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Abstract Commodity prices went through a dramatic shift from 2014 through the first quarter of 2016. In this paper, change in activity levels, stimulation techniques and the resulting impact on production throughout the Permian Basin are reviewed. This includes but is not limited to activity levels, drilled but uncompleted activity, fracture treatment fluid systems, proppant types, and proppant volumes. The authors utilize public data sources to correlate activity level including drilled but uncompleted wells in the Permian basin to commodity price by location and target zone. Trends on fracture treatment style and downhole consumables are then correlated to activity and commodity price. The production analysis shows the impact of changing completion methodology on well performance and economics. The number of wells completed in the Permian Basin has declined by 77% from October 2014 through January 2016. Completion trends during this time period include increasing proppant intensity along with a transition from Hybrid and Crosslink treatments to Slickwater, which grew from 36% to 59% of the completion market, while average proppant per lateral foot in the Permian Basin increased by 14% over the same time period. The authors conclude that commodity price pressure did cause a slowdown in activity along with a transition in completion styles. However, during this period of time, short term production rates did not suffer as expected. The activity, completion and production trends reviewed in this paper will be useful to engineers and managers for operator, well service provider and financial analysts planning and/or evaluating oil and gas opportunities in the Permian Basin at suppressed commodity prices.
Abstract The goal of our work was to maximize gas production and recovery from a horizontal appraisal well in the Mancos shale in New Mexico. This required a fracture design that would maximize perforation cluster efficiency and a lateral placement strategy that would maximize gas recovery. A key challenge was to design a fracture treatment that would overcome the extreme stress shadowing effects. Another key challenge was to optimize the lateral placement balancing multiple factors. Fracture treatment simulations were completed for various designs. Fracture simulations indicated cluster efficiency could be dramatically improved by optimizing the way we pump the pad. A step-up technique for increasing pumping rates during the pad stage helped to initiate more fractures. Intra-stage diversion was utilized. Fracture simulations were performed to optimize the lateral placement. This required balancing multiple factors to access the highest gas-in-place (GIP) interval yet facilitate more fracture initiations per stage. Fracture descriptions from the fracture simulations were input to a reservoir simulator to determine the optimal design. This paper will focus on the hydraulic fracture modeling. This appraisal well was the most productive Mancos gas well ever delivered in the San Juan Basin. The 9,546’ lateral produced at a choke constrained plateau rate of about 13 MMscfd for 7 months and produced over 6 BCF in the first 20 months. A radioactive tracer log indicated an overall perforation cluster efficiency of 83%, a significant achievement in a shale with high stress shadowing. The fracturing fluid design, diverter design and pumping techniques can be applied in many other shales as a low-cost way to increase perforation cluster efficiency, which will in turn result in higher production rates and higher cumulative recovery. Building on the success observed in the Mancos wells, BP and BPX Energy have subsequently utilized these techniques in other shale plays with success. The concepts and workflow used to decide the optimal lateral placement is a well-defined approach that can be applied to other unconventional wells to increase hydrocarbon recovery.
Owens, Matt (Extraction Oil & Gas) | Silva, Jesse (Extraction Oil & Gas) | Volkmar, Matt (Extraction Oil & Gas) | Poppel, Ben (Liberty Oilfield Services) | Siegel, Joel (Liberty Oilfield Services) | Losacano, Tony (Liberty Oilfield Services) | Weijers, Leen (Liberty Oilfield Services)
Abstract The Denver-Julesburg Basin has been going through a new cycle of development with horizontal drilling and high-intensity hydraulic fracturing. Since the first horizontal wells in 2008, more than 4,000 horizontals have been drilled, leading to a four-fold production increase between 2008 and 2012. While completion practices have been fairly similar across the basin over these early-development years, several operators are now starting to experiment with different completion designs. The objective of this paper is to discuss the benefits of these new designs and further evaluate what completion changes deliver the most "bang for the buck" in a challenging pricing environment. Use of a novel completion design and development of a low-cost ultra-low concentration fluid system resulted in significant cost saving while maintaining or improving overall production, thus lowering $/BOE in a challenging industry environment. Lowering cost per BOE drove a process of completion design changes that started with fluid compatibility testing, including regained permeability testing in proppant load cells, which showed that a light and more cost-effective Borate Guar can result in similar or better cleanup than a CMHPG-Zirconate system traditionally used in the DJ basin. Multi-variate analysis results from an extensive petrophysical / completion / production database showed production in the basin predominantly benefits from increase proppant volume and higher stage intensity. Field implementation of this system and a design with more proppant and stage intensity focused on consistently being able to place higher proppant loadings with less polymer. More than 150 horizontal wells were completed between mid-2014 and early 2016 in T5-6N R64-67W while implementing this strategy. When compared to about 350 other horizontal wells, mostly completed without these changes, overall results of the new completion strategy have been very encouraging: Higher injection rates and improved pump time to downtime resulted in a 20+% reduction in days required to complete a typical 8-well pad. Over a period of about 130 pumping days, more than 2,100 frac stages were completed. Supply chain efficiency improvements were implemented to keep up with proppant demand averaging 3.5 million pounds of sand every day, occasionally peaking to above 8 million pounds of sand per day; A new ultra-low concentration Guar Borate system was developed that could be crosslinked at concentrations down to 8 lbs/Mgal. Together with high rate, this fluid system enables placing proppant concentrations up to 6 PPA, making the system significantly cheaper and cleaner than the conventional 20+ lbs/Mgal CMHPG systems that were routinely used in the DJ Basin. Overall production in both Codell and Niobrara was above results for nearby peers over a wide range of production metrics. A petrophysical workflow was developed to arrive at a proper apples-to-apples comparison of historical production response in the area as compared with the results associated with this new strategy. Through various statistical analysis tools such as multi-variate analysis, the authors evaluated the importance of both reservoir and completion changes, and identified several key characteristics that are closely tied to the highest production responses in the DJ Basin.
