Shale Oil Production Performance from a Stimulated Reservoir Volume

Abstract

The horizontal well with multiple transverse fractures has proven to be an effective strategy for shale gas reservoir exploitation. Some operators are successfully producing shale oil using the same strategy. Due to its higher viscosity and eventual 2-phase flow conditions when the formation pressure drops below the oil bubble point pressure, shale oil is likely to be limited to lower recovery efficiency than shale gas.However, the recently discovered Eagle Ford shale formations is significantly over pressured, and initial formation pressure is well above the bubble point pressure in the oil window. This, coupled with successful hydraulic fracturing methodologies, is leading to commercial wells. This study evaluates the recovery potential for oil produced both above and below the bubble point pressure from very low permeability unconventional shale oil formations.We explain how the Eagle Ford shale is different from other shales such as the Barnett and others. Although, Eagle Ford shale produces oil, condensate and dry gas in different areas, our study focuses in the oil window of the Eagle Ford shale. We used the logarithmically gridded locally refined gridding scheme to properly model the flow in the hydraulic fracture, the flow from the fracture to the matrix and the flow in the matrix. iv The steep pressure and saturation changes near the hydraulic fractures are captured using this gridding scheme. We compare the modeled production of shale oil from the very low permeability reservoir to conventional reservoir flow behavior.We show how production behavior and recovery of oil from the low permeability shale formation is a function of the rock properties, formation fluid properties and the fracturing operations. The sensitivity studies illustrate the important parameters affecting shale oil production performance from the stimulated reservoir volume. The parameters studied in our work includes fracture spacing, fracture half-length, rock compressibility, critical gas saturation (for 2 phase flow below the bubble point of oil), flowing bottomhole pressure, hydraulic fracture conductivity, and matrix permeability.The sensitivity studies show that placing fractures closely, increasing the fracture half-length, making higher conductive fractures leads to higher recovery of oil. Also, the thesis stresses the need to carry out the core analysis and other reservoir studies to capture the important rock and fluid parameters like the rock permeability and the critical gas saturation.

Factors controlling production in hydraulically fractured low permeability oil reservoirs

“…The oil rate from simulation for permeabilities ranging from 1 nD to 5,000 nD and the oil rate are shown in Figure 3 for three different initial GORs. Similar trends were reported by Chaudhary et al (2011). The oil rate for a 400 nD reservoir (single fracture) is expected to be between 40 STB/day to about 10 STB/day in the first year.…”

“…Similar studies were conducted for oil production from unconventional reservoirs like Eagle Ford (Chaudhary et al, 2011). Chaudhary et al (2011) considered the impact of matrix permeability, flowing bottom-hole pressure, fracture spacing, etc., on oil production from tight oil reservoirs. They did not consider many important properties like relative permeability, fluid PVT properties and rock compressibility in their study.…”

Evaluation of Thermal Stability by Comparison of Potassium Chloride and Potassium/Sodium Formate Fluids

“…(2) Format has a good compatibility with the oilfield commonly used polymer, and can slow the speed of hydrolysis and oxidation degradation of many thickeners and filtrate reducers under high temperature and pressure [7][8][9][10][11][12].…”

Numerical Simulation of Fluid Flow through Fractal-Based Discrete Fractured Network

“…The dual porosity model was first introduced by Warren and Root [3] to characterize the behavior of naturally-fractured reservoirs and is now widely applied in the shale gas fracture modeling [4][5][6][7]. Chaudhary [8] and Agboada et al [9] simulate the fracture network with the help of logarithmic grid refinement, coupled with the dual porosity model, which is more flexible and able to offer a better description of pressure and saturation changes near the fracture. Hence, more accurate characterization of the flow pattern in the complex fracture network in the shale oil reservoir is obtained.…”