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Petroleum Engineering, University of Houston, 2. Metarock Laboratories, 3. Department of Earth and Atmospheric Sciences, University of Houston) 16:00-16:30 Break and Walk to Bizzell Museum 16:30-17:30 Tour: History of Science Collections, Bizzell Memorial Library, The University of Oklahoma 17:30-19:00 Networking Reception: Thurman J. White Forum Building
- Research Report > New Finding (0.93)
- Overview (0.68)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral (0.72)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.68)
- (2 more...)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.93)
- North America > United States > Texas (1.00)
- Europe (0.93)
- Research Report > New Finding (0.93)
- Overview (0.88)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.47)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.93)
Abstract CO2 capillary trapping increases the total amount of CO2 that can be effectively immobilized in storage aquifers. This trapping, manifesting itself as accumulated CO2 columns at a continuum scale, is because of capillary threshold effects that occur below low-permeability barriers. Considering that capillary pressure is dictated by heterogeneous pore throat size, the trapped CO2 column height and associated CO2 saturation will vary spatially within a storage aquifer. This variation will be influenced by two pressure-dependent interfacial parameters: CO2-brine interfacial tension and CO2-brine-rock contact angle. Our objective is to understand how the pressure-dependence of these two parameters affects the heterogeneity of capillarity-trapped CO2 at a continuum scale. Our conceptual model is a one-dimensional two-zone system with the upper zone being a flow barrier (low permeability) and the lower zone being a flow path (high permeability). The inputs to this model include microfacies-dependent capillary pressure versus saturation curves and permeability values. The input capillary pressure curves were collected in literature that represents carbonate microfacies (dolomudstone, dolowackstone, dolopackstone, and dolograinstone) in a prevalent formation in the Permian Basin. We then employed the Leverett j-function to scale the capillary pressure curve for the two zones that are assigned with the same or different microfacies. During scaling, we considered the influence of pressure on both the interfacial tension and contact angle of CO2/brine/dolomite systems. We varied the zone permeability contrast ratio from 2 to 50. We then assumed capillary-gravity equilibriums and calculated the CO2 saturation buildup corresponding to various trapped CO2 column heights. The CO2 saturation buildup is defined as the CO2 saturation in the lower layer minus that in the upper one. We found that the saturation buildup can be doubled when varying pressure in a storage aquifer, after considering pressure-dependent interfacial tension and contact angles. Thus, assuming these two parameters to be constant across such aquifers would cause large errors in the quantification of capillary trapping of CO2. The whole study demonstrates the importance of considering pressure-dependent interfacial properties in predicting the vertical distribution of capillary-trapped CO2. It has important implications in developing a better understanding of leakage risks and consequent storage safety.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > CO2 capture and management (1.00)
Dynamics of Surfactant Imbibition in Unconventional Reservoir Cores
Wei, B. (Southwest Petroleum University, Chengdu, Sichuan, China) | Wang, Y. (Southwest Petroleum University, Chengdu, Sichuan, China / The University of Tulsa, Tulsa, Oklahoma, the United States) | Wang, L. (Southwest Petroleum University, Chengdu, Sichuan, China) | Li, Q. (Southwest Petroleum University, Chengdu, Sichuan, China) | Lu, J. (The University of Tulsa, Tulsa, Oklahoma, the United States) | Tang, J. (United Arab Emirates University, Al Ain, United Arab Emirates)
Abstract Despite the promising results observed from the utilization of interfacial-active additives in enhancing imbibition-based oil recovery from tight reservoirs, the predominant mechanisms governing this process remain inadequately understood. A meticulously designed workflow was implemented to conduct experimental and modeling studies focusing on imbibition tests performed on tight cores utilizing surfactant and microemulsion. The primary objective of this research was to investigate the response of oil recovery to these additives and to develop a robust and reliable model that incorporates the intricate interactions, thereby elucidating the underlying mechanisms. We systematically designed and prepared two imbibition fluids, namely surfactant (AES) and microemulsion (mE), while utilizing brine as a reference fluid. A comprehensive investigation was conducted to analyze the physicochemical properties of these fluids, encompassing phase behavior, density, viscosity, and wettability alteration, with the aim of establishing fundamental knowledge in the field. Imbibition tests were carried out on oil-wet cores to observe the response of oil production and optimize the experimental methodology. Subsequently, we proposed a numerical model that fully coupled the evolution of relative permeability and capillary pressure with the dynamic processes of emulsification, solubilization, and molecular diffusion. All tested fluids exhibited favorable density (1.05-1.07 g/cm) and viscosity (1.0 cp) at the reservoir temperature of 44 ยฐC. AES effectively reduced the oil-water interfacial tension (IFT) to 10 mN/m, while mE achieved an ultralow IFT of 10 mN/m, accompanied by strong emulsification capability and a high solubilization ratio. Both solutions demonstrated the ability to alter the wettability of the rock surface from oil-wet to water-wet, albeit through different mechanisms (adsorption for AES and solubilization for mE). In line with the IFT and phase behavior experiments, imbibition tests on cores revealed that aqueous solutions with interfacial-active additives resulted in significantly higher oil recovery compared to pure water. Notably, the core treated with mE exhibited the highest oil recovery, reaching 36.5% of the original oil in place (OOIP). To further elucidate the observed effects, a modeling study was conducted, considering the aforementioned mechanisms. The results demonstrated the crucial role of emulsification/solubilization in the imbibition process.
