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Abstract The topic of this paper is related to the study of what is known in the industry as the "parent-child" effect. This is accomplished by using a coupled hydraulic fracture and reservoir simulator to perform a sensitivity analysis of the impact on the results of the EUR of the child well, based on a conceptual static model for the hub core of the Vaca Muerta, considering two landing zones, different spacing between wells, degree of depletion of the parent well, the addition of a second child well and the use of an improved completion design for the child well. The objective is to investigate, through sensitivity analysis, the scenarios with the greatest impact on the EUR of the child well and to measure the magnitude or influence of each of them. Once the dynamic simulation model is calibrated, the first step is to locate and stimulate a fictitious child well in the vicinity of its parent well and perform various sensitivity analyses by varying one variable while holding the other variables constant. We considered two key variables: the well spacing (200m, 300m, 400m and 600m) and the time lag between the start of production of the child well and its parent well, with depletion intervals ranging from 0 to 5 years. A second sensitivity analysis is performed by adding two child wells, 300m and 600m from the parent well, to be stimulated simultaneously using the previous time intervals. Finally, using the 300m well spacing scenario, an improved completion design for the child well was proposed and compared to the actual completion. The result of analyzing a single child well and varying the well spacing over time intervals was, as expected, the improvement for the impairment of the child well EUR at greater distances from the depletion area, with no effect observed for the 600m spacing situation. For the case of two child wells analysis, the EUR for the outer child well at 600m showed some degree of effect (different from the previous 600m case) and for the inner child well at 300m the EUR response was similar to the single child well at 300m spacing. Finally, changing the completion design drivers (specifically volumes per cluster) of the child well showed an improvement in child well EUR reduction over the current design. The significance of this project is to establish a workflow, or methodology, for evaluating the influence of the parent-child effect on EUR using numerical simulations that can be applied and adapted to any unconventional formation characteristics and input variables (well spacing, completion design, etc.), allowing an informed strategy definition for field development and optimized EUR. This working methodology is based on a fracture simulation software that integrates 3D reservoir model, hydraulic fracturing, and production simulations, using a single package designed to analyze the entire life cycle of a well, from fracturing to long-term production, making it suitable for the objectives of this project.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (4 more...)
Abstract The combination of hydraulic fracturing and horizontal drilling unlocked a huge energy potential in the US. The unconventional plays have been developed by drilling several horizontal wells and hydraulically fracturing them to enhance the fluid flow. The implementation of these well can be done at the same time, known as Tank Development; however, due to the high capital expenditure and the increased risks associated with such an approach, in addition to the limited number of available drilling rigs. Operators try to hold the lease first by drilling one well, producing it, then extending the lease with additional wells. The challenge is that by producing from these wells, the stress and pore pressure state changes around the first wells (i.e., parent well). These changes directly affect the hydraulic fracture propagation from the offset wells (i.e., child wells). In this work, we build a numerical that represents a real case study. The model was calibrated using data from (a) Microseismic Depletion Delineation, (b) Microseismic events, (c) 10 years of production. Synthetic offset wells were implemented to run a sensitivity analysis on the well design (well spacing, cluster spacing, injection volume) and to understand how to design better wells that have been influenced by production from a primary well. The simulations were run for 10 years. The results show that wider well spacing results in better production, whereas lower cluster spacing had better production. This study allows operators to design better offset wells drilled next to a depleted parent well in the Bakken.
- North America > United States > North Dakota (1.00)
- North America > Canada > Saskatchewan (0.69)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
- North America > United States > West Virginia > Appalachian Basin > Utica Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (30 more...)
- Well Drilling (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (7 more...)
