In order to better understand the process of fracturing tight gas sands, a comprehensive data set was gathered and analyzed for the Bossier formation in the Dowdy Ranch field. The dataset collected on the APC Anderson #2 well represents one of the most comprehensive datasets ever collected for a commercial gas well. The entire interval was cored, and a complete set of core analysis was performed across the sands. Stress profiles derived from dipole sonic logs across the pay zone and in the shales below were calibrated with stress tests. The frac jobs were micro-seismically monitored with downhole geophones and included breakdown and mini-frac stages. Post fracture data collection included pressure buildup testing, production logs with multiple passes, and tracer logs with multiple isotopes. Additional data was collected on five offset wells in the field. Results from these wells will be presented in a companion paper. The bottomhole treating pressures were found to be higher than expected based on the measured stress profiles. However, the higher treating pressures encountered did not result in excessive fracture height growth. This may be partially attributed to unexpected faulting providing a conduit for fluid leak-off, resulting in low efficiency and narrow fractures. Propped or effective fracture lengths derived from pressure buildup analysis and history matching production data were significantly shorter than designed frac lengths (or those predicted from uncalibrated frac models). The net pressure plots showed some evidence of proppant bridging even at low proppant concentrations, again indicating only limited fracture widths were being achieved. The data collected and analyzed provide valuable insight into the performance of water and hybrid fracs in tight gas formations. Recommendations for the design of future fracture treatments are made based on the findings. Introduction Water-fracs and hybrid-fracs are the type of stimulations used in many low-permeability reservoirs in East Texas and throughout the United States. Improving the performance of gas wells in marginal gas plays typically requires improvements to fracturing technologies. To ensure that these gas wells remain economically attractive even at modest gas prices, completion and fracturing practices must be optimized. Research aimed at improving the performance and reducing the cost of fracture treatments by acquiring and analyzing fracture treatment data from the Bossier play in East Texas has been undertaken by The University of Texas at Austin and Anadarko Petroleum Corporation (APC). The project is co-funded by the US Department of Energy - National Energy Technology Laboratory. Six gas wells (data wells) were identified in the Dowdy Ranch field for a detailed analysis of the well and fracture treatment data prior to, during, and after a fracture treatment. This paper focuses on the data acquired in the APC Anderson #2 well, summarizes our findings thus far and presents recommendations for better fracture treatments based on the lessons learnt. Some relevant results from the offset wells are also discussed here. A detailed analysis of data from the other wells will be presented in a later publication. Background In many low-permeability gas reservoirs, water-fracs and hybrid fracs are common stimulation methods. These treatments involve creating fractures using slick water rather than cross-linked gels. The proppant is carried into the fracture either with a gelled fluid (hybrid frac) or slick water (water frac). In theory, low viscosity pad fluids allow creation of more confined fractures. However, the low viscosity promotes proppant settling and, therefore, can lead to poor proppant placement and also leads to narrower fractures, which in some cases can cause proppant bridging.

This paper focuses on the evolution of an advanced completion design utilizing solid particulate diverters resulting in a dramatic increase in the number of fracture initiation points as validated with radioactive (RA) tracers. The ultimate goal of this strategy is to increase capital efficiency by placing a dense fracture network more contained within the producing formation. The information contained in the paper should be of great benefit to completion engineers working across a variety of unconventional oil and gas basins. It is generally proven that larger proppant volumes and more frac stages result in higher oil and gas recoveries, i.e., bigger is better. Practically, the number of stages for a 9,500 ft lateral (typical for the Bakken) is limited to 40 or 50 stages due to operational and cost limits. For advanced completion designs (complex fracture networks), the goal is not to just increase the stage count but to increase the number of initiation points (perforation clusters) that are effectively stimulated increasing the contacted fracture surface area. Considerations when executing this strategy include, but are not limited to: proppant transport, screen out risk, stress shadowing and geo-mechanical variability along the wellbore. With volatile oil prices, continued innovation is necessary to sustain the unconventional shale success. In pursuit of better well performance AND lower capital costs, Liberty Resources has moved to a completion design that incorporates a high density perforating strategy and a focus on diversion methods to effectively stimulate each cluster. Solid particulate diverter was utilized to increase perforation cluster efficiency. Production performance is encouraging, and RA proppant tracers show that cluster stimulation efficiencies in excess of 85% can be achieved. The unconventional shale revolution that began 15 years ago has successfully returned the United States to being a world leader in oil and gas production and technology. Completion designs have evolved significantly from the first early Barnett Shale completions and are now quite diverse. Variations in design are driven by the uniqueness of each basin's geologic and reservoir properties as well as operator bias. This diversity in completion methodologies has contributed significantly to technology advancement; the status quo is continually tested with new innovations. The Williston Basin was one of the first unconventional shale oil successes and it continues to contribute to the advancement of horizontal fracturing technology.

