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Western Australia
All are playful nicknames for the oil and gas icon known as a pumpjack. To the uninformed, the pumpjack is a thing-a-ma-jig that has something to do with oil, probably "fracking" because that's what drilling rigs do, right? But as an industry-educated and well-informed reader of JPT, you know this is inaccurate. By whatever name you call it, you know that the pumpjack is the visible manifestation of an invisible physics equation, a mechanism buried deep underground that lifts reservoir fluids to the surface. You also know it is one type of artificial lift available in a stable of systems with equally curious and technical names like progressive cavity, plunger, jet, gas lift, and electrical submersible pump (ESP).
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > WA-209-P > Stag Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > WA-15-L > Stag Field (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- (26 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (0.70)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (0.70)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (0.69)
- (5 more...)
This page is currently being authored by a student at the University of Oklahoma. This page will be complete by May 6, 2020. Eagle Ford Basin (also known as the Eagle Ford Shale) is a Sedimentary Rock Formation that was deposited in the Cenomanian and Turonian ages of the Late Cretaceous Period. The late Cretaceous Period was estimated to have lasted for around 89-95 million years old This Basin covers the Southwest area of Texas to just North of Austin, Texas. This basin was deposited in an inland sea that would cover modern-day Texas.
- Geology > Rock Type > Sedimentary Rock (0.98)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.37)
- 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)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Pepper Field (0.89)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (0.70)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.52)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (0.51)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Modeling on Enhanced Gas Recovery and Evaluation CO2 Sequestration Capacity Under Different Mechanisms in Shale Gas Reservoirs
Li, Weirong (Petroleum engineering, Xi'an Shiyou University, Xian, Shaanxi) | Hou, Bingchen (Petroleum engineering, Xi'an Shiyou University, Xian, Shaanxi) | Dong, Zhenzhen (Petroleum engineering, Xi'an Shiyou University, Xian, Shaanxi) | Zhang, Tianyang (Petroleum engineering, Xi'an Shiyou University, Xian, Shaanxi) | Qian, Shihao (Petroleum engineering, Xi'an Shiyou University, Xian, Shaanxi) | Wei, Xin (Petroleum engineering, Xi'an Shiyou University, Xian, Shaanxi) | Pu, Hui (Petroleum Engineering, University of North Dakota, Grand Forks)
Abstract Carbon capture and storage in depleted shale gas reservoirs offer an opportunity to utilize CO2 for enhanced gas recovery while providing access to fossil fuels. To evaluate CO2 sequestration coupled with enhanced gas recovery (CO2-EGR-CCUS), we have developed a model that takes into account all the major contributing mechanisms of enhanced gas recovery and CO2 sequestration in shale gas. The CO2-EGR-CCUS process is divided into pe-riods of primary production, CO2 huff and puff, and CO2 sequestration. Firstly, a dual-porosity, dual-porosity-dual-permeability model was built for a shale gas well in Weiyuan Field, the production history was matched, and the depletion production was predicted. Then, the CO2 huff and puff scheme was optimized to maximize gas recovery, including CO2 injection timing, injec-tion rate, injection time, soaking time, and production times. After that CO2 sequestration mass at different times under different mechanisms was calculated, including adsorption sequestra-tion, structural sequestration, residual sequestration, dissolution sequestration, and mineral se-questration. This investigation shows that 17.11% percent of the injected CO2 can be sequestered in shale while providing 4-13% incremental gas recovery. The main CO2 storage mechanisms in this shale gas reservoir for the long term is adsorption sequestration(73.73%), followed by structural sequestration(22.68%), dissolution sequestration (0.98%), mineral sequestration(0.62%), and re-sidual sequestration(1.99%), while the dissolution sequestration and mineral sequestration mass will increase with time. This study has made made a number of significant contributions to the field of evalution CO2 sequestration capacity for unconventional resources, including evaluate CO2 sequestration ca-pacity under different mechanisms, and identify the main CO2 storage mechanisms during CO2 enhanced gas recovery in shale gas reservoirs. Introduction To address the shortage of conventional energy and meet international commitments to "carbon neutrality", the development of unconventional energy sources is of great stra-tegic significance for adjusting the domestic energy structure, ensuring energy security, and reducing carbon emissions . Unconventional energy mainly refers to oil and gas re-sources including tight oil, shale oil, tight gas, shale gas, and coal bed methane. Shale gas, as a clean energy source, has good development potential and value , and China has abundant shale gas resources , mainly concentrated in the Sichuan Basin and the Ordos Basin . The Sichuan Basin, as the main area of shale gas resources in China and one of the most successful development areas, mainly distributes in the east and southwest. By adopting the concept of "pressure-controlled production" for Silurian-Ordovician shale gas, the average ultimate recoverable reserves (EUR) per well has been increased from 0.9×10 m to 1.2×10 m.
