Determination of Closure Stress and Characterization of Natural Fractures with Micro-Fracturing Field Data

Abstract

Hydraulic fracturing is now considered to be a standard completions process used to improve oil and gas recovery in unconventional reservoirs. Injection/fall-off pressure from a micro-fracturing test contains important geomechanical information, including the inference of the minimum horizontal stress, natural fracture permeability, and in-situ pore pressure. The determination of in-situ stress is crucial for designing, modeling, and evaluating hydraulic fractures. This paper presents a field example of a micro-fracturing job to determine minimum horizontal stress and characterize natural fractures in terms of permeability. The analysis of micro-fracturing data consists of two parts: pre-closure analysis and after-closure analysis. The pre-closure analysis involved the analysis of early pressure fall-off data to determine the fracture closure stress of a particular formation at a specific depth. The tests were performed by injecting a small volume of fluid into a small, confined, and isolated zone at low rates to create a small fracture. The closure stress was determined from the analysis of the pressure decline after shut-in. To estimate natural fracture permeability, a series of numerical fully coupled hydro-mechanical simulations of hydraulic fracture propagation was conducted in a naturally fractured reservoir by varying the natural fracture initial permeabilities. The pressure decline after shut-in of the formation tester pump was analyzed using G-function and square-root-time methods. The point at which the G-function derivative began to deviate downward from the linear trend was identified as the point at which the fracture closes. The cycle of injection and fall-off was repeated four times. After the first cycle, in each subsequent cycle, the fracture pressure was reduced by approximately 20 psi. Based on these four cycles and petrophysical data, a customized model was developed, and poro-mechanical simulations were performed to characterize natural fractures in the formation. The simulation results explain the variation of micro-fracturing pressure history, during the four injection cycles. A comparison of the pressure history from the micro-fracture tests with the injection pressure obtained from the numerical simulation suggested that the formation included relatively impermeable natural fractures. The characterization of natural fractures during micro-fracturing provides additional information not captured by a traditional G-function or square-root-time analysis. Multiple cycles of injection and pressure fall-off provide a qualitative assessment of in-situ pore pressure and a consistent minimum in-situ stress. Understanding the fracture pressure and natural fractures in the formation is a key component of successful reservoir completion and development. However, challenges exist in the measurement of these reservoir properties with conventional methods of diagnostic fracture injection testing (DFIT™). This new analysis method represents a step forward in terms of overcoming such challenges.