350ยฐC. The most significant influence on the cumulative production is provided by the injection rate, reservoir permeability, initial temperature of the injecting fluid, as well as the thermal properties of the rock. When the temperature reaches 300ยฐC, the reaction of peroxide decomposition begins to accompany the ISC of oil, which is self-initiated, since there is a sufficient amount of oxygen in the formation formed during the decomposition of H2O2. An effective application of the technology is possible during a sufficiently fast rate of the peroxide decomposition to avoid the dissipation of the released heat due to two possible mechanisms: heating (up to ~150ยฐะก) of injected agent (effective, but it is associated with additional costs for equipment and technological risks); use of widely available and cheap catalysts. As a result of the work, the most promising strategies of H2O2 injection technology for heating a carbonate reservoir were identified. The option of full-scale injection of the H2O2 is associated with high costs and limited development rates. This method can be applied to objects with specific conditions of elevated temperatures where the peroxide decomposition reaction will be the most active.
- Europe (0.47)
- Asia (0.47)
- North America > Canada (0.28)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock (0.93)
- Asia > Russia > West Siberian Basin > Bazhenov Formation (0.99)
- Europe > Russia > Volga Federal District > Samara Oblast > Volga Urals Basin > Zhigulev-Orenburg Arch > Dmitriyevskoye Field (0.97)
Abstract Mukhaizna is a heavy oil field in southern Oman operated by Oxy. It is a multi-stacked reservoir under steamflood since 2007. The main sandstone reservoirs were developed using horizontal producers in each target zone supported by vertical injectors. Although most of the patterns are thermally mature, a few areas are still awaiting steamflood response. Hence, different options were evaluated across the field to help establishing thermal processing in areas with such a delay in steam response. One of the options considered and trialed was a Steam-Assisted Gravity Drainage (SAGD) in a pattern with two horizontal producers (HPs) originally drilled within the same zone. The subject pattern is characterized with thin, discontinuous shale baffles that have limited the communication between the upper producer and the supporting injectors. Therefore, a modified SAGD configuration that involved converting the upper producer as an injector was considered to help sweeping the remaining oil in the upper sand. Additionally, analog SAGD projects were also evaluated to increase the chance of success although the target reservoir is not ideal for typical SAGD. As this pattern was originally supported by a continuous steamflood, the same was continued to avoid any change in operating conditions around the SAGD trial. As a result, liquid production rate gradually increased from the lower producer after converting the upper producer into steam injection associated with increase in water cut initially. However, oil rate started to improve with a continuous increase in pumping speed. Salinity test of produced water showed significant increase over the expected level of condensed steam which could be attributed to either water encroachment from edge aquifer or high TDS in the injected low steam quality hot water. Nevertheless, the lag in oil response suggests most of the incremental oil resulted from the initiation of the SAGD trial that has changed the pressure dynamics in the reservoir and provided additional mean to deliver some heat and displacement forces to unswept areas although steam chamber was most likely not developed due to the low steam quality of injected steam. This paper describes the potential, challenges, and opportunities of using a modified SAGD configuration in Mukhaizna heavy oil field in sub-optimum operating conditions for SAGD projects in terms of depth, thickness, patterns, and well configuration.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.35)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- Asia > Middle East > Oman > South Oman > South Oman Salt Basin > Gharif Formation (0.99)
- Asia > Middle East > Oman > Al Wusta Governorate > South Oman Salt Basin > Mukhaizna Field (0.99)
Abstract Most Surmont SAGD producer wells are drilled and completed to accommodate 500 series ESPs. However, as reservoirs age, downhole completion failures occur more frequently, such as intermediate casing deformation. These failures usually lead to smaller downhole diameter drifts, which in turn require the use of smaller diameter 400 series ESPs (a.k.a., "slim hole" SAGD ESPs) in wells that otherwise would have continued to be better suited for the originally planned larger size ESP. This paper presents a comprehensive review of the reliability performance of 400 series ESPs installed at Surmont in the last few years. Analysis of fifty-nine 400 series ESP installations shows that while their reliability is lower than that of larger diameter ESPs, 400 series ESPs do provide an attractive solution to lifting in wells with smaller intermediate casing clearance. Main failure modes and how they relate to operating conditions are discussed. Finally, recommendations measures to improve 400 series equipment reliability performance are addressed.
