The Haynesville-Bossier (HB) Shale is an extensive gas resource that has received significant publicity over the past two years, and is currently being developed by numerous operators. Since the HB is a relatively new play, it is anticipated that there will be many learnings in the future that will further improve well completions. However, the more quickly datasharing and adoption of best practices occurs, the more effectively this tremendous resource will be developed. This paper will describe some of the reservoir and completion concerns that have driven this operator's current completion philosophy, particularly as they affect well stimulation. Some of the topics described in the paper include:• Consideration of vertical and horizontal wellbores • Horizontal lateral placement within the vertical pay section • Orientation of wellbores with respect to anticipated fracture azimuth • Fracture stage isolation considerations • Perforation strategy • Design and implementation of hydraulic fracture treatments • Considerations to accommodate elevated temperatures and stresses in the frac design • Management of closure stresses on proppant Hydraulic fractures are the key to unlock the potential of most low permeability shale reservoirs such as the Haynesville Shale, and many drilling and completion decisions must be made to ensure successful placement of the stimulation treatment. Although the approach used on initial wells is expected to evolve with future experimentation and optimization, it is hoped that this early discussion of current design philosophy will be useful to the SPE audience, and allow the industry to optimize their Haynesville completions in a timelier manner.
In an unconventional reservoir, the success of a project is driven by the completion. Unconventional plays have become the primary area of development in the US, and shale formations dominate the current rig activity. Most shale wells are drilled utilizing long horizontal wellbores, and completed using cemented or uncemented casing strings. To be economic, they require large hydraulic fracture treatments in multiple stages along the lateral. Total well costs are driven by the cost of fracturing, often representing as much as 60% of the total well cost. This requires the operator to select the best completion method which includes casing and wellhead selection that is based on stimulation needs. The stimulation is regulated by injection rates, treating pressures, the volume of the stimulation, type of fluid, proppant selection, perforations, and the number of stages. This paper focuses on several areas that are critical in a successful completion such as: casing size and pressure rating, wellhead selection, treatment design, spacing of the perforations and stages, linear verses cross-linked fluid, and the impact of proppant selection. With over 1800 wells completed and stimulated so far, a comparison of successful treatments and the cause of unsuccessful treatments will be provided. A review of actual field applications will be presented where possible, and a method for identifying best completion practices will be discussed. Those working in or considering developments in unconventional plays around the world will be able to compare their current completion techniques to those presented in the paper. In addition, while no two resource plays are the same, the findings in this paper can be used by engineers as a guide for moving up the learning curve more quickly in other unconventional plays.
The success of the Barnett Shale has many operators in search of similar producing formations. One such formation is the Woodford Shale which stretches from Kansas to west Texas. The Woodford is an ultra-low permeability reservoir that must be effectively fracture stimulated in order to obtain commerical production. Once a formation that was drilled through on the way to deeper horizons, this shale play now dominates drilling activity in southeast Oklahoma. Like the Barnett, initial testing of the Woodford Shale was from existing vertical wells that penetrated deeper horizons. Currently, the main exploitation of the Woodford Shale is from long horizontal wells with some lateral lengths exceeding 4000 ft. The wells are stimulated in stages with large hydraulic fracture treatments. Successful shale plays have demonstrated that production is directly related to the size of the stimulated reservoir volume. Techniques to optimize hydraulic fracturing effectiveness have been evolving in the area the last few years. Over 100 frac stages have been mapped in the Woodford Shale using surface tiltmeters, offset-well microseismic and treatment-well microseismic mapping techniques. This paper will examine the effect of lateral azimuth, formation dip and its influence on asymmetric fracture growth; the effect of existing faults and its interaction with the fracture stimulation. Additionally, stimulation size, number of stages, perforation clusters and fracture initiation problems will be discussed. Finally, a comparison to Barnett Shale type fracture networks will be made. Understanding fracture growth in the Woodford Shale willl enhance the development of the play by helping operators optimize fracture completion and well placement strategies. Overview of the Woodford Shale The Woodford Shale is of Devonian age and extends from southern Kansas, through Oklahoma and into west Texas. It is found within the black shale belt as show in Figure 1. It is easily identified by a very high gamma ray streak and is 50–300 ft thick as shown in Figure 2. Completions have been made from depths of 900 ft in northeast Oklahoma to 13,000 ft in west Texas. A typical core contains: 35–50% quartz, 0–20% calcite/dolomite, 0–20% pyrite, and 10–50% total clay. Porosity ranges from 3–9% and permeability ranges from 0.000001 md to 0.001 md. Water saturation varies from 30% to 45%. The formation is slight underpressured with pressure gradients in the 0.35 to 0.44 psi/ft range. The Woodford Shale was first produce in 1939 in southeast Oklahoma. Drilling activity that targeted the Woodford Shale as the primary objective was slow to grow. By late 2004 there were only 22 Woodford shale completions. By the end of 2006 there were 143 Woodford Shale completions.[1,2] Through mid year 2007, there had been an additional 176 wells drilled with an estimated total of 350 wells for the year (see Figure 3).