Production Data Analysis of Shale Oil Reservoir Using the Dynamic Drainage Pore Volume Concept: Lessons-Learned from Well-To-Well Fracture Driven Interaction in Lucaogou Shale Formation
Pan, Yuewei (1. PetroChina Exploration & Production Company, Beijing, China) | Qin, Jianhua (2. Research Institute of Petroleum Exploration & Development, Beijing, China) | Zhang, Jing (Xinjiang OilField Company, Karamay, Xinjiang, China) | Shang, Jianlin (Xinjiang OilField Company, Karamay, Xinjiang, China) | Ma, Wei (Xinjiang OilField Company, Karamay, Xinjiang, China)
Abstract Many pilot researches consider production gains or losses in parent/child wells in short-term thereby determining the optimal completion parameters (eg. well spacing, stage spacing). Long-term recovery varies from negative-to-positive during the post-frac-hit evaluation based on the magnitude of the pressure sink and the distance of parent/child wells. However, quantitatively analyzing frac-hits impact remains unsolved. This paper presents a novel workflow combining RTA diagnostic plots and the prediction of dynamic drainage pore volume (DDPV) to analyze the frequent well/well fracture-driven interaction (FDI) (commonly referred to as frac-hits) in the Lucaogou shale formation, Junggar Basin. According to the published knowledge, different strategies have been employed in Lucaogou formation to minimize the negative effect and to avoid the parent/child wells (e.g cube-development). Thus, optimizing stage, cluster and well spacing in well-pad zipper-frac development is in necessity. This paper first reviews the frac-hit mechanisms in both parent/child wells and well-pad zipper-frac development. We then characterize, quantify and rank the historical frac-hit events in Lucaogou formation based on the documented data. With the prediction of DDPV using numerical integration/differentiation assisted by diagnostic plots and specialized plots in RTA (eg. flowing material balance plot, square-root-of-time diagnostic plot), the pressure sink front can be acquired. The accuracy of DDPV forecast is validated using a synthetic case study. We further apply it to three field case studies to demonstrate the versatility and applicability of the proposed workflow. The successful applications suggest that the proposed workflow is an alternative to making field-development decisions, minimizing the negative impacts of frac-hits and thus freeing the cashflows. The outcomes are mainly but not limited to: 1) the common early departures from linear flow regime are in good alignment with the DDPV forecasts in both parent/child and well-pad development scenarios; 2) A competition of the per-well DDPV might be triggered during frac-hits in parent/child well and 3) long-term recovery in well-pad development with a tighter well-spacing might be boosted with a smaller per-well DDPV and DOI.
- North America > United States > Texas (1.00)
- Asia > China (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline (1.00)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- North America > United States > Arkansas > Haynesville Shale Formation (0.99)
- (3 more...)
- Well Completion > Hydraulic Fracturing (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)
- (8 more...)
Abstract The objective of this study was to investigate the trend of increasing water cuts in Permian Basin unconventional reservoirs and understand its relationship with development and production strategies, which have evolved greatly in the past 10 years. In many Permian Basin unconventional reservoirs, field production data show that over the long term, water cuts tend to increase as field development and production strategies improve. Many questions have arisen concerning this increasing water trend: What will be the impact of increasing water cuts on overall recovery? Where is the water coming from? Is there a nearby mobile aquifer? Are we drilling and fracturing into wet zones? What can we do to mitigate it? This study finds that while drilling and fracturing into wet zones will result in a high water cut, the increase over time is not because of a mobile aquifer or necessarily due to wet zone completion. Rather, the increasing water cut trend is mostly because of improved completion methods, increased well density, and aggressive production techniques that speed up fluid withdrawal rates. Without pressure maintenance from injection, gas cap expansion, or aquifer influx, changes in water cut are controlled by changes in fluid properties, saturation, and effective permeability with pressure depletion. The trend is normal for a volumetric oil reservoir under solution gas drive. It will keep on increasing as operational efficiency keeps on improving and the reservoir depletes faster. The study also found that the increasing water cut trend did not have a significant impact on section oil recovery. Introduction Over the last decade, drilling and completions in Permian Basin unconventional reservoirs have evolved tremendously. What started as a vertical well drilling campaign is now a horizontal well campaign with laterals reaching 1–2 miles. As drilling has evolved, so has hydraulic fracturing. What started as a single-stage hydraulic fracture is now a multi-stage, multi-cluster per stage completion with higher ratios of proppant per foot and fluids per foot. Uddin et al. (2018) enumerated the evolution of Permian Basin hydraulic fracturing techniques over the decade. With respect to field development, what started as one or two wells per section today involves up to 8 wells per bench per section. Operationally, the basin has also shifted from a slow flowback strategy to a more aggressive and efficient flowback. Xie et al. (2021) highlighted some of the flowback optimization strategies currently in place in Permian Basin unconventional reservoirs and concluded that aggressive flowback won't significantly impact overall oil recovery.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (1.00)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- 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)
- (23 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (2 more...)
