In the San Juan basin Fairway, cavitated Fruitland coalbed-methane (CBM) wells have been successfully producing for the past 30 years. However, over the years, coal-fines migration into these cavitated wellbores has resulted in pump issues and coal-fines production, leading to a significant decline in production. To clean out the coal fines and replace the pumps on a continuous basis is a costly workover issue. Hence, a foamed remedial treatment was designed to displace the conductivity-plugging coal fines away from the wellbore and immobilize them with the foam also serving as a diverting agent. This has allowed the production and dewatering process to continue without any interruption. The remedial treatment was chosen because the aqueous tackifier in it can control the fines and help prevent them from plugging the flow path. Also, it dissolves any calcium-carbonate scale in the wellbore and near-wellbore region. In this study, 15 cavitated wells with coal-fine issues were selected for the foamed remedial treatment. In all of these 15 wells, the coal-fines issues were resolved. This allowed production to be uninterrupted and reduced the cost of workover rigs and pumps. As a secondary benefit, production stabilized in 10 wells and increased in 5 of these wells. This study shows the production results from these two groups of wells that were treated. It also discusses the design options for the treatments and lessons learned from the process. This technology can be applied to openhole as well as cased multilayered CBM wells.

Hydraulic fracturing continues to be the primary mechanism to produce hydrocarbons out of the tight shale reservoirs. Ever since the success of Barnett shale program, operators are inclined to pump similar large volume water fracture treatments with little or no proppants in their respective shale plays. This assumes that all shale plays are the same and react accordingly to large volume treatments. The basic objective behind such treatments is to contact large surface area, which has been very successful in the Barnett shale play. Such large volume treatments in other shale plays may not be an optimized solution for the specific shale attributes and the response may lead to uneconomical production results. Some shales based on their reservoir characteristics might require a conductivity type fracture treatment. So, it is important to understand the characteristics of these shales before deciding the stimulation treatments. In addition to core and log analysis of these shales, fluid sensitivity tests, Brinell hardness tests, unpropped fracture conductivity tests and more importantly a Diagnostic Fracture Injection Test (DFIT) can help define the guidelines for choosing between a surface area and a conductivity type fracture treatment.Integrating the various data sources is important in arriving at these guidelines. The main objective of this paper is to provide these guidelines along with examples such that the costly trial and error approach for stimulating shales can avoided. Examples from both oil and gas shales namely, the Gothic, Haynesville, Eagle

Summary Hydraulic fracturing continues to be the primary mechanism to produce hydrocarbons out of tight shale reservoirs. Ever since the success of the Barnett shale program, operators are inclined to pump similar large-volume water-fracture (waterfrac) treatments with little or no proppant in their respective shale plays. This assumes that all shale plays are the same and react accordingly to large-volume treatments. The basic objective behind such treatments is to contact large surface area, which has been very successful in the Barnett shale play. Such large-volume treatments in other shale plays may not be an optimized solution for the specific shale attributes, and the response may lead to uneconomical production results. Some shales might require a conductivity fracture treatment on the basis of their reservoir characteristics. So, it is important to understand the characteristics of these shales before deciding on the stimulation treatments. In addition to core and log analysis of these shales, fluid-sensitivity tests, Brinell hardness (BHN) tests, unpropped-fracture-conductivity tests, and, more importantly, a diagnostic fracture injection test (DFIT) can help define the guidelines for choosing between a surface-area and a conductivity-type fracture treatment. Integrating the various data sources is important in arriving at these guidelines. The main objective of this paper is to provide these guidelines along with examples so that a costly trial-and-error approach for stimulating shales can be avoided. Examples from both oil and gas shales (i.e., the Gothic, Haynesville, Eagle Ford, and Barnett shale plays in the USA) are included in this work.

Permeability and pore pressure are critical parameters in the evaluation of a coalbed methane (CBM) project. Coal permeability is particularly problematic, as it is highly stress dependent and estimates made from cores generally do not adequately reflect in situ reservoir conditions. Pressure buildup, injection falloff and more often slug tests have been used to determine in situ permeability in coal. However, buildup tests are costly, time consuming, and cannot be applied effectively in underpressured reservoirs; slug tests require an accurate estimate of wellbore storage effects. Similar to buildup tests, injection falloff tests are very time consuming and costly because of the longer shut-in times. Also, if fracture pressure is exceeded during an injection-falloff test, conventional analysis can give erroneous results. This paper presents a more effective method for determining pore pressure and permeability in coals using a diagnostic fracture injection testing technique. A diagnostic fracture injection test (DFIT) is a small-volume, cost-effective, and short-duration test that has been used successfully in tight gas sands in the Piceance and other basins. The test consists of (1) a G-function derivative analysis to identify the leakoff mechanism and closure, (2) a calibrated before-closure analysis using modified Mayerhofer method to determine the permeability, and (3) an after-closure analysis to estimate pore pressure and permeability. The uniqueness in applying this test in coals is that both the before- and after-closure analysis can be utilized where pseudo-radial flow is not dependent upon the fracture half-length. The technique works because the permeability in coals is high enough that after-closure pseudo-linear and pseudo-radial flows are normally observed with an extended shut-in. Once pseudo-radial flow is observed, estimating pore pressure and transmissibility becomes straightforward and provides calibration for the before-closure analysis. Hundreds of diagnostic fracture injection tests have been conducted in all the CBM basins in the rockies and in Canada with remarkably consistent results. Examples are provided from San Juan basin and Canadian coals where diagnostic injection tests have been applied successfully for various operators. DFIT's have been applied successfully in other CBM basins like Sand Wash, Greater Green River, Piceance, and (western) Powder River basin. Introduction Pressure-transient testing of CBM wells has developed rapidly in the past fifteen years. Interference testing in coals was reported by Koenig and Stubbs.1 Mavor and Saulsberry2 wrote an entire chapter that dealt with the testing of coalbed methane wells in detail. Seidle et al.3 addressed the issues relating to testing new coal wells. Shu et al.4 estimate coal permeability by history matching a slug test and they also report the data analysis from packer tests performed at one of the BHP Steel Colliery sites. Pressure-transient analysis with sorption phenomena for single-phase gas flow in coal seams was addressed by Anbarci and Ertekin5. Jochen et al.6 studied existing analytical models for estimating permeability in CBM reservoirs. They stress the need to use a reservoir simulator in case of desorption in the development of CBM reservoir description.

The permeability, pore pressure, and leakoff type interpreted from more than 1,200 diagnostic fracture-injection/falloff tests were collected in a database and statistically evaluated for four Rocky Mountain basins. The statistical analysis includes the range of observed permeability and pore pressure and the fracture leakofftype distribution.The analysis reveals that pressure-dependent leakoff, fracturetip extension during shut-in, and fracture-height recession during shut-in are the most common leakoff types. Overall, pressuredependent leakoff, which can be indicative of highly productive fractured reservoirs, is the most common leakoff type in all Rocky Mountain basins. The analysis also shows orders-of-magnitude variation in gas permeability within all basins, with observed gas permeability ranging from less than 0.001 to greater than 0.10 md. G-FunctionDerivative Analysis. G-function derivative analysis is used to identify a leakoff type and provide a definitive indication of fracture-closure stress. The graphical technique, which was proposed by Barree and Mukherjee, 8 requires a graph of bottomhole pressure, the derivative of pressure (dp/dG), and the superposition derivative (Gdp/dG) vs. the G-function.The leakoff type is identified using the characteristic shape of the pressure-derivative and superposition-derivative curves. Fig. 1