The United States Geologic Survey (USGS) reported in 2008 that undiscovered technically recoverable oil in the Bakken was about 3.6 billion barrels across the U.S. portion of the basin, considering recent successful application of horizontal wells and multistage hydraulic fracturing technologies. As the development of the unconventional resources in the Williston Basin continues beyond the phases of exploration and lease evaluation, optimum well spacing and recovery factor will become forefront considerations in the formulation of asset development strategies. Based on our studies the reservoir producing mechanism is primarily solution gas drive and primary oil recovery factor is lower than 15% of the original oil in-place. This low recovery or very high oil volume remaining in place is a strong motivation to investigate the application of enhanced oil recovery methods in this basin. This paper describes the construction of numerical simulation models using typical fluid and rock properties for the Bakken and Three Forks, assuming both naturally fractured and single porosity systems and their combinations. Multistage hydraulic fracture properties are determined from well completion engineering and coupled with the flow models. The flow models are constrained by well operating practices implemented by operators across the basin during primary oil production. The results of pressure maintenance methods to arrest the rapid reservoir pressure decline due to large pressure drawdown necessary to produce oil and water, as well as gas (including carbon dioxide) and water injection methods to improve oil recovery are presented.

In field development programs where large variations in reservoir and completion parameters exist, the evaluation of reservoir performance to determine the optimal completion strategy can be a challenging task. This paper presents findings from a recent integrated cross-discipline analysis of a pilot program performed in the Bakken and Three Forks Formations (Williston Basin, North Dakota) to evaluate the impact of petrophysical and geomechanical properties on hydraulic fracture lengths, reservoir connectivity, well performance and well spacing.Microseismic, geological, geomechanical, completions, engineering and production data were integrated in single and multiwell modeling approaches to provide an objective method to evaluate and compare well performance. Results and conclusions from various disciplines were validated by integrating operational observations with the modeling. The application of the proposed workflow allows one to (1) understand and evaluate the effect of fracturing parameters (length/conductivity) on well performance, (2) characterize reservoir and fracture properties using hydraulic fracture pressure and production history matching techniques (3) relate fracture parameters to reservoir, geology and mechanical properties and, (4) provide a methodology to understand key drivers controlling the development strategy of an asset.

Home to one of the largest North American deposits discovered in the last few decades, the Bakken, spanning 200,000 square miles along the borders of Saskatchewan, North Dakota and Montana is rivaling some of the largest proven reserves. As the use of long horizontal wells and multi-stage fracturing technology has significantly increased productivity and activity in the basin, the challenges associated with infill-completions, depletion and controlled fracture growth must be addressed to ensure efficient and effective practices, encouraging long-term planning without hindering investment.In this paper, models are built to replicate well performance (fracturing and production-numerical & rate-transient) and to understand the impact of key technologies (multi-stage/completion type and multi-laterals) across the basin to demonstrate why completion strategies must be modified based on reservoir quality and stress state. Confusion between the success of sliding sleeves/plug and-perf and what drives the optimal number of stages is also addressed using fracture modeling and production modeling with emphasis on key parameters (fracture length, connectivity, number of fractures) influencing productivity. The recent focus on data acquisition and modeling in the Three Forks has presented a range of challenges and opportunities due to the laminations in this reservoir. Log up-scaling methods and simulator engines were crucial to modeling and thus evaluating propagation behavior. This paper also presents how the use of data gathering (log, routine and specialized core) and modeling has enabled us to understand how in-fill drilling can alter drainage patterns and influence production success.

Offshore and remote-location hydrocarbon production structures operate in a dynamic (unsteady state) environment where decisions continually have to be made about equipment design, construction, and operation. Such decisions and resulting subsequent actions have a significant and lasting effect on the operation, safety, and profitability of the structure. For example, during the life of an offshore structure, decisions have to be made about the number, placement, and design of separators, dehydration, sweetening or other processing units; switching times from production to injection; timing and location of multilateral branches; etc. The engineer faced with carrying out tasks such as the above may be substantially aided by suitable computer-aideddesign-and-operation software tools. Use of such tools could (a) streamline or automate design tasks (thus improving repeatability and reliability of task completion, making efficient use of manpower, reducing task completion time, effectively coordinating interdependent concurrent tasks, and cost-effectively approaching optimality) and (b) optimize operating strategies (thus safely and reliably improving long-term profitability without burdening the engineer with excessive decision making tasks). This paper introduces the technology of integrated computer-aided design and operations to petroleum production. Current practices in other industries such as oil refining, petrochemicals, and aerospace will be investigated with the intention, first, to modify them for petroleum applications and, potentially, advance the state-of-the-art.

When calculating the downhole stresses affecting a wellbore during depletion it has become a standard industry practice to assume only the pore pressure changes, and not the rock mechanical properties. This assumption has the potential to underestimate the total horizontal stress (Sh) causing unrealistic fracture containment. It will also overestimate the effective horizontal stress (Sh' = Sh - Biot * Pore Pressure) for open-hole wellbore failure. High effective horizontal stress assumption can potentially transform rock from brittle to ductile behavior and failure mechanics from shear to compaction and the model becomes overly conservative. Ductile and compaction failure can cause changes in well integrity, as well as changes in fracture geometry from offset infill wells. This paper will document changes in rock properties in the Bakken formation during variable depletion (10% to 65%) and recalculate rock properties (velocities, mechanical properties - Young's modulus, Poisson's ratio, and Biot's anisotropic compressibility constant) as a function of effective stress due to production in order to accurately calculate fracture geometry at an offset well and parent well bore integrity. Hydraulic fracturing simulations are performed to simulate well communication between the fractured well and the depleted parent well along with the potential to re-fracture the parent well using the pore pressure, linear, and non-linear models. Laboratory testing performed on rock samples is shown to validate the non-linear model.