Effective hydraulic fracturing has become a critical component in the successful development of most unconventional gas reservoirs, including the massive Haynesville Shale. The rig count in the Haynesville currently exceeds 130 active units and is expected to continue to climb. Many hundred horizontal wells have been drilled and completed, and several thousand stages have been hydraulically fractured. With this large and sometimes diverse cross section of wells, best practices have begun to emerge for various aspects of the stimulation design. This paper focuses on several areas of the completion and hydraulic fracture design in the Haynesville Shale that are identified as critical to the success of this play, including: The impact of lateral length, number of fracture stages and perf clusters The impact of effective fracture length The impact of fracture conductivity This paper will review production data from 56 wells completed in close proximity by a single operator to evaluate the impact of fracture design on initial production rates and sustained productivity after six and twelve months. These findings will be compared to reservoir simulator predictions, pressure transient testing, and production data analysis interpretations to evaluate the mechanisms constraining well production. Readers of this paper who are currently working in the Haynesville will be able to compare their current completion techniques to those presented in the paper. The authors hope this paper will promote a continued dialog on best completion practices among operators in this massive shale play. The findings in this paper may also be used by engineers as a guide for moving up the learning curve in other unconventional plays.
Summary. Oryx Energy Co. used three basic completion techniques and various combinations of them to complete 20 horizontal wells in the Pearsall Austin Chalk. The completion method selected is based on a Pearsall Austin Chalk. The completion method selected is based on a general set of guidelines. Additionally, equipment selection and various type of workover operations are reviewed. Introduction The Pearsall field is located in south Texas, about 80 miles south-west of San Antonio (Fig.1). Field development of the Austin Chalk begin in the early 1930's. Several drilling "booms" have occurred during the past 60 years. The well count in the Austin Chalk was approaching 2,000 wells by 1982, but at that time, interest in drilling declined sharply. Until 1985, the Pearsall field was developed with vertical characterized by high initial production rates (200+ BOPD), variable PI's (PI=0.5 to 2.0 BPD/psi), steep initial declines (70% to 80% for PI's (PI=0.5 to 2.0 BPD/psi), steep initial declines (70% to 80% for the first year), and low cumulative production (34,000 bbl oil). To continue exploiting the Austin Chalk, all negative vertical-well characteristics had to be eliminated, especially in light of the low oil prices in late 1985, when the additional development of the Austin Chalk began. Horizontal drilling technology was used to address the production problems of a vertical well. Careful consideration for the drilling and completion of horizontal wells has led to the successful redevelopment of the Austin Chalk. Austin Chalk Geology The Austin Chalk formation is a white-to-gray Upper Cretaceous Age limestone with intermixed shale layers. The matrix permeability and porosity are generally low, between 0.01 and 0.25 porosity are generally low, between 0.01 and 0.25 and less than 5%, respectively. The entire Austin Chalk interval is about 500 ft thick in the Pearsall area. The production is associated primarily with small tensional fractures that resulted from downwarping, or subsidence, of the U.S. gulf coast geosyncline during late Cretaceous and early Teriary time,**Available oriented-corer information indicated that the fracture orientation is approximately northeast-southwest. Early Wells. Innovative techniques were required to offset the unpredictable results of vertical wells. Recent work on horizontal well successes influenced efforts to use horizontal drilling techniques in the Austin Chalk. A horizontal well addresses many of the problems associated with vertical wells. A vertical well has to encounter a prolific vertical fracture system to develop commercial reserves. A horizontal well, drilled obliquely to the naturally occurring vertical fractures, has a higher probability of intersecting one of more of these fracture systems. Encountering multiple productive fracture systems with a horizontal