- Oceania > Australia > Western Australia > North West Shelf > Muderong Shale Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (13 more...)
Molecular-Scale Quantitative Evaluation of the Competitive Sorption of Methane and Carbon Dioxide on the Different Constituents of Organic-Rich Mudrocks
Gomaa, Ibrahim (The University of Texas at Austin) | Heidari, Zoya (The University of Texas at Austin) | Espinoza, D. Nicolas (The University of Texas at Austin)
ABSTRACT Clay minerals and kerogen, dominant components of organic-rich mudrocks, play a key role in carbon dioxide (CO2) and methane (CH4) sorption. Studying CO2 sorption in organic-rich mudrocks is essential for both enhanced gas recovery (EGR) and carbon capture utilization and storage (CCUS) applications. Most studies so far have explored the sorption of CH4 and CO2 on kerogen and clay structures separately and overlooked their competitive sorption behavior at the molecular scale. The objectives of this paper are to (a) evaluate the CH4 and CO2 sorption capacity of different kerogen types under reservoir pressure and temperature, (b) quantify the influence of kerogen thermal maturity on the competitive sorption of CH4 and CO2 gases, and (c) evaluate the CH4 and CO2 sorption capacity of illite and kaolinite clays with different surface charges. We used realistic kerogen molecular models that were condensed and optimized to mimic the actual kerogen structures. Kerogen molecules of different types (i.e., type I, II, and III) and different thermal maturity levels were transformed into dense porous structures through an annealing process. Meanwhile, illite and kaolinite samples were modeled honoring their real chemical composition, surface charges, and pore size. We then performed Grand Canonical Monte Carlo (GCMC) simulations to evaluate the CH4 and CO2 sorption isotherms for kerogen and clay structures. To investigate the effect of reservoir temperature on the sorption capacity, sorption isotherms were constructed for a pressure range of 1–20 MPa under temperatures of 300 K, 330 K, 360 K, and 400 K. Results show a tight relation between the kerogen geochemical structure and gas sorption capacity. Changing kerogen types from type IA, to type IIIA led to increase the CO2 sorption capacity by 300% at temperature and pressure of 400 K and 20 MPa, respectively. Moreover, increasing kerogen thermal maturity from type IIA to type IID raised the CO2 sorption capacity from 2.8 to 5.48 mmol/g at the same pressure and temperature conditions. Meanwhile, the negative surface charge of the illite clay reduced its CO2 sorption capacity by 55% compared to the neutral kaolinite clay. The helium void fractions of illite and kaolinite clay minerals were found to be higher than all the tested kerogen types, however, most kerogen structures demonstrated higher surface area than clays. This made the CO2 and CH4 sorption capacity of both kerogens and clays intercalated under the tested temperature and pressure conditions. Therefore, characterizing the clay mineral composition and total organic carbon content (TOC) of organic-rich mudrocks is crucial for EGR and CCUS applications.
- Europe (1.00)
- North America > United States > Texas (0.70)
- Research Report > New Finding (0.88)
- Research Report > Experimental Study (0.66)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.31)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- Oceania > Australia > Western Australia > North West Shelf > Muderong Shale Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (7 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (2 more...)
An empirical elastic anisotropy prediction model in self-sourced reservoir shales and its influencing factor analysis
Zhao, Luanxiao (Tongji University) | Cai, Zhenjia (Tongji University) | Qin, Xuan (University of Houston) | Wang, Yang (University of Houston) | Long, Teng (University of Houston) | Han, De-Hua (University of Houston) | Zhang, Fengshou (Tongji University) | Geng, Jianhua (Tongji University)
ABSTRACT Organic shales can split into laminae or thin layers due to their fissility and are usually characterized as transverse isotropic media. Understanding their elastic and anisotropic properties plays a significant role in geophysical modeling and imaging, reservoir geomechanics, and reservoir characterization. One can obtain their velocity anisotropy through laboratory and field measurements or rock-physics models. However, the measurements are scarce, and theoretical modeling of Thomsen’s anisotropy parameters generally requires extra inputs, which are sometimes difficult to obtain. We have compiled ultrasonic data from 159 self-sourced reservoir shale samples from the literature and our own measurements. Simple exponential models can capture the trends of the P- and S-wave anisotropy parameters and decreasing with the increasing vertical P- and S-wave velocities, with being above 0.84. The error in estimated anisotropy is small for high-velocity () shales but relatively large for low-velocity () shales. We analyze the influence of multiple geologic factors on the proposed anisotropy-velocity relationships. We observe that velocity anisotropy generally increases with clay content. In addition, mature shales (0.6 < Ro (%) < 1.4) generally have stronger anisotropy strength spreading in a broader range than overmature shales (Ro (%) > 1.4). Overall, no single parameter dominates the source of velocity anisotropy, which is jointly affected by the coupled factors of clay content, organic matter, porosity, maturity level, and geologic history. The empirical model has the potential to offer a fast and straightforward method of predicting P- and S-wave anisotropy strength from vertical P- and S-wave velocities.