- North America > United States > Texas (0.47)
- Asia > Middle East > UAE (0.28)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Wolfcamp Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Experimental Study of Surfactant Flooding on Organic Shale with Integrated Characterization
Jiang, T. | El-Sobky, H. F. (ConocoPhillips) | Bonnie, R. J. M. (ConocoPhillips) | Bone, R. (ConocoPhillips) | Beveridge, W. (ConocoPhillips) | Carman, P. S. (ConocoPhillips) | Jweda, J. (ConocoPhillips) | Long, H. (ConocoPhillips) | MacMillan, A. (ConocoPhillips) | Nguyen, V. H. (ConocoPhillips) | Warren, L. (ConocoPhillips) | McLin, K. S. (ConocoPhillips)
Abstract Enhanced oil recovery from organic shale reservoirs has increasingly gained interest from oil and gas industry in recent years. The recovery factor of organic shale oil production depends on formation wettability and pore fluid trapping mechanisms. A combination of hydraulic fracturing and surfactant flooding can be used to reduce oil trapping and increase oil recovery by reducing the interfacial tension and decreasing oil wettability. A novel experimental workflow has been developed based on fluid flow monitoring and NMR characterization to study the effect of surfactant flooding on organic-rich shales in the lab. Two blends of surfactants (cationic and nonionic) were carefully selected from prior contact angle (CA) and interfacial tension (IFT) measurements for the surfactant flooding tests. Micro-CT screening was used to select fracture-free samples for these tests. Prior to flooding we acquired nuclear magnetic resonance (NMR) T1-T2 measurements on as-received core samples to establish base-line water and oil saturations. Next, the core samples were pressure-saturated with crude oil at reservoir pressure and temperature, and we continued the aging process for a given time. Following aging, core samples were flooded using continuous crude oil injection from one end of the core sample whilst monitoring fluid flow rate, temperature, and pressure. Robust initial effective oil permeability was computed when the flow system reached steady state. Next, fracturing fluids -with and without surfactants- were injected from the opposite end of the core plugs to simulate the forced imbibition of fracturing fluid along with hydraulic fracturing in real field operations. Finally, the injection of crude oil was resumed from the original end of the core sample to establish the flowback effective oil permeability after hydraulic fracturing and surfactant flooding. We acquired NMR data after each fluid injection step to monitor fluid saturation and wettability changes in the core samples. Additionally, porosity and saturation measurements, X-ray diffraction (XRD), rock-eval pyrolysis and mercury injection capillary pressure (MICP) tests are performed to characterize fluid distribution, mineralogy and pore throat sizes of the rock samples. The results of fracturing fluid injection in all core samples clearly indicate that the water from the fracturing fluid does partially displace the crude oil in the core, effectively making this oil recoverable. Samples injected with the blend of cationic surfactants show less than 3% incremental recovery over samples with no surfactant injection. The flowback effective oil permeabilities of all core samples are much lower than the initial effective oil permeabilities prior to fracturing fluid injection. This observation is corroborated by the differences in MICP results before and after fracturing fluid injection, showing smaller pore throat sizes after fracturing fluid injection. Our novel workflow has successfully characterized the impact of surfactant flooding on organic-rich shale samples in lab-scale tests. and can be used for screening of surfactant enhanced oil recovery before running more expensive field trials.
- North America > United States > Texas (0.46)
- North America > United States > Colorado (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline (1.00)
- 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 > Permian Basin > Wolfcamp Formation (0.99)
- (3 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (3 more...)
