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Brinkley, Kourtney (Devon Energy) | Ingle, Trevor (Devon Energy) | Haffener, Jackson (Devon Energy) | Chapman, Philip (Devon Energy) | Baker, Scott (Devon Energy) | Hart, Eric (Devon Energy) | Haustveit, Kyle (Devon Energy) | Roberts, Jon (Devon Energy)
Abstract This case study details the use of Sealed Wellbore Pressure Monitoring (SWPM) to improve the characterization of fracture geometry and propagation during stimulation of inter-connected stacked pay in the South Texas Eagle Ford Shale. The SWPM workflow utilizes surface pressure gauges to detect hydraulically induced fracture arrivals athorizontal monitor locations adjacent to the stimulated wellbore (Haustveit et al. 2020). A stacked and staggered development in Dewitt County provided the opportunity to jointly evaluateprimary completion and recompletion efforts spanning three reservoir target intervals. Fivemonitor wells at varying distances across the unit were employed for SWPM during the stimulation of four wells. An operational overview, analysis of techniques, correlation with seismic attributes, image log interpretations, and fracture model calibration are provided. Outputs from this workflow allow for a refined analysis ofthe overall completion strategy. The high-density, five well monitor array recorded a total of 160 fracture arrivals at varying vertical and lateral distances, with far-field fracture arrivalsprovidingsignificant insight into propagation rates and geometry. Apronounced trend occurred in both arrival frequency and volumes pumped as monitor locations increased in distance from the treatment well. Specific to target zone isolation, it was identified that traversing vertically in section through a high stress interval yielded a 30% reduction inarrival frequency. An indirect relationship between horizontal distance and arrival frequency was also observed when monitoring from the same interval. A decrease in fracture arrivals from 70% down to 8% was realized as offset distance increased from 120 to 1,700 ft. The results from this study have proven to be instrumental in guiding interdisciplinary discussion. Assessing fracture geometry and propagation during stimulation, particularly in the co-development of a stacked pay reservoir, is paramount to the determination of proper completion volume, perforation design, and well spacing. Leveraging the observations of SWPM ultimately provides greater confidence in field development strategy and economic optimization.
Infill development typically strives to improve resource recovery while maximizing economic objectives of the organization. Success is dependent on many variables, several of which include well spacing, completion design, and mechanical stratigraphy. Optimizing development is contingent upon understanding how these variables interact with one another and what combination of development strategies will maximize the company objective. One of the challenges with optimizing horizontal multi-frac wells has been quantifying well to well connectivity, understanding the appropriate amount, and how various development strategies impact that relationship. This paper will present a case for development optimization by integrating the results of multiple quantitative pressure interference tests with completion design and well spacing in the STACK play. The framework for quantifying the connectivity between wells was developed by Chu et al (2018) and is often referred to as Chow Pressure Group (CPG). Using this technique, the Magnitude of Pressure Interference (MPI) was quantified between 25 horizontal wells within 10 development units. The dataset is unique because the infill units were developed with varying completions and well spacings which provides an opportunity to isolate and understand how each variable directly impacts well to well connectivity. This study also addresses the desired amount of connectivity between horizontal wells and how it impacts well performance and recovery.
The results from this case study suggest there is a clear relationship between well spacing and MPI, consistent with the findings by Chu et al (2018). Ultimate recovery was investigated and found to have a correlation with the amount of connectivity between development wells. Additionally, at consistent well spacing, higher proppant volume per cluster increased MPI and Estimated Ultimate Recovery (EUR) per well. Increasing proppant per cluster is likely extending the conductive half-length, increasing fracture overlap and MPI, and reducing bypassed resource beyond the tips of the fractures, resulting in higher EUR and Drilling Spacing Unit (DSU) recovery.
This case study provides asset teams with valuable relationships between reservoir, completions, geologic characteristics and how they tie to well performance in the Anadarko Basin. These relationships are expected to be different in every basin/formation, however, it highlights the power of quantitative interference tests in optimizing infill development and understanding the appropriate amount of well to well connectivity. This work also lays out a practical example regarding the dependent nature of completions and reservoir well spacing which can serve as a workflow for asset teams working unconventional plays across the world.
