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Abstract Optimizing a well's hydraulic fracture design within a pad development environment is a multi-disciplinary effort and requires a 4-dimensional understanding of the reservoir. This paper presents a workflow that uses an integrated workflow that combines geology, and geomechanics to build a reservoir model which can be interrogated and updated with a geologically and geomechanically constrained grid-based 3D planar frac model and production simulation using a fast marching method. In this case, as applied to an Eagle Ford well to address concerns of completion optimization, production and depletion forecasting, well spacing and well interference. The workflow captures the variability of stresses and rock properties along the wellbore and around it by using multiple geologic and geomechanical approaches. The estimated variability of rock mechanical properties is used as input in a 3D planar frac simulator. An alternative approach to geoengineering a completion, using the differential stress derived from geomechanical simulation that overcomes the limitations of well centric methods, is also illustrated. The frac design results are used as inputs/constraints in a new reservoir simulator that was developed using the Fast Marching Method to estimate drainage area. This allows for a constrained, yet extremely fast estimate of the EUR and resulting pressure depletion, addressing the important concerns of well spacing optimization and prevention of frac hits and well interferences, all in a timely manner. The integrated approach facilitates adaptive frac design which honors in-situ conditions including stress field heterogeneity, stress shadow effects and the pressure depletion from nearby producing wells. The proposed workflow enables greater investment efficiency and promotes field development optimization.
With the success of hydraulic fracturing in the US shale-gas plays, why are more operating companies not using energized fluids to minimize the use of water, decrease the amount of proppant required, and (theoretically) enhance long-term productivity? It appears that Canadians have been somewhat more receptive to the idea and are more willing to use energized fluids, with apparently positive results. Perhaps it is too early in the game to convince operators in the US to take another look at this technology with an open mind. Allow me to start a dialogue in this area. The perception that using energized fluids is more expensive to achieve the same goal could be one hurdle keeping operators from using them.
Abstract Frac hits relates to the problem of newly created hydraulic fractures interacting with either primary and/or secondary fractures from offset wells. This fracture-driven interaction (FDI) represents a major concern for shale oil and gas producers given that infill wells experiencing frac hits typically underperform parent wells landed in the same zone. In addition, the sudden pressure communication established through frac hits between multi-fractured horizontal wells (MFHW) can result in damage to parent wells. In this work, we introduce an analytical model to detect frac hits and assess the fraction of primary fractures connected between the infill and offset well. We assume that frac hits are due to overlapping primary fractures. Frac hits are modeled as a valve between MFHWs that allows certain degree of pressure communication. While the aperture of this valve is controlled by the number of frac hits, the leakage rate is governed by the bottomhole pressure (BHP) differential between wells. The analytical solution to the fluid-flow model is derived in Laplace domain and is inverted numerically. We found that BHPs are coupled via the degree of interference coefficient δw, defined as the ratio of frac hits to the total number of primary fractures of the infill well. We utilize δw to history-match the analytical model with numerical data. As a result, history-matched δw delivers an estimate of the actual fraction of frac hits ((Equation)). We study several sensitivity analyses to examine the impact of variation in MFHW properties on the accuracy of the estimation of (Equation) via δw. In general, our model gives an accurate estimation (Equation) for most of the cases evaluated in this work; however, we see that the analytical model may introduce significant error in the estimation of frac hits when SRV and matrix permeability are the same order magnitude. Type-curves for rate-normalized data as well as (Equation) vs δw tables are discussed herein. The computational script used for the analytical calculations in this work proved to be efficient and straightforward to implement.
Abstract The Barnett Shale is one of the first unconventional shale plays developed with multistaged, fracture-stimulated horizontal wells in the world. It is located in North Central Texas near Fort Worth. At the end of 2013, the Barnett Shale had over 14,000 multistaged hydraulically fractured horizontal wells (MFHW) with approximately 7,600 of these wells with over five years of production history. In addition to these MFHW, there are approximately 4,000 vertical wells. Production forecasting for unconventional reservoirs with MFHW is a topic with a great amount of interest. The question is what are the appropriate decline parameters to be used in the forecast? Are multisegment forecasts with their own decline parameters necessary? Currently, production forecasting using a modified hyperbolic Arps equation is still widely accepted. This work provides analysis in characterizing decline parameters during and after linear flow for horizontal wells in the Barnett Shale using public data. There will be examples of MFHWs from the Barnett where the hyperbolic b-exponent will be calculated for each month of production and shown to vary with time as flow regimes change. Single well simulation will be used to characterize the different flow regimes and their effect on decline parameters. Simulation of wells with and without volume outside of fracture tips and their effect on decline parameters will be shown. The decline parameters were in an Arps forecast to match our single well simulation forecast. Uncertainty analysis of production forecast using simulation models is also presented in this work.
Abstract 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.