Optimization of Hydraulic Fracturing Design under Spatially Variable Shale Fracability

Hydraulic fracturing optimisation for tight sandstone requires a reliable geomechanical model in the reservoirs and bounding formations to achieve a desired hydraulic fracture geometry (height, width and length) and optimum production recovery post fracturing. The objective of this study was to validate and calibrate the horizontal stress profile in various intervals of the target formation. This paper presents a few cases from Asia Pacific region tight reservoirs where field structure is composed of multiple reservoir sandstones with interbedded shales. Sandstones with low porosity and permeability were targeted for hydraulic fracturing. An integrated approach was proposed to use existing wells data including acoustic and wellbore image logs, as well as miniFrac and Step-rate tests to calibrate the fieldwide pore pressure and in-situ stress models. The model was applied to optimise hydraulic fracturing design and treatment schedule. In pre-fracturing stage, geomechanical model was developed for target intervals using offset wells data including regional fracture closure pressures from past miniFrac tests. To estimate the reservoir and bounding formations Young’ modulus and Poisson's ratio, compressional and dipole shear wave slowness logs as well as bulk density logs from nearby wells were used. Poroelastic minimum horizontal stress in the sandstone intervals was calibrated with closure pressure data from nearby wells and formations while bounding shale stress was calibrated with regional leak-off pressures. Number of deviated wells sub-parallel to maximum horizontal stress azimuth were drilled for reservoir stimulation using hydraulic fracturing. Full-wave Acoustic logs were acquired and used to validate the preliminary elastic properties of target formations which were then used for poroelastic stress calculations and fracture toughness estimation for hydraulic fracturing design. Analysis of real-time mini fall-off tests revealed significant level of reservoir pressure depletion in the target sandstones. Depletion induced poroelastic stresses were calculated while closure pressure interpreted from formation breakdown and miniFrac tests was used to calibrate the minimum horizontal tress profile. Re-calibrated model with actual reservoir pressure and closure pressure data revealed considerable stress contrast between reservoir sandstones and bounding shales, which provides sufficient bounding stress for fracture containment within the target sandstones. Model was used to design the main hydraulic fracturing including optimisation of size, volume and concentration of injected proppants and volume of fracturing fluid. Integrated Geomechanical modelling with advance acoustic logging and fracturing design enabled to achieve a successful hydraulic fracturing stimulation by exceeding the planned production rate. To date, more than five well stimulation campaigns have deployed the proposed workflow and successfully completed the fracturing operations with outstanding production results. Post fracturing production showed initial rate of tens of barrel oil per day higher than expected production rate from stimulated reservoir volume. Furthermore, calibrated geomechanics model provided valuable inputs for proppant size and conductivity optimisation to reduce the effects of proppant embedment as well as proper estimation of injected proppant volume based on robust minimum horizontal stress profile to minimize the risk of unwanted vertical fracture propagation to other zones such as water.

In recent years, the petroleum industry has been aware of the potential for non-Darcy flow in propped fracture. In hydraulic fracture stimulation treatments, the effects of non-Darcy flow as one of the most critical factors in reducing the productivity of hydraulically fractured high rate wells have been studied widely with examples of field cases. In the hydraulic fracture design, the non-Darcy flow can have great impact on the reduction of a propped half-length, thus lowering the well’s productive capability. These non-Darcy flow effects in propped fractures have been typically associated with high flow rates in both oil and gas wells. This paper studied the effects of non-Darcy flow in fracture on the hydraulic fracturing design, studied the propped porosity and bottom-hole on hydraulic fracturing design and deliverability of fractured well taking into account non-Darcy flow. Key words: Non-Darcy flow; Hydraulic fracturing; Optimization design; Productive capability

