The Bakken formation in the Williston Basin of Montana has undergone rejuvenation thanks to the success of horizontal drilling and completions. Over the last several years there has been an evolution in the drilling and completion methodology, which has resulted in significant improvements in well productivity. Although the horizontal wells will produce at economic rates without stimulation, hydraulic fracturing increases well productivity significantly. For the program discussed in this paper, the wells are drilled for longitudinal fracture orientation. The original wellbores had cemented liners and employed the limited-entry technique to distribute the fracture treatment. This program now uses noncemented liners and a modified fracture treatment with diverter stages. This paper presents a review of the approach taken to evaluate the most effective way to complete and hydraulically fracture these laterals. It documents the evolution of the hydraulic fracture design and wellbore configurations. It also presents results showing the improvements in proppant distribution along the wellbore caused by changes in fracture treatment design and its impact on well productivity. Introduction The Sleeping Giant project is a stratigraphic middle Bakken play located in Richland County, MT (Fig. 1), covering approximately 400 square miles. It is bounded by a facies change and loss of porosity to the northeast and pinch-out to the southwest. During the late 1980s, there was a marginally successful horizontal play in the Bakken formation to the east of Richland County. The Bakken is present in only the subsurface of the Williston Basin. It is comprised of three distinct intervals, each of which are near termination in the project area. Fig. 2 shows a type log through the Bakken section. The three intervals are described as: The Mississippian - Upper Bakken Shale (Highstand) This "hot" gamma ray zone serves as the contact of the Bakken with the overlying Mississippian - Lodgepole. It is comprised of a black, organic-rich, pyritic shale with measured total organic content (TOC) up to 40%. It is between 8 ft and 12 ft thick in the project area, and serves as a good overlying seal. It is well within the mature oil envelope in the Sleeping Giant Project area, and is the primary source of hydrocarbons for the Middle Bakken and several other shallower reservoirs. The Devonian/Mississippian - Middle Bakken (Lowstand) This interval contains the main reservoir facies, composed of burrowed, silty and sandy dolomite with fair to good (8% to 15% density) porosity and heavy oil staining. This primary interval is up to 15 ft thick and laterally homogeneous. Fossils include brachiopods, pelmatozoan fragments, gastropods and trace fossils. Above and below this interval are the transgressive and regressive sequences, respectively, each becoming increasingly muddy and laminated approaching the bounding shales. The Devonian - Lower Bakken Shale (Highstand) This "hot" gamma ray zone is comprised of a black to brownish-black, fissile, non-calcareous, organic mudstone or shale. It has TOC of up to 21% as measured in area cores. It serves as the basal contact of the Bakken with the underlying Devonian - Three Forks, and is between absent and 6 ft thick in the project area. The organic matter appears to be distributed evenly throughout the member. Quartz is the dominant mineral with minor amounts of muscovite, illite and other clays. Pyrite is present in lenses, laminations, or is finely disseminated throughout. Fossils within the shale member include conodonts, algal spores, brachiopods, fish teeth, bones and scales. In this area the Bakken formation is found at a depth of approximately 10,000 ft. The fracture gradients range from 0.69 to 0.75 psi/ft. Reservoir fluid properties are: oil gravity of 42° API and 0.95 gas gravity with an initial GOR of 500 scf/bbl. The reservoir is slightly overpressured with an initial pore pressure gradient of 0.5 psi/ft and a bottomhole static temperature of 240°F.
The permeability, pore pressure, and leakoff type interpreted from more than 1,200 diagnostic fracture-injection/falloff tests were collected in a database and statistically evaluated for four Rocky Mountain basins. The statistical analysis includes the range of observed permeability and pore pressure and the fracture leakofftype distribution.The analysis reveals that pressure-dependent leakoff, fracturetip extension during shut-in, and fracture-height recession during shut-in are the most common leakoff types. Overall, pressuredependent leakoff, which can be indicative of highly productive fractured reservoirs, is the most common leakoff type in all Rocky Mountain basins. The analysis also shows orders-of-magnitude variation in gas permeability within all basins, with observed gas permeability ranging from less than 0.001 to greater than 0.10 md. G-FunctionDerivative Analysis. G-function derivative analysis is used to identify a leakoff type and provide a definitive indication of fracture-closure stress. The graphical technique, which was proposed by Barree and Mukherjee, 8 requires a graph of bottomhole pressure, the derivative of pressure (dp/dG), and the superposition derivative (Gdp/dG) vs. the G-function.The leakoff type is identified using the characteristic shape of the pressure-derivative and superposition-derivative curves. Fig. 1
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe permeability, pore pressure, and leakoff-type interpreted from more than 1,200 diagnostic fracture-injection/falloff tests were collected in a database and statistically evaluated for four Rocky Mountain basins. The statistical analysis includes the range of observed permeability and pore pressure and the fracture leakoff-type distribution.Specially designed "mini-frac" or diagnostic fractureinjection/falloff tests were routinely implemented throughout Rocky Mountain basins beginning in late 1998 for the sole purpose of estimating reservoir-engineering parameters. Using three recently developed analysis methodologies, more than 1,200 tests have been analyzed to determine permeability, pore pressure, and leakoff type.The analysis reveals that pressure-dependent leakoff, fracture-tip extension during shut-in, and fracture heightrecession during shut-in are the most common leakoff types. Overall, pressure-dependent leakoff, which can be indicative of highly productive fractured reservoirs, is the most common leakoff type in all Rocky Mountain basins. The analysis also shows order-of-magnitude variation in gas permeability within all basins with observed gas permeability ranging from less than 0.001 md to greater than 0.10 md.
