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Collaborating Authors
Thermal methods
ABSTRACT We compare microseismic observations against pumping information, landing heights, and various well logs. The data were acquired during cyclic-steam injection between September 2002 and December 2005. Ninety-five percent of the microseismicity occurred during injection and in the overburden; 70% of the events happened during the first cycle. Microseismicity in the overburden is likely caused by a greater brittleness than in the reservoir and a cluster of microseismic events in regions with a smaller landing height, thereby facilitating dry cracking due to the volumetric expansion of the reservoir. Yet, other areas with equally shallow landing heights displayed little to no microseismicity, pointing to an inhomogeneous steam front. Furthermore, recorded microseismicity is subject to the Kaiser effect in that event rates are low in subsequent cycles until the current injection pressure exceeds the previous maximum, explaining why 70% of the events occurred during the first cycle and possibly why microseismicity during production accounted for only 5%. Microseismicity in brittle formations can be caused by pore-pressure variations (wet cracking) and/or changes in the total stresses (dry cracking). Identification of pore-pressure variations in the overburden is important because it may indicate containment challenges. Analysis of the growth rate of the microseismic cloud combined with the shallow landing height indicated dry cracking to be more likely than wet cracking but analysis of additional data is required to strengthen this conclusion.
- North America > Canada > Alberta (1.00)
- Europe (0.93)
- North America > Canada > British Columbia (0.68)
- Geology > Sedimentary Geology (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.46)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Greater Peace River High Basin > Debolt Formation (0.99)
- North America > Canada > British Columbia > Peace River Field (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
ABSTRACT We compare microseismic observations against pumping information, landing heights, and various well logs. The data were acquired during cyclic-steam injection between September 2002 and December 2005. Ninety-five percent of the microseismicity occurred during injection and in the overburden; 70% of the events happened during the first cycle. Microseismicity in the overburden is likely caused by a greater brittleness than in the reservoir and a cluster of microseismic events in regions with a smaller landing height, thereby facilitating dry cracking due to the volumetric expansion of the reservoir. Yet, other areas with equally shallow landing heights displayed little to no microseismicity, pointing to an inhomogeneous steam front. Furthermore, recorded microseismicity is subject to the Kaiser effect in that event rates are low in subsequent cycles until the current injection pressure exceeds the previous maximum, explaining why 70% of the events occurred during the first cycle and possibly why microseismicity during production accounted for only 5%. Microseismicity in brittle formations can be caused by pore-pressure variations (wet cracking) and/or changes in the total stresses (dry cracking). Identification of pore-pressure variations in the overburden is important because it may indicate containment challenges. Analysis of the growth rate of the microseismic cloud combined with the shallow landing height indicated dry cracking to be more likely than wet cracking but analysis of additional data is required to strengthen this conclusion.
- North America > Canada > Alberta (1.00)
- Europe (0.93)
- North America > Canada > British Columbia (0.68)
- Geology > Sedimentary Geology (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.46)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Greater Peace River High Basin > Debolt Formation (0.99)
- North America > Canada > British Columbia > Peace River Field (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
We compare microseismic observations against pumping information, landing heights and various well logs. The data were acquired during cyclic-steam injection between September 2002 and December 2005. 95% of the microseismicity occurred during injection and in the overburden; 70% of the events happened during the first cycle. Microseismicity in the overburden is likely caused by its higher brittleness than in the reservoir, cluster of microseismic events in regions with a smaller landing height, thereby facilitating dry cracking due to the volumetric expansion of the reservoir. Yet, other areas with equally shallow landing heights displayed little to no microseismicity, pointing to an inhomogeneous steam front. Furthermore, recorded microseismicity is subject to the Kaiser effect in that event rates are low in subsequent cycles until the current injection pressure exceeds the previous maximum, explaining why 70% of the events occurred during the first cycle, and possibly why microseismicity during production accounted for only 5%. Microseismicity in brittle formations can be caused by pore-pressure variations (wet cracking) and/or changes in the total stresses (dry cracking). Identification of pore-pressure variations in the overburden is important since it may indicate containment challenges. Analysis of the growth rate of the microseismic cloud combined with the shallow landing height indicated dry cracking to be more likely than wet cracking but analysis of additional data is required to strengthen this conclusion.