- Research Report (0.46)
- Overview (0.34)
- Well Drilling (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
Improving ESP Survivability in the SAGD Environment: An Integrated Approach to Managing ESP Performance in Challenging Conditions
Joseph, Rejish (Suncor Energy Inc., Calgary, Alberta, Canada) | Babatunde, TK (Suncor Energy Inc., Calgary, Alberta, Canada) | Briceno, Lisett (Suncor Energy Inc., Calgary, Alberta, Canada) | Gaviria, Fernando (Suncor Energy Inc., Calgary, Alberta, Canada) | Plaxton, Bill (Suncor Energy Inc., Calgary, Alberta, Canada)
Summary Firebag SAGD (Steam Assisted Gravity Drainage) asset has shown steady growth in well count, with ESPs (Electric Submersible pumps) as the primary mode of lift. In the high temperature environment, robust design and material selections are important considerations to achieve long run lives. However, key constraints such as economic conditions, increasing well count and changing well performance require solutions that optimize cost and reliability. This is critical to offering flexibility in approaches to addressing the top failure modes of the ESPs at Firebag. The paper discusses Suncor's efforts to prioritize not only prevention, but also management of the key failure modes to optimize reliability and cost in the SAGD environment by developing a better understanding of the problem. This includes novel approaches to treat an installed ESP as a repairable system through cable-only replacement (non-serviced motor reruns) and re-landing an ESP as-is when a cable failure is located close to the surface. Risk mitigation is done primarily through data analysis of teardown information and statistical survivability rates at both the system and sub-component level. This risk mitigation includes building the foundation for information gathering through a clear teardown process on every ESP pulled from service, gaining insights on failures, challenging traditional assumptions based on the data obtained, and driving focused trials and initiatives.
- North America > United States (0.94)
- North America > Canada > Alberta (0.28)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
Thermal and Hydraulic Performance Testing of a Novel High Temperature ESP System for SAGD under Real Conditions
Klaczek, W. (C-FER Technologies, Edmonton, Alberta, Canada) | Robles, J. (C-FER Technologies, Edmonton, Alberta, Canada) | Stewart, J. (Summit ESPยฎ a Halliburton Company, Houston, Texas, USA) | Kopecky, T. (Summit ESPยฎ a Halliburton Company, Tulsa, Oklahoma, USA) | Frey, J. (Summit ESPยฎ a Halliburton Company, Tulsa, Oklahoma, USA) | Webster, J. (Summit ESPยฎ a Halliburton Company, Tulsa, Oklahoma, USA)
Abstract It has been about 10 years since High Temperature Electrical Submersible Pumps (HT ESPs) were first deployed at downhole temperatures of 250ยฐC (482ยฐF). Since then, these pumps have become one of the most popular forms of artificial lift for most Steam Assisted Gravity Drainage (SAGD) producers. Despite this popularity, the severity of the operating conditions in SAGD wells continues to present challenges to the development of new HT ESP technology. A Joint Industry Project (JIP) of major thermal operators commissioned this research to evaluate the performance of some novel HT ESP technology that was developed by Summit ESP a Halliburton Company. This novel HT ESP technology was specifically designed to operate in a SAGD environment. This paper describes the full-scale testing that was independently conducted by the JIP on this HT ESP technology using a specialized high temperature flow loop at C-FER. Testing was completed to better understand the performance and reliability of this novel HT ESP technology over a wide range of representative SAGD conditions. The program included several diverse tests conducted at fluid temperatures up to 250ยฐC (482ยฐF). This included a wide range of operating conditions, including low levels of sub cool and different multiphase fluid combinations with oil, water, gas, and steam. As noted in past experimental work conducted on HT ESPs by Waldner et al. (2012), understanding the thermal profile of the ESP system (specifically the motor) as well as the effect of multiphase flow conditions on motor heat dissipation and pump hydraulic performance when operating in a SAGD wellbore are key considerations when assessing ESP systems. For this reason, additional downhole instruments were installed to monitor the temperature profile of the ESP system in the wellbore during this test. The experimental setup also included internal pressure monitoring of the ESP motor oil volume compensation system to carefully observe the interactions between the wellbore environment and ESP system performance. This paper presents an overview of the test objectives, the experimental setup (including the instrumentation), the HT ESP system, as well as a selection of key laboratory test results. Collectively this paper provides insight into the test methodology and performance of this new HT ESP under various conditions representative of a SAGD wellbore in the field. Technical Categories: ESP Thermal Operations, New ESP Technologies
- North America > United States > Texas (0.71)
- Asia (0.68)
- North America > Canada > Alberta (0.47)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-7 > Peregrino Heavy Field (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-47 > Peregrino Heavy Field (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
CO2 Huff and Puff Injection Operation Overview in Jatibarang Field Lessons Learned from a Successful Case Study in Mature Oil Field
Halinda, D. (PT Pertamina, Persero) | Zariat, A. Az (PT Pertamina EP) | Muraza, O. (PT Pertamina, Persero) | Marteighianti, M. (PT Pertamina, Persero) | Setyawan, W. (PT Pertamina, Persero) | Haribowo, A. (PT Pertamina EP) | Rajab, M. (PT Pertamina EP) | Firmansyah, M. (PT Pertamina EP) | Hasan, I. (PT Pertamina EP) | Nurlia, D. (PT Pertamina EP) | Adham, A. (PT Pertamina EP) | Prabowo, P. (PT Pertamina EP) | Okabe, H. (JOGMEC) | Mikami, K. (JOGMEC) | Kento, K. (JOGMEC) | Susanta, P. (NESR Indonesia) | Palupi, A. S. (NESR Indonesia)
