A Novel Approach to Identifying Refracturing Candidates and Executing Refracture Treatments in Multiple Zone Reservoirs

Abstract

Abstract Refracture candidate selection and treatment execution has always presented four main challenges to the industry when multiple pay zones are involved. The first challenge is determining the underlying cause of the poor production performance (poor reservoir quality, an ineffective original stimulation treatment, or both). The second challenge is the identification of the specific zones with significant remaining reserves that have been poorly stimulated. The third challenge is determining the current reservoir pressure in all of the prospective refracture candidate zones. The fourth major challenge is selectively stimulating the target zones in the wellbore when there are existing perforations above the target zones. The first and second challenges are addressed using the "Completion Efficiency" (CE) or "Recovery Factor" (RF) techniques discussed in SPE 90483.1 These techniques use an integrated petrophysical, reservoir, and completion model to evaluate well and zone performance. The techniques has been employed on over 3000 zones to date in a wide variety of reservoirs with excellent results. The CE and RF analysis can be supplemented by rate-transient production decline analysis if adequate producing time has elapsed. The third challenge is addressed using selective zone buildup and/or injection tests to obtain reservoir pressure and permeability. The recommended technique uses a service rig and a low rate pump truck, tubing, packer, bridge plug, and a surface readout pressure gauge with downhole shutin. This technique has recently been employed on over 60 zones in the last two years in the Hugoton field in Kansas with excellent results. The fourth challenge is selectively isolating individual perforated intervals for the refracture treatments. The most efficient technique involves the use of openhole packer hardware set inside the cased hole. The openhole packer technology has been primarily deployed in horizontal openhole wellbores to date, however the hardware is readily adaptable to cased holes and has been used on a number of vertical cased holes to date (Table 1). The integration of these proven techniques (CE, RF, downhole shutin surface readout testing, and openhole packer hardware) provides the means to meet all of the main challenges of refracturing multiple zone wells. Field examples are provided to demonstrate the viability of the concept, and a methodology is proposed for "best practices" in the implementation of the techniques. Introduction Refracture treatments have been routinely used to improve well productivity in the oil and gas industry in a wide variety of reservoirs worldwide. A literature search on the topic yields numerous papers that discuss mostly successful applications of refracturing technology.2,3 In almost all of these studies the prior treatments that were applied involved outdated technology such as low strength proppant selection in high closure stress reservoirs, low proppant volumes where higher conductivity was needed, slickwater treatments where conventional gelled treatments damaged the reservoir and didn't create fracture complexity, etc. In most of these cases the application of more modern "best practices" proppant type and proppant volumes for a field resulted in improved productivity. Very few studies addressed the situation where "best practices" fluids and proppants were applied and the result was still a low CE or RF. The CE studies done to date have identified significant remaining mobile hydrocarbons in numerous zones in a wide variety of reservoirs even with the application of "best practices" fluids and proppants-low recovery factors and completion efficiencies are the rule and not the exception. Three recent projects were done on fields where the productive areas of the field were fully drilled up on 40 acre spacing (and the operators had no plans to file for 20 acre spacing). Field 1 had an average recovery factor (EUR/Current Gas in Place) of 31%, with estimated ultimate recovery of 19.2 BCF in a field with 62.1 BCF gas in place. Field 2 had the same development status (no additional proration units available without downspacing) and the estimated ultimate recovery was estimated at 41 BCF. The volumetric analysis of the developed area indicated 136.6 BCF gas in place or a 30% expected recovery factor.