scholarly journals Investigation of Multistage Hydraulic Fracture Optimization Design Methods in Horizontal Shale Oil Wells in the Ordos Basin

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-17
Author(s):  
Suotang Fu ◽  
Jian Yu ◽  
Kuangsheng Zhang ◽  
Hanbin Liu ◽  
Bing Ma ◽  
...  
Keyword(s):  
Optimization Design ◽  
Ordos Basin ◽  
Design Methods ◽  
Oil Wells ◽  
Optimization Techniques ◽  
Hydraulic Fractures ◽  
Shale Oil ◽  
Natural Fractures ◽  
Fracture Geometry ◽  
Secondary Fractures

Based on the analysis of the typical Ordos well groups, this study began with the accurate characterization of the fracture geometry by adopting advanced laboratory experiment methods and monitoring techniques. Then, with the integration of fracture geometry characterization and in situ stress distributions, fracture optimizations of the target wells were performed through numerical simulations methods. Finally, this study established a sweet spot prediction and identification method for long horizontal shale oil wells and constructed a set of optimization design methods for multistage hydraulic fracturing. This investigation revealed that the hydraulic fractures in Chang-7 terrestrial shale oil reservoirs exhibited the belt pattern, and the primary fractures generated the secondary fractures, which activated the natural fractures and induced shear failure. Macroscopic fractures were found to be perpendicular to the direction of the minimum principal stress. Secondary fractures and activated natural fractures were distributed around the primary fracture in the form of fracture types I and II. Multicluster perforation optimization techniques, which were based on shale reservoir classification and evaluation, and aimed at activating multiclusters and determining fracture sweet spots, were developed. These were successfully applied to the field operation and achieved production enhancement performance.

Integration of Geoscience and Engineering Concepts to Account for Natural Fractures in Fluid Flow within Shale Reservoirs

2021 ◽  
Author(s):  
Clay Kurison ◽  
Ahmed M. Hakami ◽  
Sadi H. Kuleli
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Eagle Ford ◽  
Fracture Geometry ◽  
Ongoing Research ◽  
Linear Flow ◽  
Matrix Permeability ◽  
The Subject ◽  
Shale Reservoirs

Abstract Unconventional shale reservoirs are characterized by low porosity and ultra-low permeability. Natural fractures are known to be present and considered a critical factor for the enhanced post-stimulation productivity. Accounting for natural fractures with existing techniques has not been widely adopted owing to their complexity or lack of validation. Ongoing research efforts are striving to understand how natural fractures can be accounted for and accurately modeled in fluid flow of the subject reservoirs. This study utilized Eagle Ford well data comprising reservoir properties, stimulation metrics, production, microseismicity and permeability measurements from a core plug. The methodology comprised use of production data to extract a linear flow regime parameter. This was coupled with fracture geometry, predicted from hydraulic fracture modeling and microseismicity, to estimate the system permeability. From interpreting microseismic events as slips on critically stressed natural fractures, explicit modeling incorporating a discrete fracture network (DFN) assumed activated natural fractures supplement conductive reservoir contact area. Thus, allowed the estimation of matrix permeability. For validation, the aforementioned was compared with core plug permeability measurements. Results from modeling of planar hydraulic fractures, with microseismicity as validation, predicted planar fracture geometry which when coupled with the linear flow parameter resulted in a system permeability. Incorporation of DFNs to account for activated natural fractures yielded matrix permeability in picodarcy range. A review of laboratory permeability measurements exhibited stress dependence with the value at the maximum experimental confining pressure of 4000 psi in the same range as the computed system permeability. However, the confining pressures used in the experiments were less than the in situ effective stress. Correction for representative stress yielded an ultra-low matrix permeability in the same range as the DFN-based picodarcy matrix permeability. Thus, supporting the adopted drainage architecture and often suggested role of natural fractures in shale reservoir fluid flow. This study presents a multi-discipline workflow to account for natural fractures, and contributes to understanding that will improve laboratory petrophysics and the overall reservoir characterization of the subject reservoirs. Given that the Eagle Ford is an analogue of emerging shales elsewhere, results from this study can be widely adopted.

