In conventional oil and gas reservoirs, the use of prefrac pump-in tests, in conjunction with analysis of the shut-in pressure response, has been a tremendous asset in improving fracture stimulation designs. Since its introduction in 1979, many modifications and improved analysis techniques have evolved to increase the value of "minifrac" tests. In recent years, the popularity of completing wells in coal formations has led to the use of minifrac applications in these wells as operators attempt to better understand how coals respond to hydraulic fracturing. Although some operators have enjoyed success with minifracs, the usefulness of these types of prefrac tests has been limited as compared to applications in conventional gas reservoirs.
In fracture stimulations of coal bed methane wells, the use of minifrac tests and other pump-in tests has sometimes resulted in abnormally high injection pressures during the subsequent fracturing treatment. Many times the result has been an early screen out during the proppant placement. Some operators have abandoned the use of minifrac type pump-in tests far fear of creating pressure problems that would jeopardize the stimulation treatment.
In this paper, problems attributed to minifrac tests are described, along with explanations for many of these occurrences. Also included are successful applications of pump-in tests and a modifications to improve fluid loss calculations. Recommended procedures to minimize the possibility of creating high injection pressures are given. Field examples from the Son Juan, Basin, Piceance Basin Block Warrior Basin and the Central Appalachian, Basin are used to illustrate problems and support the recommended procedures presented.
References and illustrations at end of paper.
A historical review of minifrac pump-in testing in coalbed methane wells will reveal three general classifications as to the use of the process:
(1) successful applications where treatment designs have been significantly improved by the results of the analyses;
(2) applications where no testing abnormalities were noted, but the resultant data could not be meaningfully interpreted by classical analysis methods, and
(3) instances where pressure abnormalities occurred either during or following the minifrac test.
When fracture stimulating coal seams, treating pressure gradients observed may vary from unusually low (0.5 psi/ft) to very high (>1.8 psi/ft).1–5 With coal seams, treating pressure that an operator will classify as "normal" will usually be some average that is representative of what is most commonly observed for a particular field. Classic elastic rock theory would typically predict values in the range of 0.6 to 0.8 psi/ft for vertically oriented fractures in shallow, low pressure reservoirs characteristic of most coal seams being stimulated. Although there is definitely evidence of horizontal fracture components, a review of the current literature finds most authors supporting the concept that vertical fractures are the predominant result, even when a horizontal component(s) is present. Possible reasons for abnormally high treating pressures in coal seams have been well documented in recent literature. The more commonly offered suggestions are listed in Table 1, as well as references that discuss the theory and mechanisms that may be contributing to the high pressures.2–7