Application of the Producer-Based Capacitance Resistance Model to Undersaturated Oil Reservoirs in Primary Recovery
Parra, Josรฉ E. (Universidad Nacional Autรณnoma de Mรฉxico (UNAM) (Corresponding author)) | Samaniego-V, Fernando (Universidad Nacional Autรณnoma de Mรฉxico (UNAM)) | Lake, Larry W. (The University of Texas at Austin)
The University of Texas at Austin Summary We investigated the application and usefulness of the producer-based representation of the capacitance resistance model (CRM) to characterize single and multiwell undersaturated oil reservoirs during primary recovery. The CRM is a physics-based, data-driven method that has been amply used to model reservoirs under different recovery stages, particularly during flooding processes. However, there have been very few applications to primary recovery. The previous work on primary recovery used the rate and bottomhole pressure (BHP) data to calculate the time constant or storage capacity, and the productivity index (PI) associated with each production well. Here, we incorporate popular productivity models in CRM, making the results comparable with those from pressure transient analysis (PTA) or rate transient analysis (RTA). We also investigate various topics that have not been discussed or that deserve a further explanation to include CRM in the reservoir engineering toolbox. These comprise constant and variable rate wells, transient flow, well location, well geometry, anisotropy, and different types of reservoir heterogeneity. CRM is systematically compared and validated against analytical and numerical models of single and multiwell reservoirs. We also use it to characterize flow in a real oil reservoir. Our results demonstrate that CRM can provide important parameters for reservoir characterization using BHP and rate data acquired from routine production operations, that is, without the need to shut in wells or perform dedicated tests. It yields reasonable estimates of flow resistance properties that depend on reservoir geology, petrophysics, and well condition. It can also be applied during successive time intervals to assess changes in well-reservoir properties, such as drainage radius or the PI, an indication of well damage. Most importantly, we show that for several well-reservoir cases with multiple complexities, CRM can accurately capture the reservoir size, or the drainage pore volume (PV) associated with each well in developed fields, which enables the calculation of average pressure and helps assess interwell communication and opportunities for infill drilling. Introduction The CRM combines reduced-physics and data-driven methods for reservoir characterization and modeling. The modern CRM is an analytical approach (Yousef et al. 2006, 2009), as opposed to the experimental models developed much earlier (Bruce 1943; Wahl et al. 1962). It is derived from a coupling of material balance (a continuity equation) and a rate equation.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Enhanced Imbibition Through Wettability Alteration During Shut-In Treatment After Hydraulic Fracturing
Fan, Xibin (Xinjiang Oilfield Company) | Wang, Wenzhong (China University of Petroleum) | Zhu, Shijie (Xinjiang Oilfield Company) | Wang, Yingwei (Xinjiang Oilfield Company) | Bai, Hao (China University of Petroleum) | Liang, Tianbo (China University of Petroleum)
ABSTRACT Tight oil reservoirs are characteristic of low porosity and permeability, complex pore-throat network, and typically oil-wet, which results in a low oil recovery rate of less than 10%. Surfactant can alter the rock wettability while maintaining an ultralow adsorption rate on rock surface, and thus can be a promising method to enhance the oil recovery. This paper uses the numerical simulation method to understand how shut-in pressure affects the imbibition of fracturing fluid when rock wettability changes. Results show that wettability has a great influence on water imbibition depth of fracturing fluid and the change of water saturation at the invasion front. There is a positive correlation between the imbibition rate and the water-oil interfacial tension in a water-wet reservoir, but a negative correlation in an oil-wet reservoir. In water-wet reservoirs, when the shut-in pressure keeps the same, the water imbibition rate is linear to sqrt (K/ฯ), and increases with the interfacial tension. When the oil-wet reservoir is altered to water-wet, although the water imbibition rate is reduced by 37%, water saturation in the invasion front significantly increases from 0%-1.75% to 8%-15%, resulting in an enhanced water imbibition efficiency of 6.25% to 15%. INTRODUCTION Abundant oil and gas resources are present in tight reservoir formations, which are widely distributed all over the world. Tight reservoirs have small pore radius, few effective pores, and complicated pore throats with abundant microfractures. In this kind of reservoir, the traditional water flooding method is difficult to achieve the effective use of crude oil. Hydraulic fracture is needed to improve the conductivity of the matrix. Research and practice indicate imbibition flooding can significantly improve recovery in fractured tight reservoirs. In general, imbibition refers to the spontaneous entry of the wetting-phase fluid into the pore throat of the rock under the action of capillary forces, displacing the non-wetting phase fluid in the pores. To study the imbibition characteristics and imbibition displacement mechanism of tight reservoir can provide an effective method for improving the recovery efficiency of tight reservoir.