scholarly journals The Effect of Hydraulic Fracture Geometry on Well Productivity in Shale Oil Plays with High Pore Pressure

Energies ◽  
2021 ◽  
Vol 14 (22) ◽  
pp. 7727
Author(s):  
Daniela A. Arias Ortiz ◽  
Lukasz Klimkowski ◽  
Thomas Finkbeiner ◽  
Tadeusz W. Patzek
Keyword(s):  
Pore Pressure ◽  
Hydraulic Fracture ◽  
Hydraulic Fractures ◽  
Shale Oil ◽  
Production Forecast ◽  
Fracture Geometry ◽  
Hydrocarbon Production ◽  
Reservoir Simulations ◽  
Bedding Planes

We propose three idealized hydraulic fracture geometries (“fracture scenarios”) likely to occur in shale oil reservoirs characterized by high pore pressure and low differential in situ stresses. We integrate these geometries into a commercial reservoir simulator (CMG-IMEX) and examine their effect on reservoir fluids production. Our first, reference fracture scenario includes only vertical, planar hydraulic fractures. The second scenario has stimulated vertical natural fractures oriented perpendicularly to the vertical hydraulic fractures. The third fracture scenario has stimulated horizontal bedding planes intersecting the vertical hydraulic fractures. This last scenario may occur in mudrock plays characterized by high pore pressure and transitional strike-slip to reverse faulting stress regimes. We demonstrate that the vertical and planar fractures are an oversimplification of the hydraulic fracture geometry in anisotropic shale plays. They fail to represent the stimulated volume geometric complexity in the reservoir simulations and may confuse hydrocarbon production forecast. We also show that stimulating mechanically weak bedding planes harms hydrocarbon production, while stimulated natural fractures may enhance initial production. Our findings reveal that stimulated horizontal bedding planes might decrease the cumulative hydrocarbon production by as much as 20%, and the initial hydrocarbon production by about 50% compared with the reference scenario. We present unique reservoir simulations that enable practical assessment of the impact of varied hydraulic fracture configurations on hydrocarbon production and highlight the importance of constraining present-day in situ stress state and pore pressure conditions to obtain a realistic hydrocarbon production forecast.

scholarly journals Pore Type, Pore Structure, and Controlling Factors in the Late Triassic Lacustrine Yanchang Shale, Ordos Basin, China

Energies ◽  
2021 ◽  
Vol 14 (11) ◽  
pp. 3053
Author(s):  
Ming Cheng ◽  
Yuhong Lei ◽  
Xiaorong Luo ◽  
Likuan Zhang ◽  
Xiangzeng Wang ◽  
...  
Keyword(s):  
Ordos Basin ◽  
Controlling Factors ◽  
Shale Oil ◽  
Thermal Maturity ◽  
Third Order ◽  
First Order ◽  
Pore Structures ◽  
Grain Sorting ◽  
Pore Types ◽  
Organic Pores

