Browsing by Subject "Unconventional reservoir"
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Item Automatic history matching with data integration for unconventional reservoirs(2021-01-21) Liu, Chuxi; Sepehrnoori, Kamy, 1951-Given the dynamic production data of a reservoir, numerical optimization tools such as history matching can minimize the global error and find an optimal reservoir model that can approximate the fracture geometry and petrophysical parameters in the subsurface. For unconventional reservoirs, the idea behind the automatic history matching is well developed and the workflow is also applied to statistically generate an ensemble of solutions that quantitatively characterizes associated uncertainties. However, more uncertainties regarding fracture and reservoir properties could be further reduced by using available information. Therefore, the objective of this study is to minimize uncertainty when make realizations of shale reservoirs, by integration of data from geology and geomechanics. We utilized the developed automatic history matching (AHM) code and modified the proxy engine, by substituting the neural network (NN) model with XGBoost (XGBOOST) model. The XGBOOST is found to perform more efficiently and accurately than NN, when the size of the available dataset for training is small. Furthermore, the AHM workflow is capable of modelling non-uniform half-length of hydraulic fractures in the corner point gridding system and complex, realistic natural fracture distributions using the fractal theory. Both of these functionalities partially fulfill some degrees of reality, by mimicking the irregular half-length outputted from fracture modelling software and naturally occurring patterns often found at cores. We applied this innovative approach to actual shale gas and shale oil wells. We then found that by coupling additional data into the AHM process, the fracture geometries and petrophysical properties can be more accurately depicted. The obtained results are also highly assimilating with the field experience from the engineers. In addition, by studying natural fractures in the model, we found out that the connectivity between natural fractures and wellbore/hydraulic fractures plays an important role in determining the well’s EUR potential. This study is beneficial because more reliable and robust results based on geological/geomechanical information, along with non-deterministic realizations of reservoir and fractures, can provide invaluable guidance towards well spacing planning, EUR estimation and economic appraisal, and fracture design optimizationsItem CO2 injection for enhanced oil and gas recovery and its role in carbon storage and utilization in unconventional reservoirs(2023-12) Zhumakhanova, Nazerke; Sepehrnoori, Kamy, 1951-Enhanced Oil and Gas Recovery (EOGR) methods are increasingly becoming essential components in the future of hydrocarbon production, with CO2 injection emerging as a promising technique for unconventional reservoirs. In addition, the persistent rise in CO2 emissions is a significant environmental concern and requires innovative solutions. Sequestering CO2 in gas shale formations not only addresses this issue but also provides the added benefit of enhancing oil and gas recovery, potentially making the injection of CO2 economically viable. This study presents reservoir-simulation based investigation of shale gas reservoirs for CO2 injection, considering factors such as adsorption, molecular diffusion, natural fractures, and conducting several sensitivity analyses. The success of CO2 injection and methane (CH4) recovery in shale reservoirs depends on various engineering and geological parameters, including operational aspects such as injection volume and time, as well as geological factors like reservoir permeability and porosity. Despite the complexity of these interactions, the study thoroughly investigates the influence of uncertain parameters on the processes of CO2-Enhanced Gas Recovery (EGR) and CO2 storage, identifying the most critical factors controlling these processes. Two CO2 injection scenarios were explored when primary gas production reaches economic limits: (1) CO2 huff-n-puff in a single horizontal well, and (2) CO2 flooding in an injector/producer pair of horizontal wells. The proposed models were employed to analyze the impact of CO2 injection on EGR and CO2 storage. Subsequently, CO2 flooding in a gas reservoir was compared with that in an oil reservoir. The findings contribute valuable insights into the potential of CO2 injection methods for improving hydrocarbon recovery and mitigating environmental concerns.Item Coupled geomechanics and multiphase flow modeling in naturally and hydraulically fractured reservoirs(2022-05-05) Pei, Yanli; Sepehrnoori, Kamy, 1951-; Chin, Lee; Delshad, Mojdeh; Marcondes, Francisco; Olson, JonFluid injection and production in highly fractured unconventional reservoirs could induce complex stress reorientation and redistribution. The strong stress sensitivity of fractured formations may also lead to non-negligible fracture opening or closure under the reservoir loading