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Results
Investigating the causes of permeability anisotropy in heterogeneous conglomeratic sandstone using multiscale digital rock
Chi, Peng (China University of Petroleum (East China), China University of Petroleum (East China)) | Sun, Jianmeng (China University of Petroleum (East China), China University of Petroleum (East China)) | Yan, Weichao (Ocean University of China, Ocean University of China) | Luo, Xin (China University of Petroleum (East China), China University of Petroleum (East China)) | Ping, Feng (Southern University of Science and Technology)
Heterogeneous conglomeratic sandstone exhibits anisotropic physical properties, rendering a comprehensive analysis of its physical processes challenging with experimental measurements. Digital rock technology provides a visual and intuitive analysis of the microphysical processes in rocks, thereby aiding in scientific inquiry. Nevertheless, the multiscale characteristics of conglomeratic sandstone cannot be fully captured by a single-scale digital rock, thus limiting its ability to characterize the pore structure. Our work introduces a proposed workflow that employs multiscale digital rock fusion to investigate permeability anisotropy in heterogeneous rock. We utilize a cycle-consistent generative adversarial network (CycleGAN) to fuse CT scans data of different resolutions, creating a large-scale, high-precision digital rock that comprehensively represents the conglomeratic sandstone pore structure. Subsequently, the digital rock is partitioned into multiple blocks, and the permeability of each block is simulated using a pore network. Finally, the total permeability of the sample is calculated by conducting an upscaling numerical simulation using the Darcy-Stokes equation. This process facilitates the analysis of the pore structure in conglomeratic sandstone and provides a step-by-step solution for permeability. From a multiscale perspective, this approach reveals that the anisotropy of permeability in conglomeratic sandstone stems from the layered distribution of grain sizes and differences in grain arrangement across different directions.
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 338 > Block 16/1 > Edvard Grieg Field > ร sgard Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 338 > Block 16/1 > Edvard Grieg Field > Skagerrak Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 338 > Block 16/1 > Edvard Grieg Field > Hegre Formation (0.99)
- (3 more...)
Simultaneous prediction of the geofluid and permeability of reservoirs in prestack seismic inversion
Yang, Wenqiang (Laoshan Laboratory, China University of Petroleum (East China), Pilot National Laboratory for Marine Science and Technology (Qingdao)) | Zong, Zhaoyun (Laoshan Laboratory, China University of Petroleum (East China), Pilot National Laboratory for Marine Science and Technology (Qingdao)) | Sun, Qianhao (Laoshan Laboratory, China University of Petroleum (East China), Pilot National Laboratory for Marine Science and Technology (Qingdao))
ABSTRACT Geofluid discrimination and permeability prediction are indispensable steps in reservoir evaluation. From the perspective of prestack seismic inversion, predicting fluid indicators is an effective method for obtaining fluid properties directly from seismic data. In contrast, the direct prediction of permeability from observed seismic gathers is constrained by the difficulty in establishing a link between permeability and elastic parameters. However, we show that the pore structure parameters in seismic petrophysical theory are highly related to permeability, providing a new solution for predicting permeability using seismic data. Therefore, the correlation between the shear flexibility factor and permeability is first verified based on logging curves and laboratory data, and the results demonstrate that the shear flexibility factor can be an indicator of reservoir permeability. Second, an approximate reflection coefficient equation is derived for the direct characterization of the shear flexibility factor. In the developed equation, a novel fluid indicator, expressed as the ratio of Russellโs fluid indicator to the square of the shear flexibility factor, is defined for the simultaneous prediction of fluid types and permeability. With the validated response of the novel fluid indicator to geofluid types, we achieve simultaneous predictions of fluid types and reservoir permeability characteristics from prestack seismic data, using a boundary-constrained Bayesian inversion strategy. The model tests and the application of field data from a clastic reservoir confirm the effectiveness and applicability of the method.
