Hydraulic fracturing continues to be the primary mechanism to produce hydrocarbons out of the tight shale reservoirs. Ever since the success of Barnett shale program, operators are inclined to pump similar large volume water fracture treatments with little or no proppants in their respective shale plays. This assumes that all shale plays are the same and react accordingly to large volume treatments. The basic objective behind such treatments is to contact large surface area, which has been very successful in the Barnett shale play. Such large volume treatments in other shale plays may not be an optimized solution for the specific shale attributes and the response may lead to uneconomical production results. Some shales based on their reservoir characteristics might require a conductivity type fracture treatment. So, it is important to understand the characteristics of these shales before deciding the stimulation treatments. In addition to core and log analysis of these shales, fluid sensitivity tests, Brinell hardness tests, unpropped fracture conductivity tests and more importantly a Diagnostic Fracture Injection Test (DFIT) can help define the guidelines for choosing between a surface area and a conductivity type fracture treatment.Integrating the various data sources is important in arriving at these guidelines. The main objective of this paper is to provide these guidelines along with examples such that the costly trial and error approach for stimulating shales can avoided. Examples from both oil and gas shales namely, the Gothic, Haynesville, Eagle

The early stages of a coalbed methane (CBM) project development often require more extensive use of currently available technologies than can be economically justified when approached from a conventional oil and gas drilling focus. As a result, key evaluation tools and technologies are either omitted or not considered before significant decisions are made regarding viability of a CBM play. Understanding that the various lifecycle phases will each affect different objectives and decision points is important. Following site acquisition and estimating basic drilling costs, at least five lifecycle phases can be identified: (1) Regional Resource Reconnaissance, (2) Local Asset Evaluation, (3) Early Development, (4) Mature Development; and (5) Declining Production.A systematic review of current and recently developed enabling technologies is presented in the context of their potential use and applicability. Environmental risk and other constraints that can impact development vary globally, as do economics and production forecasting. New and emerging chemical technologies, as well as hydraulic fracturing refinements, play key roles in various lifecycle phases and decision making to identify successful CBM development projects as early as possible. The paper presents strategies that can reduce development phase failure risk and help predict or rank production potential. Economic constraints usually become more restrictive as the lifecycle moves to Phase 4 and beyond, but key information needed to enter Phase 4 is often overlooked. Examples of this scenario are presented from a global perspective.Globally, new and existing technologies combined with dynamic gas and electricity markets are changing the nature of CBM development opportunities. More accurate and timely go/no-go information needs to be used in the decision making process. Converting development opportunities to development successes involves integrating planning and evaluation methods, using targeted development technologies in the proper phase, and managing risk. TX 75083-3836, U.S.A., fax 01-972-952-9435.

Improvements in stimulation technology have continued to increase our ability to economically extract hydrocarbons from very low permeability reservoirs. The Jonah field, in Southwest Wyoming is a classic example of a reservoir that was commercialized with newer stimulation technology. The Lance formation in the Jonah field consists of several hundred feet of stacked lenticular sands with reservoir permeability to gas less than 10 µD. Completion techniques have evolved over the years employing a variety of hydraulic fracturing techniques. In the past 2 years three techniques have emerged as the predominant completion methods: traditional nitrogen assist, induced stress diversion, and the use of flow thorough composite bridge plugs. This study evaluates the different techniques using spatial sampling to compare each well to its offsets and identify the completion scheme that yields the best results on cumulative production. From this study a clear best practice for completing wells in the Jonah field to maximize production was determined. Introduction Jonah field is located in the northwestern corner of the Green River foreland basin (T28 - 29N, R108W) (Fig. 1) between the Wyoming Thrust Belt to the west and the Wind River Mountains to the east. The field is 60 miles north of Rock Springs, Wyoming. By the end of 2000 over 200 commercial wells have been drilled on 40-acre spacing. The eastern (downdip) edge of the field is still being extended. The known limits of the field currently exceed 38 square miles. Jonah field is bounded on the south and northwest by two wrench faults. Faults within the field boundaries add to the complexity of the reservoirs. Wells within the field encounter overpressured gas at 8,100 to 9,300 ft (0.58 to 0.65 psi/ft gradient) whereas nearby wells drilled across the bounding faults find normal pressure gradients at similar depths. The Lance formation is Upper Cretaceous in age and consists of 2,000 to 3,000 ft of interbedded fluvial sands, mudstones, and coals. Individual sandstone units range from 5 ft to over 50 ft in thickness and have areal extents ranging from a few acres to 100 acres. Individual sands are geologically heterogeneous reservoirs because of their depositional shapes, but certain stratigraphic intervals consistently have sands developed. Sand-rich intervals are locally called the Upper Lance, Middle Lance, Jonah, Yellow Point, Wardell, and Upper Mesaverde (or Rock Springs). Total net sand in the field ranges from 300 to 600 ft of stacked net pay. Drilling depth ranges from 11,000 to 12,500 ft depending on how many sand packages an operator believes to be economical to develop. More specific geological descriptions can be found in references.1,2 Sand porosity ranges from 5 to 14% with relative gas permeability ranging from 0.001 to 0.02 md. Water saturation varies between 30 to 60%; currently there is no significant water production in the field. The producing condensate yield is between 8 to 10 bbl/mmscf with an API gravity of 52°. PVT fluid data are scarce, although the fluid composition appears to be very similar throughout the entire productive section. Due to the low permeability of the Lance formation in this area stimulation is required for economical production rates. Although all operators use hydraulic fracturing for stimulation there are a variety of different treatment types, fracture isolation methods, and time between treatments.3,4 Until 1998 the typical treatment consisted of treating three to six individual sands per fracture treatment with the limited entry technique. A total of four to six fracture treatments were performed per well. After a fracture treatment the well was flowed back for 1 week or longer to clean up. Several methods were used to isolate each fracture treatment including pumping a sand plug to cover previous stages to running wireline set tubing retrieve bridge plugs.

