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He, Mei (China University of Geosciences) | Xue, Jiao (China University of Geosciences) | Wan, Huan (Unconventional Oil and Gas Technology Research Institute of Enertech-Drilling and Production Company, CNOOC) | Zhong, Yu (China University of Geosciences) | Zhou, Longgang (Unconventional Oil and Gas Technology Research Institute of Enertech-Drilling and Production Company, CNOOC) | Gu, Hanming (China University of Geosciences (Corresponding author))
Summary Coal measure gas is a research hotspot in recent years. And yet the complexity of source-reservoir relationships and the ambiguity of the gas/water interface in coal measure reservoirs bring challenges to the traditional gas identification methods. With the development of intelligent computing, machine learning has shown good development prospects in the field of oil and gas exploration and development. However, on the one hand, the more capable the learning algorithm is, the greater the demand for data; on the other hand, traditional learning methods suffer from difficulties in hyperparameter tuning and generalization improvement when learning samples are insufficient. To perform intelligent and reliable gas identification in the coal measure reservoir, an ensemble learning-based gas identification method was proposed. The first layer consists of multiple models that were trained by different learning algorithms, such as k-nearest neighbor (kNN), decision tree (DT), neural network (NN), and support vector machine (SVM). While the second layer was used to relearn the output of the first layer, which was implemented by logistic regression (LR). We tested and practically applied this method to real data from a coal measure reservoir in Block A of the Ordos Basin, China. The experimental results showed that our method significantly improved the learning ability of the individual learners on the small sample and performed most consistently when the hyperparameter changes. Moreover, random forest (RF) and deep NN (DNN), as the comparison methods in practical applications, were slightly inferior to ours due to greater computational effort and lower robustness and prediction accuracy. This demonstrates the superiority of our method for fast and effective log-based gas identification, and also suggests that stacking has great potential that is not limited to gas identification tasks. Introduction Accurate oil and gas distribution information can guide exploration and development, thus reducing exploration risks and improving economic efficiency.
Mei, Lan (Institute of Geophysics and Geomatics, China University of Geosciences, Wuhan) | Wei, Wei (Institute of Geophysics and Geomatics, China University of Geosciences, Wuhan) | Cai, Jianchao (Institute of Geophysics and Geomatics, China University of Geosciences, Wuhan) | Meng, Qingbang (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing (Corresponding author))
Summary The fluid exchange behavior for counter-current imbibition in fractured reservoirs can be quantitatively characterized by the transfer function in numerical simulation. The time-dependent shape factor (TDSF) in the transfer function is one of the main factors controlling fluid transport, which directly affects the result of ultimate oil recovery prediction. In practice, fractured reservoirs with different microscopic pore structures often have varied flow laws under the same flow conditions. However, the current TDSFs proposed for counter-current imbibition assume that the microscopic pore structure has no impact on the fluid inter-porosity flow behavior, which is inconsistent with the actual situation. In this work, the fractal theory is used to establish the TDSF of counter-current imbibition, which is related to the microscopic pore structure. First, the analytical solutions of average water saturation and imbibition rate are obtained under different conditions related to the maximum pore diameter and tortuosity fractal dimension of the matrix. The validity of the new analytical solution for strong water-wet and moderate water-wet reservoirs is ascertained by a single-porosity model and experimental data. Subsequently, the proposed analytical solution is applied to the two-phase transfer function to develop the new TDSF for counter-current imbibition, and the sensitivity analysis is carried out. The results demonstrate that the unsteady-state duration of the TDSF is proportional to the characteristic length and tortuosity fractal dimension of the matrix, and it is negatively proportional to the maximum pore diameter of the matrix. The influence of the characteristic length, tortuosity fractal dimension, and maximum pore diameter of the matrix on a constant shape factor (SF) under quasi-steady-state is exactly the opposite. This work provides an enhanced clarification of the fluid exchange behavior of counter-current imbibition in strong water-wet and moderate water-wet fractured reservoirs.
