Impact of Natural Fractures in Drainage Volume Calculations and Optimal Well Placement in Tight Gas Reservoirs

Abstract

Current practice of well placement in tight gas reservoirs generally involves the use of empirical correlations based on reservoir properties and analysis of past production and pressure histories and/or pressure maps from flow simulation. No rigorous procedure is available to compute well drainage volumes in the presence of permeability heterogeneity controlled by the distribution and orientation of natural fractures. The situation is complicated by the routine use of horizontal and complex wells in tight gas reservoirs and the presence of multistage hydraulic fractures. The computation of drainage volume will be critical to our understanding of the interaction between existing wells, potential infill locations and the estimated ultimate recovery (EUR) computations for infill wells. We propose a rigorous approach for well drainage volume calculations in tight gas reservoirs based on the flux field derived from dual porosity finite-difference simulation and demonstrate its application to optimize well placement. Our approach relies on a high frequency asymptotic solution of the diffusivity equation and emulates the propagation of a ‘pressure front’ in the reservoir along gas streamlines. The proposed approach is a generalization of the radius of drainage concept in well test analysis (Lee, 1982). The method allows us not only to compute rigorously the well drainage volumes as a function of time but also examine the potential impact of infill wells on the drainage volumes of existing producers. Using these results, we present a systematic approach to optimize well placement to maximize the EUR. We demonstrate the power and utility of our method using both synthetic and field applications. The synthetic example is used to validate our approach by establishing consistency between the drainage volume calculations from streamlines and the EUR computations based on detailed finite-difference simulations. We also present comparison of our approach with analytic drainage volume calculations for simplified cases. The field example is from one of the tight gas fields in the Rocky Mountain region. We utilize the streamline-based drainage volumes to identify depleted sands and generate a reservoir ‘depletion capacity’ map to optimize infill well placement based on the undepleted and undrained regions. The field application clearly demonstrates a systematic approach to optimal well placement in tight gas reservoirs.

Impact of Distance-of-Investigation Calculations on Rate-Transient Analysis of Unconventional Gas and Light-Oil Reservoirs: New Formulations for Linear Flow

“…The radius-(distance-) of-investigation concept is used in well testing and is a measure of how fast pressure waves diffuse through porous media. It is used for example in the determination of distance to boundaries (e.g., faults or other no-flow boundaries), but defined differently by investigators (e.g., Kuchuk 2009). The most commonly accepted definition for DOI is the calculated maximum radius (distance) in a formation in which pressure has been affected during the flow period of a transient well test.…”

“…Some others proposed the distance at which the rate or pressure disturbance generated during a drawdown reaches 1% of the rate or the pressure drop at the wellbore. Kuchuk (2009) provided a comprehensive study on the radius of investigation for radial geometry.…”

“…The distance travelled by pressure waves depends on both reservoir and fluid properties. Different investigators have proposed various expressions to quantify the speed of pressurewave propagation through reservoir rock (e.g., Kuchuk 2009). To the best of our knowledge, none of these approaches have been applied to linear flow.…”

Visualization of drained rock volume (DRV) in hydraulically fractured reservoirs with and without natural fractures using complex analysis methods (CAMs)

“…Likewise, conventional reservoirs produced via hydraulically fractured wells in the presence of highly conductive fractures and non-conductive natural fractures will affect the flow region near the hydraulic fractures (Doe et al 2013). Consequently, the most accurate flow simulation and production forecasting models must strive to account for the impact of natural fractures, based on their orientations, distributions, connectivity, strengths and interactions with the hydraulic fractures (Olson 2008;Cipolla et al 2011;Kang et al 2011).…”

A New Method of Optimization Design of Hydraulic Fracture Parameters in Low Porosity and Fractured Gas Reservoir

“…There are hydraulic fractures, natural fractures and the matrix to be considered during numerical simulations. Dual porosity (DP) models/ dual porosity and dual permeability (DPDK) models [1][2][3][4][5][6][7], single porosity models [8], and discrete models [9][10][11] are the most commonly used methods for naturally fractured reservoirs. Single porosity models cannot represent the interaction between the fracture and the matrix, and discrete models are time-consuming in setting up hydraulic and natural fractures and of high computational cost.…”