Several major developmental programs in the Rocky Mountain region of the United States are in fields where zones of several hundred to several thousand feet of stacked, tight (<0.05 md) lenticular gas sands exist. In order to be productive, these wells require multiple fracture treatments over the pay interval. Since field development has been ongoing, the drilling programs are extending into more marginal production areas. Infill programs are downsizing spacing, and also, successful refracturing programs are being conducted in some fields. Before 1998, traditional methods were being used to isolate fracture treatments. These methods usually required killing the well between fracture treatments or during cleanout operations. Unfortunately, field studies have determined that the traditional isolation methods have negatively impacted well productivity. In view of the costs involved and the lower productivity experienced with the new drilling programs, it became apparent that either well costs had to be reduced or well productivity had to be improved! This paper will discuss the application of flow-thru composite frac plugs (FTCFP) and how they were capable of addressing the current needs to reduce operational costs and improve productivity. These plugs can be used as an alternative to traditional isolation methods, or induced stress diversion. Through June 2002, there have been over 3,200 FTCFPs run in the Rocky Mountain region. The benefits gained from FTCFP usage are derived from the following:Well drill-out costs are reducedPositive isolation is allowedAll zones can be produced during completion. Their use has now become a "best practice" in stacked-pay completions. Introduction Six states make up the Rocky Mountain region in the Western United States (Fig. 1). Hundreds of different formations are productive in this region with the vast majority of these formations being classified as tight gas sands with permeabilities of less than 0.05 md. Some formations may consist of one significant sand or a couple of sands and are economic by themselves, such as the Almond in the Wamsutter area of south west Wyoming. However, as shown in Fig. 2, formations like the Mesaverde, found throughout Colorado, Utah and Wyoming, may consist of 20 to 50 individual sands spread over 1,000 to 5,000 ft of gross interval. This later scenario is the more common in the wells currently being drilled. To economically produce these formations, the majority of these tight gas sands require hydraulic fracturing. For the formations consisting of only one or two sands, the process is straight forward. The sands are perforated, fractured, and then placed on production. For formations consisting of multiple sands and those that cover a long interval, the fracturing process is more complicated, since these formations require multiple fracturing treatments. A significant portion of the current activity in the Rocky Mountain region is in fields that were uneconomic prior to the 1990's. Throughout the 1990's, a variety of different techniques were tried to effectively stimulate multiple-sand formations. The most common technique was to break up a well into several fracture treatments with each treatment consisting of several sands. For each treatment, the sands were perforated using limited-entry perforating1 to help ensure that each sand would be treated. The interval sizes varied throughout this time period from 200- to over 500-ft per fracture treatment. In the Piceance basin, however, it was found that longer gross intervals for each treatment significantly reduced completion coverage.2 This study also showed that as the number of sands per treatment increased, the completion coverage decreased.
SPE Members Abstract In the last several years, limited-entry perforating has been used for hydraulically fracturing the Codell and Niobrara formations in the Denver-Julesburg (DJ) Basin. Limited-entry perforating reduces stimulation costs with no apparent effect on production. Several papers have presented guidelines for designing a limited-entry treatment. A primary concern for treating multiple intervals is to ensure that both zones receive the necessary treatment. Currently, some operators simply ratio the number of perforations in each interval to the volume of treatment required for each interval. To ensure that both zones are being treated, a minimum pressure drop of 700 to 1,000 psi is usually used for limited-entry design. Changes in the perforation discharge coefficient and diameter during the treatment, combined with changes in the net treating pressure, affect the perforation pressure drop calculation. To determine the actual pressure drop across the perforations, designers use a real-time spreadsheet calculation. This paper reviews limited-entry treatments pumped in 34 wells that verify spreadsheet calculations. Changes in the perforation discharge coefficient and diameter will be presented, as well as the effect of proppant concentration and velocity through the perforation. The current spreadsheet calculation used on location to calculate the pressure drop across the perforations is also discussed. Introduction The Niobrara and Codell formations are the two primary production intervals for most of the wells being completed in the DJ Basin. The Niobrara is a micritic limestone consisting of three benches. At a depth of approximately 6,800 ft, the overall interval is generally between 150 and 250 ft thick. The Ft. Hays formation, the lower member of the Niobrara group, separates the Niobrara and Codell. There is a transition at the top of the Codell from a carbonate to a calcareous sandstone to a fine-grained sandstone with a high clay content. At a depth of approximately 7,000 ft, the Codell is typically 8 to 14 ft thick. Both the Codell and Niobrara are overpressured gas reservoirs with a low permeability ranging from 0.01 to 0.1 md. In the past, the Codell and Niobrara intervals were fractured separately. P. 107
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