- North America > United States (0.68)
- Asia > China (0.49)
- Research Report > New Finding (0.49)
- Research Report > Experimental Study (0.35)
- North America > United States > California > Sacramento Basin > 2 Formation (0.99)
- Asia > China > Shanxi > Ordos Basin (0.99)
- Asia > China > Shaanxi > Ordos Basin (0.99)
- (6 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- (2 more...)
Understanding Imbibition Mechanisms of Catanionic SurfactantโStabilized Nanoemulsion for Enhanced Oil Recovery in Tight Sandstone Reservoirs: Experimental and Numerical Assessment
Wei, Bing (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University (Corresponding author)) | Wang, Lele (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Mao, Runxue (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Yu, Guanqun (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) | Lu, Jun (McDougall School of Petroleum Engineering, The University of Tulsa) | Tang, Jinyu (Department of Chemical and Petroleum Engineering, United Arab Emirates University)
Summary Surfactant-induced imbibition is considered a promising method for increasing oil recovery from tight oil reservoirs beyond primary production. Nanoemulsion (nE) offers a great potential for this application owing to its unique physicochemical properties, such as kinetic stability, large surface area, and low oil-aqueous interfacial tension (IFT). Herein, we designed and prepared a series of surfactant-stabilized oil-in-water (O/W) nE using efficient catanionic surfactants by a low-energy method. The physicochemical properties of the nE samples were comprehensively characterized to better perform experimental and numerical simulations and constrain the modeling. We conducted imbibition tests on Chang 7 tight cores using nE and brine and also assessed the imbibition dynamics. Results indicated that nE was successfully synthesized at a surfactant concentration ranging from 0.4 to 1.0 wt%. The oil droplets in nE had a mean size of 10 nm. All the nE samples were able to lower the oil-aqueous IFT to an ultralow level of 10 mN/m. In addition, nE demonstrated superior capacities in wettability alteration, and oil solubilization and emulsification, which were all integrated into numerical modeling. The imbibition oil recovery was increased by 18.8% of the initial oil in place when nE1 (0.4 wt%) was used compared to that of brine. Because of the interactions among oil, nE, and rock surface, nE required a longer time to reach imbibition equilibrium than brine. The simulation results, for the first time, suggested that the dominant imbibition mechanisms of nE varied with time, during which IFT reduction and wettability alteration played the leading roles in the first 50 hours. The reactions of oil solubilization and emulsification became significant after 50 hours and then contributed equally to the oil recovery with IFT reduction and wettability alteration. The diffusion of nanosized oil droplets increased the equilibrium time of imbibition, thereby promoting the ultimate oil recovery.
- Asia (1.00)
- North America > United States > Texas (0.93)
- Europe (0.67)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- (3 more...)
- Information Technology > Modeling & Simulation (0.66)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Search (0.46)
- Information Technology > Artificial Intelligence > Natural Language > Information Retrieval (0.46)
A Systematic Laboratory and Model-Based Surfactant Screening Workflow for Enhanced Recovery via Wettability Alteration in the Eagle Ford
Jweda, Jason (ConocoPhillips) | Bone, Russ (ConocoPhillips) | El-Sobky, Hesham (ConocoPhillips) | Nguyen, Viet (ConocoPhillips) | Carman, Paul (ConocoPhillips) | Long, Hui (ConocoPhillips) | Beveridge, William (ConocoPhillips) | Warren, Logan (ConocoPhillips) | Bonnie, Ronald (ConocoPhillips) | Jiang, Tianmin (ConocoPhillips) | Hoyt, Jennifer (ConocoPhillips) | MacMillan, Andrew (ConocoPhillips) | McLin, Kristie (ConocoPhillips)
Abstract Surfactants are among the most common additives utilized in the oil industry. One focus of industry investigations in unconventional liquid-rich reservoirs is surfactant-mediated wettability alteration to enhance hydrocarbon recovery. Previous experimental studies and published field trials have shown that injected surfactants can be an effective means of improving recovery. Most experiments, however, have been conducted at ambient rather than reservoir conditions. This study presents a novel approach to screen thermally stable surfactants at high pressures and high temperatures for the explicit purpose of wettability alteration in ConocoPhillipsโ Eagle Ford acreage. We designed a systematic workflow that reduced costs and avoided potentially ambiguous field trial results to evaluate surfactant stability and efficacy. The behaviors of different surfactants were first investigated through contact angle (CA) and interfacial tension (IFT) measurements at โผ350ยฐF and โผ5000 psi on crude-oil-saturated Eagle Ford formation core plugs. A subset of surfactants with favorable wettability alteration potential were tested for completions compatibility and further evaluated by spontaneous imbibition and flow-through experiments. An integrated