The Clair field could be described as an ‘unconventional’ conventional reservoir. The rock matrix permeability places reservoir into the conventional category, for which conventional fracturing design in terms of high proppant concentration and fracture conductivity are required for production uplift. However, the presence of natural fractures brings the Clair field a similarity to unconventional reservoirs where impact and contribution of natural fractures must be taken into the equation. This paper describes the integrated fracturing and production optimization study that was conducted to optimize multistage hydraulic fracturing design in the presence of natural fractures of various density in the Clair field. The production uplift of hydraulic fracturing in conventional reservoirs is well understood. However, the presence of natural fractures adds an unconventional twist of complexity and uncertainty to fracturing design and even more so to production uplift estimates. To reduce the uncertainty of hydraulic fracturing uplift in the presence of natural fractures, specialized software was used to explicitly model cases with a range of density discrete fracture networks (DFNs) and the interaction with hydraulic fractures. Then the resulting fracture geometries were input into production modelling software to estimate uplift and calibrated back to producers in the segment. This process was repeated for several reservoir scenarios and fracturing designs to establish the production uplift range and ultimately inform optimal hydraulic fracturing design recommendations. One of the most valuable, yet not most intuitive observations was that the natural fractures and the hydraulic fractures can have a synergistic effect on production. All DFN cases modelled showed benefit from using hydraulic fracturing including high density DFNs. Even when natural fractures are already present, hydraulic fractures will help in connecting the natural fractures to the well and increase production. Higher numbers of hydraulic fractures were associated with the best uplift predictions. The described work has been instrumental in changing how hydraulic fracturing is being considered for naturally fractured reservoirs in general and for the Clair field in particular. Hydraulic fracturing had originally just been seen as a mitigation to a poorly fractured (low/no DFN) outcome. With the results of this study however it is evident that hydraulic fracturing is also an enabler for increased production in a wide range of DFN cases. Several practical recommendations have resulted from this study such as multistage fracture spacing, number of fractures, optimized proppant placement between stages and fracture geometry. The impact of fracture vs wellbore orientation and overflush were also modelled. This is the first time such a workflow has been applied for a conventional yet naturally fractured reservoir. The proposed modelling workflow allows for optimization and robust fracturing design in environment of reservoir and geological uncertainties.

Development of tight or low permeability reservoirs (e.g. Bakken formation) commences to reveal its potential and significance and expected to become even more essential in the future. The Canadian Bakken has been produced for over 40 years. At present, the combination of horizontal well drilling and the new multi-stage fracturing and completion technologies has been the key to economically unlocking the vast reserves of the Bakken formation. Parametric studies of fracture geometry on well productivity and oil recovery are essential for a successful hydraulic fracturing stimulation treatment. In this paper, we will investigate the best hydraulic fracturing scenario for Bakken formation and the effects of fracture geometries on oil recovery. More specifically, a geological model is firstly built using typical fluid and rock properties in Bakken formation; the horizontal wells with multistage hydraulic fractures will then be modeled using local grid refinement (LGR) and history matched based on the field production data. Various fracture treatment designs are evaluated, which include the investigation of various fracture spacing, lengths, and fracture locations on the horizontal wells. The results of this study show that, employing multistage hydraulic fracturing along horizontal wells can significantly improve oil recovery in Bakken formation. Compared to fracture length, fracture spaces or fracture numbers have greater impacts on oil recovery. More importantly, for the same fractured volume in the reservoir (i.e., the same usage of proppant and fracturing fluid), fractures with longer and smaller fracture numbers lead to a similar oil recovery compared to shorter but larger fracture numbers along the horizontal well laterals.

SummaryPerforming hydraulic fractures on gas storage wells to improve their deliverability is a common practice in the eastern part of the U.S. Most fields used for storage in this region are old, and the reservoir characteristic data necessary for most reservoir studies and hydraulic fracture design and evaluation are scarce. This paper introduces a new method by which parameters that influence the response of gas storage wells to hydraulic fracturing may be identified in the absence of sufficient reservoir data. Control and manipulation of these parameters, once identified correctly, could enhance the outcome of frac jobs in gas storage fields. We conducted the study on a gas storage field in the Clinton formation of northeastern Ohio. We found that well-performance indicators before a hydraulic fracture play an important role in how good the well will respond to a new frac job. We also identified several other important factors.The identification of controlling parameters serves as a foundation for improved frac job design in the fields where adequate engineering data are not available. Another application of this type of study could be the enhancement of selection criteria among the candidate wells for hydraulic fracturing. To achieve the objective of this study, we designed, trained, and applied an artificial neural network. The paper will discuss the results of the incorporation of this new technology in hydraulic fracture design and evaluation.

