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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).
Morales, Adrian (Chesapeake Energy Corp.) | Holman, Robert (Chesapeake Energy Corp.) | Nugent, Drew (Chesapeake Energy Corp.) | Wang, Jingjing (Chesapeake Energy Corp.) | Reece, Zach (Chesapeake Energy Corp.) | Madubuike, Chinomso (Chesapeake Energy Corp.) | Flores, Santiago (Chesapeake Energy Corp.) | Berndt, Tyson (Chesapeake Energy Corp.) | Nowaczewski, Vincent (Chesapeake Energy Corp.) | Cook, Stephanie (Chesapeake Energy Corp.) | Trumbo, Amanda (Chesapeake Energy Corp.) | Keng, Rachel (Chesapeake Energy Corp.) | Vallejo, Julieta (Chesapeake Energy Corp.) | Richard, Rex (Chesapeake Energy Corp.)
Abstract An integrated project can take many forms depending on available data. As simple as a horizontally isotropic model with estimated hydraulic fracture geometries used for simple approximations, to a large scale seismic to simulation workflow. Presented is a large-scale workflow designed to take into consideration a vast source of data. In this study, the team investigates a development area in the Eagle Ford rich in data acquisition. We develop a robust workflow, taking into account field data acquisition (seismic, 4D seismic and chemical tracers), laboratory (geomechanical, geochemistry and PVT) measurements and correlations, petrophysical measurements (characterization, facies, electrical borehole image), real time field surveillance (microseismic, MTI, fracture hit prevention and mitigation program through pressure monitoring) and finally integrating all the components of a complex large scale project into a common simulation platform (seismic, geomodelling, hydraulic fracturing and reservoir simulation) which is used to run sensitivities. The workflow developed and applied for this project can be scaled for projects of any size depending on the data available. After integrating data from various disciplines, the following primary drivers and reservoir understanding can be concluded. At a given oil price, optimum well spacing for a given completion strategy can be developed to maximize rate of return of the project. Many operators function in isolated teams with a genuine effort for collaboration, however genuine effort is not enough for a successful integrated modelling project, a dedicated multidisciplinary team is required. We present what is to our knowledge, one of the most complete data sets used for an integrated modelling project to be presented to the public. The specific lessons from the project are applied to future Eagle Ford projects, while the overall workflow developed can be tailored and applied to any future field developments.
Diakhate, Mamadou (Pioneer Natural Resources) | Gazawi, Ayman (Pioneer Natural Resources) | Barree, Bob (Barree & Associates) | Cossio, Manuel (Pioneer Natural Resources) | Tinnin, Beau (Pioneer Natural Resources) | McDonald, Beth (Pioneer Natural Resources) | Barzola, Gervasio (Pioneer Natural Resources)
Abstract This paper outlines a refrac pilot testing program conducted in the Eagle Ford Shale. As wells in the Eagle Ford accumulate production over time and the pressure around the horizontal wellbore declines, it is important to also consider communication due to offset fracture stimulation. Refracturing trials in older fields, such as the Barnett Shale have yielded a positive enhancement of well performance (Siebrits et al., 2000). This paper evaluates the concept of diverting fluid and proppant along horizontal wells in the Eagle Ford, while considering any communication with older producing wells during refracturing operations. Pumping data acquired during the refracturing is used to explain some of these concepts. Modeling of induced fracture geometry, considering the effect of current pore pressures, is conducted with a fully three-dimensional hydraulic fracture numerical simulator. The pressure of the subject zone may affect the containment and rate of growth of the new fractures, as well as the re-orientation of the existing fractures. Refracturing an old horizontal well with 5,000 ft lateral length and more than 800 existing perforation holes in the casing is very challenging and requires a careful integration of reservoir knowledge, completions skills and experience. The technical team at Pioneer Natural Resources has developed an integrated workflow to design and execute a refracturing job for an Eagle Ford well. The work flow includes: 1) identification of the lower pressure areas along the lateral using surveillance data from the well, such as microseismic, tracer logs, and production data. 2) identifying which wells within the drilling schedule are offsetting older wells that have high cumulative production, and 3) designing a single fracturing job with several sub-stages separated by diverting agents. Each sub-stage is intended to target specific areas along the lateral, which were previously identified as low pressure zones. Volumes and pump schedules will be specific for each candidate and are based on but not limited to proximity to an offset well, lateral length, and existence of geological structures such as faults and fractures in the area. The results from this pilot testing program such as the radioactive tracers and the fracture gradient changes before and after refrac will be evaluated upon completion of the field execution.