modeling workflow combining molecular dynamics, the Lattice-Boltzmann method, and reservoir simulations provided a model-based assessment of production uplift due to the wettability changes associated with injected surfactants. Initial testing with synthetic porous media at reservoir conditions demonstrated that some โoff-the-shelfโ surfactants were prone to pore clogging or thermally unstable. CA and IFT revealed that most surfactants and blends would be relatively ineffective at favorably altering wettability at ConocoPhillipsโ Eagle Ford reservoir conditions. A thermal stability breakthrough to overcome temperature limitations was achieved by blending co-surfactants. However, imbibition and flow-through experiments with the few promising co-surfactant blends indicated that recovery factor uplifts via wettability alteration were minimal. Furthermore, flow simulation modeling suggested that altered wettability due to usage of surfactants would encourage imbibition and retention of injected water in the rock matrix but not improve oil recovery. This paper presents a systematic multi-year, multi-disciplinary approach to screen thermally stable surfactants at reservoir conditions using CA and IFT measurements, completions compatibility testing, spontaneous imbibition, flow-through experiments, and reservoir simulations. The goal was to establish a rigorous screening workflow and identify potential surfactant application from laboratory and simulation modeling with the explicit purpose of wettability alteration before conducting expensive and possibly ambiguous field trials.
- Research Report > New Finding (0.88)
- Research Report > Experimental Study (0.66)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (4 more...)
Advanced Dual-Porosity and Dual-Permeability Model for Tight Rock Integrated Primary Depletion and Enhanced Oil Recovery Simulation
Yang, Daegil (Chevron Technical Center) | Do, Tyler (Chevron Technical Center) | Yang, Changdong (Chevron Technical Center) | Sun, Hao (Chevron North America E&P Co.) | Ramsaran, Keith (Chevron North America E&P Co.) | Shi, Xundan (Chevron Technical Center) | Zhou, Dengen (Chevron Technical Center) | Chen, Jianping (Chevron Technical Center) | Lee, Mathis (Chevron Technical Center)
Abstract Discrete fracture or dual porosity modeling has been widely adopted for tight rock simulation with respective advantages. To represent the complex fracture heterogeneity and simplify its characterization, we present a new simulation model to 1) holistically optimize the tight rock reservoir completion, primary depletion and enhanced oil recovery modeling and 2) retain the injection mechanism and simplify the complex fracture characterization to enhance the computation efficiency. This newly developed advanced dual porosity dual permeability (A-DPDK) model transfers the complex hydraulic fracture characterization from the fracture simulation model to the A-DPDK model through a shape factor (matrix-fracture coupling) calculation. The model enables users to characterize different properties in multiple regions (matrix, propped hydraulic fracture, unpropped hydraulic fracture, enhanced permeability, and natural fracture). The newly implemented local grid refinement algorithm adaptively refines the coarse grid cells intersected by hydraulic fractures and accelerates the computation efficiency by five times without losing accuracy. We tested the model with several hypothetical completion design, primary depletion and gas injection cases to demonstrate its useability, computational efficiency and production mechanism retained. The fracture characterization functionality could rank various completion design to significantly simplify the existing completion design workflow. The primary depletion profile and gas injection uplift is comparable with the general industry reported observation without significantly losing the computational efficiency. This tool will have broad application in supporting asset development decisions, such as well landing & spacing, completion design, primary depletion forecast and EOR pilot design. Introduction Unconventional reservoirs play a critical role in domestic energy independence due to the vast resources, short investment cycles and favorable geopolitical locations. Over the past decade, technological advances in horizontal drilling and hydraulic fracturing have allowed the access to large volumes of shale oil that were previously uneconomical. The U.S. Energy Information Administration (EIA) estimates that in 2021, about 7.23 million barrels per day of crude oil were produced directly from shale & tight (S&T) oil resources in the United States. This was equal to about 64% of total U.S. crude oil production in 2021. Current production in the US relies heavily on drilling and fracturing large numbers of wells, which is capital intensive. The estimated recovery factors with current production practices range around 10% of OOIP, we will need a simulation workflow to holistic optimize S&T resource asset development from primary depletion to enhanced oil recovery process (Sun, et al. 2015a, 2015b, 2016, 2017, 2023).
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.46)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)