Horizontal drilling and multi-stage hydraulic fracturing have made the commercial development of nano-darcy shale resources a success. Although current production volumes are promising but currently published simulation results show single-digit recovery factors under depletion. Such low recovery factors highlight the importance of accurate modeling of fluid flow and well performance for wells draining such resources. In this study, explicit hydraulic fracture modeling based on data from Eagle Ford shale oil window was performed by linking hydraulic fracture design and reservoir simulation softwares. Simulated production profiles of a homogenous simplified profile and an actual conductivity profile generated by hydraulic fracture design software were compared. The amount of fracturing fluid flowback during the first year of production was examined. The effect of unpropped zone conductivity on production performance was also investigated. The modeling results highlight the pitfalls of misrepresenting the hydraulic fracture with a constant conductivity profile. It also emphasizes the importance of appropriately modeling the amount of recovered fracturing fluid by correctly incorporating fracture propagation predicted by hydraulic fracture design software into the flow simulation model. Oil and water production trends for a single hydraulic fracture stage were observed with and without considering fracturing fluid flowback. Results of a single stage hydraulic fracture simulation showed that ignoring flowback overestimated oil recovery by about 17%. Assuming a constant permeability in the hydraulic fracture plane resulted in overestimation of oil recovery by almost 25%. The conductivity of the unpropped zone affects the recovery factor predictions by as high as 10%. For the case investigated, about 25% of the fracturing fluid was recovered during the first 2 months of production. Increasing the shut in time after fracture stimulation from 6 hours to 24 hours resulted in an increase of flowback volume by 5%. This paper addresses the importance of proper modeling hydraulic fracture conductivity in simulation of hydraulically fractured shale wells. It also highlights the importance of the amount and duration of fracturing fluid flowback, and explains how fracturing and fluid flow modeling softwares can be linked for better well performance predictions.

Hydraulic fracturing is a method of choice to improve production for the most of gas-condensate wells. In this work, hydraulic fracture effect on well production has been considered in one of Iranian gas condensate reservoirs. The target for propped hydraulic fracturing treatments is two sandstone layers with gross thickness of 101.7 ft and 95.1 ft at average depths 8725.45 of ft-TVD and 8823.75 of ft-TVD. In this study, different seven scenarios have been defined. For any scenarios, a hydraulic fracture has been designed. In the scenarios design, has been tried to attend all possible options of hydraulic fractures. In following, well cumulative production has been forecasted in both conditions without and with fracturing operation. The production forecast of seven scenarios represent that all scenarios increase cumulative production more than %19. In final, NPVs of the scenarios have been calculated and compared together and selected optimum scenario. The results are shown average fracture permeability is more effective than fracture length. Comparing NPVs of the scenarios represents NPV of Fourth Scenario is optimum. Since this is the first hydraulically fracture design in Iran, the design and results can be very useful for production planning of other Iranian tight gas reservoirs.