or unloading process. Hence, a coupled flow and geomechanics model is in high demand to assist with stress prediction and production forecast in unconventional reservoirs. In this dissertation, an enhanced geomechanics model is developed for fractured reservoirs and integrated with the in-house compositional reservoir simulator – UTCOMP for coupled flow and geomechanics modeling. The multiphase flow model is solved using the finite volume method (FVM) with an embedded discrete fracture model (EDFM) to represent flow through complex fractures. Based on static fracture assumption, the finite element method (FEM) is applied to solve the geomechanics model by incorporating fracture effects on rock deformation through pore pressure changes. An iterative coupling procedure is implemented between fluid flow and geomechanics, and the 3D coupled model is applied to predict spatiotemporal stress evolution in single-layer and multilayer unconventional reservoirs. To consider dynamic fracture properties, the geomechanics model is further enhanced by the extended finite element method (XFEM) with a modified linear elastic proppant model. The fracture surface is under the coeffects of pore pressure and proppant particles, and various enrichment functions are introduced to reproduce the discontinuous fields over fracture paths. The enhanced geomechanics model is validated against classical Sneddon and Elliot’s problem and presents a first-order spatial convergence rate. Numerical studies indicate that modeling fracture closure is necessary for poorly propped, highly stressed, or fast depleted reservoirs, and fracture opening can be significant under high permeability and low stiffness conditions. The coupled flow and geomechanics model is finally combined with a displacement discontinuity method (DDM) hydraulic fracture model to establish an integrated reservoir-geomechanics-fracture model for the end-to-end optimization of secondary stimulations. It is applied to Permian Basin and Sichuan Basin tight formations to optimize parent-child well spacing at different infill times. The integrated model provides hands-on guidelines for refracturing and infill drilling in multilayer unconventional reservoirs and can be easily adapted to other basins under their unique dataItem Development and application of embedded discrete fracture model for conventional and unconventional reservoir simulation(2018-08-17) Xu, Yifei (Research engineer); Sepehrnoori, Kamy, 1951-; Delshad, Mojdeh; Foster, John T.; Okuno, Ryosuke; Chin, Lee; Marcondes, FranciscoThe simulation of fractured reservoirs is a challenging topic in reservoir simulation owing to the complexity of fracture geometry and recovery processes related to fractured reservoirs. Reliable and efficient numerical models are required for the representation of hydraulic and natural fractures in conventional and unconventional reservoirs. The objective of this work is to develop a numerical approach for simulating complex fractures and complex recovery processes in fractured reservoirs using various types of computational grids. This research is an extension of the Embedded Discrete Fracture Model (EDFM). In this work, methodologies were developed to model various types of 2D and 3D complex fracture geometries. The EDFM was also extended to handle several types of computational grids, including corner-point grids, locally-refined grids, and unstructured grids with mixed elements. Geometrical algorithms were developed and implemented in a general-purpose preprocessing code for the calculation of EDFM connection factors in such grids. The use of the EDFM with matrix grids using various numerical approximation schemes, such as finite-volume method and element-based finite-volume method, was also studied. Furthermore, the model was improved regarding modeling fracture transient flow and dynamic fracture behaviors. For the simulation of hydraulically fractured unconventional reservoirs, various important flow mechanisms were implemented in a compositional simulator. The simulator was used to investigate the relative importance of these mechanisms. The developed methodology was applied to a series of synthetic and realistic case studies. The accuracy of the model was confirmed through comparison with other models for simulating various types of fracture geometries in different hydrocarbon recovery processes. A high computational performance was also achieved using the model. Furthermore, based on the results of this research, for long-term production forecasting, the accuracy of the EDFM is not sensitive to the type of grid, the detailed gridding around fractures, or the numerical approximation scheme, if a similar gridblock size is used in the simulations. For the simulation of short-term flow, the combination of the EDFM with nested grid refinement greatly improves the simulation accuracy for various flow regimes. The modeling of dynamic fracture behaviors and unconventional reservoir flow mechanisms demonstrates the flexibility of the proposed approach in incorporating different physicsItem Experimental studies on the reservoir dynamics of water-based