Localisation and Recovery Planning of the Remaining Hydrocarbon Reserves
Aslanyan, Artur Mihailovich (Nafta College) | Popov, Arkadii Yurievich (Gazpromneft STC) | Zhdanov, Ivan Aleksandrovich (Gazpromneft STC) | Pakhomov, Eugeny Sergeevich (Gazpromneft STC) | Ibryaev, Nikolay Petrovich (Gazpromneft-Noyabrskneftegas JSC) | Kuznetsov, Maksim Aleksandrovich (Gazpromneft-Noyabrskneftegas JSC) | Krichevsky, Vladimir Markovich (Sofoil) | Garnyshev, Marat Yurievich (Sofoil) | Guss, Rodion Vladimirovich (Sofoil)
Abstract The paper presents the results of a study project of 60+ well block of the large (> 1,000 wells) mature (30 year old) oilfield in Western Siberia with objective to localise and characterize residual recoverable reserves and propose the optimal economic scenario for further depletion. Low permeability, heterogeneous reserve structure along the cross-section, numerous induced hydraulic fractures in producing wells and numerous spontaneous fractures in injecting wells with dynamic behavior, aggravated by numerous behind-the-casing crossflows in almost every well have resulted in a very complex conditions of remaining reserves. The conventional methods of production analysis and surveillance (well testing and production logging) do not provide a consistent picture of the current distribution and conditions of the remaining reserves and required a deeper and more complex analysis. Development Opportunities Management workflow was chosen for this particular holistic study, which includes a set of interconnected studies, field surveillance, geological and flow modelling and culminated in field development planning based on the digital asset twin. (Ganiev, B., 2021) Digital asset twin was constructed based on results of this workflow with a full-range economical model, flow simulation over the thoroughly calibrated fine-grid 3D dynamic model and production complication model (dynamic behavior of the fractures and behind-casing channeling). The 3D model has been calibrated on results of the cross-well pressure-pulse surveillance, reservoir-oriented production logging and was validated by the results of the drilling of the transition wells. The digital asset twin was used to find the optimal investment scenario based on multivariate calculations with the help of digital assistants. Due to simplicity of the user interface and client-server design, the digital twin was made available for various corporate engineers and managers without any modelling skills to play around with their own ideas on possible production/investment scenarios which gave another level of validation of the ultimate field development plan. All activities carried out within the digital twin automatically generate a complete package of investment metrics (NPV, PI, IRR, MIRR, Cash Flow and many correlation graphs) to assess the economic efficiency of each package and select the most appropriate solution for further ultimate choice. The approved scenario was based around drilling 6 producing side-tracks in specific locations/trajectories, performing workovers on specific offset injectors and re-scheduling of the production/injection rates in all block wells. The results of the field development's activities implementation will be the subject of a future publication.
- Europe (0.93)
- Asia > Middle East (0.67)
- North America > United States > Texas (0.34)
- North America > Canada > Alberta (0.34)
- North America > Canada > Alberta > High Level Field > Amax Andex Et Al Highl 16-13-111-20 Well (0.99)
- Africa > Middle East > Libya > Wadi al Hayat District > Murzuq Basin > Block NC 186 > I&R Fields > R Field > Mamouniyat Formation (0.99)
- Africa > Middle East > Libya > Wadi al Hayat District > Murzuq Basin > Block NC 115 > I&R Fields > R Field > Mamouniyat Formation (0.99)
- (14 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (4 more...)
