Microseismic Imaging of Hydraulic Fracture Complexity in the Barnett Shale

Abstract

Microseismic monitoring has been used to image hydraulic fracture growth in the Barnett Shale. The Barnett is a naturally fractured shale reservoir, which causes significant complexity in fracture growth during well stimulation operations. Several Barnett treatments have been successfully imaged between March 2000 and December 2001. In this paper, examples will be given to illustrate the complexity and variability which is developed during the treatment as the slurry interacts with the pre-existing fracture sets. The microseismic images explain why the stimulations occasionally grow at an angle to the assumed fracture orientation and into neighboring wells. Differences in production rates from various wells could also be related to the fracture geometry. The implications of the images to reservoir management highlight the benefit of imaging individual fracture networks to avoid overlapping and for targeting potential new well locations. Introduction Fracture diagnostics is critical in understanding the details of actual subsurface fracture growth, especially in cases of fracture complexity. Several diagnostic techniques exist, although microseismic imaging perhaps offers the best resolution to image fracture complexity. Even with relatively simple fracture geometries (i.e. a Perkins-Kern type fracture geometry), fractures can grow asymmetrically, have variable confinement across geologic interfaces, and change orientation. However, fracture growth in a naturally fractured reservoir can exhibit additional complexities associated with interaction between the hydraulic fracture and the pre-existing fracture network. In this paper, we describe the results of microseismic imaging of hydraulic fractures in Devon Energy's (formerly Mitchell Energy) Barnett Shale Gas Field, Texas1–4. The images are the first successful microseismic images in the Barnett, recorded between March 2000 and December 2001. The field is in the Fort Worth Basin, comprising the Mississippian shale lying between the Viola Limestone and the Marble Falls Limestone. The shale varies between 300' to 1000' thick, and is extremely low permeability (approximately 0.0001 millidarcies). Large scale hydraulic fracturing is required to stimulate production in the field to economic levels1. The objective of the microseismic imaging was to define the fracture growth characteristics during these well stimulations. The large scale hydraulic fractures, combined with infill drilling on spacing as tight as 27 acres and apparenent fracture complexity related to interaction with pre-existing fractures, resulted in a need to better understand the fracture geometry5. To image the actual fracture behavior in the field, a series of stimulations have been imaged using passive microseismic imaging to determine the fracture geometry and growth characteristics. Here, we present selected examples from images collected during numerous stimulations over a period of two years, which demonstrate substantial fracture complexity resulting from interaction with the natural fractures in the field. The paper reports the fracture geometry and complexity, comparisons with the final well production, and implications for field management.

Computer simulation of hydraulic fractures

“…These include: (i) how best to address, in a numerically efficient and physically realistic manner, the handling of layer debonding and fluid invasion along layer interfaces with associated stunting of fracture height growth in shallower wells-relatively limited progress has been made in this area [94][95][96]; (ii) how to appropriately adjust current (linear elastic) simulators to enable modeling of the propagation of hydraulic fractures in highly cleated coal bed seams (for the extraction of methane) [97]; (iii) how to appropriately adjust current (linear elastic) simulators to enable modeling of the propagation of hydraulic fractures in weakly consolidated and unconsolidated ''soft'' sandstones, such as are found in the Gulf of Mexico-limited progress has been made in this area [98,99]; (iv) laboratory and field observations demonstrate that mode III fracture growth does occur [100], and this needs to be further researched; (v) related to (iii), the effect of the invaded zone ahead of the fracture tip needs to be further researched-a criterion to switch from a fluid lag based approach to an invaded zone based approach in a numerical model is required; (vi) suitable models for the propagation of hydraulic fractures in naturally fractured reservoirs that result in complex (non-planar) geometric configurations requires development [101]; and (vii) how to efficiently model 3D or ''out of plane'' effects, such as fracture re-alignment (when the fracture initiates following an orientation that is not perpendicular to the minimum in situ stress and then tries to re-align itself), which could be a cause of near-wellbore tortuosity or even ''pinching,'' a factor that usually determines the success or failure of hydraulic fracturing treatments [102].…”

Fracture propagation in a naturally fractured formation

“…Microseismic measurements and other evidences [1,2] have confirmed that the creation of a complex fracture network during fracture treatment is a common occurrence in unconventional ultra-low permeability shale reservoirs. It has long been observed in mine-back and fracture core-through experiments [3][4][5][6] that the interaction between hydraulic fracture (HF) and the pre-existing natural fracture (NF) in the shale are the likely reason of forming this complex fracture network.…”

A grain based modeling study of fracture branching during compression tests in granites

“…Besides direct observations in neighboring wells [7], microseismicity [8][9][10][11], tilt mapping [7], treatment pressure analysis [7], production data [7], and reservoir modeling [13] from hydraulic fracturing treatments in many geological environments also support the observation of complex fracture network development at macro scale. The most important natural factors triggering hydraulic fracture complexity were found to be discontinuities (joints, faults, bedding planes) and heterogeneities within the rock mass [3] in conjunction with the in-situ stress field (e.g.…”

“…Chen et al [14]). Environments where complex fracture networks may be formed include shale formations such as the Barnett shale [11,7] and granitic basement rock [13].…”