Zhao, Guang (China University of Petroleum East China - Qingdao Campus, School of Petroleum Engineering) | Dai, Caili (China University of Petroleum East China - Qingdao Campus, School of Petroleum Engineering) | Xu, Bozhao (China University of Petroleum East China - Qingdao Campus, School of Petroleum Engineering) | Zhao, Wenxun (Sinopec Shengli Oilfield) | Ma, Tiantai (Sinopec Shengli Oilfield)
Abstract Wet-phase modified expandable graphite (WMEG) particles have been successfully developed for in-depth steam channeling control in heavy oil reservoirs. WMEG particles can expand 4 to 7 times in a wet-phase environment and form a worm-like structure at steam temperature. The sand-pack flowing experiments demonstrated that WMEG particles have good injection, steam erosion resistance and selective plugging capacity characteristics. By directly plugging and bridge plugging after expansion, WMEG particles can effectively plug steam channels. To better explain the steam plugging mechanism, the energy changes during WMEG particle expansion were also analyzed. The release of gas at different stages is the source of energy for WMEG particle expansion. WMEG particles have been successfully applied to 12 wells of four typical heavy oilfields in China. The results from these applications confirm that the injection of WMEG particles is an effective steam channeling control treatment. The success of these oilfield tests can also serve as a reference for similar steam injection heavy oilfields.
Wei, Bing (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University (Corresponding author)) | Zhong, Mengying (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Wang, Lele (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Tang, Jinyu (Department of Chemical and Petroleum Engineering, United Arab Emirates University) | Wang, Dianlin (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | You, Junyu (School of Petroleum Engineering, Chongqing University of Science & Technology) | Lu, Jun (McDougall School of Petroleum Engineering, The University of Tulsa)
Summary When reservoir fluids are confined by nanoscale pores, pronounced changes in fluid properties and phase behavior will occur. This is particularly significant for the natural gas huff ‘n’ puff (HNP) process as a means of enhanced oil recovery (EOR) technology in unconventional reservoirs. There have been considerable scientific contributions toward exploring the EOR mechanisms, yet almost none considered the effects of nanopore confinement and its proportion on the oil recovery dynamics. To bridge this gap, we developed an approach to calculate fluid phase equilibrium in nanopores by modifying the Rachford-Rice equation and Peng-Robinson equation of state (PR-EOS), completed by considering the shifts of fluid critical properties and oil/gas capillary pressure. Afterward, the effect of nanopore radius (rp) on the phase behavior between the injected natural gas and oil was thoroughly investigated. Compositional simulation was performed using a rigorously calibrated model based on typical properties of a tight reservoir to investigate the production response of natural gas HNP, including the effects of nanopore confinement and its proportion. We demonstrated that the critical pressure and temperature of fluid components decreased with the reduction in rp, especially for heavy constitunts. The saturation pressure, density, and viscosity of the oil in the presence of natural gas all declined linearly with 1/rp in the confined space. The suppression of fluid saturation pressure was indicative of an extended single-phase oil flow period during production. The cumulative oil production was approximately 12% higher if the confinement effect was considered in simulation. Moreover, the average reservoir pressure declined rapidly resulting from this effect, mainly caused by the intensified in-situ gas/oil interaction in nanopores. The results of this paper supplement earlier findings and may advance our understanding of nanopore confinement during natural gas HNP, which are useful for field-scale application of this technique.
Sennaoui, B. (University of North Dakota, Grand Forks) | Pu, Hui (University of North Dakota, Grand Forks) | Malki, M. L. (University of Wyoming) | Afari, A. S. (University of North Dakota, Grand Forks) | Larbi, A. (University of North Dakota, Grand Forks) | Tomowewo, O. S. (University of North Dakota, Grand Forks) | Araghi, R. H. R. (University of North Dakota, Grand Forks)
Abstract Low primary recovery percentages (usually 10% or less) in unconventional reservoirs, such as the Three Forks Formation in the Williston Basin, mean that potentially billions of barrels of oil are left behind in the reservoirs. Gas enhanced oil recovery (EOR) pilot studies that were performed in the Three Forks Formation suggest that cyclic gas injection is a viable approach for enhancing oil recovery in unconventional reservoirs. Due to limited knowledge of the cyclic gas injection mechanisms and the interaction between the injected gases and Three Forks reservoir fluids, additional investigations are mandatory despite of the pilot studies and the published findings in the Three Forks Formation. This paper conducts a series of experiments on core samples from the Upper Three Forks (UTF) and Middle Three Forks (MTF) under different constraints. The parameters that affect the performance of the cyclic gas injection during the Huff and Puff (HnP) technique are analyzed, including soaking time in miscible and immiscible conditions, injection pressure, vapor-supercritical states, density change, gas type (CO2), Ethane (C2H6), Propane (C3H8), within these formations (Upper Three Forks, and Middle Three Forks), and the microscopic pore distribution effect on hydrocarbon transport for the production using the Nuclear Magnetic Resonance (NMR) approach. The findings indicated that the soaking time improved recovery factors significantly below and close to the CO2's minimum miscibility pressure (MMP), but its effectiveness decreased for the injection pressures over the MMP. At low injection pressures, propane (C3H8) was shown to be the most effective gas, followed by ethane (C2H6) and then carbon dioxide (CO2). Due to a significant shift in density, ethane (C2H6) and carbon dioxide (CO2) both performed better during increasing pressure. In contrast, increasing the injection pressure of propane (C3H8) above 6.89 MPa did not affect the performance since the density of propane at 6.89 MPa caused a negligible density change. Additionally, the NMR measurements conducted at the UTF indicated that in the first cycle of HnP, oil extraction was dominated by micropores, mesopores, and less by small pores. Increasing the HnP cycles, micropores will be the dominant source of oil production. However, in MTF, the mesopores were the dominant pore distributions, followed by small pores, which affect the micro oil mobilization during the HnP process. This work provides a new insight into understanding the mechanisms of gas HnP enhanced recovery in the Three Forks formation, which is of great significance for the efficient hydrocarbon exploitation and greenhouse gas utilization in the Three Forks.