- North America > United States > Texas (1.00)
- Asia > China (1.00)
- Oceania > Australia > Western Australia > Canning Basin (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin (0.99)
- (29 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Multiscale Pore Structure Evolution of Longmaxi Shale Induced by Acid Treatment
Xu, Sai (Key Laboratory of Tectonics and Petroleum Resources, Ministry of Education, China University of Geosciences, Wuhan) | Zhou, Shangwen (Research Institute of Petroleum Exploration and Development, PetroChina, Beijing) | Zhou, Junping (State Key Laboratory of Coal Mine Disaster Dynamics and Control, Chongqing University) | Wang, Lei (College of Resources and Environmental Science, Chongqing University) | Sheng, Mao (Key Laboratory of Tectonics and Petroleum Resources, Ministry of Education, China University of Geosciences, Wuhan) | Cai, Jianchao (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing)
Summary Hydraulic fracturing to generate complex fracture networks is essential for shale reservoir development. However, the recovery of shale oil and gas is still low due to various engineering and geological factors. Acid treatment has been approved as a potential approach to enhance stimulated reservoir volume (SRV) by changing petrophysical and mechanical properties. Understanding the multiscale pore structure evolution behind the macro-performance change is critical in the application of acid treatment in shale reservoirs. In this study, cylindrical and powder shale samples from the Longmaxi formation are treated with 15 wt% hydrochloric acid (HCl) for 10 days. Before and after acid treatment, X-ray computed tomography (CT) and N2 adsorption techniques are used to characterize shale pore structure at microscale and nanoscale, respectively. Combined with the determination of variations in chemical compositions of shale samples and acid solutions, the mechanism of multiscale pore structure evolution induced by acid treatment is discussed. The N2 adsorption results uncover a considerable increase in volume and size of nanopores. All the nanopores increase in carbonate-rich shale, whereas the micropores and mesopores undergo a decrease in clay-rich shale. Reconstructed 3D CT images reveal the generation of large volumes of microscale pores and fractures, which leads to an increase in porosity of about 9%. The pore structure evolution in shale due to acid treatment is controlled by both mineralogy and microstructure. These findings demonstrate the promise of acid treatment for enhanced SRV and long-term productivity of shale oil and gas reservoirs in China.
- Asia > China (1.00)
- North America > United States > North Dakota (0.93)
- South America > Argentina > Neuquén Province > Neuquén (0.28)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (22 more...)
Abstract The exploration of unconventional hydrocarbon resources mainly targets the tight source rock reservoirs where hydraulic fracturing is needed for an effective hydrocarbon production. This project aims to predict new areas with high hydrocarbon production potential that can be effectively stimulated/fractured, known as sweet spots, in a tight Jurassic carbonate source rock. A rock physics model was developed to link the seismic properties to rock properties of the target formation. Three main rock properties are used in this study to define the sweet spots: total organic content (TOC), Young's modulus (YM) and Poisson's ratio (PR). TOC is a geochemical property that is related to the production potential and is obtained in the laboratory from core, while YM and PR are rock elastic properties that are related to the frackability and are obtained from density and sonic (compressional and shear) logs. Sweet spots are generally characterized by high values of TOC, high values of YM and low values of PR. Using well data, these three properties were cross-plotted against two derivative elastic properties (lambda-rho and mu-rho) that are calculated using sonic (compressional and shear) and density logs to obtain a linear relationship. Lambda and mu are measures of incompressibility and shear rigidity, respectively, while rho is density. Cutoffs of lambda-rho and mu-rho were chosen to represent the sweet spots. The distribution of sweet spots in the study area was then mapped using a rock physics model that is built by integrating two inverted 3D seismic volumes; lambda-rho and mu-rho. Results show that sweet spots are characterized by low values of lambda-rho and mu-rho, and are well distributed in the study area. In addition, results show that TOC has an inverse relationship with frackability which means that there should be a balance between reservoir quality and completion quality when targeting sweet spots for more economical hydrocarbon production.