Abstract Infill completions have been explored by many operators in the last few years as a strategy to increase ultimate recovery from unconventional shale oil reservoirs. The stimulation of infill wells often causes pressure increases, known as fracture-driven interactions (FDIs), in nearby wells. Studies have generally focused on the propagation of fractures from infill wells and pressure changes in treatment wells rather than observation wells. Meanwhile, studies regarding the pressure response in the observation (parent) wells are mainly limited to field observations and conjecture. In this study, we provide a partialcorrective to this gap in the research.We model the pressure fluctuations in parent wells induced by fracking infill wells and provide insight into how field operators can use the pressure data from nearby wells to identify different forms of FDI, including fracture hit (frac-hit) and fracture shadowing. First,we model the trajectory of a fracture propagating from an infill well using the extended finite element methods (XFEM). This method allows us to incorporatethe possible intersection of fractures independent of the mesh gridding. Subsequently, we calculate the pressure response from the frac-hit and stress shadowing using a coupled geomechanics and multi-phase fluid flow model. Through numerical examples, we assess different scenarios that might arise because of the interactions between new fractures and old depleted fractures based on the corresponding pressure behavior in the parent wells. Typically, a large increase in bottomhole pressure over a short period is interpreted as a potential indication of a fracture hit. However, we show that a slower increase in bottomhole pressure may also imply a fracture hit, especially if gas repressurization was performed before the infill well was fracked. Ultimately, we find that well storage may buffer the sudden increase in pressure due to the frac-hit. We conclude by summarizing the different FDIs through their pressure footprints.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.48)
- North America > United States > Texas > Permian Basin > Central Basin > 3000 Formation (0.99)
- Asia > Middle East > Iran > Lavan Island > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Salman Field (0.93)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (4 more...)
The Influence of Development Target Depletion on Stress Evolution and Infill Drilling of Upside Target in the Permian Basin
Pei, Yanli (University of Texas at Austin (Corresponding author) | Yu, Wei (email: yanli.pei@utexas.edu)) | Sepehrnoori, Kamy (University of Texas at Austin and Sim Tech LLC) | Gong, Yiwen (University of Texas at Austin) | Xie, Hongbing (Sim Tech LLC and Ohio State University) | Wu, Kan (Sim Tech LLC)
Summary The extensive depletion of the development target triggers the demand for infill drilling in the upside target of multilayer unconventional reservoirs. However, such an infill scheme in the field practice still heavily relies on empirical knowledge or pressure responses, and the geomechanics consequences have not been fully understood. An embedded discrete fracture model (EDFM) is deployed in our fluid-flow simulation to characterize complex fractures, and the stress-dependent matrix permeability and fracture conductivity are included through the compaction/dilation option. After calibrating reservoir and fracture properties by history matching of an actual well in the development target (i.e., third Bone Spring), we run the finite element method (FEM)-based geomechanics simulation to model the 3D stress state evolution. Then a displacement discontinuity method (DDM) hydraulic fracture model is applied to simulate the multicluster fracture propagation under an updated heterogeneous stress field in the upside target (i.e., second Bone Spring). Numerical results indicate that stress field redistribution associated with parent-well production indeed vertically propagates to the upside target. The extent of stress reorientation at the infill location mainly depends on the parent-child horizontal offset, whereas the stress depletion is under the combined impact of horizontal offset, vertical offset, and infill time. A smaller parent-child horizontal offset aggravates the overlap of the stimulated reservoir volume (SRV), resulting in more substantial interwell interference and less desirable oil and gas production. The same trend is observed by varying the parent-child vertical offset. Moreover, the efficacy of an infill operation at an earlier time is less affected by parent-well depletion because of the less-disturbed stress state. The candidate infill-well locations at various infill timings are suggested based on the parent-well and child-well production cosimulation. The conclusions provide practical guidelines for the subsequent development in the Permian Basin.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- (7 more...)