The Lance formation in the Jonah field is an over pressured, tight-gas sand that requires hydraulic fracturing for economic production. Because of large gross intervals containing several individual sands, limited entry has been the typical fracturing technique. Wells can have more than 30 individual sands that are completed with multiple fracture treatments; however, production log data indicate that only 58% of the perforated sands contribute to production. Production optimization is dependent on improving the percentage of completed pay contributing to production. A detailed field study was conducted to determine pay identification and best practices for completions. In the study, 44 wells in the Stud Horse Butte area were analyzed. The study comprised detailed log analysis, fracture treatment data, production data, reservoir analysis, and completion practices. Some of the processes used were log normalization, traditional statistical analysis, and reservoir modeling. Log and treatment data were also analyzed with an artificial neural network (ANN). Introduction Discovered in 1975, Jonah field is located in the Hoback sub-basin in the far northwest corner of the Green River foreland basin (T28 - 29N, R108W) (Fig. 1). The Hoback Basin lies between the Wyoming Thrust Belt to the west and the Wind River Mountains to the east. The field is 60 miles north of Rock Springs, WY. By mid-1999, more than 100 commercial wells had been drilled on 80-acre spacing. Field boundaries to the north, south, and west have been well defined. The eastern (downdip) edge of the field is still being extended. The known limits of the field exceed 33 square miles. Jonah Field is bounded on the south and northwest by two wrench faults. Faults within the field boundaries add to the complexity of the reservoirs. Wells within the field encounter overpressured gas at 8,100 to 9,300 ft (0.58 to 0.65 psi/ft gradient), whereas nearby wells drilled across the bounding faults find normal pressure gradients at similar depths. The Lance formation is from the Upper Cretaceous age and consists of 2,000 to 3,000 ft of interbedded fluvial sands, mudstones, and coals. A log section of the Lance is shown in Fig. 2. Individual sandstone units range from 5 ft to more than 50 ft in thickness, and have areal extents ranging from a few acres to 100 acres. Individual sands are geologically heterogeneous reservoirs because of their depositional shapes, but certain stratigraphic intervals consistently have sands developed. Sand-rich intervals are locally called the Upper Lance, Middle Lance, Jonah, Yellow Point, Wardell, and Upper Mesaverde (or Rock Springs). Total net sand in the field ranges from 300 to 600 ft of stacked net pay. Drilling depths range from 11,000 to 12,500 ft, depending on the number of sand packages an operator believes to be economically feasible to develop. More specific geological descriptions can be found in references.1,2 Sand porosity ranges from 5 to 14%, with relative gas permeability ranging from 0.001 to 0.02 md. Water saturation varies from 30 to 60%. Currently, there is no significant water production in the field. The producing condensate yield is between 8 and 10 bbl/MMscf, with an API gravity of 52°. Pressure-volume-temperature (PVT) fluid data are scarce, although it appears that the fluid composition is similar throughout the entire productive section.