Organic-rich lacustrine shales in the Upper Triassic Yanchang Formation with thermal maturity mainly in the oil window are the main shale oil and shale gas system in the lacustrine strata of the Ordos Basin, China. Pore systems are important for the storage and transfer of shale oil and gas. The main objectives of this study are to identify the pore types and pore structures and investigate the controlling factors for pore types, pore structures, and total porosities of the lacustrine Yanchang Shale. In this study, organic-rich mudstones, mudstones with siltstone interlayers, siltstone, and sandstones were selected from 15 wells in the southern Ordos Basin. X-ray diffraction, pyrolysis, scanning electron microscopy (SEM), low-pressure nitrogen adsorption analysis, and helium porosimetry were conducted to investigate the mineral compositions, pore types, pore structures, porosities, and controlling factors. Siltstone and sandstone interlayers heterogeneously developed in the Yanchang Shale. The petrology, mineral composition, geochemistry, pore type, pore structure, and porosity of siltstone interlayers are different from those of mudstones. The siltstone and sandstone interlayers usually have more quartz and feldspars, greater detrital grain sizes, and relatively better grain sorting but are lower in clay minerals, total organic carbon (TOC), amount of free liquid hydrocarbons values (S1), and total residual hydrocarbons values (S2), compared to mudstones. Interparticle (interP), intraparticle (intraP) pores, and organic pores (OPs) were developed in both siltstones and mudstones. OPs were observed in samples with lower thermal maturity (e.g., 0.5–0.85%). The inorganic pore size is greater than that of OPs. Additionally, the inorganic pore diameters in siltstone interlayers are also greater than those in mudstones. Organic-rich mudstones generally have higher pore volumes (PVs) of pores with sizes less than 10 nm, pore volumes of pores with sizes between 10 and 50 nm (PV, 10–50 nm), and specific surface area (SSA), but they have lower PVs of pores with sizes greater than 50 nm, total PV, and porosity when compared to siltstone and sandstone interlayers. The dominant pore type in mudstones is OPs and TOC (first order), sources and OM types (second order), and thermal maturity (third order), while the abundances of rigid grains with greater sizes and grain sorting are the main controlling factors of pore structures, SSA and PV. Both inorganic pores and organic pores are abundant in the siltstone interlayers. The pore size distribution (PSD), PV, and porosity of siltstone interlayers are related to the abundance of rigid grains (first order), grain sorting (second order), grain size (third order), and carbonate cement content. The total PV and porosity of Yanchang Shale reservoirs may have increased with the increased abundance of siltstone and sandstone interlayers.

A Superior Shale Oil EOR Method for the Permian Basin

2021 ◽  
Author(s):  
Robert Downey ◽  
Kiran Venepalli ◽  
Jim Erdle ◽  
Morgan Whitelock
Keyword(s):  
Oil Recovery ◽  
Reservoir Simulation ◽  
Simulation Modeling ◽  
Lower Cost ◽  
Oil Production ◽  
Oil Wells ◽  
Oil Well ◽  
Shale Oil ◽  
Permian Basin ◽  
Artificial Lift

Abstract The Permian Basin of west Texas is the largest and most prolific shale oil producing basin in the United States. Oil production from horizontal shale oil wells in the Permian Basin has grown from 5,000 BOPD in February, 2009 to 3.5 Million BOPD as of October, 2020, with 29,000 horizontal shale oil wells in production. The primary target for this horizontal shale oil development is the Wolfcamp shale. Oil production from these wells is characterized by high initial rates and steep declines. A few producers have begun testing EOR processes, specifically natural gas cyclic injection, or "Huff and Puff", with little information provided to date. Our objective is to introduce a novel EOR process that can greatly increase the production and recovery of oil from shale oil reservoirs, while reducing the cost per barrel of recovered oil. A superior shale oil EOR method is proposed that utilizes a triplex pump to inject a solvent liquid into the shale oil reservoir, and an efficient method to recover the injectant at the surface, for storage and reinjection. The process is designed and integrated during operation using compositional reservoir simulation in order to optimize oil recovery. Compositional simulation modeling of a Wolfcamp D horizontal producing oil well was conducted to obtain a history match on oil, gas, and water production. The matched model was then utilized to evaluate the shale oil EOR method under a variety of operating conditions. The modeling indicates that for this particular well, incremental oil production of 500% over primary EUR may be achieved in the first five years of EOR operation, and more than 700% over primary EUR after 10 years. The method, which is patented, has numerous advantages over cyclic gas injection, such as much greater oil recovery, much better economics/lower cost per barrel, lower risk of interwell communication, use of far less horsepower and fuel, shorter injection time, longer production time, smaller injection volumes, scalability, faster implementation, precludes the need for artificial lift, elimination of the need to buy and sell injectant during each cycle, ability to optimize each cycle by integration with compositional reservoir simulation modeling, and lower emissions. This superior shale oil EOR method has been modeled in the five major US shale oil plays, indicating large incremental oil recovery potential. The method is now being field tested to confirm reservoir simulation modeling projections. If implemented early in the life of a shale oil well, its application can slow the production decline rate, recover far more oil earlier and at lower cost, and extend the life of the well by several years, while precluding the need for artificial lift.

