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Sinopec announced this week that production at China's largest shale-gas development has jumped 20% year-over-year. This is based on first quarter results that showed natural-gas production from the Fuling gas field in Chongqing reached a cumulative output of 1.78 Bcm, or nearly 63 Bcf. The boost comes after Sinopec brought 28 new wells on stream this year, the state-owned oil and gas producer said in an announcement. Sinopec is China's second-largest gas producer and said during its earnings call that it is aiming for an annual increase in gas output of 10% over the next 3 years. The operator produced a total of 30.2 Bcm in 2020 and is aiming for 34 Bcm this year. Sinopec's next expected milestones are 38 Bcm in 2022 and 42 Bcm in 2023.
Devon Energy considers its development of a new completions technology called Sealed Wellbore Pressure Monitoring (SWPM) to be one of the shale sector's biggest breakthroughs in subsurface engineering. The approach to fracturing diagnostics represents a class of next-generation tools designed to make on-the-fly stimulation designs more practical than ever. But the innovation has done something else, too. It has raised old questions within a relatively new sector about the role of intellectual property (IP) protection. When SWPM was introduced to petrotechnicals outside of Devon, some initially questioned how or why the technique needed to be patented at all. The ingenuity behind SWPM could be boiled down to solving a math problem: How much fluid is pumped during the hydraulic fracturing treatment of one well before it travels across a known distance and applies pressure to the unperforated casing of a neighboring shut-in well?
Wu, Jiwei (East China University of Science and Technology, Harvard University, Yangtze University) | Pan, Jiake (East China University of Science and Technology) | Wang, Hualin (East China University of Science and Technology (Corresponding author) | Wang, Lixiang (email: email@example.com)) | Liu, Wenjin (PetroChina Southwest Oil & Gas Field Company, Chengdu Natural Gas Chemical General Plant) | Zhang, Le (Sinopec, SJ Petroleum Machinery)
Summary With the flourishing shale gas exploitation producing more oil-based mud (OBM) cuttings, the hard-to-treat hazardous wastes heavily burden the local environment. However, the problems of treating OBM cuttings, such as huge energy consumption, tremendous treatment costs, and high risk of secondary contamination, still remain unsolved with the current treatment technologies, such as thermal desorption, incineration, and chemical extraction. In this study, we introduce a new method and equipment based on cyclone desorption to recover oil from OBM cuttings. The technological process includes viscosity reduction in heated gas, cyclone deoiling, condensation and recycling of the exhaust, and separation of oil and water in the coalescer. Based on the analysis of the physicochemical properties and the oil distribution inside the OBM cuttings samples collected from the Chongqing shale gas field, we designed this cyclone oil desorption technology and built the pilot-scale equipment to conduct the deoiling experiments. The results showed that the deoiling efficiency of OBM cuttings improved as the processing time increased. To be precise, after 2.7 seconds of treatment, the oil content of the cuttings samples fell sharply from 17.9 to 0.16%, which is about one-half of the maximum allowable oil content in pollutants of 0.3%, specified in the national standard (GB 4284-84 1985) promulgated by the People’s Republic of China. The foundation of the technology is that the particles have a high-speedself-rotation (more than 30,000 rad/s) coupled with a revolution in the cyclone in which a generated centrifugal force removes the oil from the pores of the particles. This process is purely physical and involves no phase change of the oil, so it is free of chemical addition and high heating temperature. The application of this newly developed cyclone oil desorption technology is expected to lower the treatment costs, enhance the processing efficiency, contribute to the energy development, and eventually benefit the local environment where the shale gas exploitations take place.
Su, Hang (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing) and Research Institute of Petroleum Exploration & Development, PetroChina) | Zhou, Fujian (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing)) | Wang, Qing (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing)) | Yu, Fuwei (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing)) | Dong, Rencheng (University of Texas at Austin) | Xiong, Chunming (Research Institute of Petroleum Exploration and Development) | Li, JunJian (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing)) | Liang, Tianbo (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing) (Corresponding author)
Summary Enhanced oil recovery (EOR) in fractured carbonate reservoirs is challenging because of the heterogeneous and oil-wet nature. In this work, a new application of using polymer nanospheres (PNSs) and diluted microemulsion (DME) is presented to plug fractures and enhance water imbibition to recover oil from the tight, naturally fractured carbonate reservoirs. DME with different electric charges is compared through contact-angle and core-imbibition tests to evaluate their performances on EOR. The cationic DME is chosen because it has the fastest wettability-alteration rate and thus the highest oil recovery rate. Migration and plugging efficiency tests are conducted to identify the screened particle sizes of PNSs for the target reservoir cores. PNSs with a particle size of 300 nm are demonstrated to have the best performance of in-depth propagation before swelling and plugging after swelling within the naturally fractured cores are used in this study. Then coreflooding experiments are conducted to evaluate the EOR performance when PNSs and DME are used together, and results indicate that the oil recovery rate is increased by 24.3 and 44.1% compared to using PNSs or DME alone. In the end, a microfluidic experiment is carried out to reveal how DME works with PNSs. Introduction Fractured carbonate reservoirs have been demonstrated to host a large amount of oil and gas resources throughout the world (Alhuraishawy et al. 2018; Dong et al. 2018, 2019a, 2019c, 2020). However, the development of these resources is currently constrained by the generally low water sweep efficiency because carbonate reservoirs are usually fractured and oil-wet (Dong et al. 2018, 2019b; Wu et al. 2008). Water can channel through fractures, generally leading to small swept areas in these fractured carbonate reservoirs. Meanwhile, the oil-wet nature of the reservoir can prevent water from entering the matrix to displace the oil, resulting in low waterflooding efficiency (Liang et al. 2017a, 2017b, 2017c).
