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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.
Abstract In multi-stage plug-and-perf horizontal well completions, there are a multitude of moving parts and variables to consider when evaluating performance drivers. Properly identifying performance drivers allows an operator to focus their efforts to maximize the rate of return of resource development. Typically, well-to-well comparisons are made to help identify performance drivers, but in many cases the differences are not clear. Identifying these drivers may require a better understanding of performance variability along a single lateral. Data analytics can help to identify performance drivers using existing data from development activities. In the case study below, multiple diagnostics are utilized to identify performance drivers. A combination of completion diagnostics including oil and water tracers, stimulation data, reservoir data, 3D seismic, and borehole image logs were collected on a set of wells in the early appraisal phase of a field. Using oil tracers as the best indication of stage level performance along the laterals, data analytics is applied to uncover the relationships between the tracers and the numerous diagnostics. After smoothing was applied to the dataset, trends between oil tracer recovery, several independent variables and features seen in image logs and 3D seismic were identified. All the analyses pointed to decreasing tracer recovery, and likely decreased oil production, near faulted areas along each lateral. A random forest model showed a moderate prediction power, where the model's predicted tracer recovery on blind stages was able to explain 54% of the variance seen in the tracer response (r=0.54). This analysis suggests the identification of certain faulted areas along the wellbore could lead to ways of improving individual well economics by adjusting completion design in these areas.
Summary The pressure decline data after the end of a hydraulic fracture stage are sometimes monitored for an extended period of time. However, to the best of our knowledge, these data are not analyzed and are often ignored or underappreciated because of a lack of suitable models for the closure of propped fractures. In this study, we present a new approach to model and analyze pressure decline data that are available in unconventional horizontal wells with multistage, transverse hydraulic fracturing. The methods presented in this study allow us to quantify closure stress and average pore pressure inside the stimulated reservoir volume (SRV) and to infer the uniformity of proppant distribution without additional data acquisition costs. For the first time, field data of diagnostic fracture injection test (DFIT), flowback, and pressure decline of main fracturing stages from the same well are compared and analyzed. We found that the early-time main fracturing stage pressure decline trend is controlled by fracture tip extension, followed by progressive hydraulic fracture closure on the proppant pack, whereas late-time pressure decline reflects linear flow. When DFIT data are not available, pressure decline analysis of a main hydraulic fracturing stage can be a substitution if it can be monitored for an extended period to allow fracture closure on proppants and asperities.
Summary Optimal spacing between fracture clusters has eluded reservoir and completions engineers since the inception of multistage hydraulic fracturing. Very small fracture spacing could result in fracture to fracture (intrawell) interference and a higher completion cost, whereas very large fracture spacing could lead to inefficient hydrocarbon recovery, which is detrimental to the well economics. Meramec Formation has moved to full‐field development, and multiple wells are put on production in a relatively short time. Depending on the desired economic metric, net present value (NPV), or rate of return (ROR), the magnitude of intrawell interference can be optimized by adjusting fracture spacing. For instance, if the objective is to maximize ROR, then tighter fracture spacing can be accepted. Furthermore, petroleum economics are often ignored in simulation studies, particularly the concepts of time value of money and oil‐price sensitivity. This has led to a knowledge gap in identifying optimal drawdown procedure and fracture spacing from numerical models. This study proposes a framework that integrates petroleum economics with simulation results to optimize a horizontal well from the Meramec Formation. On the basis of this framework, we identified optimal drawdown procedure and fracture spacing. Then, oil‐pricing sensitivity analysis was conducted to illustrate the effect of oil‐price volatility on design parameters. Moreover, this study investigates the relative contribution of reservoir and completions characteristics with regard to short‐ and long‐term well performance. These characteristics include drawdown management, fracture spacing, pressure‐dependent permeability, critical gas saturation, and petrophysical properties. Available geologic data were integrated to construct a geologic model that is used to history match a well from the Meramec Formation. The geologic model covers an area of 640 acres that encompasses a multistage hydraulically fractured horizontal well. The well is unique because it is unbounded and has more than 2 years of continuous production without being disturbed by offset operations. Findings suggest that the drawdown strategy (aggressive vs. conservative) has more effect on short‐term oil productivity than fracture spacing. Drawdown strategy even has more of an effect on short‐term oil recovery than does a 20% error in porosity, or water saturation. Furthermore, the profile of the producing‐gas/oil ratio (GOR) depends on completions efficiency, and it has been interpreted using linear‐flow theory.
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).
This paper chronicles the progression of liner refracs on mature wells in the South Texas Eagle Ford Shale. Operational issues, strategies to mitigate the risk, and well results will be reviewed.
Liner refracs involve running and cementing smaller casing as a liner inside previously stimulated 5 ½-in. cased hole lateral completions. This method of isolating existing perforations has been successfully applied to allow subsequent refrac plug and perf operations. The operational steps to execute these deployments impose more risk than completing new wells and significant failures have occurred. Fit for purpose equipment, best practices, and a steep learning curve have been employed to mitigate the risk and improve the overall economic benefits of the program. An account of the failures and efforts to prevent these issues is provided.
From the summer of 2018 through 2019, 15 liner refracs have been executed in high temperature wells in Dewitt County, Texas. Three of the wells with operational issues are presented along with the approach to prevent reoccurrence. One well was eventually lost when the production casing was inadvertently damaged while attempting to mechanically cut the installed liner. This prompted an alternative deployment method, and the development of an anchor system which has now been used on six wells. The smaller geometry and tools required in liner refracs impose additional challenges. This study outlines this operator's approach to minimize the risk and reduce failure frequency. Dramatic increases in pressure and production have been observed on the liner refracs. The wells that have been executed successfully, have exceeded return on investment expectations.