- Asia > China > Sichuan Province (0.28)
- North America > United States > Texas (0.28)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.69)
- Geophysics > Seismic Surveying > Seismic Processing > Seismic Migration (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling > Seismic Inversion (1.00)
- Oceania > New Zealand > North Island > Taranaki 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)
- (24 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
Frequency-dependent elastic properties of fracture-induced VTI rocks in a fluid-saturated porous and microcracked background
Wang, Wenhao (China University of Petroleum (East China)) | Li, Shengqing (China University of Petroleum (East China), Laoshan National Laboratory) | Guo, Junxin (Guangdong Provincial Key Laboratory of Geophysical High-resolution Imaging Technology, Southern University of Science and Technology) | Zhang, Chengsen (PetroChina Tarim Oilfield Company) | Duan, Wenxing (PetroChina Tarim Oilfield Company) | Su, Yuanda (China University of Petroleum (East China), Laoshan National Laboratory) | Tang, Xiao-Ming (China University of Petroleum (East China), Laoshan National Laboratory)
Fractures are widely distributed underground. The stiffness matrix of fractured rocks has been extensively investigated in a fluid-saturated porous background medium. However, the existing stiffness models only incorporated the attenuation mechanism of wave-induced fluid flow (WIFF). For macroscopic fractures, the elastic scattering (ES) of fractures cannot be ignored. To alleviate this issue, a frequency-dependent stiffness matrix model was developed, including the mesoscopic wave-induced fluid flow between fractures and background (FB-WIFF), the microscopic squirt flow, and the macroscopic ES from the fractures. By combining the far-field scattered wavefields of normal incident P and SV waves with the linear slip theory, the dynamic full-stiffness matrices for fracture-induced effective VTI rocks in a fluid-saturated porous and microcracked background were derived. Then, the P, SV, and SH wave velocities and attenuation can be obtained through the Kelvin-Christoffel equation. The results indicate that the FB-WIFF mechanism significantly affects the velocities and attenuation of the P and SV waves, but has nearly no effect on the SH wave, while the squirt flow and ES mechanisms affect the velocities and attenuation of both the P, SV, and SH waves. For validation, the model was compared with existing models and previous experimental ultrasonic data.
- North America > United States > New Mexico > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
- North America > United States > Colorado > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
- Asia > China > Xinjiang Uyghur Autonomous Region > Tarim Basin (0.99)
- Asia > China > Sichuan > Sichuan Basin (0.95)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
Abstract Drilling for groundwater is expensive and challenging. It is even more challenging to find a location that will result in a high-yield well in heterogeneous environments. To tackle the heterogeneity issue, geophysical surveys can help in mapping the subsurface structure and delineating the drilling trajectory. The current study displays the effectiveness of 3D electrical resistivity tomography (ERT) to locate a permeable groundwater zone within a highly heterogeneous and clayey subsurface. Ground truthing the acquired geophysical data with in-situ sampling helps ensure accuracy in classifying groundwater zones in the final inverted 3D data set while also delineating boundaries between permeable groundwater zones and less permeable clayey structures. In-situ samples of groundwater and soil were used to measure the saturated region's resistivity in the laboratory using a column setup. Clay zones in the data set are classified from the nearby well data at similar depth ranges and from very low resistivity values from ERT data and laboratory measurements. The results display highly differentiating resistivity zones that are attributed to the scattered clay lenses (low resistivity) in conjunction with the freshwater zone (high resistivity). The distinction between clayey and nonclayey bodies is important to better inform drilling locations for optimal groundwater yield. This study concludes that with the aid of low-cost geophysical surveys and minimal in-situ sampling data correlations, permeable groundwater boundaries and clay lens volumes can be identified easily.