and gas-based fracturing fluids in tight rocks(2017-05) Luo, Xiao; DiCarlo, David Anthony, 1969-; Nguyen, Quoc P.Low permeability formations, including shale and tight reservoirs, have contributed over 50% of U.S. annual oil production. Many of these formations are oil productive formations, they include Bakken, Eagle Ford, Marcellus, Permian, and Utica. In order to obtain economic production, large amounts of fracturing fluids are consumed during the hydraulic fracturing treatments, but only a small fraction of the fluid is returned to the surface as flowback. Water-based fracturing fluids may invade the rock matrix in a tight or unconventional reservoir and result in a water block that hinders oil production. To remedy this possibility, gas- and foam-based fluids have been developed. For an oil productive formation, the invasion of gas can also result in oil permeability reduction, i.e. a gas block, but the mechanism and clean up are likely to be different than a water block. As the two fluids exhibit different wetting nature, it is not clear how they compare to each other in a multi-phase flow perspective, such as their impact on the productivity in the short and long term. In this work, we conduct experimental studies the reservoir dynamics of invaded fracturing fluids, reduction in the hydrocarbon permeability, and potential mitigation for cleaning up the fluid block. We scaled down this fluid invasion problem to a laboratory core sample. Water and N₂ are injected into a rock matrix to mimic the invasion of slickwater and gas-based fracturing fluids, respectively. We studied the evolution of the oil productivity and flowback versus time during the oil production. The respective performances for different fracturing fluids under different conditions will also be investigated in this study.Item Fracture spatial arrangement in tight gas sandstone and shale reservoir rocks(2017-09-18) Li, John Zihong; Laubach, Stephen E; Gale, Julia F.W.A new statistical analytical method was applied to quantify the spatial arrangement of fractures in sandstones and shales. Results show that spatial arrangements of fractures in the subsurface have a wide range of patterns and that fracture clusters are prevalent. The Upper Cretaceous Frontier Formation is a naturally fractured gas-producing sandstone in Wyoming. East-west-striking regional fractures sampled using image logs and cores from three horizontal wells exhibit clustered patterns, whereas data collected from outcrop have patterns that are indistinguishable from random. Image log data analyzed with the correlation count method shows clusters ~35 m wide and spaced ~ 50 to 90 m apart as well as clusters up to 12 m wide with periodic inter-cluster spacings. A hierarchy of cluster sizes exists; arrangement within clusters is likely fractal. Regionally, random and statistically more clustered than random patterns exist in the same upper to lower shoreface depositional facies. These rocks have markedly different structural and burial histories, so regional differences in degree of clustering are unsurprising. Application to shale reservoirs further link fracture clusters and spatial arrangements with reservoir mechanical stratigraphy: Vaca Muerta Formation shale shows strong control of fracture cluster locality by reservoir mechanical properties; Middle Devonian shales in the Horn River Basin identify spatial arrangement and cluster dimensions associated with preferred wellbore intervals; Marcellus Formation shale shows spatial arrangement controlled by mechanical bed thickness. Our results show that quantifying and identifying patterns as statistically more or less clustered than random delineate differences in fracture patterns that are not otherwise apparent but that may influence petroleum and water production, and therefore may be economically important.Item Lithofacies, diagenesis, and reservoir quality of the unconventional Wolfcampian succession in the Southeast Midland Basin, West Texas(2017-09-18) Zhang, Hualing; Janson, Xavier; Fu, QilongThe Lower Permian Wolfcampian basinal succession in the Midland Basin has become an important unconventional reservoir. Reservoir characterization of Wolfcampian strata is challenging because of the complex arrangement of lithofacies. This study combined petrographic and scanning electron microscope (SEM) cube observations from cores, and thin sections, as well as X-ray fluorescence (XRF) data, X-ray diffraction (XRD) data, and total organic carbon (TOC) data in order to provide an integrated characterization of the Wolfcamp succession. Lithofacies investigations were made using six cores (totally 667 ft total) from Glasscock, Sterling, and Irion Counties in Texas. Seven lithofacies were defined based on petrographic observations: (1) sandy siltstone, (2) argillaceous mudstone, (3) very fine to fine sandstone, (4) massive to weakly laminated calcareous mudstone, (5) laminated calcareous mudstone, (6) mud-dominated bioclastic packstone/rudstone, and (7) grain-dominated bioclastic packstone-grainstone/rudstone. Mudrocks were deposited mostly through hemipelagic settling and diluted turbidity