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201346, “Are We Overstimulating Our Laterals? Evaluating Completion Design Practices Based on Field Offset Well-Pressure Measurements,” by Puneet Seth, SPE, The University of Texas at Austin, and Brendan Elliott, SPE, and Trevor Ingle, SPE, Devon Energy, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Increased injection volumes coupled with a suboptimal completion design can lead to overstimulation at current well-spacing densities. In the complete paper, the authors analyze offset well-pressure measurements in the Permian Basin to evaluate if a fracturing job is overstimulated. Additionally, numerical modeling studies are performed to evaluate the extent of overstimulation in different scenarios and provide recommendations to maximize the capital efficiency of a fracturing job. In their analysis, the authors focus on the scenario in which fracturing hits occur when child-well fractures intersect with the parent well. Field Data Analysis Pumping for the full designed volume and time (typically 90 minutes) according to well-stimulation procedures is currently common in the industry. Often, the observation of hydraulic interactions is not coupled with a decision to alter or change the stimulation. The authors analyzed the offset well-pressure response monitored with a surface pressure gauge in multiple parent wells in the Permian Basin during stimulation in nearby child wells. The child wells were stimulated after roughly 1 year of production from the parent wells. The focus of this study was to identify fracture-driven interactions—specifically the timing of intersection of the child-well fractures with the offset parent wells, which are recorded as massive hydraulic pressure responses. The results of this analysis for different well pairs are presented in the complete paper. To better understand the factors that affect fracture propagation from the child wells toward the parent wells, fracture arrival times, and capital efficiency of a fracturing job, a series of numerical simulations was performed with a fully coupled hydraulic fracturing simulator. Simulation Results Numerical simulations were performed using an integrated hydraulic fracturing and reservoir simulator developed at The University of Texas at Austin. This simulator solves for flow and geomechanics in the reservoir, fracture, and wellbore domains in a tightly coupled manner. Hydraulic fractures are modeled as compliant discontinuities in the reservoir rather than high-permeability gridblocks. This is important in order to capture the stress alterations around a propagating fracture accurately. Effect of Parent-Well Production (Depleted Region). For this study, two scenarios were analyzed. In the first case, fracture propagation from a child well stimulated near a recently fractured unproduced parent well (no depletion) was considered. In this case, the fracture from the child well propagates away from the parent well because of elevated stresses near the parent well. In the second case, a child well is stimulated near a parent well that has been producing for 300 days before child-well stimulation. In this scenario, the child-well fracture propagates toward the parent well because of a depleted region that develops near the parent well (because of production) and relaxes the reservoir stresses around the parent well. This causes the child-well fracture to grow preferentially toward the parent well (toward the low-stress region). In fact, in this scenario, as the fracture reaches the depleted reservoir region, its growth accelerates toward the parent well and intersects with the parent well. Even minor depletion can induce asymmetric growth of infill child-well fractures toward the parent well.
- 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...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.53)
- Management > Asset and Portfolio Management > Field development optimization and planning (0.53)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (0.35)
Abstract Hydraulic fracturing is a widespread well stimulation treatment in the oil and gas industry. It is particularly prevalent in shale gas fields, where virtually all production can be attributed to the practice of fracturing. It is also used in the context of tight oil and gas reservoirs, for example in deep-water scenarios where the cost of drilling and completion is very high; well productivity, which is dictated by hydraulic fractures, is vital. The correct modeling in reservoir simulation can be critical in such settings because hydraulic fracturing can dramatically change the flow dynamics of a reservoir. What presents a challenge in flow simulation due to hydraulic fractures is that they introduce effects that operate on a different length and time scale than the usual dynamics of a reservoir. Capturing these effects and utilizing them to advantage can be critical for any operator in context of a field development plan for any unconventional or tight field. This paper focuses on a study that was undertaken to compare different methods of simulating hydraulic fractures to formulate a field development plan for a tight gas field. To maintaing the confidentiality of data and to showcase only the technical aspect of the workflow, we will refer to the asset as Field A in subsequent sections of this paper. Field A is a low permeability (0.01md-0.1md), tight (8% to 12% porosity) gas-condensate (API ~51deg and CGR~65 stb/mmscf) reservoir at ~3000m depth. Being structurally complex, it has a large number of erosional features and pinch-outs. The study involved comparing analytical fracture modeling, explicit modeling using local grid refinements, tartan gridding, pseudo-well connection approach and full-field unconventional fracture modeling. The result of the study was to use, for the first time for Field A, a system of generating pseudo well connections to simulate hydraulic fractures. The approach was found to be efficient both terms of replicating field data for a 10 year period while drastically reducing simulation runtime for the subsequent 10 year-period too. It helped the subsurface team to test multiple scenarios in a limited time-frame leading to improved project management.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- Geology > Geological Subdiscipline > Geomechanics (0.47)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Management > Asset and Portfolio Management > Field development optimization and planning (0.96)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (0.88)
Proper lateral and vertical well spacing is critical for efficient development of unconventional reservoirs. Much research has focused on lateral well spacing but little on vertical spacing, which is challenging for stacked-bench plays such as the Permian Basin. Following a previous, successful single-well study in paper SPE 189855, the authors have performed a seven-well case study in which the latest complex fracture modeling and reservoir-simulation technologies have been applied. This synopsis will concentrate on the methodology behind the study; the reader is encouraged to view the complete paper for specific comparisons of completion designs. Complex-fracture-modeling tools are used frequently to study well spacing.
- 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...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Management > Asset and Portfolio Management > Field development optimization and planning (1.00)
- (2 more...)