- Asia (1.00)
- North America > United States (0.69)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock (0.94)
- Geology > Geological Subdiscipline (0.93)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (0.91)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (0.88)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.68)
Effects of Drilling Number and Distribution on Fracture Using the Pulse Plasma on Tight Sand Reservoir
Li, Zhaoxuan (Petroleum and Gas Engineering, LiaoNing Petrochemical University) | Wang, Shuo (Petroleum and Gas Engineering, LiaoNing Petrochemical University) | Pan, Yi (Petroleum and Gas Engineering, LiaoNing Petrochemical University (Corresponding author)) | Zhang, Rongqi (Petroleum and Gas Engineering, LiaoNing Petrochemical University) | Chen, Jiajun (Petroleum and Gas Engineering, LiaoNing Petrochemical University)
Petroleum and Gas Engineering, LiaoNing Petrochemical University Summary The permeability of unconventional reservoirs is extremely low, resulting in their drainage area being limited to tens of feet. Therefore, researchers have developed an effective stimulation technology that can be used in combination with conventional hydraulic fracturing, namely, pulsed plasma fracturing technology. Pulsed plasma fracturing technology is an efficient and environmentally friendly auxiliary hydraulic fracturing stimulation technology. However, most existing studies have focused only on the effect of pulsed plasma fracturing on single wells, ignoring the effect of the number and distribution of wells drilled on pulsed plasma fracturing. In this paper, pulsed plasma fracturing is studied by a self-built pulsed plasma experimental platform and nonlinear finite element software. First, the generation and propagation mechanism of shock wave, fracture type, and stress field analysis of rock mass in pulsed plasma fracturing technology are discussed. The double-well experiment was carried out by using the experimental platform, and the fracture law of fractures under different wellhead distribution conditions was obtained. In addition, a multiwell mathematical model is established by using the combination of the Euler method and Lagrange method to simulate the interaction between fluid and solid, that is, arbitrary Lagrangian Eulerian (ALE) multimaterial fluid-solid coupling method and the influence of drilling times and wellhead distribution on pulsed plasma fracturing is discussed. Stress analysis shows that the rock is mainly affected by ground stress, liquid column pressure, and shock wave pressure. The experimental results show that the discharge voltage is positively correlated with the shock wave pressure on the rock. The distribution of different wellheads affects the distribution and length of fractures. The double-well experiment makes the fractures easier to fracture. The simulation results show that the fracture length in the connection direction of the two wells is longer, and the fracture length in the vertical direction is shorter. This shows that the number and distribution of drilling affect the initiation and propagation of fractures. Introduction Nowadays, with the increasing demand for oil and gas resources, conventional oil fields have entered a period of exploitation attenuation (Asif and Muneer 2007; Li et al. 2017; Williamson and Esterhuyse 2020; Madon 2020).
- Research Report > Experimental Study (0.68)
- Research Report > New Finding (0.54)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.84)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- Asia > China > Liaoning > Bohai Basin > Liaohe Basin > Liaohe Field (0.99)
- Asia > China > Henan > Gucheng Field (0.99)
- Asia > China > Hebei > Bohai Basin > Huabei Field (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (0.93)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.88)
Experimental Study on Permeability and Gas Production Characteristics of Montmorillonite Hydrate Sediments Considering the Effective Stress and Gas Slippage Effect
Wu, Zhaoran (School of Vehicle and Energy, Yanshan University) | Gu, Qingkai (School of Vehicle and Energy, Yanshan University) | Wang, Lei (School of Vehicle and Energy, Yanshan University) | Li, Guijing (School of Vehicle and Energy, Yanshan University) | Shi, Cheng (School of Vehicle and Energy, Yanshan University) | He, Yufa (State Key Laboratory of Natural Gas Hydrate) | Li, Qingping (State Key Laboratory of Natural Gas Hydrate) | Li, Yanghui (Key Laboratory of Ocean Energy Utilization and Energy Conservation of Ministry of Education, Dalian University of Technology (Corresponding author))