flow. Depositional processes for sandstone, siltstone, and carbonate lithofacies include turbidity flows, debris flows, and hyperconcentrated density flows. These sediments are interpreted to be deposited in a deep-water, dysoxic to anoxic slope to basinal setting. High-frequency cyclicity is observed in meter scale as a relative carbonate-rich lithofacies overlain by a relative siliclastic-rich lithofaices. The Wolfcamp succession reveals a complex diagenetic history in sandstone and carbonate facies, including compaction, calcite, silica, and siderite cementation, and dissolution. The combined effects of compaction and cementation result in relatively low porosity. However, dissolution and siderite grain-coating in the sandstones create/save pore spaces for hydrocarbon storage. Measured core-plug porosity and permeability (por–perm) in sandstone successions suggest moderate porosity up to 11.6%. Based on por–perm results, siderite-coated sandstone is considered to be of the highest reservoir potential. The Wolfcamp has fair to good organically rich mudrocks, with an average TOC of 1.4%. TOC is facies-dependent with the highest value in the argillaceous mudstone lithofacies. The enrichment of organic matter increases with increasing primary productivity by showing positive relation with Ni, Cu, and P element. Organic enrichment also increases with bottom water anoxia by showing a positive relation with Mo and U elements. TOC enrichment is also affected by sediment influx during early Wolfcampian.Item Various topics in unconventional reservoir simulation(2022-04-27) Zhao, Yajie; Sepehrnoori, Kamy, 1951-; Yu, WeiWith the recent progress in technologies such as hydraulic fracturing and horizontal drilling, unconventional resource development has exploded in recent years. Nevertheless, significant challenges remain for shale reservoirs because of the extensive number of uncertainties. Without proper characterization processes, extracting economic values from these projects will be difficult, and optimizations for future plans will also be challenging. Therefore, efficient models in production mechanism, management and optimization have gradually become hot topics among the petroleum industry. This study aims to address various crucial challenges during the production process of shale reservoirs, including unconventional well gas oil ratio (GOR) characterization, choke management, and well spacing optimization. Due to the ultra-low permeability and porosity, the fluid phase behavior in shale reservoirs significantly differs from the conventional fluid behavior and increases the production forecasting complexity. A substantial effort to better understand the mechanism is to characterize the unconventional well GOR, which always plays as a critical indicator to help predict long-term oil/gas production trends and develop appropriate production strategies. In this research, GOR behavior was first evaluated by a set of comprehensive sensitivity studies in a tight oil well model, which helped to investigate the key drivers that can impact the GOR response in unconventional resources. Then, a parent-child well-set case in Eagle Ford was presented. Through detailed characterization of the producing GOR, an improved understanding of the parent-child well behavior and the fracture hit impact can be obtained. In order to improve the efficiency of field operation, seeking for proper operation plan has been the focusing topic among the oil and gas industry. Choke management strategy selection is one of the essential measures to regulate fluid flow and control downstream system pressure, which could significantly impact the well production rate and estimated ultimate recovery (EUR). In this study, we utilized the non-intrusive embedded discrete fracture model (EDFM) method to handle complicated fracture designs and predicted the long-term EUR from conservative to aggressive choke strategy. Meanwhile, a series of sensitivity studies were presented to evaluate the impacts of various factors on shale gas production, including fracture permeability modulus, fracture closure level, and natural fractures network. The model becomes a valuable stencil to design fracture closure and complex fracture networks, which is a significant improvement for a more reliable choke management model in unconventional area. Another crucial part for well performance improvement is well spacing optimization. Consistent estimates of well spacing help reduce the impact of complex uncertainties from unconventional reservoirs, thereby improving the EUR and enhancing economic growth. We demonstrated a case study on well spacing optimization in a shale gas reservoir located in the Sichuan Basin in China. By using the advanced EDFM technology, complex natural fractures can be effectively captured and simulated. In this study, five different well spacing scenarios ranging from 300 m to 500 m were simulated individually to find the optimum well spacing that maximizes the economic revenue. As the practicability and the convenience showed in this workflow, it becomes feasible to be utilized in any other shale gas well.