Hydraulic fracturing and stimulation of wells is common practice in the United States and particularly in tight gas formations. Often the only measure of fracturing success is an increase in production following the fracturing process. Therefore, understanding the created fracture geometry is essential to the effectiveness of any stimulation program.

Technology has progressed to the point where microseismic monitoring of hydraulic fractures can provide extensive diagnostic information on fracture development and geometry. Typically, microseismic monitoring uses an array of geophones in a nearby well to monitor the hydraulic fracturing of the treatment well. Critical elements of a microseismic monitoring system include the downhole tool, usually an array of three component receivers, and the telemetry system. Receivers should be extremely sensitive, well coupled to the formation, and exhibit a linear response to capture a wide range of signal strengths and frequencies. Additionally, an acquisition system check should be performed before and after the monitoring campaign to ensure the quality of the recorded signals. Telemetry cartridges need to capture and transmit the continuous stream of data acquired by the receivers and withstand the high-pressure, high-temperature environments often encountered in the intervals of interest. Traditional borehole seismic checkshot, vertical seismic profile (VSP), and walkaway VSP surveys have been employed in the construction of calibrated earth models for many years. Prior to the hydraulic fracture stimulation, a borehole seismic survey enables (i) calibration of sonic velocities acquired along the axis of the wellbore, (ii) optimum tool location to accommodate background noise or acoustic coupling, (iii) determination of anisotropy parameters, and (iv) qualification of wavefield mode conversions.

Geology is a fundamental element in the design of a stimulation program and the interpretation of its results. Rock properties govern the type of fluids to be injected in the formation as well as the pumping schedule. Rock layering controls the location of the monitoring device, guides the depth at which perforations should be located, and determines how hydrocarbons flow within the formation. Despite these facts, the impact geology may have on the stimulation results is often overlooked as it is often assumed that stimulated fractures have a symmetric planar geometry.

First, we present the results of hydraulic fracture stimulations in various geological environments that have been monitored using microseismic data. We illustrate with these case studies that in, some rare cases, simple radial and planar fracture system may be generated as predicted using simple modeling techniques. However, in most cases the final fracture system geometry is asymmetric and largely governed by geologic discontinuities such as joints, faults, and bedding planes. These geologic discontinuities significantly affect the overall geometry of the hydraulic fracture system. This may limit the fracture system’s development, increase fluid leakoff, hinder proppant transport, or even create a complex fracture network. Ultimately, such factors impact well productivity.

Second, we present the results of a multi-stage hydraulic fracture monitoring campaign performed in 2004 on a producing well in a mature tight gas field. The purpose of these microseismic monitoring surveys was to determine the overall geometry of the hydraulically induced fractures in the Canyon Sand formation. Information and results derived from the microseismic interpretation were used to provide the operator with recommendations for reservoir management (e.g., down-spacing, finding suitable infill drilling locations, completion practices, etc.) An initial borehole seismic survey confirmed optimum tool positioning to accommodate background noise and acoustic coupling. Additionally, calibration of sonic velocities was performed. All these factors led to an unprecedented level of understanding of the treated formations. All available pieces of information pertaining to the monitoring and treatment wells were combined to give a calibrated velocity model, which lead to the accurate processing of the microseismic data acquired during the one-day long hydraulic fracture operation. The stimulation treatments utilized a titanate fracturing fluid system assisted with carbon dioxide. Five of six stages were successfully placed with little or no adjustment to the treatment design, however one stage was surface pressure limited. All imaged fracture systems were oriented along the same azimuth. Larger than anticipated fracture heights were generated, and the acoustically-defined effective lateral extent of the various fracture systems was as anticipated. Higher than designed fracture heights illustrate that it may be beneficial prior to the next design to measure specific mechanic parameters (e.g., in-situ stress, Young’s modulus, Poisson’s ratio, etc.) for simulation purposes. To minimize height development, fracturing fluids exhibiting lower fluid viscosity, injection rate adjustments, etc. have been recommended. Imaged fracture systems, all oriented along the same azimuth, suggested that present drilling pattern was inadequate for optimum drainage purposes. Therefore, new locations for infill drilling have been decided. Infill wells are currently being drilled. To further complement the added value of the information obtained to this data, we are performing a prorated production rate transient analysis. This will help determining effective permeability, effective fracture systems half-length, fracture systems conductivity, and skin damage factors.

Figure 1. Microseismic event locations from six independent hydraulic fracture stimulations in tight gas formations.

Copyright ©2005. The American Association of Petroleum Geologists. All Rights Reserved.