Abstract Fine migration is considered to be the primary factor leading to the production decline of the unconsolidated sandstone formations. Micro-fracturing technology is regarded as a practical approach to solving these problems for improving the permeability near the wellbore. However, no detailed and comprehensive research has investigated the blockage-removing mechanism upon microfracturing. Therefore, a comprehensive simulation method is proposed in this study, capable of simulating the permeability evolution and the mechanical responses of the unconsolidated sandstone during the micro-fracturing. Afterward, the blockage-removing mechanism of micro-fracturing and the associated mechanical deformation are analyzed in a field case. Furthermore, the simulation results were classified using digital method and made into a predictive chart. The results show that the permeability damage caused by a blockage in an unconsolidated sandstone can be treated by micro-fracturing. The underlying mechanisms can be summarized in three aspects. First, the hydraulic effect can mitigate the permeability damage caused by particle deposition. Secondly, the increase in pore throat radius due to pore dilation can disrupt the structure of the particle bridging. Third, the blockage caused by size exclusion is diminished due to an increase in the effective pore radius. These results elucidated the mechanism of blockage removal by microfracturing and provided valuable guidance for field engineers to improve the subsequent stimulation work. Introduction In recent years, more and more oil and gas resources are found in unconsolidated sands or weakly consolidated sandstones, such as the Gulf of Mexico, Athabasca (Canada), Orinoco (Venezuela), and Bohai Bay Basin of China (Xiong et al., 2018; Wang et al., 2021). These resources include conventional oil and gas reservoirs and unconventional reservoirs such as oil sands. The loss of permeability caused by fines migration in the reservoir is always considered a significant factor responsible for productivity decline. Due to unconsolidated cementation, fines migration almost occurs during the whole process of oil and gas reservoir development, such as drilling, fracturing, water injection, or liquid production. Due to the high fluid velocity near-wellbore, it is essential to note that fines migration and blocking always occur near the wellbore. Various approaches have been proposed to alleviate the adverse effects of fines migration on reservoir permeability, including nanofluid clay stabilizers, and polymers. (Huang et al., 2008; Yuan et al., 2016; Zhang et al., 2015). However, these methods are not only costly and effective for a short period, but are mainly preventive in focus.
Zhao, Geng (Schlumberger) | Fould, Jeremie (Schlumberger) | Dong, Yifan (South Sulige Operating Company) | Li, Changwei (Schlumberger) | Huo, Ying (Schlumberger) | Liu, Xiaoli (Schlumberger) | Liu, Yang (Schlumberger) | Wang, Qiang (South Sulige Operating Company) | Yang, Shengfang (South Sulige Operating Company) | Jin, Ting (South Sulige Operating Company) | Ma, Qian (South Sulige Operating Company) | He, Tao (South Sulige Operating Company)
Abstract Hydrocarbon resources have primarily been accessed from onshore environments. Most of the explored basins have matured, with some even nearing the end of their field lives. Production from these traditional resources has declined over the past few years, and new discoveries of vast resources are becoming rarer. Global exploration trends focused on deepwater (and even ultradeepwater) fields, deeper onshore formations, and unconventional resources are aligned with the focus of China's hydrocarbon industry. In 2021, China completed its first self-operated subsea deepwater gas project, Lingshui 17-2, and a series of new projects is planned for the next few years. In terms of developing deeper (> 4000 m) onshore formations, Sinopec Northwest set a record in Shunbei Field with an ultradeep oil development that reached 8874.4 m. Famous fields in China for unconventional hydrocarbon development, some of which are in deeper formations, include PetroChina Southwest in the Sichuan Basin, PetroChina Changqing in the Ordos Basin for tight gas/shale gas and shale oil, and Sulige in the Ordos Basin for tight gas. During China's 14th Five-Year Plan period, from 2021 to 2025, the proportion of unconventional oil and gas production will further increase, and production is expected to increase rapidly to align with the country's energy security strategy. Furthermore, the oil and gas industry worldwide has been placing a greater emphasis on carbon footprint reduction; while the number of new oil projects decreases every year, natural-gas projects, especially in deepwater environments and shale/tight reservoirs, have been rapidly increasing. This paper will focus on the unconventional hydrocarbon development methodology and discuss the evolution of fracturing technology, particularly multistage fracturing completion tools over the past two decades; then, the paper will review the various design concepts, features, and serviceability of representative completion tools during each fracturing period. A successful 10-year tight-gas sandstone application in Ordos, China, will be used to review the slim multistage fracturing sleeve (SMFS), the most-reliable fracturing string design, and its key operational improvements. The design has been informed by previous field knowledge and experiences, resulting in a simple, cost-efficient, and technology perfect adaptability tool that can be used to illustrate the development trend of multistage fracturing completion tools.