- North America > Canada > Alberta (1.00)
- Europe (0.93)
- North America > Canada > British Columbia (0.67)
- Geology > Sedimentary Geology (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.46)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
Summary Since the late 1980s, when the Alberta Oil Sands Technology and Research Authority Underground Test Facility project first demonstrated the feasibility of the steam-assisted gravity drainage (SAGD) technology, many commercial SAGD projects were brought online in Western Canada. Now, many of these projects have late-life SAGD wells approaching their ultimate SAGD recovery factors. Although these projects have demonstrated highly variable production performance, there is an opportunity to use the industry production data to find what they have in common and develop a normalized SAGD model. For this paper, we collected oil production history from several leading SAGD projects with late-life production in the Athabasca oil sands area and confirmed the three stages in an SAGD project lifespan: chamber rising, chamber spreading, and chamber falling stages. By normalizing the field data, all SAGD projects converged to one type curve, regardless of reservoir quality and operating conditions. Based on this observation, a new simple normalized model is derived to model the bitumen production in a typical SAGD process for Athabasca oil sands. The new model bridges the gap between the existing SAGD analytical model and conventional decline analysis and provides oil production forecasts based on the inputs for the five-component recovery factor method defined in the Canadian Oil and Gas Evaluation Handbook(Society of Petroleum Evaluation Engineers 2018). The model has been applied to one of the thermal projects to history match the field production. By running a Monte Carlo simulation, this model further demonstrates its capability to capture the uncertainty of the production forecast for the project at different stages of SAGD operation. In addition, by properly modifying the type curve of the analytical model, a similar workflow can be used to model cases with special reservoir quality or different operational limitations.
In-situ combustion processes are largely a function of oil composition and rock mineralogy. The extent and nature of the chemical reactions between crude oil and injected air, as well as the heat generated, depend on the oil-matrix system. Laboratory studies, using crude and matrix from a prospective in-situ combustion project, should be performed before designing any field operation. The chemical reactions associated with in-situ combustion are complex and numerous. They occur over a broad temperature range.
- North America > United States (1.00)
- North America > Canada > Alberta (0.29)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Investigating the Impact of Aqueous Phase on CO2 Huff โnโ Puff in Tight Oil Reservoirs Using Nuclear Magnetic Resonance Technology: Stimulation Measures and Mechanisms
Liu, Junrong (School of Petroleum Engineering, China University of Petroleum (East China)) | Li, Hangyu (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum (East China)) | Liu, Shuyang (SchoolSchool of Petroleum Engineering, China University of Petroleum (East China)) | Xu, Jianchun (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum (East China) (Corresponding author) of Petroleum Engineering, China University of Petroleum (East China)) | Wang, Xiaopu (School of Petroleum Engineering, China University of Petroleum (East China)) | Tan, Qizhi (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum (East China))
Summary CO2 huff โnโ puff is a promising enhanced oil recovery (EOR) technique for tight/shale reservoirs, also enabling CO2 geological storage. However, the effectiveness of this method can be significantly affected by the aqueous phase resulting from connate water and hydraulic fracturing. The mechanism underlying the influence of the aqueous phase on oil recovery during CO2 huff โnโ puff, as well as the corresponding stimulation methods in such scenarios, remain unclear and warrant further study. To investigate this, we utilized a nuclear magnetic resonance (NMR) instrument to track the movement of fluids during CO2 huff โnโ puff under water invasion conditions. The impact of the invaded aqueous phase on oil recovery was examined, and the impact of different treatment parameters was explored. The results show that the aqueous barrier formed by water invasion alters the pathway of CO2 diffusion to matrix oil. This alteration leads to a diminished concentration of CO2 in the oil phase, which, in turn, results in a substantial reduction in oil recovery. Consequently, the performance of CO2 huff โnโ puff is highly sensitive to the water phase. Nevertheless, the oil recovery dynamics in cyclic CO2 huff โnโ puff under water invasion exhibit distinctive patterns compared with those without water invasion. These differences manifest as notable low oil recovery in the first cycle, followed by a rapid increase in the second cycle. This behavior primarily arises from the expulsion of a significant portion of the invaded water from the macropores after the first cycle. However, the effectiveness of this mechanism is limited in micropores due to the challenging displacement of trapped water in such pores. Raising the injection pressure mainly boosts oil recovery in macropores, with minimal response in micropores. Yet, the achievement of miscibility does not lead to a substantial improvement in the CO2 huff โnโ puff performance, primarily due to the constraints imposed by the limited CO2 dissolution through molecular diffusion Additionally, we have proposed three stimulation mechanisms achieved by lengthening the soaking time under water invasion conditions. First, the prolonged soaking time increases the concentration of CO2 molecules that diffuse into the matrix oil. Second, it promotes the imbibition of the trapped water on the fracture surface into the deeper matrix to alleviate water blockage. Finally, the invaded water in macropores displaces oil in micropores by capillary force during the soaking period.
- North America > United States > Texas (0.46)
- North America > Canada > Alberta (0.46)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.88)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.49)
- 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)
- (6 more...)