well should increase the PI, minimize the problems of the steep initial decline rate, and enhance the estimated ultimate recovery. The primary goals of the first wells were to prove the horizontal wells could be drilled and completed in the Austin Chalk and to show that these wells could have a significant potential for increasing recoverable reserves. The directional technology used for years in offshore drilling operations was extended to drilling the Austin Chalk horizontally. As an alternative, recent developments of slim-hole directional-drilling equipment made re-entry of small-diameter casing possible. The technical issues of each drilling alternative are not discussed in this paper. A newly drilled horizontal well would created the problem of distinguishing between incremental horizontal-well reserves and vertical-well reserves. A depleted vertical well was selected for re-entry because incremental reserves would be attributed to the horizontal well. Selecting the proper candidate for the first horizontal re-entry well was critical. The primary selection criteria were a large casing (5 1/2 in. minimum), high cumulative production, adequate initial stimulation, and a well production rate at an economic limit. Only a small percentage of the Pearsall Austin Chalk wells were completed with 5 1/2 -in. or larger casing. The available directional tools dictated that 5 1/2 in - was the minimum casing size. Average well cumulative production in the Pearsall area was 34,000 bbl of oil. All the vertical wells were fracture stimulated in stages at rates of 20 to 60 bbl/min with 200,000 to 350,000 Ibm of sand on initial completion. Because a well producing at its economic limit has re-covered all its reserves, any additional production would be directly attributed to the horizontal section. Table 1 summarizes the wells available at the onset of the project that had penetrated the Austin Chalk. Based on low cumulative project that had penetrated the Austin Chalk. Based on low cumulative production, Wells B, D, and F were not considered as initial production, Wells B, D, and F were not considered as initial candidates. Well C was still producing in excess of its economic limit and was not considered as an initial candidate because of its remaining reserves. This left two wells for the initial project phase. Well A was selected first because of its cumulative production, which was nearly four times the Pearsall field average. Well A was drilled with short-radius (curve build rate of 2 degs to 3 degs/ft) equipment with a final Austin Chalk exposure of 153 ft. Following a successful stimulation treatment, oil production increased 25-fold. Well E, the second re-entry test, was also drilled with short-radius equipment and had a final reservoir exposure of 270 ft. Oil production increased nine-fold after a stimulation treatment. The production increased nine-fold after a stimulation treatment. The production results of these two wells were encouraging; however, production results of these two wells were encouraging; however, problems encountered during drilling resulted in the actual reservoir problems encountered during drilling resulted in the actual reservoir exposure in either well being less than the 750-ft planned lateral lengths were limited because the wells could not be kept unloaded. The additional fluid head that existed from this condition exceeded the pressure rating of the bottomhole assembly. The availability of medium-radius (curve build rate of 8 degs to 20 deg/100 ft) steerable tools made it possible to drill a longer-reach lateral from an existing well. Well C, which was used for this third lateral, reached the planned exposure of 950 ft and had a production increase of 15-fold without stimulation. This increase could have been higher, but field rules prevented higher producing rates. The success of these three wells was the driving influence for the continuation of the program. The types of completion used for these three wells were varied and were based on the conditions of the well drilled. Completion Types Three basic techniques were used to complete the first 20 horizontal wells, including the three wells discussed above. The three basic methods are openhole (Fig. 2), slotted liner (Fig. 3), and cased hole (Fig. 4). Table 2 summarizes these completions with data on the well type (re-entry or new), completion type, and Austin Chalk exposure. Openhole Completions. Of the first 20 completions, 14 used the openhole method. SPEPE P. 144
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