Chang, Long (CNPC Engineering Technology R&D Company Limited) | Zou, Lingzhan (CNPC Engineering Technology R&D Company Limited) | Wang, Haige (CNPC Engineering Technology R&D Company Limited) | Yu, Yangfei (PetroChina Xinjiang Oilfield Company) | Liu, Qi (CNPC Engineering Technology R&D Company Limited) | Zhuo, Lubin (CNPC Engineering Technology R&D Company Limited) | Yu, Jing (CNPC Engineering Technology R&D Company Limited) | Wu, Baocheng (PetroChina Xinjiang Oilfield Company) | Xu, Jiangwen (PetroChina Xinjiang Oilfield Company) | Shi, Jiangang (PetroChina Xinjiang Oilfield Company)
Abstract The Triassic Baikouquan Formation reservoir in the Mahu Sag, Junggar Basin is characterized by tight sandy conglomerate oil reservoir with long drilling cycle and great fracturing difficulty. The factory drilling and fracturing techniques of horizontal wells for the Ma131 Well Block of Mahu Oilfield have been determined by regional geological characteristics research and optimization scheme design. The key technologies for horizontal well drilling speed improvement were explored by designing small three-stage wellbore structure, customizing the PDC bit properly, optimizing drilling tool combination, and selecting the drilling fluid with inhibition and plugging ability. The factory reservoir stimulation technique carried out horizontal well hydraulic fracturing with small well spacing for two sets of beds, and adopted bridge plug + clustering perforation staged fracturing and slick water + gel composite fracturing technology. 12 wells in a drilling pad were arranged in the demonstration area with the depth of 5000m, the distance between adjacent sections was 150m or 100m, with the horizontal section length of 1800m. Batching drilling operation pattern was adopted, with 3⁃well drilling for each of rig. Rapid inclining prevention drilling through vertical sections adopted PDC bit + screw + MWD, with high rotary speed and high flow rate. In the build-up section, radical drilling parameters was used to improve the top drive rotary speed and release the torque. In the horizontal sections, rotary steering tool + low speed high torque screw was adopted. The application of this technology achieved good results, with average drilling cycle of 48.3 d and average ROP of horizontal section increased by 77%. The fracturing construction adopted high pad fluid ratio, high sand ratio and high pump rate. More than 10,000 m3 fluid was injected in a single well with high-intensity proppant injection. The factory operation was carried out in the order of construction from the two sides to the middle well with microseismic monitoring. Factory fracturing with small well spacing generated stress interference and improved the fracture reconstruction effect. Higher shut-in pressure, more microseismic events and large-scale stimulated reservoir volume had been carried out in horizontal wells fractured later. The factory drilling and fracturing techniques of horizontal wells for the Ma131 Well Block have achieved the goals of improving drilling speed and volume fracturing, which provided technical support for the efficient development of the tight sandy conglomerate oil reservoir of the Mahu Oilfield.