Hydraulic fracturing technology is usually required to allow tight gas to escape from the low-permeability reservoir and flow through the wellbore to the surface. So far, there are no numerical tools in the petroleum industry which can optimize the whole process from geological modeling, hydraulic fracturing until production simulation with the same 3D model with consideration of the thermo-hydro-mechanical coupling. In addition, optimization design should be considered from the perspective of production, especially for multiple hydraulic fractures. Thus, the simulation of the production phase with created fractures in one model is very important for the optimization design. In this dissertation, a workflow and a numerical tool chain were developed for design and optimization of multistage hydraulic fracturing in horizontal well with regard to a maximum productivity of the tight gas wellbore. Frac-Simulator was developed to match the fracturing operation history automatically and optimize the hydraulic fracturing with consideration of thermal effect and gel-breaking. The temperature change will affect the fracture propagation process directly through the thermal stress as well as expansion or shrinkage. The temperature can also influence the fluid properties (gel breaking) as well. In order to maximize the productivity of the above mentioned tight gas wellbore, Frac-Produ Simulator was developed for the simulation of the gas production. The change of stress tensor ij and the fracture conductivity F CD during gas production are also taken into account. After the verification of the developed Simulators, a full 3D reservoir model is generated based on a real tight gas field in the North German Basin. After the history matching of the stimulation phase, the same 3D reservoir model is generated, including formations and the created fractures with their own fracture geometries and proppant concentration. The bottomhole pressure development derived from the measured treating pressure was used as input data for the stress sensitive reservoir simulation. Through analysis of simulation results, a new calculation formula of F CD was proposed, which takes the proppant position and concentration into account and can predict the gas production rate of each fracture more accurately. However, not only F CD but also proppant distribution and hydraulic connection of stimulated fractures to the well, geological structure and the interaction between fractures are determinant for the gas production volume of each fracture. Hence, the relationship between gas production rates from each fracture in the later production is different from that at the beginning. For the sensitivity analysis numerical simulations were carried out with different design parameters, including proppant type, viscosity of the injection fluid and injection time. The results show that the influences of proppant type on fracture geometry and fracture conductivity is much larger than that of the viscosity of the injection fluid, while the influences of the injection time are the smallest. For the optimal fracture treatment design different numerical simulations with varied fracture number/spacing and treatment schedule were performed. The results show that the injection rate is not the higher the better. If it is too high, the fracture width will become wider and the proppant will settle down easier to the bottom, which leads to insufficient hydraulic connection between fracture and wellbore. The fracture spacing should also not be too small, otherwise the influence area/drainage radius is not enough. Thus, there is no unique criterion to determine the optimal number and spacing of the fractures, it should be analyzed firstly in detail to the actual situation and decided then from case to case.

The Akshabulak field in the South Turgayskiy basin is located in a Mesozoic intracontinental rift with an Upper Jurassic to Lower Cretaceous fill. The heterogeneous reservoir hosts significant oil and gas reserves and it has been successfully exploited with the implementation of hydraulic fracturing. After nearly 20 years of production, the reservoirs are significantly depleted and drilling new wells has been challenging. It became clear that an improved understanding of the geomechanical properties is required for delivery of a quality borehole and optimum hydraulic fracture stimulation for achieving long-term sustainable well performance. This paper illustrates the workflow used for building the 1D-Geomechanical model required for optimum well construction and for optimizing the design of multi-stage hydraulic fracturing jobs. The one-dimensional model integrates basic petrophysical logs, dipole acoustic data, regional tectonic history, interpretation of mini-frac data and drilling data for identification of the current stress state. The resulting best-fit 1D-Geomechanical model has been successfully applied on the latest wells drilled in this field. The new understanding of the in-situ stresses along with optimized wellbore stability predictions effectively balanced the risk of mud losses with the risk of borehole shear failures. Recently, a high quality horizontal well was successfully drilled towards the predicted best stress orientation, enabling optimal reservoir development and production. Additionally, having a better understanding of the fracture gradient in the carbonate formation, which serves as a seal isolating the reservoir from the lower water zone, is critical. The new geomechanical model predicted a higher stress gradient as opposed to the established understanding of this formation. The hydraulic fracturing design was optimized by allowing a higher pump pressure during the stimulation treatment, which resulted in higher production without any sign of water breakthrough. Consequently, a robust and effective geomechanical model has proven to be essential for enhancing recovery by improving the effectiveness of hydraulic fracturing, improving borehole quality by applying recommended optimal mud weights, as well as reducing NPT and costs by improving drilling performances.

