The Gas Research Institute's (GRI) fourth Staged Field Experiment (SFE No. 4) well was drilled as part of a field-based research program that has been conducted in the Frontier formation of southwest Wyoming. During this experiment, data were collected from whole cores, multiple sets of openhole logs, in-situ stress measurements, microseismic surveys, and multiple injection (mini-frac) tests. These comprehensive data sets have been used to fully describe the Frontier sandstone. This paper summarizes the analysis of abnormally high fracture treating pressures that were observed on SFE No. 4.
Over the past two decades, the analysis of the net or excess pressure has become an important diagnostic tool for the petroleum engineer to evaluate hydraulic fracture treatments. The technique was introduced to the industry by Nolte and Smith and has been used in many situations to diagnose fracture growth patterns. Net pressure analysis can also be used to categorize formation types based on their net pressure response. Abnormally high fracture pressures encountered in certain formations have also been evaluated with this method.
It was evident from the initial injection tests on SFE No. 4 that the injection pressure was noticeably higher than other wells in the area. Due to this high injection pressure, a series of diagnostic injection tests was developed to evaluate the cause of the high pressure. These tests indicated the high injection pressures were caused in part by high near wellbore friction. We also saw evidence of high net pressures in the fracture, indicating that multiple fractures were simultaneously.
This paper presents a detailed evaluation of the data from three of the mini-fracs. Also included is a brief summary of the three treatments and a description of the methodology used to analyze the data and determine the reservoir situation.
As shown in Table 1 (at the end of this paper), we attempted a total of fourteen (14) injection tests. The data from every injection (minifrac) tests were analyzed in this project. However, the results from only the June 5, August 5, and August 10 injection tests will be discussed in detail in this paper. These treatments were selected for the following reasons:
the bottomhole treating pressure was measured with a downhole gauge,
surface data were recorded with the GRI Treatment Analysis Unit (TAU), and
large fluid volumes were injected.
The knowledge gained by analyzing the data from all 14 tests was invaluable in determining the cause(s) for the abnormally high fracture treating pressure. We can state conclusively that the results obtained from the three injection treatments we describe in this paper are consistent with the analyses from all of the injection tests.
At the start of the June 5 injection test, the tubing-casing annulus contained 2 percent KCL water (280 bbls) from a previous injection. The pumping schedule on June 5 consisted of 750 bbls of 40 lb/1000 gal crosslinked gel displaced with 260 bbls of 2 percent KCL water. Numerous flow rate changes and shut-ins were performed to gather data that we could use to evaluate friction pressures in the near wellbore vicinity.