Objectives/Scope This field case history details the objectives, design, field operations, and production, pressure, and other surveillance results of the first rich gas multiwell cyclic huff ‘n’ puff pilot in the Bakken and Three Forks intervals of the Williston Basin. The broad goal of the enhanced oil recovery (EOR) pilot was to identify key performance metrics of rich gas injection leading to the design of a commercial field-scale EOR process. Objectives included demonstrating the ability to contain gas within the target intervals vertically and laterally and build pressure to promote a miscible displacement process in a fully developed 1280-acre drill spacing unit (DSU) in the Bakken tight oil play. Methods, Procedures, Process The paper includes the geologic reservoir description of the pilot area in the northeast Williams County Nesson Anticline area based on well logs, seismic, and core materials. Background includes the development history of the eleven-well, 1280-acre DSU including well completions and production data. The paper describes details on methods and results of laboratory studies of representative Bakken fluids and core materials including characterizing PVT (pressure, volume, temperature) properties, minimum miscibility pressure (MMP) measurements, and fluid extraction tests. Case results include a description of the facilities and field operations through the execution of the pilot. Further, the paper includes key considerations in the planning and design phase, including injection order, offset monitoring, and facilities design considerations for gas rates and volumes. Production results from within the DSU and surrounding DSUs include a total of 24 horizontal Bakken or Three Forks wells. Surveillance results include oil, water, and gas rates; injection and downhole pressures; and gas chromatograph data from injection and offset wells as a basis for assessing pilot results versus goals and objectives. Results, Observations, Conclusions Bakken/Three Forks produced gas is miscible with reservoir fluids at pressures above ~2500 psi, given the relatively high fluid fraction of ethane and propane. This produced gas recovers a large fraction of reservoir fluids from Middle Bakken, Three Forks, and Upper and Lower Bakken Shales in laboratory extraction tests. Gas injection into the Bakken and Three Forks intervals was achieved through the full range of the pilot design, and over 90% of the injection gas was recovered as wells were returned to production based on measured rates, volumes, and other surveillance data. While actual pilot gas injection rates were too low to achieve a material EOR oil response, surveillance data indicated that pressures increased with gas injection and that gas was contained within the 1280-acre DSU as designed. Further, history-matched simulations indicated that higher gas injection rates could yield EOR recoveries comparable to that reported in successful Eagle Ford projects. Key insights include that much higher gas injection rates are required for an economical process and that initiation of gas injection cycles earlier in the well life will reduce the volume of gas and injection time required to build bottomhole pressures above the MMP to promote EOR. Novel/Additive Information This first multiwell rich gas injection pilot in the Bakken/Three Forks play identified several design and operational efficiencies beneficial to an economical field-scale project. For example, jet pump installations allowed gas injection operations without modifying production wells via costly workovers. Injection/production conversions could be completed at minimal cost by cycling out jet pumps and installing pressure gauges. Further, wells completed with cemented plug and perforated liners for hydraulic fracture stimulation may promote improved gas injection conformance across the horizontal completed intervals.

This paper presents the continuing evolution of our Bakken advanced completion design with the added enhancement of Extreme Limited Entry (XLE) perforating. With this cost-effective XLE strategy, we are consistently stimulating more than eleven perforation clusters per stage. Confirmation of this high number of active clusters, or fracture initiation points, has been directly measured with radioactive tracers and fiber optic diagnostics, and more importantly, is validated through improved production relative to offset completions. The goal of this strategy is to consistently and confidently drive a high number of clusters per stage, ultimately increasing capital efficiency by right sizing the cluster and stage count per well. Practically, the number of stages for a 9,500-ft. lateral is limited to 40 or 50 stages in the Bakken due to operational and cost limits. We believe the published trends on stage count are fundamentally linked to the number of active clusters per stage or fracture initiation points, and by driving significantly more active clusters per stage with XLE perforating in combination with previously presented High Density Perforating (HDP), we now have proven the ability to reduce stage count without sacrificing performance. Liberty now incorporates XLE as a key design technique to successfully stimulate 15 clusters per stage. Production performance is encouraging and post frac fiber optic diagnostics support prior radioactive proppant tracer data in showing that over 11 of the 15 clusters shot can be stimulated with slickwater at 80 bpm. XLE operational considerations for frac plug ratings, oriented perforating, even-hole perforating charges, variable pipe friction and a review of existing papers on limited entry are included as well. Limited entry perforating has been around for over 50 years; however, its effectiveness has been limited in the horizontal revolution due to insufficient perforation friction relative to the variability in stress and near-wellbore tortuosity found within a stage. This paper presents the improved results for specifically designing perforations and stimulation injection rates to achieve diversion to almost all 15 perforation clusters per stage. For this paper, we define XLE as completion designs with perforation friction exceeding 2,000 psi. Since the beginning of 2015 we have reduced our standard stage count from 50 down to 27, for a 9,500-ft lateral, while continuing to significantly outperform offset operators. When it comes to value creation, the cost per barrel of oil produced is a critical metric to assess development opportunities and achieving the same or increased oil production with less capital has led to significant gains in capital efficiency.

The Bakken drilling boom in North Dakota has seen a frenzy of activity over the past several years as operators sought to hold acreage and create value with the drill bit. This has been particularly true in the Central Basin portion of the Williston Basin where initial wells drilled prior to 2008 were uneconomic. However, advances in completion technology caused such a fundamental shift in economics that the whole Central Basin area of over 2500 square miles has been opened to economic development with ~100 rigs currently drilling in the region.The most fundamental change in completion design has been the incorporation of "high-intensity" multi-stage fracturing. What makes Bakken completion design fundamentally different from recent shale gas developments has been the widespread use of uncemented liners with external packers in the open-hole lateral in order to create the multi-stage zonal isolation.As operators have advanced the application of multi-stage completion techniques there has been a wide variety of completion equipment used and stimulation designs that have been pumped. This operator decided to employ a completion design that comprised:(i) An open-hole "uncemented" liner section; (ii) Annular zonal isolation created by swell packers; (iii) The use of "plug and perf" technology to individually open successive zones to stimulation; (iv) The pumping of slickwater fracture treatment fluids at high rate; (v) The use of high-quality ceramic proppant to generate the required fracture conductivity.Production data are presented from 58 wells in which this completion and stimulation design has been conducted, which show that the use of this approach has resulted in well performance that is 25-45% superior to any other Bakken completion technique.