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Abstract This paper presents a diagnostic-driven method of evaluating refracturing (refrac) techniques in unconventional wells. Detailed analysis across the lateral, using intervention based distributed fiber optic (DFO) measurements, allows for a comprehensive understanding of the refrac performance. While there are various approaches to refracing an unconventional well, there is a categorical division of two main strategies: iterations of limited interval re-stimulation or re-stimulate the entire lateral at once. Stage-by-stage refrac, via casing-in-casing or coil tubing with isolation-type packer tool, offers potential control over stimulation distribution but often incurs heavier cost compared to refracing the entire well simultaneously. The economically favorable simultaneous refrac of all stages (Bull head) can be executed at a lower price but at the cost of not knowing the extent of lateral distribution. With several possible approaches for refracing an entire lateral at once, further questions arise regarding which method provides the most laterally uniform re-stimulation and whether the resultant production improvement is from re-stimulated existing or newly created fractures. A major hurdle in both executing and evaluating the success of an all stage simultaneous refrac is the uncertainty of creating new fracture initiation points; furthermore, with complex heterogenic rock, different fracture designs, and different well completions, it is difficult to develop a comprehensive understanding of how well the refrac design worked. Diagnostic validation of the success of a refrac operation, as well as iterative improvements based on those learnings, is fundamental to determining a cost-effective strategy. A strong data set takes the guesswork out of refrac and is the best method for understanding how effective the refrac designs performed.
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).
Abstract In the present cost-constrained environment, it is critical that operators effectively complete their wells while minimizing capital expenditure. Optimization efforts focus on increasing recovery factor by managing landing zone, increasing the number of effective fractures, increasing the size of the fractures, and increasing the length of the lateral, while reducing the total number of stages and job size, without sacrificing efficient proppant and fluid delivery. The same pressure to reduce expenditure also impacts decision making on diagnostic evaluation, reducing operators to ‘free’ or low-cost feedback, like surface production rates and decline curves. Operators are responding to these challenges by utilizing a combination of lower cost, post-completion diagnostics like deployed fiber optics, downhole camera evaluation of perforations and radioactive tracers. These less expensive options allow for a broader scope and number of diagnostic inquiries, whereas a permanent fiber may prove to be cost-prohibitive, reducing diagnostic focus to one well, in one part of a play. Combining differing diagnostic technologies enhances the overall description of the well and reservoir behaviors and improves confidence in their interpretation of stimulation and production efficiency; furthermore, where a single diagnostic measurement may be unlikely to justify dramatic change in a completion strategy, a combination of data points from different domains can and does support design change that leads to rapid, real world performance improvements. Care is needed in the conclusions drawn when utilizing complimentary diagnostics due to the differences in depth of investigation and the non-unique interpretation of some data types. This paper discusses three post-completion diagnostic technologies, perforation evaluation by downhole camera, radioactive tracers, and distributed acoustic and temperature sensing (DAS+DTS) data and their respective physical measurements, strengths and weaknesses and how they can be combined to better understand well and reservoir behavior. It concludes with a review of completion optimization efforts from the Rockies area, where these post-completion diagnostic technologies were applied in the evaluation of eXtreme Limited Entry (XLE) trials. A statistical analysis of the RA tracer, downhole camera measurement of perforation area and deployed fiber optic acquisition of DAS+DTS reveals no correlation between diagnostic answers, indicating no one diagnostic measurement can accurately predict the other, such that it could substitute for that diagnostic and provide the same answer. Asking the right question can often enhance the value of diagnostic descriptions of the system in question. Those answers often lead to the next question and clear the path forward in advancing completion optimization. Complimentary diagnostics facilitate a more complete understanding of stimulation and production performance when compared, increasing confidence when they agree. When one or more appear to disagree, the different respective physical measurements and depths of investigation often reveal a more complete and complex understanding of stimulation and production efficiency. As an aggregate they provide clarity on the effect of efforts to create conductive pathways into the reservoir, allowing operators increased control over the resulting production.