Key Laboratory of Ocean Energy Utilization and Energy Conservation of Ministry of Education, Dalian University of Technology Summary Gas permeability in hydrate reservoirs is the decisive parameter in determining the gas production efficiency and gas production of hydrate. In the South China Sea (SCS), the gas flow in tight natural gas hydrate (NGH) silty clay reservoirs is significantly affected by the gas slippage effect and the effective stress (ES) of overlying rock. To improve the effectiveness of hydrate exploitation, it is necessary to understand the influence of gas slippage in hydrate reservoirs on the permeability evolution law. For this paper, the gas permeability characteristics and methane production of hydrate montmorillonite sediments were studied at different pore pressures and ESs. Experimental data revealed that the gas permeability of montmorillonite samples before methane hydrate (MH) formation is seriously affected by the Klinkenberg effect. The gas permeability of montmorillonite sediments before hydrate formation is generally smaller than that after hydrate formation, and the gas slippage effect in the sediments after hydrate formation is weaker than that before hydrate formation. With the change in ES, the intrinsic permeability of sediment has a power law relationship with the simple ES. As pore pressure decreases and MH decomposes, montmorillonite swelling seriously affects gas permeability. However, the gas slippage effect has a good compensation effect on the permeability of montmorillonite sediments after MH decomposition under low pore pressure. The multistage depressurization-producing process of MH in montmorillonite sediments is mainly 3 MPa depressurization-producing stage and 2 MPa depressurization-producing stage. In this paper, the influence mechanism of gas slippage effect of hydrate reservoir is studied, which is conducive to improving the prediction accuracy of gas content in the process of hydrate exploitation and exploring the best pressure reduction method to increase the gas production of hydrate in the process of exploitation. Introduction As one of the most prospective clean energy sources in the 21st century, NGH mainly exists in permafrost and continental margins of the world's oceans (Sloan Jr. and Koh 2007). MH is the most important component of NGH. MHs are ice-like crystalline compounds in which the host methane molecule is surrounded by a cage of water molecules (Sloan 1998; Li et al. 2023).
- North America > United States (1.00)
- Europe > Norway > Norwegian Sea (0.64)
- Asia > China > Liaoning Province > Dalian (0.24)
- Research Report > New Finding (0.83)
- Research Report > Experimental Study (0.64)
- Asia > China > South China Sea > Yinggehai Basin (0.99)
- Asia > China > South China Sea > Qiongdongnan Basin (0.99)
- South America > Falkland Islands > South Atlantic Ocean > South Falkland Basin > Stokes Prospect > Darwin Formation (0.94)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
A new nuclear magnetic resonance-based permeability model based on two pore structure characterization methods for complex pore structure rocks: Permeability assessment in Nanpu Sag, China
Xie, Weibiao (China University of Petroleum (Beijing) at Karamay, China University of Petroleum (Beijing)) | Yin, Qiuli (China University of Petroleum (Beijing) at Karamay) | Wu, Lifeng (China Petroleum logging Co., Ltd) | Yang, Fan (China Petroleum logging Co., Ltd) | Zhao, Jianbin (China Petroleum logging Co., Ltd) | Wang, Guiwen (China University of Petroleum (Beijing))
ABSTRACT The nuclear magnetic resonance (NMR) estimate of permeability is a fundamental method that has numerous applications in reservoir engineering and petrophysics. To improve the accuracy of the NMR-based permeability model, many variables are introduced into NMR-based permeability prediction models due to geometric complexity and pore structure heterogeneity. In this paper, two pore structure characterization methods are investigated based on the Kozeny-Carman model and equivalent component model. Furthermore, an NMR-based permeability model accounting for the effect of pore structure is developed based on the analysis of the relationship between two pore structure parameters, and it is applied to practically predict permeability. Results indicate that the new model-calculated permeability has good agreement with experimental data; moreover, the adaptability of the new NMR-based permeability prediction model is highly improved through reducing undetermined variables, and key parameters can be measured directly using NMR. The new model provides a valuable scientific resource and assists in the evaluation of hydrocarbon-bearing reservoirs with complex pore structure, such as tight sandstone, shale, and carbonate rock.