Haustveit, Kyle (Devon Energy) | Elliott, Brendan (Devon Energy) | Haffener, Jackson (Devon Energy) | Ketter, Chris (Devon Energy) | O'Brien, Josh (Devon Energy) | Almasoodi, Mouin (Devon Energy) | Moos, Sheldon (Devon Energy) | Klaassen, Trevor (Devon Energy) | Dahlgren, Kyle (Devon Energy) | Ingle, Trevor (Devon Energy) | Roberts, Jon (Devon Energy) | Gerding, Eric (Devon Energy) | Borell, Jarret (Devon Energy) | Sharma, Sundeep (Devon Energy) | Deeg, Wolfgang (Formerly Devon Energy)
Over the past decade the shale revolution has driven a dramatic increase in hydraulically stimulated wells. Since 2010, hundreds of thousands of hydraulically fractured stages have been completed on an annual basis in the US alone. It is well known that the geology and geomechanical features vary along a lateral due to landing variations, structural changes, depletion impacts, and intra-well shadowing. The variations along a lateral have the potential to impact the fluid distribution in a multi-cluster stimulation which can impact the drainage pattern and ultimately the economics of the well and unit being exploited. Due to the lack of low-cost, scalable diagnostics capable of monitoring cluster efficiency, most wells are completed using geometric cluster spacing and the same pump schedule across a lateral with known variations.
A breakthrough patent-pending pressure monitoring technique using an offset sealed wellbore as a monitoring source has led to advancements in quantifying cluster efficiencies of hydraulic stimulations in real-time. To date, over 1,500 stages have been monitored using the technique. Sealed Wellbore Pressure Monitoring (SWPM) is a low-cost, non-intrusive method used to evaluate and quantify fracture growth rates and fracture driven interactions during a hydraulic stimulation. The measurements can be made with only a surface pressure gauge on a monitor well.
SWPM provides insight into a wide range of fracture characteristics and can be applied to improve the understanding of hydraulic fractures in the following ways: Qualitative cluster efficiency/fluid distribution Fracture count in the far-field Fracture height and fracture half-length Depletion identification and mitigation Fracture model calibration Fracture closure time estimation
Qualitative cluster efficiency/fluid distribution
Fracture count in the far-field
Fracture height and fracture half-length
Depletion identification and mitigation
Fracture model calibration
Fracture closure time estimation
The technique has been validated using low frequency Distributed Acoustic Sensing (DAS) strain monitoring, microseismic monitoring, video-based downhole perforation imaging, and production logging. This paper will review multiple SWPM case studies collected from projects performed in the Anadarko Basin (Meramec), Permian Delaware Basin (Wolfcamp), and Permian Delaware Basin (Leonard/Avalon).
Mukherjee, Souvik (CARBO Ceramics) | Al-Tailji, Wadhah (CARBO Ceramics) | Palisch, Terry (CARBO Ceramics) | Haustveit, Kyle (Devon Energy) | Schwarzbach, Christoph (Computational Geosciences Inc.) | Haber, Eldad (Computational Geosciences Inc.) | Feng, Wanjie (Zonge International) | Urquhart, Scott (Zonge International)
ABSTRACT Application of electromagnetic techniques to determine propped fracture characteristics is currently a hot topic of interest in the unconventional reservoir industry. For widespread adoption of this method, key questions on utility for making business decisions need to be addressed. The present work provides a semi quantitative framework for analyzing inversion results and its accompanying error bars. In the absence of conventional drill bit based "ground truth" data, such an approach provides a practical method for narrowing down input options for key propped fracture parameters used for making decisions on optimized well spacing, developing production forecast models, and meeting other important business objectives for the industry. Presentation Date: Tuesday, September 17, 2019 Session Start Time: 8:30 AM Presentation Time: 9:45 AM Location: 225C Presentation Type: Oral
Haustveit, Kyle (Devon Energy) | Almasoodi, Mouin (Devon Energy) | Al-Tailji, Wadhah (CARBO Ceramics Inc.) | Mukherjee, Souvik (CARBO Ceramics Inc.) | Palisch, Terry (CARBO Ceramics Inc.) | Barber, Rusty (Formerly Devon Energy)