- Asia > Middle East > Saudi Arabia (0.70)
- North America > United States > Texas (0.47)
- Research Report > New Finding (0.89)
- Research Report > Experimental Study (0.69)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (0.50)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (0.35)
- South America > Falkland Islands > South Atlantic Ocean > North Falkland Basin > PL032 > Sea Lion Field > F3 Sands Formation (0.99)
- South America > Falkland Islands > South Atlantic Ocean > North Falkland Basin > PL 004A > Sea Lion Field > F3 Sands Formation (0.99)
- Oceania > Australia > Western Australia > Perth Basin (0.99)
- (13 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
A New Workflow for Improved Resistivity-Based Water Saturation Assessment in Organic-Rich Mudrocks: Application to Haynesville, Eagle Ford, and Woodford Formations
Dash, Sabyasachi (The University of Texas at Austin) | Garcia, Artur Posenato (The University of Texas at Austin) | Heidari, Zoya (The University of Texas at Austin (Corresponding author))
Summary Reliable fluid saturation assessment in organic-rich mudrocks has been a challenge for the oil and gas industry. The composition and spatial distribution of rock components have a significant impact on electrical resistivity and, thus, on hydrocarbon reserves estimates. Clays are typically considered, in resistivity models, to be distributed in laminated or dispersed forms. Additionally, conventional resistivity models do not incorporate conductive components other than brine. Such assumptions can lead to uncertainty in fluid saturation assessment in organic-rich mudrocks. We introduce a well-log-based workflow that quantitatively assimilates the type and spatial distribution of all conductive components to improve reserves evaluation in organic-rich mudrocks and demonstrate its field application in the Eagle Ford, the Woodford, and the Haynesville formations. The introduced workflow consists of an inversion algorithm to estimate geometry-dependent parameters (depolarization factors or geometric model parameters) and water saturation. Inputs to the inversion algorithms include volume concentrations of minerals, estimated from the multimineral analysis. Other inputs are conductivity of rock components and porosity obtained from laboratory experiments and interpretation of well logs. The petrophysical model considers that brine forms the conductive background to which conductive (e.g., clay, pyrite, and kerogen) and nonconductive (e.g., grains and hydrocarbon) components are incorporated. The assumed/estimated petrophysical properties have an impact on the effective conductivity of the rock and thereby can impact the performance of the new resistivity-based method. We applied the new method to different organic-rich mudrock formations to test the universal nature of the method and its efficacy in organic-rich mudrock reservoirs with varying volumetric concentrations of minerals within the rock. We successfully applied the workflow to four wells in the Eagle Ford, the Woodford, and the Haynesville formations. The formation-by-formation inversion showed a variation in geometric model parameters in different petrophysical zones, resulting in improved water saturation estimates. A comparison of the results obtained from the new workflow against those from the Waxman-Smits and Archie models indicated a relative improvement in saturation estimates of 9.5 and 26.3% in the Eagle Ford formation. Similar improvements were noted in the Woodford and the Haynesville formations as well. The improvement can be enhanced in formations with larger fractions of conductive components. The results confirmed that the new workflow improves the reliability of water saturation estimates in organic-rich mudrocks, which has been a challenge for the oil and gas industry. In contrast to conventional techniques, the new method does not need water saturation obtained from core measurements for calibration efforts. All the parameters in the new workflow are geometry- or physics-based. We verified that formation-based geometric model parameters in the Eagle Ford formation were consistent in both wells, which is promising for calibration-free assessment of water/hydrocarbon saturation in the field-scale domain using electrical resistivity measurements. The new method minimizes the need for expensive and time-consuming core measurements of water saturation, which is a unique contribution of this work. Finally, the new workflow is physics-based and incorporates the volumetric concentration and electrical conductivity of all rock components. This enables the introduced workflow to be applied to different formations with ease for improved assessment of water saturation.
- North America > United States > Texas (1.00)
- Europe (1.00)
- Asia (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (1.00)
- Geology > Mineral (1.00)
- Oceania > Australia > Western Australia > Canning Basin (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (34 more...)
