10122-43

Primary Performer
Texas A&M University, College Station, TX

Additional Participants
Hess
Shell USA

Abstract
Multiple fracturing (multistage or simultaneous multiple fracturing) is the most popular, and by far, the most effective stimulation method to develop unconventional shale gas, shale oil, and tight gas formations. In the last several years, fracturing methods have evolved and improved very rapidly, however, the fracturing process is still uncertain and is not yet fully understood, especially when complex fracture systems including natural fracture networks are involved. Given increasing complexity in completions, the need for diagnosing effectiveness of these fractures has grown dramatically. Various interpretation methodologies have been attempted to understand in-place volume in the stimulated-reservoir volume (SRV) and the expected ultimate recovery (EUR). However, these gross estimates do not help assess the stimulation effectiveness, which directly leads to optimize overall depletion plan, well spacing, and the size of stimulation treatments. In many cases, the operators cannot even tell how many fractures are actually created and where the fractures are located.

We propose to develop a new methodology for hydraulic fracturing diagnosis using downhole temperature and pressure data to identify fracture locations and types (longitudinal versus transverse), estimate fracture geometries and evaluate fractured well performance. Temperature and pressure data can be provided by fiber optic downhole sensors (distributed temperature sensors or DTS, and pressure sensors) or production logging.

The objectives of the proposed research are to develop novel approaches to using temperature data to diagnose stimulation treatments, to estimate fracture geometry, and to evaluate fractured well performance in unconventional tight sand and shale reservoirs. The ultimate goal is to improve the efficiency of multiple fracture stimulation. The approach we will use in this study is to develop and apply a rigorous theoretic model of mass and heat flow in a multiple complex fracture system. We will develop mathematical models that describe energy and mass flow in horizontal wells with multiple fractures in typical shale and tight sand producing wells, and inversion models that translate temperature and pressure data to descriptions of complex fracture systems. The thermal model for simulating the temperature behavior during fracturing can be developed by coupling a wellbore and a near-wellbore temperature model considering the effect of both mass transfer and heat transfer between wellbore and formation. Based on the distinctive effects of heat convection in a fracture system and heat conduction in the porous medium, we believe that this thermal model can be used for interpretation of the dynamic temperature profile to estimate fracture initiation points, number of created fractures, distribution of stimulation fluid along the lateral, and the effectiveness of diversion processes during the fracturing treatment. These results later can be used for more accurate fracture modeling and better estimation of fracture conductivity and fracture geometry. Furthermore, the developed thermal model can be extended to simulate the temperature behavior after treatment in a shut-in period (warm back) and also during production. Integration of temperature data analysis during and after the treatment provides a bigger picture of fractured well production behavior, which will help us to better understand fracturing treatments some of the nuance of hydraulically induced fractures, along with microseismic and radio-active tracers, leading to overall understanding of unconventional well completions and stimulation, assess the effectiveness of treatments, evaluate well performance, and improve stimulation design and practice.

Principal Investigators: Dr. Ding Zhu, Dr. A. D. Hill and Dr. B. Jafarpour

Project Duration: 3 years