Archibong-Eso, Archibong (University of Birmingham) | Baba, Yahaya (Sheffield University) | Aliyu, Aliyu (University of Huddersfield) | Ribeiro, Joseph (Kumasi Technical University) | Abam, Fidelis (Michael Okpara University of Agriculture) | Yeung, Hoi (Cranfield University)
Summary In this study, an investigation of sand transport in heavy-oil/water multiphase flow is performed. The study is conducted in three multiphase-flow pipeline-test facilities with internal diameters (IDs) of 1, 1, and 3 in. Oil viscosity of 3.5 and 10.0 Pas with sand volume fractions from 0.010 to 0.100 vol% were used in the study. The effects of oil viscosity, upward inclination, sand volume fraction, pipe ID, and water cut on the sandtransport mechanism in pipelines are investigated. In the horizontal test section, flow patterns--namely, dispersed flow (DF), plug flow (PF), plug flow with moving sand bed (PFM), and plug flow with stationary sand bed (PFS)--were identified through flow visualization. In addition to the aforementioned, two flow patterns--stratified wavy flow with moving sand bed (SWM) and stratified wavy flow with dunes (SWD)--were observed in the inclined pipeline orientation. The pressure gradient measured decreased with a decrease in water cut until a minimum value was reached. Beyond the minimum pressure gradient, further reduction in water cut led to an increase in pressure gradient. The sand minimum transport condition (MTC) in the oil/water/sand test was largely the same for the 1-in. An improved MTC predictive correlation is proposed for multiphase heavy-oil/water/sand flow. The proposed correlation outperforms the existing models when tested on the heavy-oil/water/sand data set. Introduction Three-phase oil/water/sand flow in pipelines is prevalent during crude-oil production. These flows are encountered when water is used to assist the production and transport of unconventional crude-oil resources such as heavy oils and bituminous sand. Numbers released by BP's statistical review of the World Energy 2019 Report (BP 2019) shows that the world's primary energy consumption grew by 2.9% from 2018.
Ji, Dongqi (China University of Geosciences, Beijing) | Wu, Shuhong (PetroChina) | Wang, Baohua (PetroChina) | Li, Zhiping (China University of Geosciences, Beijing (Corresponding author) | Lai, Fengpeng (email: firstname.lastname@example.org)) | Chen, Zhangxin (China University of Geosciences, Beijing) | Dong, Mingzhe (University of Calgary (Corresponding author) | Ge, Chenqi (email: email@example.com))
Summary Temperature-dependent irreducible water saturation has great implications for heavy-oil production. Especially in processes using thermal methods, the irreducible water saturation varies significantly when temperature rises from the initial reservoir condition to the temperature of injected hot fluids. In this work, the irreducible water saturation retained in a heavy-oil/oil-sands reservoir has been theoretically analyzed as a function of temperature in the view of thermodynamics. This analysis involves oil/water interactions, thermodynamic stability, pendular rings between particles, and a dense random-packing theory. The temperature-dependent irreducible water saturation in two heavy-oil reservoir samples (Coalinga and Huntington Beach) and two oil-sands reservoir samples (Cat Canyon and Peace River) have been analyzed using an oil/water/silica system. The computed results have been compared with published experimental data. The good agreements of the comparison demonstrate the feasibility of the proposed analysis to describe the irreducible water saturation in a heavy-oil/oil-sands reservoir up to 300°C. Through these analyses, the theoretical understandings of temperature-dependent irreducible water in a heavy-oil/oil-sands reservoir have been provided. As temperature increases, the mutual water/oil solubilities are increased by enhanced molecular interactions, as well as the surface energy at an oil/water connecting interface. As a result, the oil/water interfacial tension (IFT) decreases, which diminishes the contact angle and enlarges a water-filled pendular ring between particles at elevated temperatures. Thus, the irreducible water saturation is increased by the enlarged pendular rings in a dense packing porous medium. In addition, this study demonstrates the possibilities to alter the irreducible water saturation appropriately in a heavy-oil/oil-sands reservoir to enhance oil recovery, decrease water cut, save costs of surface oil/water separation, and reduce heat consumption.