scholarly journals Black shale formation environment and its control on shale oil enrichment in Triassic Chang 7 Member, Ordos Basin, NW China

2021 ◽  
Vol 48 (6) ◽  
pp. 1304-1314
Author(s):  
Bin ZHANG ◽  
Zhiguo MAO ◽  
Zhongyi ZHANG ◽  
Yilin YUAN ◽  
Xiaoliang CHEN ◽  
...  
Keyword(s):  
Black Shale ◽  
Ordos Basin ◽  
Shale Oil ◽  
Nw China ◽  
Shale Formation

Pressure Depletion Mapping Using Multi-Well DFITs and its Applications in Hydraulic Fracture Characterization and Permeability Estimation: Examples from Montney Formation

2021 ◽  
Author(s):  
Behjat Haghshenas ◽  
Farhad Qanbari
Keyword(s):  
Data Analysis ◽  
Surface Area ◽  
Reservoir Simulation ◽  
Production Data ◽  
Hydraulic Fractures ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
Field Case ◽  
Pressure Depletion ◽  
Montney Formation

Abstract Recovery factor for multi-fractured horizontal wells (MFHWs) at development spacing in tight reservoirs is closely related to the effective horizontal and vertical extents of the hydraulic fractures. Direct measurement of pressure depletion away from the existing producers can be used to estimate the extent of the hydraulic fractures. Monitoring wells equipped with downhole gauges, DFITs from multiple new wells close to an existing (parent) well, and calculation of formation pressure from drilling data are among the methods used for pressure depletion mapping. This study focuses on acquisition of pressure depletion data using multi-well diagnostic fracture injection tests (DFITs), analysis of the results using reservoir simulation, and integration of the results with production data analysis of the parent well using rate-transient analysis (RTA) and reservoir simulation. In this method, DFITs are run on all the new wells close to an existing (parent) well and the data is analyzed to estimate reservoir pressure at each DFIT location. A combination of the DFIT results provides a map of pressure depletion around the existing well, while production data analysis of the parent well provides fracture conductivity and surface area and formation permeability. Furthermore, reservoir simulation is tuned such that it can also match the pressure depletion map by adjusting the system permeability and fracture geometry of the parent well. The workflow of this study was applied to two field case from Montney formation in Western Canadian Sedimentary Basin. In Field Case 1, DFIT results from nine new wells were used to map the pressure depletion away from the toe fracture of a parent well (four wells toeing toward the parent well and five wells in the same direction as the parent). RTA and reservoir simulation are used to analyze the production data of the parent well qualitatively and quantitatively. The reservoir model is then used to match the pressure depletion map and the production data of the parent well and the outputs of the model includes hydraulic fracture half-lengths on both sides of the parent well, formation permeability, fracture surface area and fracture conductivity. In Field Case 2, the production data from an existing well and DFIT result from a new well toeing toward the existing wells were incorporated into a reservoir simulation model. The model outputs include system permeability and fracture surface area. It is recommended to try the method for more cases in a specific reservoir area to get a statistical understanding of the system permeability and fracture geometry for different completion designs. This study provides a practical and cost-effective approach for pressure depletion mapping using multi-well DFITs and the analysis of the resulting data using reservoir simulation and RTA. The study also encourages the practitioners to take every opportunity to run DFITs and gather pressure data from as many well as possible with focus on child wells.

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