- Asia > China (1.00)
- Africa > Middle East > Egypt (0.46)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.70)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.35)
- Asia > China > Xinjiang Uyghur Autonomous Region > Junggar Basin > Lucaogou Formation (0.99)
- Asia > China > Shandong > Gaoqing Field (0.99)
- Asia > China > Bohai Basin (0.99)
- Africa > Middle East > Egypt > Gulf of Suez > Gulf of Suez Basin > Kareem Formation > Shagar Member (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Engineered Ultra-Low Invasion Loss Control Solution Allows Circulation, Ensuring Cement Placement and Zonal Isolation in Liner Cementing Jobs and Through Coiled Tubing โ Case Studies
Fazal, Muhammad Adnan (Sprint Oil and Gas Services FZC) | Ahmad, Syed Hamza (Sprint Oil and Gas Services FZC) | Yousuf, Arif (Sprint Oil and Gas Services FZC) | Rehman, Aziz ur (Sprint Oil and Gas Services FZC) | Noor, Sameer Mustafa (Oil & Gas Development Company Limited) | Nazir, Irfan (Oil & Gas Development Company Limited)
Abstract The conventional loss cure techniques are largely reactive and include addition of coarse grade particle, fibrous material and other viscous pills that are lost into formation during loss cure attempts. Being highly invasive, these loss cure solutions block pore throats and line producing fractures causing considerable formation damage and loss of net asset value. Moreover, these techniques pose additional challenges while placing thru slim liners and coiled tubing (in rigless applications) due to elevated risk of getting the circulation ports plugged. Moreover, during the era of technological revolution and decarbonization, an effective and efficient solution aids to promote the practices producing low carbon emission. The proactive wellbore shielding loss cure is a particle size distribution-based LCM solution having excellent fluid loss properties and exhibiting low permeability barrier at the fluid-rock interface. The low permeable shielding effect offers less invasion across a broad range of pores (1microns to 4,000microns) and thereby protecting formation from any permanent impairment. The solution covers the wide range applications of loss cure throughout well life ensuring zonal isolation and saving significant rig time. Customized particle size distribution does allow LCM solution to be pumpable thru liner complying the allowable particle sizes (less than 1,000microns) and concentrations (upto 18 lbs/bbl) and for coiled tubing specialized applications with allowable particles size of 100 microns while maintaining rheological properties (Fluid Loss<50 ml/30 min, 5lbs/100ft2>Ty<10lbs/100ft2 & PV<90 cp). This paper demonstrates the working principle and practical applications of engineered solution for loss cure and successfully achieving zonal isolation in 7" liner being placed as pre-cement spacer in naturally fractured formation. The wellbore shielding pre-cement spacer ensured the cement rise above loss point thus achieving zonal isolation in partial to complete losses environment and helps in minimizing formation's impairment. The same approach was adopted to cure losses in rigless with coiled tubing in both carbonate and sandstone reservoirs for well killing and zonal isolation without plugging the CT BHA and circulation ports while complying design requirements.
- South America (0.68)
- Asia > Middle East (0.28)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- (8 more...)