Hydraulic fracturing is more popular, due to its revolutionary impact in the US oil industry, especially in unconventional reservoirs. This paper first presents the analysis of hydraulic fracturing treatments in 56 vertical and horizontal wells in the Wolfcamp and Spraberry formations of the Permian Basin in West Texas. Intrinsic treatment strategies and operational methodologies used by different operators in the Basin were evaluated with the goal of extracting and deducing insights into criteria that characterizes operational virtuosity. The evaluation focused on: proppants types and amounts, fluid types and volumes, treatment rates, well productivity and treatment cost. The second part presents the application and integration of these best practice concepts in the re-designing of hydraulic fracture treatments in a case study well already stimulated with available treatment data. Vertical wells were studied with 25 wells with over 150 treatments in both formations, 18 horizontal wells in the Spraberry formation with over 200 treatments, in Midland sub-basin and 13 horizontal wells in horizontal Wolfcamp in Delaware sub-basin. The Spraberry formation is very fine-grained sandstone, siltstone and carbonates with shales. The Wolfcamp is a complex formation divided into A, B, C and D, mostly limestone, with interbedded organic-rich siltstones. Empirical and statistical analysis using correlations and analysis of variance were used to identify and distill the best practices that actively and positively increase the production rates and decrease the production costs in each of these formation and well types. These results were then integrated in designing optimal hydraulic fracture treatments for these formations in the case well. Log analysis was done with industry standard software for accurate interpretation of the target formations and determination of rock mechanical properties used in the hydraulic fracture design software. Mined data and analysis showed that operators merely replicate designs from similar wells and formations. This practice increases the errors, costs, and reduces expected productivity. Results show that the use of 20/40 white proppant is not economical, while the use of 40/70 white proppant is recommended in both formations. Crosslinked gel creates more complex and wider fractures, but it increases cost drastically, while slickwater was amenable to treatment costs and production rate, but more volume will be needed for the treatments, hence, the use of hybrid fluids are recommended. The original design used 20/40 white sand, the total stage cost of the treatment was 707,236. In the new treatment design, 40/70 white was used instead; all the scenarios evaluated gave a reduction in cost with $100,000. These results are applicable in enhancing optimal hydraulic fracture treatment designs for these formations in the Permian Basin. Also, they serve as templates for other basins with similar formations. These results will be made better by continuous improvements with integration of field results.

Shale brittleness is one of the most important parameters to assess how the shale behaves upon subjecting to applied stress and evaluate the hydraulic fracturing treatment. Presence of lamination is a common feature in organic-rich shales which significantly create anisotropy in elastic properties and rock brittleness due to the platy minerals such as clays that have the tendency to be aligned in parallel orientation during burial and the digenesis process. Characterization of anisotropy and the understanding the controlling factors on the reservoir rock elastic properties, rock strength and rock brittleness are crucial for successful production and development of shales. The objective of this paper is to extend the previous discussion by (Ibrahim et al 2019), in which an integrated approach has been developed for evaluating the shale fracability, to explain the influences of shale lamination and emphasize on the effects of anisotropic in elastic properties on brittleness of organic-rich shales to better demonstrate the process of screening hydraulic fracturing candidate intervals and improve the hydraulic fracturing design which can eventually improve the production forecast. In this paper, we propose the vertical transverse isotropic (VTI) modeling to investigate the effect of shale lamination and anisotropy on rock elastic properties, tensile failure and wave velocity normal to bedding plane, which differ than they are when parallel to bedding plane. Throughout this study, it is observed that there is a remarkable effect of anisotropy parameters on rock elastic properties and tensile failure. This method help obtain more accurte brittleness index and give precise guide to optimize perforation depths choice and hydraulic fracturing design that can result in optimized hydrocarbon productivity.

