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In developing new coalbed methane (CBM) or coal seam gas (CSG) fields or reservoirs, the effect of many parameters are important in understanding the success or potential areas for improvement of hydraulic fracturing treatments. Estimating fracture geometry relative to the reservoir architecture is critical to understanding production variability. The Walloon Coal Measures, in the Surat Basin of Eastern Queensland, Australia, are a complex reservoir containing interbedded sandstone, siltstone, carbonaceous shale and coal seams where initial attempts at hydraulic fracturing in early pilot areas of the Surat Basin yielded poor results. Thus, when a hydraulic fracturing program was planned for this reservoir, it was decided to integrate a group of diagnostics that would be useful in understanding past results as well as deriving future improvements.Data is presented from two wells in the Walloon Sub Group (WSG) where tiltmeters and microseismic monitoring were used to evaluate fracture effectiveness relative to the reservoir architecture and to assist further design work. The treatments carried out in the studied wells were typical of CSG frac treatments used in other producing areas, incorporating stages of treated, gelled and crosslinked-gelled water with increasing concentrations of sand, up to six (6) lbm/gal. During the treatments, complex fractures were inferred based on analyses of data from both tiltmeter and microseismic monitoring methods. The collaborative data set for these wells also included a large amount of other analyses and diagnostic data. It was only possible to fully explain the treatment results through the combination of multiple diagnostics and an in-depth understanding of how the created fracture interacted with the complex reservoir and stress environment.In this paper, we outline the steps used to plan the monitoring program and describe how geological data was integrated to better understand the results observed during the treatments. We describe each of six (6) stages performed across the two wells, and how the diagnostics did or did not support the overall conclusions as to the effectiveness of each stage. Finally, this paper presents a logical framework to evaluate and integrate these technologies for use in future CSG well stimulation.2 SPE 133063 growth that would limit fracture extension or might lead to wellbore failures following hydraulic fracturing (Jeffrey et al. when a program to incorporate hydraulic fracturing was considered, it was decided that an integrated diagnostics program would be essential in understanding the fracture geometry and overall stress environment in order to improve treatment designs and to help understand past treatment results. Ridgewood Frac Pilot AreaThe area of investigation, the Ridgewood pilot (see Figure 2), was drilled on a localized structural high that appears to be a southwestern continuation of the Kogan Anticline. This area was investigated to determine if enhanced natural fracturing and associated higher permeability might exist east of the...

A considerable amount of gas is currently produced from unconventional Mississippian organic-rich shale gas fields such as the Barnett, the Fayetteville or the Bakken formations. Several tight-gas sand formations (e.g., Bossier, Cotton Valley, Lobo, Vicksburg, etc.) also provide valuable resources to be exploited. These formations are extremely low porosity and permeability reservoirs. They must be effectively and efficiently hydraulically fracture stimulated to produce at commercially economic production rates. Understanding the location and geometry of the created fractures and the area of pay affected by the fracture treatment is key to maximizing the value of the completion and reservoir management program. Technology has progressed to the point that microseismic monitoring of hydraulic fracture stimulation can efficiently provide extensive diagnostic information on fracture development and geometry. Furthermore, an acquisition system coupled to a real-time processing software linked to a fit-for-purpose visualization package enables true real-time microseismic monitoring of hydraulic fracture treatments. Firstly, this paper briefly discusses critical elements of a typical microseismic monitoring system including both hardware (e.g., quality of the downhole geophones, coupling to formation) and processing (e.g., velocity modeling, anisotropy). Secondly, we highlight some of the issues associated with manual picking of microseismic events and discuss an automatic processing technique that enables real-time determination of microseismic event locations. Thirdly, we discuss the value of real-time microseismic monitoring and the benefits it represents as an additional tool available to the stimulation engineer fracture analysis (e.g., hydraulic fracture containment, stage overlapping). Introduction The growing worldwide demand for energy requires the oil and gas industry to develop reservoirs that are increasingly more difficult to produce. These difficulties are principally related to the reservoir characteristics (e.g., tight gas sands, shale reservoirs, coal bed methane reservoirs, condensate reservoirs, deep and ultra-deep reservoirs) or their history (e.g., mature fields). Among many potential methods, one way to improve and accelerate hydrocarbon recovery is an effective stimulation program. The integration of fracture simulations and well performance can provide valuable insight into the effectiveness of a stimulation treatment. To this end, the integration of several analytical tools is required. For example, the actual rate and pressure responses from the stimulation are matched with a fracture simulator to estimate the "observed" fracture half-length. Next, the "effective" fracture half-length is determined from the production response of the well. The resulting "effective" half-length is then compared to both the pre-job estimates and the "observed" results. Today, several analytical techniques such as pressure transient testing, production analysis, production simulators, etc. are at the engineer's disposal for post-production analysis. However, to be valid, a production analysis requires an extended post-stimulation production record. Moreover, these methods only give an idea of the fracture half-length but fail to fully describe the geometry of the hydraulically induced fracture system. Several proven technologies can aid in improved defining of the fracture system geometry (temperature logging, radioactive tracing, tiltmeter surveys, etc.).1 Unfortunately, each of these tools has shortcomings. For example, a temperature log or a radioactive tracer log can only provide near-wellbore fracture height information. On the other hand, surface and downhole tiltmeter mapping can provide useful information regarding the azimuth of the hydraulically induced fracture as well as its asymmetry. However, fracture characteristics such as height, length, and width remain unclear.

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As microseismic monitoring expands, a wide variety of monitoring configurations have evolved including vertical, horizontal and deviated observation wells as well as surface and near-surface monitoring. All monitoring configurations have a common data quality indicator: signal-to-noise ratio (SNR) such that the higher the SNR the more accurate and confident the results. The key criteria for a successful microseismic project therefore primarily involve maximizing SNR. Data acquisition can be designed to optimize SNR by using low-noise equipment designed to record appropriate data quality, deployed as close as possible to the target zone. Sample rate should be tailored to the signal bandwidth, and the equipment should also have optimal directional response although for individual microseismic events both will be controlled by the data SNR. Finally, the position of the sensor array will control the fundamental location accuracy, although this will be commonly be a trade-off with SNR depending on logistical constraints of monitoring wellbore access. Recent processing techniques based on seismic migration methods, offer automated and repeatable processing with inherent signal conditioning which provided SNR improvement. Associated with the automated processing is the ability of realtime delivery of all the microseismic events for realtime stimulation decisions. A demonstration with an automatically processed dataset, illustrated the importance of filtering the events based on SNR. Low SNR events had higher location uncertainty, such that both the volume of the microseismic cloud and its aspect ratio were made anomalously large. An accurate microseismic image was produced by filtering out the low confidence, low SNR events. Beyond the geophysical processing aspects, it is equally important that the microseismic project be designed so that engineering value can be extracted by determining valuable fracture details or answering key questions.