This case history discusses the evolution of the completion strategies and fracture stimulation techniques that have turned a large marginal gas resource in the Jonah field, WY into a commercially viable field. Completion practices have evolved from single zone, high-quality nitrogen foam fracture stimulations to multiple zone completions utilizing crosslinked borate fluid systems. Using these new techniques, total field production has increased approximately 180%. A normalized comparison of productivity (q/ P) per foot of gross clean sand indicates the new completion and stimulation techniques yield shallower decline rates with initial production equal to or higher than the earlier foam treatments. Introduction The Jonah field, located in Sublette County, southwest Wyoming, has the potential to be a significant gas resource with field reserve estimates ranging up to a trillion cubic feet. Over-pressured gas is found in the tight sands of the Lance formations' fluvial sand-shale sequence that range from 1,500 to 3,000 feet in gross thickness. The primary challenge presented in the Jonah field is effectively and economically fracture stimulating (i.e., contacting) as much pay section as possible within a low gas price environment. Initially, a reservoir/stimulation description was developed to establish a baseline and to begin developing an optimal economic completion and stimulation approach. Using this approach, an integrated strategy was created and implemented to 1) complete more pay intervals with pseudo-point source perforated, multiple-staged treatments; 2) modify the borate fluid chemistry to address complicated fracture geometry and improve far-field proppant placement; 3) reduce multiple fracture initiation; and 4) eliminate screen-out problems. Initial results using these approaches in 5 wells indicated significant improvement in field economics. Both the average production and the normalized productivity (q/ P) per foot of gross clean sand are higher than the previous foam completions. The decline rates at three months are shallower suggesting better lateral and vertical proppant placement. Previously uncompleted reserves in uphole Lance pay sections were proven economic. In two of the wells reserve recovery from these shallow intervals was accelerated by commingling all the lance pay intervals in the initial completion phase. Completion costs per pound of proppant placed were reduced 35% compared to an offset foam treatment. Background The Jonah field is operated by McMurry Oil Co. and Snyder Oil Co. Figure 1 shows the location of the field and the regional geologic setting. Figure 2 is the production history of the field. Regional Geologic Setting. The Jonah field is located on the west flank of the northern Green River Basin between the Moxa Arch and the Wind River Mountains (Figure 3). Production is from the fluvial sandstone reservoirs of the Upper Cretaceous Lance Formation. The Lance Formation comprises more than 2,500 feet of heterolithic strata, including fluvial channel sandstones and siltstones, floodplain shales, and minor coals that were deposited in a broad alluvial plain. Sandstone comprises 40-50% of these sediments, which were derived from uplift of the Thrust Belt to the west and the Wind River Mountains to the northeast. These sandstones were deposited in channels 10–20 feet deep and 150–4,000 feet wide, though some amalgamated sandstone intervals are greater than 100 feet thick and over a mile wide. Fluvial architecture varies in the Lance Formation from isolated meandering river deposits to stacked, amalgamated braided river deposits. These intervals form roughly correlatable units ranging from 100 to 700 feet in gross thickness. Typically 50 to 150 feet of reservoir quality rock is found within a 300 foot interval with three to four intervals per well. The field terminology assigned to these correlatable intervals are (shallow to deep): Upper Lance, Middle Lance, Jonah, Yellow Point, and Wardell. Sandstones are fine to medium grained and are composed of detrital chert and quartz with minor feldspar, authigenic clay, quartz cement, and calcite cement. P. 521

This p@r wa~a--d for p=sentafion me~8 SPE Rocky Mountain Region alLow-Perrnaabifity Resemirs ,Symposlum and E~ibifion held in Denver, Colorado, 5-6 April 1998. 'rfds parer was selectad for presentation by an SPE Program Committee following retiew of information contained In an abstract submiflad by the author(s). Contents of the paper, as presented. habw not W retiewed by the %iefy of Petroleum Engineers and are subject tõ ty tha author(a). The materfaf, as presented, dms not necessarily reflect any position of the SmJe~-b~nMoTeufiF~V*E, W Mcem, or mamhra. Papers presented at SPE m-arR S* fo P*ficafi~m~ew by E~orial Committees of the Society of Petroleum Englneera. Electronic raproductlon, drstribuiion, or storage of any part of this paper for commerctaI purposes wffhout the wrfffen consent of the Society of Petroleum Engineers is pmhibitad Permission to rWroduce in print is restricted 10 an abstract of not more than 3C0Uus-s may nor be kqied. The abstract must contain conspicuous acknowledgment of whace and by whom the papr was presented Write tibrsrian, SPE, PO. Box 8W836, Richardson,~750s3-3636. U.SA., Tax01 .~-952-9435. -

The economic boundaries of the Williston Basin are being expanded with improved practices. This paper discusses advances in reservoir characterization coupled with the implementation of refined stimulation techniques that have achieved strongly compelling results in an area of the Williston Basin that was previously perceived to be marginally economic. After more than a decade of intense development, the remaining undrilled acreage in the core of the Bakken has been drastically reduced. Consequently, there is strong motivation to identify additional economically viable drilling locations. Hydraulic fracturing treatments incorporating increased volumes of fluid and proppant in more closely spaced clusters have successfully increased well productivity in many resource plays across the industry. The contemporary slickwater and slickwater hybrid designs implemented in the Bakken have spurred a renaissance of continued development throughout the basin. While these increasingly large frac treatments improve well productivity, in some parts of the basin the high treatment expenses and resulting elevated watercuts challenge the economic viability of development. Rote application of the "bigger is better" completion strategies developed for the core of the basin has been unsuccessful in some portions of the Bakken. This paper describes the unique geologic characteristics of the study area and the stimulation strategy that has been adapted to accommodate the geologic differences while achieving excellent economic results. Implementation of completion designs tailored to the area has yielded a 300 to 400% production increase compared to offset wells. This "right sized" completion strategy customized for the area achieved highly productive wells with substantially lower capital costs than were budgeted based on strategies currently popular in the core of the Bakken. Although treatment designs continue to evolve and additional improvements are anticipated, the summary of experimentation and learnings from seven sequential wells may be helpful to others pursuing assets considered "marginal".