Dong, X. (Key Laboratory of Continental Shale Hydrocarbon Accumulation and Efficient Development, Northeast Petroleum University) | Shen, L. W. (Faculty of Engineering, China University of Geosciences (Wuhan) (Corresponding author)) | Liu, B. (Key Laboratory of Continental Shale Hydrocarbon Accumulation and Efficient Development, Northeast Petroleum University) | Cui, L. (Key Laboratory of Continental Shale Hydrocarbon Accumulation and Efficient Development, Northeast Petroleum University) | Ostadhassan, M. (Key Laboratory of Continental Shale Hydrocarbon Accumulation and Efficient Development, Northeast Petroleum University) | Pan, Z. (Key Laboratory of Continental Shale Hydrocarbon Accumulation and Efficient Development, Northeast Petroleum University) | Li, H. (Key Laboratory of Continental Shale Hydrocarbon Accumulation and Efficient Development, Northeast Petroleum University)
Summary Successful examples of hydraulic fracturing (HF) have led to a general consensus that fractures enhance hydrocarbon production as it connects isolated pockets filled with oil. However, the fracture’s impact on the hydrocarbon recovery from rock’s pores, which can account for a significant amount, is not well studied but experimentally investigated here. Uniquely, we fill our samples' fractures with a slime made of guar gum and heavy water (D2O). Such slime cannot penetrate into pores, and the heavy water does not generate nuclear magnetic resonance (NMR) signals detectable by our apparatus. Using such slime as a fracture filling material allows us to isolate and eliminate the NMR signals from fractures. Subsequent huff ‘n’ puff (HnP) experiments show that fracture results in a decline of the total HnP recoverable oil. We reasoned that fracture reduces the treatment gas’ sweeping efficiency. This issue can be partially mitigated by injecting N2 instead of CO2; N2 can enter rock’s pores more efficiently as a treatment agent. Nevertheless, N2 HnP still suffers a noticeable reduction in the total recovery for samples with smaller pores. Our experiments provide an important new insight into the development of unconventional hydrocarbon resources. Maximizing fracture intensity in the field HF operation may negatively impact the later HnP oil recovery. At last, this observation is only possible with our unique experiment design; a misleading and opposite finding will be reached if one directly compares the results from before and after fracturing the samples. We reinforce that pore structures are changed during the fracturing process in our experiment (and possibly other researchers’ work); such change needs to be properly accounted for to assess fracture’s impact on pore fluid movement fairly.
Qu, Jianhua (Chengdu Northern Petroleum Exploration and Development Technology Co. Ltd. / China Zhenhua Oil Co.Ltd) | Zhang, Boning (Chengdu Northern Petroleum Exploration and Development Technology Co. Ltd. / China Zhenhua Oil Co.Ltd) | Deng, Qi (Chengdu Northern Petroleum Exploration and Development Technology Co. Ltd. / China Zhenhua Oil Co.Ltd) | Luo, Bo (Department of Petroleum Engineering, University of Houston) | Xue, Heng (Chengdu Northern Petroleum Exploration and Development Technology Co. Ltd. / China Zhenhua Oil Co.Ltd) | Huang, Jing (Chengdu Northern Petroleum Exploration and Development Technology Co. Ltd. / China Zhenhua Oil Co.Ltd) | Huang, Xingning (Baker Hughes) | Guo, Songyi (Chengdu Northern Petroleum Exploration and Development Technology Co. Ltd. / China Zhenhua Oil Co.Ltd)
Abstract Junggar Basin is a typical superimposed oil and gas bearing basin in western China, where Mahu Depression is the largest oil-gas accumulation zone and exploration area. On April 23rd, 2013, the peak daily oil production of Mahu No.1 well reached 52 tons, achieving a significant breakthrough. On August 23rd of the same year, the high yield of Mahu No.18 well opened a new chapter of oil and gas exploration in the slope belt of the Mahu Depression. Since then, CNPC (China National Petroleum Corporation) has increased the exploration and development process of the Mahu Depression, establishing the exploration theory and technology system of the conglomerate reservoir in the depression area. Finally, the exploration and discovery of a supergiant conglomerate oil field (1 billion tons) were achieved. However, a series of development problems were exposed, which was due to the lack of in-depth research on reservoir geomechanics and distribution law for natural fractures: 1) The Hydraulic fracture propagation law is not clear; 2) In the process of fracturing, there exists an obvious phenomenon of non-uniform fluid inflow and expansion in various clusters of fractures; 3) Serious interference occurs between wells during the fracturing operation. Therefore, it is necessary to strengthen the study of geomechanics and distribution law for natural fractures in unconventional oil reservoirs, so as to provide technical support for the optimization of the horizontal well fracturing scheme, improvement of well pattern deployment parameters, and adjustment of oil reservoir development scheme, which further leads to cost reduction and development efficiency improvement while increasing single well production in unconventional oil reservoirs.