This paper study the role of hydraulic fracture properties on the transient bottomhole pressure (BHP) behavior of a horizontal well producing from a tight fracture-cavity reservoir. A combination of point source function, Laplace transformation and Perturbation transformation are used to obtain BHP step by step. Through literature comparison and numerical simulation, the results of BHP have a good consistency, which indicates the proposed method is scientific and reasonable. We divide the fluid flow into five stages, namely the wellbore storage stage, the karst cave fluid flows to the fracture stage, the radial flow stage of karst cave and fracture system, the matrix fluid flows to the fracture stage and the quasi-steady state stage. We come to the conclusion that the number of fractures and fracture direction mainly affect radial flow stage. In contrast, the length of horizontal subsection and skin factor mainly affect the karst cave fluid flows to the fracture stage. The matrix fluid flows to the fracture stage is more obvious when the fracture half-length and the horizontal segment spacing of the horizontal well are small. The study believes special attention should be paid to reforming the formations at both ends of the horizontal well. The advantage of this method is to incorporate well geometry (skin factor) and hydraulic fracturing design (fracture parameters), which is useful for well test interpretation through generating a new set of type curves. What’s more, this new method has the characteristics of easy calculation. The findings of this study can help for better understanding of well test analysis in fracture-cavity reservoir. However, the limitation of this study is that it is only suitable for this situation the horizontal well does not encounter karst caves and the karst caves in the reservoir are connected to the wellbore through fractures.

PreviousNext No AccessUnconventional Resources Technology Conference, Denver, Colorado, 12-14 August 2013Determining the Contributing Reservoir Volume from Hydraulically Fractured Horizontal Wells in the Wolfcamp Formation in the Midland BasinAuthors: Mickey FriedrichMike MillikenMickey FriedrichPioneer Natural ResourcesSearch for more papers by this author and Mike MillikenPioneer Natural ResourcesSearch for more papers by this authorhttps://doi.org/10.1190/urtec2013-149 SectionsAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Abstract URTeC 1582170 This paper provides a methodology that is practical and logical in its approach to provide answers involving the evaluation and development of unconventional reservoirs. Multiple sources of data are analyzed to estimate the effectively stimulated volume of reservoir for horizontal wells in the Wolfcamp formation in the Midland Basin of west Texas. Estimating this volume is critical in determining optimum spacing and stacking of horizontal wellbores in unconventional reservoirs. Stimulated Reservoir Volume (SRV), as determined from microseismic, locates seismic events due to rock failure but does not necessarily represent the reservoir volume contributing to production. The reduced volume contributing to production is defined as the Contributing Reservoir Volume (CRV). This paper presents a workflow of using three methods - interpreted microseismic, proppant material balance, and calibrated hydraulic fracture modeling - to collectively estimate the CRV in hydraulically fractured horizontal Wolfcamp wells. Microseismic data is interpreted both by applying a discount factor based on industry studies and by analyzing locations and concentrations of events. Then a method of proppant material balance is used to estimate the maximum propped dimensions based on the mass of sand that is placed in each cluster of perforations. Finally, a calibrated geomechanical hydraulic fracturing model is used to model the CRV of 25 wells drilled in the Wolfcamp throughout the study area. Keywords: horizontal wells, fractures, unconventional, stacking, modelingPermalink: https://doi.org/10.1190/urtec2013-149FiguresReferencesRelatedDetailsCited ByA mathematical model for estimating effective stimulated reservoir volume24 November 2021 | Journal of Petroleum Exploration and Production Technology, Vol. 12, No. 7Analysis of Mancos Shale gas production scenarios under various stress mechanisms24 August 2021 | Arabian Journal of Geosciences, Vol. 14, No. 18A Review of Flow Mechanism and Inversion Methods of Fracture Network in Shale Gas ReservoirsGeofluids, Vol. 2021Production Interference of Hydraulically Fractured Hydrocarbon Wells: New Tools for Optimization of Productivity and Economic Performance of Parent and Child Wells3 June 2019Unconventional Reservoir Geomechanics14 June 2019 | , Vol. 1Surmounting Paucity of Data in