Summary Improvements in completion technology have continued to increase the industry's ability to economically extract hydrocarbons from very low permeability reservoirs. The Jonah field in southwest Wyoming is a classic example of a reservoir commercialized with newer completion technology. The Lance formation in the Jonah field consists of several hundred feet of stacked lenticular sands with a reservoir permeability to gas of less than 10 mu darcy, requiring hydraulic fracturing to be economic. Completion techniques have evolved over the years. In the past 4 years, two techniques have emerged as the predominant completion methods - induced stress diversion and flow-through composite fracture plugs. This study evaluates these different techniques with spatial sampling to compare each well to its offset wells and to identify the completion scheme that yields the best results on cumulative production. From this study, a clear best practice for completing wells in the Jonah field to maximize production was determined. Introduction Jonah field is located in the northwestern corner of the Green River foreland basin (see Fig. 1), between the Wyoming Thrust Belt to the west and the Wind River Mountains to the east. The field is 60 miles north of Rock Springs, Wyoming. By the end of 2000, more than 200 commercial wells had been drilled on 40-acre spacing. The northeastern (downdip) edge of the field is still being extended. The known limits of the field currently exceed 38 square miles. The Jonah field is bounded on the south and northwest by two wrench faults. Faults within the field boundaries add to the complexity of the reservoirs. Wells within the field encounter overpressured gas at 8,100 to 9,300 ft (0.58 to 0.65 psi/ft gradient), whereas nearby wells drilled across the bounding faults find normal pressure gradients at similar depths. The Lance formation is Upper Cretaceous in age and consists of 2,000 to 3,000 ft of interbedded fluvial sands, mudstones, and coals. Individual sandstone units range from 5 to more than 50 ft in thickness and have areal extents ranging up to 100 acres. Individual sands are geologically heterogeneous reservoirs because of their depositional shapes, but certain stratigraphic intervals consistently have sands develop. Sand-rich intervals are locally called the Upper Lance, Middle Lance, Jonah, Yellow Point, Wardell, and Upper Mesaverde (or Rock Springs). Total net sand in the field ranges from 300 to 600 ft of stacked net pay. Drilling depths range from 11,000 to 12,500 ft depending on how many sand packages an operator believes to be economical to develop. More specific geological descriptions can be found in Refs. 1 and 2. The sand porosity ranges from 5 to 14% with relative gas permeability ranging from 0.001 to 0.02 md. Water saturation varies between 30 to 60%; currently, there is no significant water production in the field. The producing condensate yield is 8 to 10 bbl/MMscf with an API gravity of 52°. Pressure/volume/ temperature (PVT) fluid data are scarce, although the fluid composition appears to be very similar throughout the entire productive section. Because of the low permeability of the Lance formation in this area, stimulation is required for economical production rates. Although all operators use hydraulic fracturing for stimulation, there are a variety of different treatment types, fracture isolation methods, and times between treatments.3,4 Until 1998, the typical treatment consisted of treating three to six individual sands per fracture treatment with the limited-entry technique. A total of four to six fracture treatments were performed per well. After a fracture treatment, the well was flowed back for 1 week or longer to clean up. Several methods were used to isolate each fracture treatment, including pumping a sand plug to cover previous stages and running wireline-set tubing-retrievable bridge plugs. An integrated field study completed in 1998 showed that a common factor to all the operators was 60 to 65% completion efficiency.5 The study presented that the main cause of the low completion efficiency was damage to the hydraulic fractures as a result of methods used to isolate previous treatments in the wellbore. Since 1998, induced stress diversion became a common completion technique for some operators in the field, while other operators now use flow-through composite fracture plugs for fracture isolation. In both cases, the number of individual sands treated per fracture treatment has been reduced, resulting in more treatments per well. This study evaluates these new completion techniques as well as previous methods. Completion Types Traditional Completions. These include the use of sand plugs and wireline-set/tubing-retrievable bridge plugs. Sand plugs, which were the most common method in the early development of this field, are rarely used now. The most common early completion method used was wireline-set/tubing-retrievable bridge plugs. This technique was used with 30% nitrogen assist and 70% nitrogen foam fracturing treatments along with several non-nitrogen fracturing treatments. Induced Stress Diversion (ISD). This is a completion technique described by Hewett and Spence6 as an alternative to limited entry fracturing. ISD depends on two factors - stress increases with depth and closure stress increases when the fracture closes on proppant.7 To further assist in stress diversion, attempts are made to nearly "screen out" during the treatment by pumping higher proppant concentrations at the end of the treatment. This is done in an attempt to overcome high breakdown and treating pressures uphole. Because of the number of stages being pumped, it is also necessary to use some mechanical isolation. Because ISD requires increased stress from previous fracture treatments, it is a continuous process. One advantage to this method is substantially reducing completion time (2 to 3 days vs. 4 to 5 weeks), which results in significant savings in surface-equipment rentals and reduction in fracture-equipment charges. It is important to note that most of these savings can be realized if the well is completed in continuous stages even with the use of mechanical isolation between stages. Flow-Through Composite Fracture Plug (FTCFP). This is a new item in the composite downhole tools category. Use of FTCFP to isolate hydraulic fracturing treatments has resulted in improved production rates and increased estimated ultimate recoveries in several areas.8