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).
This paper presents a case history where the entire lateral of a producing well was restimulated in a single trip using a novel cost-effective intervention tool designed to provide discrete stage isolation. Lessons learned and job details are discussed and compared with other restimulation methods used in the area. The new method is based on a novel straddle packer system that uses two mechanically-activated sealing elements—as opposed to conventional sealing cups—to overcome wear and bottomhole pressure limitations found in traditional straddle systems. The novel stage isolation system enables higher flow rates and pressure differentials as well as a larger number of stages, therefore reducing the amount of trips in the well required to complete typical refracturing operations. A comparison will be made to conventional refracturing methods based on intervention tools. As a bonus, pressure data gathered during the treatment indicating limited coverage of the primary fracturing job will be discussed. The case study provides the framework to describe how the novel technology enables multiple treatments in a single trip in the horizontal well, therefore reducing the operational time, resources, and cost required to complete a restimulation job. The paper will show how the use of the novel technology reduced operational time by 30% compared to other methods, and enabled the operator to treat a horizontal well with full mechanical isolation in a manner not previously available. In addition, the paper will discuss pressure data gathered during the deployment that suggests limited cluster efficiency on the primary fracturing operation. The results of the paper are relevant because they provide a new cost-effective alternative to conventional restimulation systems that was not available in the past due to inherent technology limitations of existing straddle packer systems. This is important because: (1) the technology described in the paper overcomes these limitations for both vertical and horizontal wells, (2) more refracturing operations are executed by blindly pumping treatments from surface into a full lateral with open perforations without an effective way to mechanically isolate target zones, and (3) the technology may shed additional light on the discussion of cluster efficiency during primary stimulation operations.
The La Cira Infantas field is located in the Middle Magdalena basin in the Santander region of central Colombia. This oil-producing development is under secondary waterflood using five-spot and inverted seven-spot patterns. The reservoir has high vertical and horizontal heterogeneity, and there was concern about effectively draining the reservoir. A new hydraulic fracturing design was deployed for the first time in Colombia (and South America) to improve drainage and surveillance. With over 1200 producers and 500 injectors, the La Cira Infantas waterflood is well established. Waterflood surveillance indicated less-than-optimal recovery due to near-wellbore skin in the injectors and suspected poor height coverage. A novel proppant technology was incorporated into the fracture design allowing for consolidation of the proppant pack in the fracture with low bottomhole temperature and minimal stress on proppant, enabling long-term undamaged injectivity. This technology also incorporates an inert tracer into the proppant grains, which provides propped height determination after the treatment using a neutron log. This multi-faceted proppant technology was successfully deployed on one well, and additional wells are planned in 2020. This paper will first review the background of the field development including current completion techniques, along with the challenges being faced with the waterflood recovery. It will review the self-consolidating proppant technology and show the benefits of its use in this application to promote high-conductivity fractures and minimize damage to injectivity. The companion tracer technology will be presented along with plans to perform neutron logging and identify propped fracture height. This information can be fed into fracture propagation models to determine the fracture geometry, which is then used for reservoir and waterflood surveillance analysis. The technique allows for meeting the goal to improve injectivity into both high-skin and low-permeability reservoirs. Although this proppant technology has been used in other frac pack applications, this is one of the first case histories of the technology being used on land for improving injectivity and waterflood coverage in Colombia. This paper will be useful for reservoir and completion engineers working on waterflood fields that contain vertically and horizontally heterogeneous formations, and wish to maintain undamaged injectivity, improve waterflood sweep efficiency, and monitor the proppant pack over time.
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