Leonard, R. S. (ProTechnics Division of Core Laboratories LP) | Woodroof, R. A. (ProTechnics Division of Core Laboratories LP) | Senters, C. W. (ProTechnics Division of Core Laboratories LP) | Wood, T. M. (ProTechnics Division of Core Laboratories LP) | Drylie, S. W. (StimLab, Inc. Division of Core Laboratories)
Abstract Refracturing continues to provide operators with the opportunity to add production at a fraction of the cost to drill and complete a new well. Various re-stimulation designs and diversion techniques are currently being utilized to maximize contact with previously un-stimulated rock. Optimizing this process involves evaluating all available diagnostic, pressure and production data and determining the optimum design that maximizes recovery. This paper describes how these diagnostic technologies have been employed to evaluate and optimize refracs in four major North American basins. The process of refracturing and recompleting wells continues to improve. Much of this improvement comes from the optimization of techniques through completion diagnostics. Diagnostics provide data that can quantify the amount of the lateral treated and the effectiveness of diversion. Operators are focused on bridging the gap between the completion methods commonly used at the time the well was originally completed and the methods of today. Application of completion diagnostics also assists in identifying opportunities to further reduce the cost of the project while achieving similar results. In this study, proppant tracing followed by spectral gamma ray logging was employed to evaluate the effectiveness of the refracs, the extent of new rock contacted, the benefits of reperforating, and various diversion methodologies. Diagnostic results from 121 vertical (34) and horizontal (87) refracs covering 16 different formations and 26 different operators were analyzed and compared based on stimulation effectiveness and performance. The wells were then grouped by well type, formation and the basic refracturing technique that was utilized. In addition to the macroscopic data interpretation; four case histories are presented from the Barnett Shale, Permian Basin, Eagle Ford, and Haynesville. These case histories include before and after reservoir production matching with fracture half-length and effective conductivity calculations along with the diagnostic analysis of new and existing perforation coverage, diversion effectiveness, and ultimately the % incremental estimated ultimate recovery (EUR).
Abstract The oil and gas production landscape in North America has seen a paradigm shift since the collapse in oil prices in 2014. Although prices remain challenging, several operators have managed to sustain the relatively long period of low margins through some aggressive approaches. This paper inspects changes in operating strategies and field development plans across all oil-rich basins in the US Rocky Mountain fields and how operators have used a combination of low oilfield service prices, high-graded well locations, and incremental fluid/proppant volumes to increase production. The paper investigates the transformation in operating philosophies since 2014 in four oil-rich basins in the Rocky Mountain region—Williston, Denver-Julesburg (DJ), Uinta, and Powder River. The Bakken formation in the Williston basin represents one of the best-quality rocks in all of North America. However, high oil-price differentials and well costs have made it difficult for drilling to remain profitable. The core of the DJ basin (Wattenberg) has one of the lowest break-even prices in the region, and rig count continues to increase as operators start seeing signs of recovery in the market. The Uinta basin, although relatively small in size, has shown tremendous return potential in the form of multiple stacked pays and promising production results. The Powder River basin poses one of the toughest operational environments in the region owing to wildlife stipulations, harsh weather, and deeper targets. High-graded well locations in the Bakken are limited to few fields, which limits the scope of expansion in the current oil price environment. The DJ basin is challenged with high-density well spacing; estimated ultimate recovery (EUR) per drilling spacing unit (DSU) continues to increase, but EUR per well has gone down by as much as 60%. In the Uinta basin, formations never known to be continuous in the Green River group have shown significant return potential. The Powder River basin has recently attracted large investments from major independent operators as they tackle drilling challenges associated with abrasive rocks and testing optimum lateral landing points. Case studies show how operating strategies have changed with changes in oil prices. The Bakken and DJ basins are relatively mature, and as drilled-but-uncompleted (DUC) inventory continues to increase, depletion from existing wells and interference between fractures is impacting production from new wells. The Powder River basin is still in the exploratory phase, and operators are still working on reducing well-costs, optimizing fracturing-fluid/proppant volumes, and examining productivity of other target rocks. The Uinta basin is in the early phases of expansion, with many of the fields still being explored for scalability. Changes in production maps and completion trends provide a comprehensive understanding of how these variables have impacted oil output from the region since 2012.