Among the operators in the US Rocky Mountains, BP America Production Co. (BP) continually searches for technologies that will help to improve production results from the complex tight gas plays that lace the region. To this end, it recently applied Schlumberger's FiberFRAC technology in the mature Jonah field, Green River Basin, Wyoming, and enjoyed a 35% increase in cumulative production from the newly stimulated well over its first 60 days on stream. This translates into an incremental gain of 35 MMscf of natural gas, or US $210,000 based on a $6/Mscf gas price.

While BP has employed Schlumberger stimulation services in Jonah field for over a decade, the late 2004 through early 2005 project described herein represents the company's first onshore US use of the fiber-based stimulation technology, which is designed specifically to enhance proppant distribution in tight gas applications.
Project challenges
Located in the southwestern corner of Wyoming, Jonah field is a large, structurally complex, wedge-shaped fault trap within the northwestern portion of the Green River Basin. It primarily produces from over-pressured, tight sandstones in the Upper Cretaceous Lance Formation.
The Lance Formation is a stacked sequence of fluvial channel sands that are interbedded with siltstones and floodplain shales. Gross interval thickness ranges from 2,800 ft to more than 3,600 ft (854 m to 1,098 m). Individual sandstone bodies occur as 10 ft to 20 ft (3 m to 6 m) thick channels within stacked channel sequences that can be greater than 200 ft (60 m) thick. The low permeabilities of the small individual pay sands within such large gross intervals present the largest reservoir development challenge.
Various stimulation practices have been applied in Jonah field over the years, as the fracturing challenges are many. Recently, the conventional stimulation has consisted of an energized borate crosslinked fluid applied using multiple flow-through bridge plugs between stages. As compared to this approach, the crosslinked fiber-based fracturing technology promised to solve one of the most common problems with tight gas stimulations, proppant settling.
In tight gas applications with conventional crosslinked fluids, the fracturing fluid is designed to break shortly after pumping. But the fracture may stay open for hours because of the low permeability typically seen in tight gas reservoirs, and the low-viscosity fluid that remains is unable to suspend the proppant for maximum production results. If the proppant settles, fracture performance can be adversely affected.
By creating a network of fibers within the fracturing fluid to provide a mechanical means to transport, suspend and place the proppant, FiberFRAC fluid technology solves proppant settling issues and frees the viscosity component of the treatment to be tailored to reservoir conditions to optimize fracture geometry. The fiber-based technology's reduced need for polymer loading also results in a proppant pack with higher retained permeabilities than those created with conventional crosslinked fluids.
Learning of the crosslinked fiber-based technology's potential, BP elected to apply it in Jonah field and compare the results it achieved with those of the energized borate crosslinked fluid approach. Close teamwork between BP and Schlumberger personnel ensured that the new technology was properly applied for maximum production and safety results.
Jonah field application
The infill drilling program in Jonah field includes drilling four wells from a single well pad using a 20-acre (8.1 hectare) drainage radius. This allows for optimum reservoir drainage while leaving a limited environmental footprint. After being drilled, each well is logged with an openhole suite and then 41/2-in. casing is run, cemented in place and selectively perforated. Typically, 10 to 12 stages are completed with an average interval of 200 ft to 300 ft (60 m to 90 m) per stage over a 3,000 ft (915 m) interval using deep-penetrating charges at four shots per foot. Figure 1 is a type log and formation nomenclature for the Jonah field.
Mini fall-off (MFO) diagnostic injection testing is used to estimate permeability and reservoir pressure. These tests were designed in late 2003 as small injection tests prior to fracture stimulation to improve log-derived pressure and permeability estimates for the field. Log and MFO data are now used routinely to design the appropriate fracture treatments for Jonah field wells.
The first onshore US application of FiberFRAC technology by BP was in Jonah field well Corona 27-30. It included placing 2.3 million lb (1.05 million kg) of 20/40 sand and 35% to 50% quality nitrogen at an average rate of 25 to 30 bpm and pressures of 4,500 psi to 6,700 psi (31.0 MPa to 46.2 MPa). Flow-through type bridge plugs were used to enable a staged treatment while providing a pathway for subsequent production from the lower zones to move to the surface. After stimulation, the well was flowed back for two to three days to ensure clean-up. Initial gas production rates were calculated from choke size and pressure calculations.
Results
After stimulation and clean-up of the Corona 27-30 well, production data were gathered for 60 days. Reservoir quality also was determined by calculating a permeability thickness (kh) value as a product of the permeability (k) and thickness (h) of the producing formation. The fiber-based treatment results were compared to those from Jonah field well Corona 39-30, in which a conventional borate treatment was applied.
Table 1 shows the results of calibrated petrophysical analyses on both wells. As shown, the kh value was substantially higher in the borate-treated well, Corona 39-30, which implies that it should have better deliverability than the Corona 27-30. However, production results told a different story.
After normalizing the production results from both wells to a kh of 5.4 (that of the fiber-based treatment well), both daily and cumulative numbers were compared (Figure 2). The FiberFRAC technology clearly provided improved production results. The Corona 27-30 well showed a 35% production improvement over 60 days as compared to Corona 39-30, which represents an incremental increase of 35 MMscf of natural gas or $210,000 based on a $6/Mscf gas price.
Initial production results using the FiberFRAC technology look very promising. Further field trials will be necessary to better demonstrate the fiber-based treatment's potential to help increase production for BP in Jonah field.

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