Field Study of Completion Fluids To Enhance Gas Production in the Barnett Shale
- Glenn S. Penny (CESI Chemical) | Terrell Allen Dobkins (Antero Resources Corp.) | John Thomas Pursley (CESI Chemical)
- Document ID
- Society of Petroleum Engineers
- SPE Gas Technology Symposium, 15-17 May, Calgary, Alberta, Canada
- Publication Date
- Document Type
- Conference Paper
- 2006. Society of Petroleum Engineers
- 2 Well Completion, 1.8.5 Phase Trapping, 4.1.2 Separation and Treating, 5.8.1 Tight Gas, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 2.5.1 Fracture design and containment, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 1.8 Formation Damage, 4.3.4 Scale, 5.1.2 Faults and Fracture Characterisation, 2.4.3 Sand/Solids Control, 2.4.6 Frac and Pack, 1.6.9 Coring, Fishing, 2.2.2 Perforating, 5.8.2 Shale Gas, 1.6 Drilling Operations, 2.7.1 Completion Fluids, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.6.5 Tracers, 5.6.4 Drillstem/Well Testing, 3 Production and Well Operations
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In this work field data and lab data are presented for various fluids pumped in the Barnett Shale. Recent fracture treatments have been light sand fracs in slick water consisting of water and friction reducer, with and without surfactants. Commonly used surfactants as well as a microemulsion system (ME) are evaluated.
Lab data is presented that illustrates how the microemulsion accelerates the cleanup of injected fluids in tight gas cores. The microemulsion additive results in lower pressures to displace injected fluids from low permeability core samples and proppant packs. The relative perm to gas is increased substantially as the water saturation is decreased. The enhanced relative permeability mechanism is the alteration of the rock-fluid interfacial tension or contact angle. It is demonstrated that this alteration effectively lowers the capillary pressure and capillary end effect associated with fractures in low perm reservoirs by as much as 50%, thus mitigating phase trapping and therefore permitting an increased flow area to the fracture, hence longer effective frac lengths.
Over 200 wells have been treated and analyzed in the Barnett Shale for this study. Several side by side comparisons of treatment variations are possible. The addition of the microemulsion to fracturing treatments has resulted in more than 50% increases in load recoveries and 30-40% increases in gas production. Pressure analysis of fractured wells shows that the damage factor is reduced by a factor of 2 in the Barnett shale with the inclusion of ME. This is a result of a combination of reduced depth of invasion, a higher relative perm in the invaded zone and/or longer effective frac lengths.
The initial Barnett shale wells in the mid nineties were completed with massive hydraulic fracturing treatments with 1 million pounds of proppant carried in crosslinked gelled fluids. In an effort to reduce stimulation costs without reducing production, light sand fracturing emerged as the method of choice. The success has been attributed to the ability of the slick water treatments to contact a larger surface area of the reservoir with minimized fracturing fluid damage at the fracture face and within the proppant pack. Even in these smaller fracturing treatments up to 1.2 million gallons of water are pumped most often with friction reducer at 0.25 - 0.5 gal/1000 gal (gpt). Treatments examined in this work varied from 23,000 bbl and 140,000 lb of sand run at 0.25 to 1.0 ppg at an average rate of 65 bpm. From fracture diagnostic work it is apparent that the fluid travels down multiple fractures running southwest to northeast. This gives the opportunity for fluid invasion of the secondary permeability surrounding the fracture of some 250 ft on each side of the fracture fairway and been microseismically mapped to extend over 2000 ft from the wellbore. Propped fracture half-lengths are estimated at 1000 ft. with damage surrounding each frac. Figure 1 shows the extensive fracture system that is proposed from microseismic. Comparison of post frac flow back volumes to frac fluid load volumes shows that 60 to 90% of the injected fluid stays in the reservoir. The insert in Figure 1 illustrates fluid that is trapped near one of the fractures by high capillary pressures and capillary end effects.
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