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.

Hydraulic fracturing has been a part of oil & gas development in North America for seven decades. Hydraulic fracturing was first conducted in 1947. Commercial operations began in 1949. After over twenty years fracturing took a large step up in the late-1970s with its application to tight gas sand formations. The game changer that brought discussion of hydraulic fracturing to dinner tables, bars and sidelines of soccer games is the recent advances that enable commercial extraction of natural gas and oil directly from shale source rocks. Since the start of shale fracturing in the early-1990s, fracturing technology and the pressure pumping industry's efficiency in delivering fracturing services have changed almost beyond recognition. The result has been the world-changing Shale Revolution. Through researching industry databases, the authors have compiled an industry-wide review of North American hydraulic fracturing activity dating back to the first work done in the late 1940s. Yearly stage count in the 1950s through the early 1990s was 10,000 – 30,000 stages/year, while recent peak levels show a step change in activity aproaching 500,000 stages/year (Fig. 1). While the North American industry's fracturing horsepower grew about 10-fold between 2000 and 2018, yearly frac stage count grew 20-fold in North America and proppant mass pumped grew 40-fold. The authors show how the industry achieved a step-change in reducing service delivery cost through innovation and efficiency, allowing sustained economic development of unconventional resources at decreasing breakeven production costs. Technological changes, as assisted by a better understanding through frac diagnostics, integrated modeling and statistical analysis have enabled the large cost reduction to commercially produce a barrel of oil. As a result, shale frac designs have focused on higher intensity completions with tighter stage and cluster spacing, improved diversion through extreme limited entry perforation design and simultaneous and zipper frac'ing, increasing proppant mass per well, utilizing next-generation frac fluids to increase produced water recycling and using cheaper lower-quality proppant. At the same time, the environmental footprint of oil & gas production has been shrinking and will continue to do so as operational changes continue to make our industry a better neighbor, for example through faster well construction utilizing fewer pad locations, development of quiet fleets, greener frac chemistry, frac focus disclosure, etc. Together, oil and gas operators and their service providers have used technology & innovation to improve efficiencies and increase the overall daily pump time per frac crew. However, there is plenty of room for further improvements in technology and efficiency. We believe this is the first industry database of its kind covering hydraulic fracturing activity in the United States, going back to the 1940s. We hope this paper provides a unique perspective of how our industry has changed through the Shale Revolution.

Multi-stage horizontal well designs have been used since 2007 in the Bakken oil-field of North Dakota. Since then over 12,000 wells have been completed in either the Middle Bakken or Three Forks zones. Early-time production rates as measured by 180-day state-reported cumulative production have increased 4-fold over this period as industry has pursued a program of innovation and continuous improvement in completions technology with production per well increasing in ten of the twelve years. Through a "Big-Data" analytical study comparing geological data, completions parameters, and state-reported production results the authors have evaluated the fundamental changes that have guided industry to produce these results over the past twelve years. While geological changes in different areas drove both the drilling "mania" during times of $100 oil and consequent contraction of the industry when wellhead prices dropped below $40 per BO; it is the advances in completion design and hydraulic fracturing that have driven macro performance over the twelve years - and resulted in this significant increase in production per well. These completion advances have allowed the region to compete on a global scale with production that while dipping to ~1.0 Million bopd in 2016 has now rebounded to over 1.2 Million bopd. Large datasets of geological, completions and production data take years to assemble and analyze. Through the authors use of multivariate analysis techniques this paper presents the deterministic factors affecting well performance in the Bakken and provides guidance and best practices towards applying these techniques in emerging international plays.