Liner refracs provide a tool to capture production and reserves from existing wells and enhance field development. Lessons learned and alternative methods to execute liner refracs are considered in this field study.
Abstract The Barnett Shale continues to offer vast opportunities for refracturing operations. This study covers diagnostic data and case histories of refracturing in the Barnett Shale. Job design and completion techniques are evaluated throughout the project. Candidate selection planys an important role in the overall success of a refracturing program. Wells are grouped by area and original completion design. Completion diagnostics are utilized to test and optimize a variety of refracturing techniques. These techniques include bullhead treatment with and without diverter, various types of diversion, and mechanical isolation. The evaluation of the refracturing program will be broken up into two parts. Bullhead refracturing techniques will be evaluated for new and existing perforation coverage as well as overall lateral coverage. The second part of the paper will evaluate mechanical isolation techniques. These techniques include the installation of a liner with and without isolation on the annulus. A plug and perf treatment is then performed through the newly installed liner. In addition to the optimization through the use of completion diagnostics, the wells are evaluated based on production analysis. This study will compare the overall economics to the method deployed. Twenty-nine horizontal wells are included in this study with some form of diagnostics utilized during the frac. Accessing new rock shows a correlation with incremental reserves as expected. Diversion is evaluated with economic projects on bullhead operations. However, the diversion is not always effective at opening up new perforations and stimulating the well effectively. This study provides data that is utilized to develop best practices for refracturing in the Barnett Shale that can be applied directly to additional basins. In addition to the direct applicability of this work, the methodology utilized to test and optimize diversion can be applied not only to refracturing operations, but also to new well completions.
Abstract A field-trialed ball-activated Outflow Control Device (OCD) is presented that eliminates coiled tubing intervention in SAGD injection wells when converting from steam circulation to SAGD. This paper builds on a previously presented paper by the same authors where the design and tool qualification of the ball-activated OCD was presented (Webb et al, 2017). In this paper, the results of the field trial are shared and compared with analogous wells where coiled tubing shiftable OCDs were used. The field trial of the ball-activated OCD is compared to coiled tubing shiftable OCDs on three main criteria: job efficiency, confirmation of shift, and environmental, health, and safety (EHS) considerations. Acoustic-based monitoring equipment and pressure signatures were used to confirm successful ball-activation of the ball-activated OCD. A tension response from the coiled tubing was used to confirm shifting of the coiled tubing shiftable OCDs. Steam modelling and observed tubing pressure drop data is also shared for all trials as another indication of successful shift. In five of six ball-activated OCD shifts, the tools functioned as intended with clear pressure and acoustic signatures confirming a successful shift of the sliding sleeve. One of six was intentionally left closed. In addition, the jobs were completed more efficiently and with less EHS risk than the coiled tubing shiftable OCDs. The coiled tubing shifting tension data indicated that two out of six coiled tubing shiftable OCDs were successfully shifted, with inconclusive shifts occurring on three OCDs, and one left intentionally closed. The observed pressure drop data presented, indicates that shifting was successful in all ball-activated trial wells, and two of three coiled tubing shiftable trial wells. The ball-activated OCD is a novel tool for use in SAGD injector wells to improve efficiency by reducing operational time and personnel required in shifting OCDs. In addition, the shift confirmation pressure signature and optional acoustic monitoring provides greater confidence of sleeve shift.
Seth, Puneet (The University of Texas at Austin) | Manchanda, Ripudaman (The University of Texas at Austin) | Elliott, Brendan (Devon Energy) | Zheng, Shuang (The University of Texas at Austin) | Sharma, Mukul (The University of Texas at Austin) | Hwang, Jongsoo (The University of Texas at Austin)
Abstract During stimulation of unconventional reservoirs, offset well pressure measurements are often used to estimate hydraulic fracture geometry. These measurements can also be used to make a quantitative estimate of the created fracture network area and the permeability of the stimulated rock volume (SRV) around the hydraulic fractures. Offset well pressure measurements recorded in the field clearly show a change in the pressure response of the monitor well when the injection rate in a nearby fracture treated well is changed. The shut-in period between two frac stages in the treatment well corresponds to a distinct pressure fall-off in the monitor well. We present a workflow where we analyze and match this pressure fall-off in an offset monitor well in response to fluid leak-off from a hydraulic fracture in the treatment well to estimate SRV permeability and the created fracture network area. The workflow and model are applied to field data from the Permian Basin. A fully-coupled, 3-D, poroelastic reservoir-fracture simulator has been used to simulate pressure fall-off in the offset monitor well. Field data and simulation results are presented to show that during shut-in between two frac stages in the treatment well, a decrease in the injection rate causes the monitored offset well pressure to fall-off. We find that this fall-off in pressure is influenced by leak-off from the treatment well fracture. During the shut-in period, fluid leak-off from the treatment well fracture into the SRV region decreases the width of the fracture which consequently affects the stress-shadow and the poroelastic pressure fall-off in the offset monitor well. The pressure fall-off in the monitor well is, therefore, shown to be caused by 1) the fluid leak-off from the monitor well fracture and 2) stress-shadow relaxation around the monitor well fracture as fluid leaks-off from the nearby treatment well fracture into the formation. We present a new method to estimate the permeability of the stimulated region around the created fractures. We show that, along with the permeability of the SRV region, the stress-shadow of the treatment well fracture on the monitor well fracture also has a significant impact on the pressure fall-off in the monitor well. We use a conceptual model to estimate the created fracture network area which can be used as a metric to identify the effectiveness of a frac job and provide insights into the generated fracture complexity during the frac job. In addition, the estimated SRV permeability and fracture network area are critical inputs in production forecast simulations that can guide an operator to make better economic decisions in a relatively inexpensive manner.