Hydraulic Fracture Designs: Case Studies From the Permian Basin23 April 2018Case Study for Effective Stimulated Reservoir Volume Identification in Unconventional ReservoirsJournal of the Korean Society of Mineral and Energy Resources Engineers, Vol. 55, No. 2PKN Solution Revisit: 3-D Hydraulic Fracture Size and Stress Anisotropy Effects24 October 2017 | Rock Mechanics and Rock Engineering, Vol. 51, No. 2Performance-based fractal fracture model for complex fracture network simulation22 December 2017 | Petroleum Science, Vol. 15, No. 1Method of Characterization of Complex Fracture Network with Combination of Microseismic using Fractal theory17 October 2017Case History - Continued Diagnostic Technology Integration with Completions in Horizontal Wolfcamp Shale Wells in the Delaware Basin9 October 2017Midland Basin Wolfcamp Shale: Completions Observations and Lateral Length OptimizationKyle M. Richter12 September 2017Application of the fractal geometry theory on fracture network simulation23 July 2016 | Journal of Petroleum Exploration and Production Technology, Vol. 7, No. 2Deciphering Dynamic Fracture Systems through Multiple Monitoring Wells with Permanent Downhole Gauges in the Midland BasinYula Tang, Baosheng Liang, and Leif Larsen3 August 2016Understanding Wolfcamp Well Performance - A Workflow to Describe the Relationship between Well Spacing and EURJared Pettegrew*, Jiale Qiu, and Lang Zhan3 August 2016Application of Real-Time Bottom-Hole Pressure to Improve Field Development Strategies in the Midland Basin Wolfcamp ShaleKyle D. Scott*, Wei-Chun Chu, and Raymond W. Flumerfelt12 August 2015The role of hydraulic fracture geometry and conductivity profile, unpropped zone conductivity and fracturing fluid flowback on production performance of shale oil wellsJournal of Unconventional Oil and Gas Resources, Vol. 9Application of Real-Time Bottom-Hole Pressure to Improve Field Development Strategies in the Midland Basin Wolfcamp Shale4 August 2015Proper Inclusion of Hydraulic Fracture and Unpropped Zone Conductivity and Fracturing Fluid Flowback in Single Shale Oil Well Simulation17 April 2014Well-Spacing Study to Develop Stacked Tight Oil Pay in Midland Basin1 April 2014Estimation of Stimulated Reservoir Volume Using the Concept of Shale Capacity and its Validation with Microseismic and Well Performance25 February 2014 Unconventional Resources Technology Conference, Denver, Colorado, 12-14 August 2013ISSN (online):2159-6832Copyright: 2013 Pages: 1229 publication data© 2013 Published in electronic format with permission by the Society of Exploration Geophysicists, American Association of Petroleum Geologists, and Society of Petroleum EngineersPublisher:Unconventional Resources Technology ConferenceSociety of Exploration Geophysicists HistoryPublished: 26 Sep 2013 CITATION INFORMATION Mickey Friedrich and Mike Milliken, (2013), "Determining the Contributing Reservoir Volume from Hydraulically Fractured Horizontal Wells in the Wolfcamp Formation in the Midland Basin," SEG Global Meeting Abstracts : 1461-1468. https://doi.org/10.1190/urtec2013-149 Plain-Language Summary Keywordshorizontal wellsfracturesunconventionalstackingmodelingPDF DownloadLoading ...

The article discusses the analysis and assessment of the optimal direction of the horizontal wellbore and its spatial location relative to the minimum and maximum reservoir stresses play a significant role in the design of an operation to create multiple hydraulic fractures. Theoretically, two cases are possible: the horizontal wellbore is located strictly in the direction of maximum horizontal stress; the horizontal wellbore is located strictly in the direction of the minimum horizontal stress. As a conclusion based on the hydraulic fracturing design, the well productivity factor was calculated and compared for longitudinal and transverse fractures; longitudinal fractures have a clear advantage. According to the presented calculation, the hydraulic fracturing method will have advantages in a horizontal well in a highly permeable reservoir. The hydraulic fracturing method will increase the vertical permeability. According to the presented calculation, the hydraulic fracturing method will have advantages in a horizontal well in a highly permeable reservoir. The hydraulic fracturing method will increase the vertical permeability and unite the disparate parts of the reservoir. The hydraulic fracturing method will increase the vertical permeability and unite the disparate parts of the reservoir, which will make it possible to more efficiently develop the reserves of the Neocomian deposits in the field.

Optimization of multiple hydraulically fractured factors to maximize the stimulated reservoir volume in silty laminated shale formation, Southeastern Ordos Basin, China