Abstract The objective of this paper is to provide an overview of the CO2 Huff and Puff injection operation in the mature Jatibarang field, Indonesia, and share the lessons learned from a successful case study. The scope of this paper includes the project preparation, implementation, and troubleshooting. The aim is to provide insights into the key factors that contributed to the success of the project and to identify potential challenges and their solutions. The paper will present a comprehensive review of the CO2 Huff and Puff injection process, start from the design of the injection plan and the monitoring and evaluation of the injection process. The methods, procedures, and process used in the project will be discussed, including the selection of candidate wells, the injectivity test, the CO2 injection rate, and the well performance evaluation. The paper will also highlight the challenges faced during the implementation of the project and the solutions adopted. The results of the CO2 Huff and Puff injection operation in the Jatibarang field are promising, with an oil production rate increase of up to 86% with minimum operational difficulties. The successful implementation of CO2 Huff and Puff injection operation in Jatibarang Field was mainly attributed to the good operation procedure that prioritized safety and efficiency. With careful planning and intensive discussion conducted to identify potential risks and minimize operational difficulties, the operation was able to run smoothly, with minimal issues and zero HSE incidents. One of the key challenges that CO2 injection operations usually face is the risk of pipe blockage due to CO2 freezing. Fortunately, no such incidents occurred during the operation. Continuous monitoring of the injection process and fluid properties managed to ensure that the CO2 remained in gas phase in surface and supercritical state in the bottom hole throughout the operation. In conclusion, the success of the CO2 Huff and Puff injection operation in Jatibarang Field was due to the careful preparation and execution of a well-designed operation procedure. The operation demonstrated that with the right approach, the potential risks and challenges associated with the project can be mitigated. This paper will present novel information on the implementation of CO2 Huff and Puff injection in a mature oil field in Indonesia. The lessons learned and the best practices identified in this project can be of benefit to the petroleum industry, particularly for those dealing with mature oil fields. The paper will also provide insights into the design of the injection plan and the monitoring and evaluation of the injection process, which can be useful for future CO2 Huff and Puff injection projects.
- Asia > Indonesia > Java > Subang Field (0.99)
- Asia > Indonesia > Java > Northwest Java Basin > Jatibarang Field > Talang Akar Formation (0.99)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (2 more...)
Abstract The implementation of cyclic gas injection, commonly known as huff-n-puff, holds significant promise in augmenting hydrocarbon recovery from shale oil reservoirs and addressing condensate blockage in liquid-rich shale formations. The effectiveness of huff-n-puff, however, depends greatly on the composition of both the reservoir fluid and the injected gas. Particularly in ultratight shale reservoirs, where diffusion and sorption play pivotal roles, a precise understanding of their influence on huff-n-puff performance becomes crucial for accurate predictions of oil recovery and solvent retention. To thoroughly assess the huff-n-puff process in shale reservoirs, we conducted extensive large-scale numerical simulations using a dual-porosity naturally fractured compositional model that incorporates molecular diffusion and sorption mechanisms. The Langmuir's adsorption model was employed to account for adsorption effects within the system. Rigorous grid block sensitivity analysis was performed to minimize numerical errors and enhance simulation accuracy. By evaluating the impact of diffusion and sorption on production performance for different fluid and injection gas combinations, we established correlations between the considered characteristics and the huff-n-puff performance. To conduct this evaluation, we selected the Eagle Ford Formation, a highly developed shale with a wide range of pressure-volume-temperature (PVT) windows, from dry gas to black oil. The simulation outcomes revealed that methane (CH4) and cyclic-produced gas exhibited the highest recovery potential, while carbon dioxide (CO2) yielded the lowest production results. The performance of the solvent was notably influenced by the content of light components in the fluid and the gas-oil ratio (GOR). Neglecting molecular diffusion, especially during the soaking period, led to underestimation of recovery factors, whereas disregarding the adsorption effect resulted in overestimation of recovery. Furthermore, we observed that the adsorption of intermediate components on the surface of organic pores in shale gas condensate effectively pushed condensate out of the pores, mitigating condensate blockage around the wellbore. This work aims to provide further insights into the huff-n-puff performance in shale reservoirs by focusing on the reservoir fluid and injection gas compositions. The results of this work will improve our understanding of the relationship between fluid compositions and diffusion and sorption. Furthermore, our findings provide insights into the optimization of the huff-n-puff process in shale reservoirs.
- North America > United States > Texas (0.67)
- North America > Canada > Alberta (0.46)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (5 more...)