Cherian, B. V. (Premier Oilfield Laboratories) | Armentrout, L.. (Murphy Exploration & Production Co., USA) | Baruah, C.. (Murphy Exploration & Production Co., USA) | Ballmer, J.. (Murphy Exploration & Production Co., USA) | Malicse, A. E. (Murphy Exploration & Production Co., USA) | Narasimhan, S.. (Premier Oilfield Laboratories) | Olaoye, O.. (Premier Oilfield Laboratories)
Abstract Like many unconventional plays, the Eagle Ford, once one of the most active shale plays in the world with over 250 rigs running, saw a vast amount of data collected during the boom over a very short time. As with most unconventional resources, a lack of validation of reservoir parameters prevailed in the early history of these plays (emerging plays) and thus, hypothesis drove drilling and completion optimization programs. The 2015 drop in commodity prices accelerated the need to optimize well designs and spacing and stacking patterns in a less capital-intensive manner. A sector model was built that enabled discrete modeling of the 4 development wells in place and significant remaining undeveloped potential to be completed both within and near the sector model area. From this model, substantial understanding around the key parameters driving subsurface performance both from the rock and wellbore design perspectives was gained. As in-fill drilling has occurred in other areas of the play, a learning curve developed around the understanding of vertical connectivity, fracture geometry, well interference and the impact of clusters and job size on fracture contact with the reservoir. This learning curve has been applied to the integrated model to understand what an optimized infill drilling program for the area would look like at various hydrocarbon pricing scenarios. This paper utilizes an integrated model approach to understand reservoir performance on a pad with four wells completed across multiple horizons in the Eagle Ford. Wireline quad combo compressional and shear log suites (including azimuthal anisotropy and VTI sonic processing, resitivity/acoustic borehole imagers, and NMR), core (geomechanical, geochemical analysis, routine core analysis and specialized core analysis), completion data (fracture treatments with pre-and post-job shut-in pressures), production data (1200 days of production history with a bottom-hole pressure gauge and calculated bottom hole pressures from rod pumps) are used to build petrophysical models, geo-models, geomechanical models, fracture propagation models and reservoir models with the aim of understanding completion and production drivers. A workflow is presented that enables these models to improve our understanding of layering effects (vertical connectivity), fracture asymmetry (pressure sinks or sources), well interference (hydraulic vs. propped lengths) and the impact of clusters and job size on fracture contact with the reservoir.
Cherian, Bilu V. (Sanjel) | McCleary, Matthew (SM Energy) | Fluckiger, Samuel (SM Energy) | Nieswiadomy, Nathan (SM Energy) | Bundy, Brent (SM Energy) | Edwards, Sarah (SM Energy) | Rifia, Rafif (Sanjel) | Kublik, Kristina (Sanjel) | Narasimhan, Santhosh (Sanjel) | Gray, James (Sanjel) | Olaoye, Olubiyi (Sanjel) | Shaikh, Hamza (Sanjel)
Abstract Until 2015, North America’s unconventional resource market was known to be home to the largest oil shale deposits of economic value. Although the recent commodity price fluctuations have exposed the role of geo-politics, world economies and commodity trading on the life cycle of assets, few field development studies have consider the impact of commodity cycles on the development of in-fill wells. Papers have been presented to demonstrate the impact of vertical fracture connectivity and fracture asymmetry on in-fill well performance (due to delayed in-fill drilling), but little has been done on validation and coupling the impact of depletion, due to production, and hydraulic fracturing (due to in-fill efficiency fracture operations). This paper presents results from the analysis of in-fill drilling on well performance. Production data, fracture treatment data, completion and production timing are analyzed using pressure/production history matching techniques and compared with results predicted by data driven models (developed to match well performance) with the aim of proposing in-fill development strategies. Analysis of the field production data indicates that timing of in-fill wells (following the parent well) can influence the in-fill production depending on the level of depletion (cumulative fluid produced) and the size/type of fracture treatments pumped. Analysis of raw production data, modeling results from multi-domain model based coupled simulations and high resolution monitoring data also indicates that the order of the in-fill operations (East-West, Zipper, etc.) also has a significant impact on performance. This paper presents a simplistic approach to understand the impact of the quest for operational efficiencies and economic cycles on development strategies.