Summary Pulse hydraulic fracturing technology can greatly improve the effect of fracture propagation in rock and form complex fracture networks in reservoirs. The interaction mechanism between hydraulic fractures and pre-existing fractures under pulse hydraulic pressure is unclear. The induced laws of pre-existing fractures on the propagation direction of hydraulic fractures under different pulse frequencies and pulse hydraulic pressures are revealed in this work. We have carried out traditional hydraulic fracturing (THF) tests and pulse hydraulic fracturing tests with rock-like specimens. We compared the interaction between hydraulic fractures and pre-existing fractures in the two hydraulic fracturing tests. Acoustic emission (AE) characteristics of the interaction between hydraulic fractures and pre-existing fractures during pulse hydraulic fracturing are analyzed. The results show that pre-existing fractures in the rock-like specimen can induce the direction of propagation of hydraulic fractures. The influence of pre-existing fracture tips on hydraulic fracture propagation is greater with low pulse frequencies than with traditional hydraulic pressures and high pulse frequencies. When the pulse frequency is 1 Hz, hydraulic fractures are easily induced by pre-existing fracture tips. With increasing pulse frequency, the hydraulic fracture propagation direction gradually moves away from the pre-existing fracture tips and extends perpendicularly to the direction of the minimum principal stress. Under pulse hydraulic loading, more hydraulic fractures are generated around the wellbore than under THF and extend to the pre-existing fracture, and more hydraulic fractures around the wellbore are created with low-frequency pulse loading than with high-frequency pulse loading. Compared with traditional hydraulic pressures, hydraulic fracture propagation with low pulse frequencies (1 and 3 Hz) is more complex than hydraulic fracture propagation with traditional hydraulic pressures and high pulse frequencies (5 Hz). Under high pulse hydraulic pressure and pulse frequency, hydraulic fractures easily extend along the direction perpendicular to the direction of the minimum principal stress like propagation under traditional hydraulic pressure. The study of the interaction mechanism between hydraulic fractures and natural fractures under pulsating hydraulic pressure can provide a method for the formation of fracture network systems in large-scale fracturing and may improve the fracturing efficiency.
Hou, Yanan (China University of Petroleum (Beijing)) | Peng, Yan (China University of Petroleum (Beijing) (Corresponding author) | Chen, Zhangxin (email: firstname.lastname@example.org)) | Liu, Yishan (University of Calgary and China University of Petroleum (Beijing) (Corresponding author) | Zhang, Guangqing (email: email@example.com)) | Ma, Zhixiao (China University of Petroleum (Beijing)) | Tian, Weibing (China University of Petroleum (Beijing))
Summary Pulsating hydraulic fracturing (PHF) is a promising fracturing technology for unconventional reservoirs because it could improve the hydraulic fracturing efficiency through inducing the fatigue failure of reservoir rocks. Understanding of the pressure wave propagation behavior in wellbores and fractures plays an important role in PHF optimization. In this paper, a transient flow model (TFM) was used to describe the physical process of pressure wave propagation induced by PHF, and this model was solved by the method of characteristics (MOC). Combination of the TFM and MOC was validated with experimental data. The impacts of controlling factors on the pressure wave propagation behavior were fully discussed, and these factors include the frequency of input loading, an injection mode, an injection position, and friction. More than 10,000 sets of pressure wave propagation behaviors in different scenarios were simulated, and their differences were illustrated. In addition, the generation mechanisms of different pressure wave propagation behaviors were explained by the Fourier transform theory and the vibration theory. The important finding is that there is resonance phenomenon in the propagation of the pressure wave, and the resonance frequencies are almost equal to the natural frequencies of a fluid column. As a consequence of resonance phenomenon, the amplitudes of bottomhole pressure (BHP) and fracture tip pressure will increase sharply when the input loading frequency is close to the resonance frequency and less than 5 Hz; otherwise, the resonance phenomenon will disappear. Furthermore, an injection mode can alter the resonance frequency and the amplitude and frequency of the induced pressure wave. In addition, a friction effect can significantly decrease both the resonance frequency and the resonance amplitude. These findings indicate that the optimized input loading frequency should be close to the natural frequency of a fracturing fluid in a wellbore to enhance its BHP.