General Optimization Framework of Water Huff-n-Puff Based on Embedded Discrete Fracture Model Technology in Fractured Tight Oil Reservoir: A Case Study of Mazhong Reservoir in the Santanghu Basin in China
Xiang, Yangyue (School of Earth Resources, China University of Geosciences, Wuhan) | Wang, Lei (School of Earth Resources, China University of Geosciences, Wuhan (Corresponding author)) | Si, Bao (Tuha Oilfield Company, Petro China, Hami) | Zhu, Yongxian (Tuha Oilfield Company, Petro China, Hami) | Yu, Jiayi (Research Institute of Exploration and Development, Tuha Oilfield Company, Petro China, Hami) | Pan, Zhejun (Key Laboratory of Continental Shale Hydrocarbon Accumulation and Efficient Development, Ministry of Education, Northeast Petroleum University, Daqing)
Summary Water injection huff-n-puff (WHnP) is currently an important technology to improve the recovery of tight reservoirs. On the one hand, this technology can replenish the formation energy, and on the other hand, it can effectively replace the oil in a tight reservoir. In this paper, the effect of WHnP on cumulative oil production and oil increase rate is simulated and analyzed by comparing depleted development and WHnP scenarios, using numerical simulation methods. A field-scale numerical simulation was modeled based on typical fluid, reservoir, and fracture characteristics of Mazhong tight oil, coupled with geomechanical effects, stress sensitivity, and embedded discrete fractures. The result of different WHnP cycles is studied, and the limiting WHnP cycle is determined to be four cycles. The WHnP efficiency is compared for different permeability scales from 0.005 to 1 md, and it is determined that WHnP at a permeability of 0.01 md resulted in the largest production enhancement. Subsequently, sensitivity studies are conducted using an orthogonal experimental design for six uncertain parameters, including the WHnP cycle, production pressure difference, permeability, natural fracture density, hydraulic fracture half-length, and conductivity. The results show that throughput period and permeability are important parameters affecting cumulative oil production, and permeability and natural fracture density are important parameters affecting oil increase rate. In addition, contour plots of permeability and WHnP cycle, hydraulic fracture half-length, and conductivity are generated. Based on these plots, the optimal conditions with better enhanced recovery results in different WHnP scenarios can be easily determined. This study can better solve the problems encountered in WHnP of tight reservoirs and provide a theoretical basis for stable and efficient development.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.42)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.35)
Figure 11.5-6 shows a difference section from the time-lapse data as in Figure 11.5-4 following cross-equalization. This difference section exhibits a strong amplitude anomaly at the reservoir level situated at the salt flank. Such an amplitude difference may be attributed to changes in the reservoir conditions as a result of production [1]. Because of a wide range of factors associated with acquisition and analysis of the 4-D data, in addition to the difference data volume, the individual data volumes themselves are also visualized and interpreted. The example of cross-equalization shown in Figure 11.5-7 relate to a steam injection project.
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (0.75)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (0.59)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (0.41)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Seismic (four dimensional) monitoring (0.40)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
A New Method to Reduce Shale Barrier Effect on SAGD Process: Experimental and Numerical Simulation Studies using Laboratory-Scale Model
Dong, Xiaohu (National Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum (Beijing) (Corresponding author)) | Liu, Huiqing (National Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum (Beijing)) | Tian, Yunfei (National Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum (Beijing)) | Liu, Siyi (National Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum (Beijing)) | Li, Jiaxin (National Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum (Beijing)) | Jiang, Liangliang (Department of Chemical and Petroleum Engineering, University of Calgary) | Chen, Zhangxin (Department of Chemical and Petroleum Engineering, University of Calgary)
Summary Shale barrier has been widely reported in many steam-assisted gravity drainage (SAGD) projects. For an SAGD project, the properties and distribution of shale barrier can significantly impede the vertical expansion and lateral spread of steam chamber. Currently, although some literature has discussed the shale barrier effect from different perspectives, a systematic investigation combining the scaled physical and numerical simulations is still lacking. Simultaneously, how to reduce the shale barrier effect is also challenging. In this study, aiming at the Long Lake oilsands resources, combining the methods of 3D experiment and numerical simulation, a new method based on a top horizontal injection well is proposed to reduce the impact of shale barrier on the SAGD process. First, based on a dimensionless scaling criterion of gravity-drainage process, we conducted two 3D gravity-drainage experiments (base case and improved case) to explore the effect of shale barrier and the performance of top injection well on SAGD production. During experiments, to improve the similarity between the laboratory 3D model and the field prototype, a new wellbore model and a physical simulation method of shale barrier are proposed. The location of the shale barrier is placed above the steam injection well, and the top injection well is set above the shale barrier. For an improved case, once the steam chamber front reaches the horizontal edge of the shale barrier, the top injection well can be activated as a steam injection well to replace the previous steam injection well in the SAGD well pair. From the experimental observation, the effect of the top injection well is evaluated. Subsequently, a set of numerical simulation runs are performed to match the experimental measurements. Therefore, from this laboratory-scale simulation model, the effect of shale barrier size is discussed, and the switch time of the top injection well is also optimized to maximize the recovery process. Experimental results indicate that a top injection well-based oil drainage mode can effectively unlock the heavy crude oil above shale barrier and improve the entire SAGD production. Compared with a basic SAGD case, the top injection well can increase the final oil recovery factor by about 8%. Simultaneously, through a mass conservation law, it is calculated that the unlocking angle of remaining oil reserve above the shale barrier is about 6ยฐ. The angle can be used to effectively evaluate the recoverable oil reserve after the SAGD process for the heavy oil reservoir with a shale barrier. The simulation results of our laboratory-scale numerical simulation model are in good agreement with the experimental observation. The optimized switch time of the top injection well is the end of the second lateral expansion stage. This paper proposes a new oil drainage mode that can effectively reduce the shale barrier effect on SAGD production and thus improve the recovery performance of heavy oil reservoirs.