Seismic characterization of in situ stress in orthorhombic shale reservoirs using anisotropic extended elastic impedance inversion
Li, Lin (China University of Petroleum (East China), China University of Petroleum (East China)) | Guo, Yanmin (Liaohe Oilfield Company of CNPC) | Zhang, Guangzhi (China University of Petroleum (East China), China University of Petroleum (East China)) | Pan, Xinpeng (Central South University, Central South University) | Zhang, Jiajia (China University of Petroleum (East China), China University of Petroleum (East China)) | Lin, Ying (China University of Petroleum (East China), China University of Petroleum (East China))
ABSTRACT Seismic characterization of anisotropic in situ stress is of great importance in improving the success of planning drilling and hydraulic fracturing treatment. Shales generally exhibit orthorhombic elastic symmetry due to the presence of vertical fractures and horizontal fine layering. We propose a novel anisotropic extended elastic impedance (AEEI) inversion approach for in situ stress estimates in shale gas reservoirs with weakly orthorhombic symmetry. Considering an orthorhombic model formed by a system of aligned vertical fractures embedded in a vertical transverse isotropic (VTI) background rock, we first derive the in situ stress expression by combining poroelastic Hooke’s law and linear slip theory. Next, we deduce a linearized PP-wave reflection coefficient as a function of fluid bulk modulus, vertical effective stress-sensitive parameter, dry-rock P- and S-wave moduli, density, dry normal and tangential weaknesses of the VTI background, and dry normal and tangential weaknesses of vertical fractures. To estimate in situ stress from the observed seismic data, we derive the AEEI and Fourier coefficients (FCs) expression and establish a three-step AEEI inversion workflow involving (1) Bayesian seismic inversion for intercept impedance, gradient impedance, and curvature impedance estimates; (2) estimating model parameters using the FCs of AEEI; and (3) estimating in situ stress using the inverted model parameters. The synthetic examples demonstrate that in situ stress can be reliably estimated even with moderate noise. Test on a real data set implies that the proposed method can generate reasonable results of in situ stress that are helpful for optimizing the horizontal drilling and hydraulic fracture stimulations of shale gas reservoirs.
- Asia > China (1.00)
- North America (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > Canada > Saskatchewan > Athabasca Basin (0.99)
- North America > Canada > Alberta > Athabasca Basin (0.99)
- Asia > India > Andhra Pradesh > Bay of Bengal > Krishna-Godavari Basin (0.99)
- (5 more...)
Multiscale Pore Structure Evolution of Longmaxi Shale Induced by Acid Treatment
Xu, Sai (Key Laboratory of Tectonics and Petroleum Resources, Ministry of Education, China University of Geosciences, Wuhan) | Zhou, Shangwen (Research Institute of Petroleum Exploration and Development, PetroChina, Beijing) | Zhou, Junping (State Key Laboratory of Coal Mine Disaster Dynamics and Control and College of Resources and Environmental Science, Chongqing University) | Wang, Lei (Key Laboratory of Tectonics and Petroleum Resources, Ministry of Education, China University of Geosciences, Wuhan) | Sheng, Mao (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing) | Cai, Jianchao (Key Laboratory of Tectonics and Petroleum Resources, Ministry of Education, China University of Geosciences, Wuhan and State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing (Corresponding author))
Summary Hydraulic fracturing to generate complex fracture networks is essential for shale reservoir development. However, the recovery of shale oil and gas is still low due to various engineering and geological factors. Acid treatment has been approved as a potential approach to enhance stimulated reservoir volume (SRV) by changing petrophysical and mechanical properties. Understanding the multiscale pore structure evolution behind the macro-performance change is critical in the application of acid treatment in shale reservoirs. In this study, cylindrical and powder shale samples from the Longmaxi formation are treated with 15 wt% hydrochloric acid (HCl) for 10 days. Combined with the determination of variations in chemical compositions of shale samples and acid solutions, the mechanism of multiscale pore structure evolution induced by acid treatment is discussed. All the nanopores increase in carbonate-rich shale, whereas the micropores and mesopores undergo a decrease in clay-rich shale. Reconstructed 3D CT images reveal the generation of large volumes of microscale pores and fractures, which leads to an increase in porosity of about 9%. The pore structure evolution in shale due to acid treatment is controlled by both mineralogy and microstructure. These findings demonstrate the promise of acid treatment for enhanced SRV and longterm productivity of shale oil and gas reservoirs in China. Introduction Shale oil and gas are important unconventional hydrocarbon resources with huge reserves, the development of which requires the integration of geology and engineering (Jarvie et al. 2007; Zou et al. 2010; Cai et al. 2021; Zhu et al. 2022). To exploit such unconventional reservoirs, hydraulic fracturing with horizontal drilling is necessary to achieve economic productivity (Zou et al. 2010; Wang et al. 2014; Soeder 2018).
- Asia > China (1.00)
- North America > United States > North Dakota (0.93)
- South America > Argentina > Neuquén Province > Neuquén (0.28)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (22 more...)