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 paper will highlight the methodology used to successfully re-stimulate a well that had been unsuccessfully stimulated from previous treatments. A field example will present a well, which was previously treated on two occasions and show the subsequent implementation of a successful treatment that displaced both Ottawa and resin coated sand from the original fracture, enabling the third treatment to be successfully pumped. The initial evaluation methods that were utilized, which included pressure buildup (PBU), reciprocal productive index (RPI), and treatment pressure analyses, will show the damage that can occur when overly aggressive stimulation treatments are applied and present a methodology for evaluating a damaged well. A treatment was specifically designed to remove the proppant pack damage and create an effective stimulation for the character of the reservoir rock. The pressure response from the third treatment will demonstrate removal of the original and the creation of an effective stimulation. Post-treatment production data and analysis is also presented. Background The Gas Research Institute initiated a re-stimulation research project in late 1997 and early 1998. This project included both consulting companies and operators to research and implement re-stimulations on gas wells in selected study areas. The GRI presented a portion of the results in a one-day re-fracturing workshop1. Their presentation contained two primary parts. The first part considered various evaluation techniques to locate potentially economic re-stimulation candidates. The second presented case histories from operators who were working with the GRI contractors as part of this program. This paper is not concerned with reviewing their work, but simply to reference it and note key issues they raised to help provide context for this topic. Of interest now are some of the statistics that they presented in their introduction to the issue of re-stimulation. Re-fracturing treatments represent only 2–3% of the total amount of stimulation activity in the industry. This amounted to an estimated 450–550 re-stimulation treatments per year at the time of their presentation. It can be deduced that this low percentage results in reduced efficiency and a lack of familiarity with some of the unique challenges and issues that re-stimulation work presents. The GRI research stated that about 85% of all gas well re-stimulation activity is conducted in the Rockies, Mid-Continent and South Texas. This implies that this activity is primarily focused in hard rock environments and lower permeability reservoirs. They also stated that about 90% of the re-stimulation decisions were made without the benefit of reservoir analysis, but instead based upon production information alone. The GRI also was able to establish that there was a general negative attitude toward re-stimulation work in the industry. This paper discusses a re-stimulation case history. This particular project was chosen to facilitate the presentation of a systemic approach to re-stimulation projects by way of field example. In the case history well presented, an initial fracturing treatment had been conducted in 1995, and a subsequent treatment had been pumped in 1999. Both jobs screened out and production response was much less than expected. Following an evaluation of well data, a third treatment was successfully pumped in 2002. Evaluation, design, and implementation techniques were employed that should be applicable for many re-stimulation candidates in hard rock areas. Re-stimulation considerations Re-stimulation projects include three discrete steps. The initial step is to indentify candidates by analyzing in detail the fracture treatment and the resultant production performance. If production improvement is possible, the re-stimulation must be designed to remove the specific problems created by the initial treatment. Finally, on-site engineering is required to ensure appropriate fluid rheology design and to make any necessary real-time modifications to effectively implement the treatment.

This paper presents the basic methodology for real-time evaluation and execution of hydraulic fracture treatments and attempts to address some of the current perspectives about the subject. It is important to realize that only a small part of real-time hydraulic fracturing is model specific. The brunt of this technology is encompassed in the techniques used to optimize the diagnostics and actual execution of the fracture treatment. A precise methodology for performing real-time evaluation and execution of hydraulic fracture treatments is discussed. Recommendations are provided to specifically tailor the design of the pre-treatment diagnostic injections to the wellbore geometry, reservoir, and fracturing characteristics. From these diagnostic injections stages, critical fracturing mechanisms such as perforation friction, near-well bore tortuosity, leakoff, fracture geometry, multiple fracturing, closure stress, pipe friction, etc. can be determined. The important consideration is that the engineer be trained to take a methodical approach to ensure the diagnostics acquire the desired information. Too often today, diagnostic injections are executed without any consideration for wellbore or formation characteristics and are consequently, in many cases, ineffective. Once these diagnostic injections are evaluated, the treatment is re-designed based upon the actual fracturing character of the formation. It is virtually impossible to predict how a reservoir will hydraulically fracture without first pumping into the interval. Real-time evaluation and execution reaches the pinnacle of technological use during the actual pumping of the fracture treatment. A variety of modern techniques exist to continue the characterization of the fluid and fracture to minimize risk of premature screenouts and optimize the proppant distribution within the fracture. Introduction Real-time hydraulic fracturing was first introduced in 1986 and has been successfully established through many successful case histories. In general, real-time evaluation and execution involves the collection and interpretation of hydraulic fracture treatment data while the treatment is in progress. Through a series of pre-treatment diagnostic injections and co-treatment execution techniques, the fracturing character of the rock is diagnosed and subsequently addressed allowing the treatment to be optimized. The overall approach is interactive, with the engineer determining the diagnostic design, data analysis technique, fracture model and evaluation criteria. Since the beginning of this modem technological evolution, many technical papers have specifically discussed various real-time data acquisition and analysis methods. New methods for determining fracture closure pressure in both the pay interval and adjacent layers have been developed. Several papers have been presented for characterizing the near-wellbore fracture geometry components and addressing them during the fracture treatment. History matching of the actual pressure response allows tangible determination of the fracture geometry and leakoff response so the treatment can be re-designed quickly based on the actual fracturing character of the rock. Recently, the recognition of multiple far-field fracture propagation has resulted in the development of predictive models and methods for remediating and addressing these complex fracture geometries. Aside from the actual mechanistic aspects previously mentioned, probably the most fascinating part of real-time execution is the integration of all data that allows every variable, either raw or calculated, to be tracked, in real-time, without processing delay. The fracture treatment response can be represented on any graph type, scale and/or with any variable. This allows a level of scrutiny of what is occurring during a job that has never before been available. The "catch 22" is that specific training, expertise and experience are necessary to achieve full benefit using this modern technology because of the fast moving process that occurs during the execution of any fracture treatment. The fracture entry character of a fluid type or proppant concentration can be observed with high resolution graphics early in the treatment, providing information on how the rock is fracturing. Associated improvements can be made to remediate pre-mature screenouts and optimize proppant distribution. P. 117^