TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper discusses an improved completions methodology and criteria for perforating/fracturing based on systematic and enhanced geomechanical reservoir characterization.Understanding of the near wellbore stress distribution is critical to implement a sound perforating strategy. Reservoir quality variations, mixed lithologies with plastic behavior and loading/unloading cycles (drilling and production operations) will alter the near wellbore stress distribution reducing the compressive stress of the rock. Thus, constant stress gradients (i.e., 0.1 psi/ft.) are misleading and rock mechanical properties measurements may prove to be of extreme importance.The case-specific examples presented in our work, demonstrate the advantages of using a detailed geomechanical reservoir description and illustrate when the "standard" assumptions and the "one-approach-fits-all" perforating approaches are not applicable. Perforation strategies are suggested to address different and complex issues; multiple fractures, phasing, shot density, vertical coverage, natural fractures, far field stresses alignment, tortuosity and erosion effects. Reservoir performance, net pressure matches and geomechanical data indicate that effective stimulation treatments can be implemented where others have failed or unacceptable production changes occurred.The perforating for fracturing methodology discussed in this paper places the set of perforations where they are needed the most, accounting for stress contrasts and optimization of shot density and phasing. Easy to implement recommendations for strategic placement of perforations and the mechanics for fracture initiation from vertical, deviated and horizontal wellbores are briefly discussed.This approach attempts to achieve effective vertical coverage and proper placement of a hydraulic fracture. As demonstrated by production results, the improved efficiency of the perforating/fracturing strategies minimizes treatment failures and has significant impact on treatment implementation and production enhancement strategies.

Borate-crosslinked fracturing fluids have been used in the oil and gas industry for nearly 40 years. These fluids consist of three basic components (polymer, crosslinker, and pH buffer) which are considered relatively simple to optimize for a variety of field applications. Among the unique features of this fluid is the ability of the crosslink viscosity to "re-heal" or "recover" after exposure to high shear rates. Based on laboratory tests described in SPE 134266, it was determined that the "re-healing" time can be excessive for some borate-crosslinked fluids exposed to high shear, resulting in limited near-wellbore viscosity and screen-outs in the field. Using a laboratory-scale flow loop to simulate the wellbore shear environment, various borate-crosslinked fluids were exposed to a wide range of shear history conditions before loading into a high temperature, high pressure rheometer. In addition to the common viscosity versus time profile, the early-time viscosity development of each fluid was analyzed to quantify the effect of shear history on recovery time. This paper defines critical shear rates and exposure times that adversely impact early-time viscosity development of borate-crosslinked fracturing fluids. Also, the test results show that the impact of wellbore shear conditions on recovery time can be minimized by adjusting the concentration of the polymer, borate crosslinker, and/or pH buffer. The techniques and guidelines provided in this paper can be used to identify detrimental wellbore shear conditions that will lead to excessive recovery times. The paper also demonstrates optimizing borate-crosslinked fluids with common on-site tests can result in fluid compositions with increased shear sensitivity.

Summary Hydraulic-fracturing treatments in shale infill wells are often impacted by existing parent-well depletion and asymmetrical fracture growth. These phenomena can result in excessive load-water production, deposition of proppant and deformation of casing in the parent well, and unbalanced stimulation of infill wells. This study determines the effectiveness of particulate materials (i.e., far-field diverting agents) for mitigating the above negative outcomes by bridging near the extremities of dominant fracture wings. Fracture propagation was modeled to characterize the width profile at fracture extremities in a depleted-stress environment. A slotted-disk device was used to evaluate and optimize particulate blends for bridging slots representative of width near the fracture tip. Rheological tests replicating the downhole environment were used to formulate a system for transporting the diverting materials. Statistical analysis of 511 fracture hits at 30 parent wells was performed on key treatment indicators by the category of diverter type and post-hit parent-well condition. Production trends of the influenced wells were compared to area-specific type curves and offset wells without diverter trials. On the basis of the simulation and testing results, two types of high-graded far-field diverter systems were field-tested in a shale play: dissolvable, extremely fine particulate mixed with a 100-mesh sand, and mixtures of a nominal 325-mesh silica flour and a 100-mesh sand. Proppant dust collected at the fracturing site was also evaluated for replacing commercial silica flour. High-graded blends of the above diverting systems demonstrated superior fracture-hit and productivity metrics as compared to the base case of not applying far-field diverters. The silica flour and 100-mesh-sand mixture performed on a par with the significantly more expensive blend of dissolvable fine particulate and 100-mesh sand. Borate-crosslinked-guar gel was an effective carrying fluid for transporting diverting materials to the fracture extremities. Statistical analysis of fracture-hit events shows that the application of far-field diverters did not reduce the magnitude of pressure buildups during fracture hits; however, it significantly increases the post-hit pressure-falloff rate at the parent wells. On the basis of the area-specific type curves, pumping far-field diverters increased the P50 estimated ultimate recovery (EUR) by approximately 6% compared with the base cases of not applying diverters. For all the wells impacted by far-field diverters, the infill wells saw larger benefits with an increment of P50 EUR by approximately 7% compared with the parent wells.

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Summary This paper covers the development, laboratory testing, and field testing of acid-soluble-plug (ASP) technology as a viable completion alternative to wireline- or tubing-conveyed perforating. The ASPs are installed in a preperforated reservoir liner and dissolve when soaked in acid, allowing access to the reservoir. This allows the technology to be easily applied in reservoirs in which matrix acid jobs or acid-fracturing techniques are used. The ASP technology was developed to reduce risk and cost associated with wireline- and tubing-conveyed perforating. ASPs were designed, manufactured, and field tested in both 5-in. and 7.625-in. reservoir liner sizes for wells in the Ekofisk field. The combination of laboratory testing and large-scale field testing influenced the design of the ASPs as well as the additives used in the acid systems used to dissolve them. From concept to initial field implementation, the process of ASP-engineering development took more than 2 years. The concept was in the beginning field-tested in deviated injectors, with ASPs installed in the deepest section of the reservoir liner. The field tests proved the ASP concept before depending on the technology in a horizontal producer with an uncemented, tubing-in-liner completion solution. The field tests showed that acid soaking dissolved the ASPs in the downhole environment and allowed efficient acid stimulation of the reservoir. It also reduced the number of wireline runs necessary to complete the well. When field tested in a tubing-in-liner completion application, installation of the ASPs in the reservoir liner eliminated tubing-conveyed-perforating runs. The reservoir liner was uncemented with mechanical openhole packers for zonal isolation. The ASPs provided a pressure-tight reservoir liner to set the packers against and eliminated fluid loss during the running of the inner completion string. Optimization of this technology is an ongoing process. The plug design itself continues to evolve as well as the operational steps to minimize the soaking time necessary to dissolve the plugs and to gain access to the reservoir.