Ju, Yang (China University of Mining and Technology (Corresponding author) | Wu, Guangjie (emails: firstname.lastname@example.org or email@example.com)) | Wang, Yongliang (China University of Mining and Technology) | Liu, Peng (China University of Mining and Technology) | Yang, Yongming (China University of Mining and Technology)
Summary In this paper, we introduce the entropy weight method (EWM) to establish a comprehensive evaluation model able to quantify the brittleness of reservoir rocks. Based on the evaluation model and using the adaptive finite element-discrete element (FE-DE) method, a 3D model is established to simulate and compare the propagation behavior of hydraulic fractures in different brittle and ductile reservoirs. A failure criterion combining the Mohr-Coulomb strength criterion and the Rankine tensile criterion is used to characterize the softening and yielding behavior of the fracture tip and the shear plastic failure behavior away from the crack tip during the propagation of a fracture. To understand the effects of rock brittleness and ductility on hydraulic fracture propagation more intuitively, two groups of ideal cases with a single failure mode are designed, and the fracture propagation characteristics are compared and analyzed. By combining natural rock core scenarios with single failure mode cases, a comprehensive evaluation index BIf for reservoir brittleness and ductility is constructed. The simulation experiment results indicate that fractures in brittle reservoirs tended to form a complex network. With enhanced ductility, the yielding and softening of reservoirs hamper fracture propagation, leading to the formation of a simple network, smaller fracture area (FA), larger fracture volume, and the need for higher initiation pressure. The comprehensive index BIf can be used to define brittleness or ductility as the dominant factor of fracturing behavior. That is, 0 < BIf ≤ 0.46 indicates that the reservoir has enhanced ductility and ductile fracturing prevails; 0.72 < BIf < 1 indicates that the reservoir has enhanced brittleness and brittle fracturing prevails; and 0.46 < BIf ≤ 0.72 means a transition from brittle to ductile fracturing. Based on fitting analysis results, the relationship between the calculated FAr and BIf is constructed to quantify the influence of reservoir brittleness and ductility on fracturing. The study provides new perspectives for designing, predicting, and optimizing the fracturing stimulation of tight reservoirs with various brittleness and ductility.
Xiaoyan, Wang (Dagang Oilfield and Northeast Petroleum University) | Jian, Zhao (Tuha Oilfield) | Qingguo, Yin (Dagang Oilfield) | Bao, Cao (Northeast Petroleum University (Corresponding author) | Yang, Zhang (email: firstname.lastname@example.org)) | Fengxiang, Zhao (Dagang Oilfield) | Lidong, Zhang (Dagang Oilfield) | Haiying, Cheng (Tuha Oilfield) | Xi, Yan (Dagang Oilfield) | Song, He (Dagang Oilfield)
Summary Achieving effective results using conventional thermal recovery technology is challenging in the deep undisturbed reservoir with extra-heavy oil in the LKQ oil field. Therefore, in this study, a novel approach based on in-situ combustion huff-and-puff technology is proposed. Through physical and numerical simulations of the reservoir, the oil recovery mechanism and key injection and production parameters of early-stage ultraheavy oil were investigated, and a series of key engineering supporting technologies were developed that were confirmed to be feasible via a pilot test. The results revealed that the ultraheavy oil in the LKQ oil field could achieve oxidation combustion under a high ignition temperature of greater than 450°C, where in-situ cracking and upgrading could occur, leading to greatly decreased viscosity of ultraheavy oil and significantly improved mobility. Moreover, it could achieve higher extra-heavy-oil production combined with the energy supplement of flue gas injection. The reasonable cycles of in-situ combustion huff and puff were five cycles, with the first cycle of gas injection of 300 000 m and the gas injection volume per cycle increasing in turn. It was predicted that the incremental oil production of a single well would be 500 t in one cycle. In addition, the supporting technologies were developed, such as a coiled-tubing electric ignition system, an integrated temperature and pressure monitoring system in coiled tubing, anticorrosion cementing and completion technology with high-temperature and high-pressure thermal recovery, and anticorrosion injection-production integrated lifting technology. The proposed method was applied to a pilot test in the YS3 well in the LKQ oil field. The high-pressure ignition was achieved in the 2200-m-deep well using the coiled-tubing electric igniter. The maximum temperature tolerance of the integrated monitoring system in coiled tubing reached up to 1200°C, which provided the functions of distributed temperature and multipoint pressure measurement in the entire wellbore. The combination of Cr-P110 casing and titanium alloy tubing effectively reduced the high-temperature and high-pressure oxygen corrosion of the wellbore. The successful field test of the comprehensive supporting engineering technologies presents a new approach for effective production in deep extra-heavy-oil reservoirs.