Abstract With the industry shifting gears toward pad development there has been a significant increase in operator press releases to stockholders expressing concern about fracture driven interactions (formerly called "frac hits") within a drilling spacing unit (DSU) (Triepke 2018). Primary wells (formerly called "parents") (Daneshy 2019) are the initial wells on the pad and infill wells (formerly called "children") are all those that follow on the pad or an adjacent pad. Failure to protect the primary well from infill well fracture driven interactions can result in up to 40% EUR losses in infill wells from asymmetric fractures (Elliott 2019)(Ajisafe et al 2017). Adverse frac interactions between wells in a DSU can be largely eliminated with a combination of primary well refracs and infill well zipper fracs. In the primary well protection process there is a movement away from "preloads" as the overall results from the preloads to date suggest they are not effective in preventing infill well frac asymmetry unless the primary well can be restored to its original stress conditions. A number of operators have announced plans in press releases to increase well spacing in the DSUs to reduce well to well interference. A number of of organic shale operators have also announced performance related reserve write downs according to a March 13, 2019 Simmons Energy report (Harrison and Todd 2019). While in some cases the writedowns were due to changes in pricing expectations, the combination of a known reserve bashing situation and numerous operators still relying on preloads for parent protection raises a red flag. It is highly likely that there is a relationship between DSUs that use preloads instead of refracs for primary well protection and poor overall performance from the DSU. It was proposed in the keynote address at a recent primary-infll frac interaction conference that refraccing primary wells is significantly more effective than preloading them in preventing large infill EUR losses (Elliott 2019) (Figures 1 and 2). Figure (3) has a microseismic interpretation of an infill well assymetric frac offsetting a primary well with no refrac. The stranded hydrocarbons are clearly where there is no microseismic activity. For a DSU with 600,000 BO wells the combination of the 40% infill well EUR loss and the loss of up to two PUDs per DSU can be in the $29 million range so this is hardly an academic exercise. Figure 1: Depletion Mitigation Opportunities Figure 2: Depletion Mitigation Results Figure 3: Infill Well Asymmetric Frac in Toe Stage with Depleted Primary Well Overlap Historically, refrac operations in horizontal organic shale wells have had unpredictable production results, with the industry moving toward mechanical isolation following an often painful history that included single stage "pump and really pray" treatments with no diversion to "pump and pray" with chemical or ball sealer diversion. While results from mechanical isolation have been more consistent than these first two methods (Cadotte et al 2018), there is now a lot of discussion on the best mechanical isolation method to use. The two most common isolation techniques are cemented conventional casing and expandable liners. The main advantage of the cemented casing is lower up initial costs, with a $123,000 difference in cost before frac operations commence for a 5000 ft refrac liner. The main advantage of the expandable liner is a larger diameter that allows for 20% to 25% higher pump rates. With the combination of the Extreme Limited Entry (XLE) completion technique and expandable liners the higher treatment rates translate directly into longer stage lengths while still maintaining high cluster efficiency. The resulting lower stage count reduces the overall stimulation cost well below the incremental initial cost of the expandable liner, with a net savings of $446,000 per refrac over the cemented liner option for a 5000 ft lateral. The savings would be higher for longer laterals as the stage number difference will increase.
Abstract The economic boundaries of the Williston Basin are being expanded with improved practices. This paper discusses advances in reservoir characterization coupled with the implementation of refined stimulation techniques that have achieved strongly compelling results in an area of the Williston Basin that was previously perceived to be marginally economic. After more than a decade of intense development, the remaining undrilled acreage in the core of the Bakken has been drastically reduced. Consequently, there is strong motivation to identify additional economically viable drilling locations. Hydraulic fracturing treatments incorporating increased volumes of fluid and proppant in more closely spaced clusters have successfully increased well productivity in many resource plays across the industry. The contemporary slickwater and slickwater hybrid designs implemented in the Bakken have spurred a renaissance of continued development throughout the basin. While these increasingly large frac treatments improve well productivity, in some parts of the basin the high treatment expenses and resulting elevated watercuts challenge the economic viability of development. Rote application of the "bigger is better" completion strategies developed for the core of the basin has been unsuccessful in some portions of the Bakken. This paper describes the unique geologic characteristics of the study area and the stimulation strategy that has been adapted to accommodate the geologic differences while achieving excellent economic results. Implementation of completion designs tailored to the area has yielded a 300 to 400% production increase compared to offset wells. This "right sized" completion strategy customized for the area achieved highly productive wells with substantially lower capital costs than were budgeted based on strategies currently popular in the core of the Bakken. Although treatment designs continue to evolve and additional improvements are anticipated, the summary of experimentation and learnings from seven sequential wells may be helpful to others pursuing assets considered "marginal".