Abstract What is the number one problem with hydraulic fracturing and the frustrations that haunt every completions engineer? Our inability to see what is going on downhole during and after a hydraulic fracture stimulation job. This deficiency leads to numerous questions when attempting to optimize well performance and drainage, such as fracture extension, height growth, proppant/fluid volume usage, parent well depletion effects, cluster efficiency, etc. Over the years, several technologies have been used in an attempt to answer these questions including fiber optic, micro-seismic, chemical and proppant tracers, pressure matching and modeling. However, to date, none have been able to answer the most basic (and some would argue most important) question of all: where is the proppant located in the far-field? A novel method that is gaining traction to answer this question is the use of electromagnetic (EM) technology to detect electrically conductive proppant. In this technology, a surface EM array is deployed and the EM field is measured both before and after the electrically-conductive proppant has been placed. Advanced modeling is then used to invert the before- and after-frac response to locate the proppant. This paper will briefly review the technology as well as the motivation for deploying the process in one operator's STACK development. The paper will then thoroughly review a case history, where this EM proppant detection method was used in two offset infill wells in the STACK (Sooner Trend Anadarko Canadian and Kingfisher counties) play of Oklahoma. The two new wells were selected to be near the parent wellbore, where depletion effects were expected to impact both wells. The primary purpose of the project was to understand the impact the parent well had on an infill stimulation design. Proppant maps will be presented which address the impact of the parent well depletion on the bi-wing fracture growth. Other complementary technologies will be presented including surface pressure monitoring of offset wells. This technology was also deployed previously in an area vertical science well and where applicable, these results will be included. This paper will be useful for engineers, geoscientists and other technicians who wrestle with how to effective place their infill wells and design their fracture stimulations, with the goal of optimally depleting their acreage.
Introduction The Mississippian Meramec STACK play is an emerging unconventional target in the Anadarko Basin in west central Oklahoma. Prolific production results have been seen through the play from multiple prospective target intervals. While there has been newfound success, historical research in the region is lacking, with no research completed specifically on the Meramec interval currently being drilled. Key geologic concepts such as facies types, type of reservoir and porosity, depositional trends, and sequence stratigraphic distribution of reservoir and non-reservoir facies have not been identified. The aim of this work is to adequately characterize the sequence stratigraphic controls within the system to identify the stacking potential and vertical reservoir segregation through the play. Lithofacies and Control on Reservoir Quality The Meramec is primarily a siliciclastic system composed of a range from argillaceous to calcareous siltstone/very fine sandstone, indicating a strong shift in depositional styles from the carbonate system in the Meramec to the north. Within the play, the primary driver of reservoir quality in the Meramec is the percentage of calcite cement within individual facies. Presence of clays is observed to inhibit cementation and preserve some primary porosity. Large amounts of cement are found in silty/peloidal turbidites which are preferentially cemented due to high initial depositional porosity while more argillaceous siltstones with lower depositional porosity and higher clay content have limited cementation and preservation of interparticle pore space. These relationships impart a dominant depositional control both vertically and laterally through the play. Mapping Geometries and Depositional Interpretation Internal mapping geometries in the Meramec, illustrated by isopach thicknesses, identify a system of prograding clinoforms. The clinoforms are identified to have strike-elongate continuity in a northeast-southwest orientation with progradation of the system to the southeast (Figure 1). Individual clinoforms are shown to have extremely low inclinations (less than 1°). Due to the low inclination, similar depositional conditions are inferred to have acted along depositional strike as well as depositional dip. Facies therefore are generally similar through each clinoform with the exception of the uppermost topset and lowermost bottomset being more calcareous and argillaceous, respectively. These characteristics fall in line with the depositional interpretation of a subaqueous delta complex. These complexes are defined by the presence of low angle, shore-parallel clinoforms fed by fine-grain riverine input deposited primarily by longshore basinal currents within or below storm wave base (Patruno et al., 2015).