- Asia > Middle East > UAE (0.46)
- Asia > China (0.28)
- North America > Canada > Alberta (0.28)
- Overview > Innovation (0.60)
- Research Report > New Finding (0.49)
Flow Control Device and Liner Floatation: Key Technology Driver in Extreme Extended Reach Shallow Steam Assisted Gravity Drainage Wells
Izadi, H. (Department of Civil and Environmental Engineering and the School of Mining and Petroleum Engineering, University of Alberta, Edmonton, AB, Canada) | Roostaei, M. (Variperm Energy Services, Calgary, AB, Canada) | Mahmoudi, M. (Variperm Energy Services, Calgary, AB, Canada) | Stevenson, J. (Variperm Energy Services, Calgary, AB, Canada) | Tuttle, A. (Variperm Energy Services, Calgary, AB, Canada) | Bustamante, G. (COSL Canada Ltd, Calgary, AB, Canada) | Rhein, Sh (COSL Canada Ltd, Calgary, AB, Canada) | Sutton, C. (Variperm Energy Services, Calgary, AB, Canada) | Mirzavand, R. (Department of Electrical & Computer Engineering, University of Alberta, Edmonton, Canada) | Leung, J. V. (Department of Civil and Environmental Engineering and the School of Mining and Petroleum Engineering, University of Alberta, Edmonton, AB, Canada) | Fattahpour, V. (Variperm Energy Services, Calgary, AB, Canada)
Abstract Pursuing more cost-effective well construction and reduced surface footprint has prompted Western Canadian operators to explore extreme extended reach drilling (ERD) wells. However, this endeavor faces a critical challenge: most heavy oil reserves are relatively shallow, resulting in the unwrapped reach ratio (the total horizontal length when projected on the horizontal plane to true vertical depth (TVD)) of more than seven. Therefore, to drill ERD wells, two crucial technical challenges must be tackled: successful liner installation, and efficient steam distribution along these long laterals to enhance production. This paper delves into the solutions for these challenges and a case study showcasing the recent drilling of a steam-assisted gravity drainage (SAGD) extreme ERD well. While floating liners are a known method for extending well reach, they are uncommon in SAGD wells. However, some companies have started exploring the use of floating liners in SAGD projects due to their potential to greatly expand lateral well length, reducing footprint and increasing the oil recovery from any one well pair. By floating the liner using plugged flow control devices (FCDs), gentler running procedures can be employed to achieve TD without risking the integrity of the liner. Moreover, utilizing FCDs in floating liners improves steam conformance and oil production while reducing the cumulative steam oil ratio (cSOR) during the production phase. Modeling results can enhance our capabilities in planning shallower SAGD wells with longer productive sections in the future, with (as described herein) horizontal liner lengths of 1700m and true vertical depths of 240m. The modeling results show that floating liners using plugged FCDs reduce torque by an average of 22% and bottom hole torque by 28%, while also decreasing drag by 16% on average, and bottom hole drag by 17%. These findings indicate that floating liners with plugged FCDs offer a promising solution for SAGD and CSS extreme ERD wells limited by liner installation forces. Furthermore, wells with FCDs in uplifted cases displayed a remarkable upswing of 57%, while concurrently, cSOR demonstrated a noteworthy decrease of 18%. Uplifted cases are identified when wells were completed or retrofitted with FCDs and showed increased oil production compared to neighboring wells. The successful implementation of floating liners with dissolvable or meltable plugs on FCDs enhances confidence in future SAGD extreme ERD wells. The implementation of FCDs in extreme ERD well designs could contribute to reduced greenhouse gas (GHG) emissions, aligning with efforts to combat climate change and minimize environmental impacts. The study's findings elaborated on driving paradigm shifts in the development of heavy oil resources as technology advances, while considering economic factors.
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)