Simultaneous prediction of geofluid and permeability of reservoirs in pre-stack seismic inversion
Yang, Wenqiang (Laoshan Laboratory, China University of Petroleum (East China), Pilot National Laboratory for Marine Science and Technology (Qingdao)) | Zong, Zhaoyun (Laoshan Laboratory, China University of Petroleum (East China), Pilot National Laboratory for Marine Science and Technology (Qingdao)) | Sun, Qianhao (Laoshan Laboratory, China University of Petroleum (East China), Pilot National Laboratory for Marine Science and Technology (Qingdao))
Geofluid discrimination and permeability prediction are indispensable steps in reservoir evaluation. From the perspective of pre-stack seismic inversion, predicting fluid indicators is an effective method for obtaining fluid properties directly from seismic data. In contrast, the direct prediction of permeability from observed seismic gathers is constrained by the difficulty in establishing a link between permeability and elastic parameters. However, we show that the pore structure parameters in seismic petrophysical theory are highly related to permeability, providing a new solution for predicting permeability using seismic data. Therefore, the correlation between the shear flexibility factor and permeability is first verified based on logging curves and laboratory data, and the results demonstrate that the shear flexibility factor can give an indicator of reservoir permeability. Secondly, an approximate reflection coefficient equation is derived for the direct characterization of the shear flexibility factor. In the proposed equation, a novel fluid indicator, expressed as the ratio of Russellยs fluid indicator to the square of the shear flexibility factor, is defined for the simultaneous prediction of fluid types and permeability. With the validated response of the novel fluid indicator to geofluid types, we achieve simultaneous predictions of fluid types and reservoir permeability characteristics from pre-stack seismic data, employing a boundary-constrained Bayesian inversion strategy. The model tests and the application on field data from a clastic reservoir confirm the effectiveness and applicability of the method.
- Asia > China > Sichuan Province (0.28)
- North America > United States > Texas (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.68)
- Geophysics > Seismic Surveying > Seismic Processing > Seismic Migration (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling > Seismic Inversion (1.00)
- Oceania > New Zealand > North Island > Taranaki 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)
- (24 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
Heat Transfer Included Simulation of Carbonate Rock Acidizing Using Two-Scale Continuum Model with Varying Rock Physics Curves
Nami, M. H. (Department of Petroleum Engineering, Amirkabir University of Technology (Polytechnic of Tehran)) | Ahmadi, M. (Department of Petroleum Engineering, Amirkabir University of Technology (Polytechnic of Tehran) (Corresponding author)) | Sharifi, M. (Department of Petroleum Engineering, Amirkabir University of Technology (Polytechnic of Tehran))
Summary Matrix acidizing is the commonly used method to enhance permeability of a damaged zone around the well. Acid injection will dissolve the rock, creating narrow, high-permeability channels, called wormholes, to bypass the damaged zone. The pattern of wormhole generation indicates the efficiency of the well stimulation process. Although the injection rate has the most important role in this process, there are other factors such as rock properties, presence of an immiscible phase, and temperature variation that could also affect the dissolution pattern. A few studies have considered the simultaneous effects of all phenomena involved in the acidizing process. We have developed a two-phase heat transfer model coupled with a two-scale continuum model considering capillary and gravity forces for the first time, to simulate the wormhole dissolution pattern. It could be used to analyze the dissolution phenomenon of carbonate rock. A new two-phase relative permeability model is implemented to take the effect of dissolution on relative permeability curves into account. The influence of acid-rock temperature difference, reaction heat, nonisothermal condition, phase saturation, formation porosity, intrinsic permeability and heterogeneity on dissolution pattern, and number of injected pore volumes (PVs) before acid breakthrough is investigated in the developed model. The simulation results show that both optimum injection rate and required PV of acid to breakthrough are strongly dependent on acid and rock temperatures. High formation temperature increases both the optimum injection rate and the optimum number of injected PVs before breakthrough. Injection of acid at lower temperatures will decrease both the optimum injection rate and the optimum number of injected PVs to break through. Simulation results show that the optimum number of injected PVs to break through is 8% higher when reaction heat is considered. Formation properties and degree of heterogeneity influence the number of required injected PVs to breakthrough. Low porosity formations with high heterogeneity correspond to the lowest number of injected PVs to breakthrough. The results indicated that formations with higher permeability will have a higher optimum number of injected PVs to break through and an optimum injection rate. Simulated results show that increasing the initial water saturation will increase the volume of acid to breakthrough. Variation in initial water saturation has a minor effect on wormhole shape, but it does not change the dissolution regime.
- Europe (1.00)
- Asia (0.67)
- North America > United States > Texas (0.28)
- Research Report > New Finding (0.88)
- Research Report > Experimental Study (0.88)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.84)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)