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.

The Bakken boom in North Dakota is currently focused on the Central Basin area where around half of the drilling rigs in North Dakota are now operating. What makes this area different compared to previous areas of Bakken development is that there is only minor structural variation and significantly less naturally induced fracturing as compared to the higher permeability rock facies that exist in the sub-reservoirs of earlier Bakken development such as at the Elm Coulee field in Montana or the Sanish and Parshall fields in North Dakota. As a consequence, the role of the well's completion and stimulation design has a greater significance and impact on well productivity and ultimate recovery. Different companies have taken very different approaches to well design using either plug and perf or ball and sleeve completions, and a variety of fracture designs with slickwater, hybrid or cross-linked gel fluids and a variety of proppants from 100% natural sand to 100% ceramics. As a consequence, it is not uncommon for different operators to have over a 2 million dollar difference in their AFE's solely because of the differences in approach to the well's completion and stimulation design. The authors have chosen to apply "advanced completion and stimulation designs" which are designed to maximize the reservoir contact area (slickwater and plug and perf) and optimize the conductivity (ceramic proppant at relatively high volumes). 1,2

Seven years ago, some operators in the United States began geo-engineering completions to more efficiently stimulate unconventional horizontal wells. Typically, engineers and geoscientists rely on expensive open-hole logs or the over-simplified use of gamma ray to infer mechanical rock properties along the lateral. Engineers then select treatment stage intervals and place perforation clusters in similarly-stressed, "like rock" to minimize the geomechanical variability. Instead of traditional open-hole logging, this paper discusses geo-engineering applications of drill bit geomechanics. Drill bit geomechanics is an innovative method for formation evaluation and reservoir characterization. It uses direct, continuous, high-resolution measurements of drilling vibrations recorded downhole. Using earthquake seismology models, one can infer rock properties from the measured drilling vibrations. These rock properties include Poisson's Ratio, Young's Modulus of Elasticity, and the presence of fractures perpendicular to the horizontal well. In this study, the Operator collected drill bit geomechanics data while drilling a new well ~8-34 ft below three existing horizontal wellbores, with over seven years of continuous production. The study well was a 9,500-ft lateral in the Bakken Formation in North Dakota. Using drill-bit-geomechanics-derived rock properties, the operator could confidently geo-engineer a completion, accounting for reservoir depletion from the older wells. The drill bit geomechanics data showed dramatic changes in mechanical properties and fracturing where the study well intersected the older wells’ stimulated reservoir volumes (SRVs). The operator had a general idea of the wells’ SRVs from microseismic data acquired during two wells’ stimulations. Using the drill bit geomechanics data from the study well, the operator could more effectively constrain the drainage ellipses from the sparse microseismic data. The operator geo-engineered a 27-stage completion by combining "like rock" of the same reservoir pressure. Measured Instantaneous Shut-In Pressures (ISIPs) during the completion showed significantly lower ISIPs for the partially-depleted stages closest to the older wells. Thus, combining similarly-pressured stages was critical to the completion's success. Well performance has proven to be excellent for the area, even when compared to wells without depletion from older producing wellbores. As shown in this case study, drill bit geomechanics is an economic, useful tool to identify depletion and accurately measure rock properties and fractures at a very high resolution.

In conventional formations it has long been established that designing fracture treatments with improved near-wellbore conductivity generates improved production and economic returns. This is accomplished by pumping treatments with increased proppant concentration in the final stages (the traditional proppant ramp design), and in some cases by changing proppant size or type in the final stages to effect greater near-wellbore conductivity - commonly referred to as a "tail-in" design. These designs overcome the impacts of greater near-wellbore pressure loss during production caused by flow concentration in the near-wellbore region compared to distal parts of the fracture. For vertical wells and crosslinked fracture fluid treatments, the fluid flow and suspended proppant transport is effectively "piston" flow and it was a relatively straight forward matter to engineer the near-wellbore region with a tail-in of higher conductivity proppant. For unconventional reservoirs, with multi-stage horizontal completions using slickwater fluids, it has not been obvious how best to create this improved near-wellbore conductivity and most operators have employed a "one size fits all" strategy of pumping a single proppant type unless there was perhaps a need for flowback control in which case a resin coated proppant might be used as a tail-in. This paper reports the results of two projects to address the engineering of the near-wellbore fracture conductivity for horizontal well fracturing. Firstly, a series of laboratory tests were run in a 10 ft. × 20 ft. slot wall to visualize near-wellbore proppant duning and layering associated with both "lead-in" and "tail-in" designs. The impacts of these depositions were then quantified using a 3D hydraulic fracture / reservoir simulation code for a variety of stimulation designs in the Middle Bakken and Three Forks formations of the Williston Basin. The results of this work show that well stimulation treatments in liquid-rich unconventional formations would benefit from a combination of small (5 to 10%) lead-ins and tail-ins of high conductivity ceramic proppant. This minimizes the effects of radial flow convergence in the transverse fractures generated from the horizontal well and maximizes the economic benefit of the well stimulation. In addition to paying out the small cost increase in only 1 to 2 months, the proppant bands of higher conductivity ceramic help mitigate the effects of longer-term sand crushing and degradation on near-wellbore plugging and thus increases 3-year cumulative free cash flow and the Estimated Ultimate Recovery (EUR) of the well.