Tip Screenout Fracturing Applied to the Ravenspurn South Gas Field Development

Abstract

Summary Tip screenout (TSO) fracturing is a means of creating greater proppedfracture widths and hence fracture conductivities than can be achieved byconventional fracture treatments. This allows more cost-effective stimulationsof higher-permeability reservoirs, especially where non-Darcy pressure lossesare significant. This paper presents a procedure to design TSO schedules andreviews field results from the Ravenspurn South gas field, which was developedbetween 1988 and 1989. Evidence is provided to support the view that TSOpressure responses are provided to support the view that TSO pressure responsesare indeed the result of processes occurring close to the fracture tip, ratherthan slurry-enhanced viscosity effects along the fracture length. Introduction The productivity increases that can be achieved by hydraulic fracturing inhigh-permeability reservoirs are strongly dependent on the created fractureconductivities. TSO fracturing enables substantially greater fracture aperturesto be achieved than by more traditional methods. It also has resulted insignificantly increased well performance in both oil and gas reservoirs. TSOfracturing involves continued slurry injection after the proppant has bridgedoff at the fracture tip, terminating fracture proppant has bridged off at thefracture tip, terminating fracture propagation. Further pumping causes thefracture to balloon, propagation. Further pumping causes the fracture toballoon, resulting in increased treating pressures, fluid storage. and fractureaperture. Unless carefully designed, such treatments may achieve only limitedaperture increases and may carry substantially increased risks of prematuretermination resulting from uncontrolled pressure rises. The first reported useof TSO fracturing concerned the stimulation of a very soft chalk formationwhere abnormally wide propped fractures were required to combat proppantembedment. propped fractures were required to combat proppant embedment. Thedeliberate use of TSO fracturing was independently recognized as havingconsiderable potential for stimulating higher-permeability reservoirs, theobjective being to maximize fracture conductivities rather than to combatembedment. Some have argued that the pressure responses ascribed to TSO's maysimply be the result of increased slurry viscosity as proppant concentrationsare increased in the fracture. Recent proppant concentrations are increased inthe fracture. Recent laboratory data and the field evidence presented in thispaper challenge this view (see Appendix A). TSO fracturing has been appliedsuccessfully to the Ravenspurn South gas-field, resulting in up to seven-foldpseudo-steady-state productivity increases (relative to a prefracture skin ofzero), productivity increases (relative to a prefracture skin of zero), compared with three-fold increases for aggressive conventional treatments. Thedesign technique presented in this paper has recently been applied successfullyin the Prudhoe Bay oil field in Alaska. This paper presents a field-provenmethodology for designing high-conductivity hydraulic fractures, supported bythe results of an extensive fracture evaluation program conducted during thedevelopment of Ravenspurn South field. Productivity Increases Resulting From Fracturing Productivity Increases Resulting From Fracturing For a well completed without skin damage, theproductivity increase achievable by propped hydraulic fracturing is primarily afunction of the fracture's length and conductivity and the formationpermeability. A dimensionless measure of the fracture flow permeability. Adimensionless measure of the fracture flow capacity, CfD, is defined as (1) where kf (and k = fracture and formation permeabilities, respectively; bf =fracture aperture, and Lf = propped fracture half-length. Fig. 1 shows thepseudo-steady-state productivity increase, relative to an undamaged verticalwell, as a function of fracture Lf and CfD. While CfD less than 10, thefracture performance will be limited by insufficient conductivity. Consider a600-ft-long fracture in a gas reservoir with 2-md permeability. The effectivefracture conductivity, after allowing permeability. The effective fractureconductivity, after allowing for non-Darcy effects, would need to be 12,000md-ft to achieve CfD = 10. For a 150-ft-long fracture in a 50-md oil reservoir, a fracture conductivity of 75,000 md-ft would be required. Practical fieldexperience has shown that conductivities of this magnitude are rarely, if ever, achieved by conventional fracture treatments (see below). The following sectionillustrates that in high-permeability reservoirs. when conventional fracturedesigns are used, there is little scope for achieving major increases infracture conductivities. Alternative techniques are required. Fracture Length. Although increasing the fracture length will increase wellproductivity. this method will probably prove uneconomical unless accompaniedby adequate fracture conductivity. particularly in high-permeabilityreservoirs. particularly in high-permeability reservoirs. Fracture Conductivity. This is the key to cost-effective fracturing inhigher-permeability reservoirs. The following section briefly examines thefactors controlling the conductivities that can be achieved by conventionalfracture designs and demonstrates the need for alternative techniques toincrease propped fracture apertures. Fracture conductivity is defined as theproduct of the effective propped aperture and the effective proppant-packpermeability. The factors controlling these components are permeability. Thefactors controlling these components are discussed below. Aperture Controls. The effective propped aperture depends on the aperturecreated during pumping, the slurry concentration, and the loss of proppant fromembedment and gel residues. Created Aperture. There is limited scope toinfluence created aperture during fracture growth. Consider, for example, aconfined height fracture. While the fracture is propagating, doubling the pumprate, the viscosity, or the fracture length would each achieve only about a 20%increase in aperture, probably at significant additional cost, even ifpractical. Lost Aperture. Laboratory studies under Ravenspurn conditions showedthat at least 0.5 lbm/ft2 of proppant may be lost to proppant embedment intothe formation and the presence of unbroken proppant embedment into theformation and the presence of unbroken filter cake. In the muchhigher-permeability Prudhoe Bay reservoir, recent tests showed that up to 1lbm/ft2 may be lost. Aperture losses between 0.5 and 1 lbm/ft2 probably applyto many reservoirs, but there is little published information on the subject. Clearly, any part of the fracture where the proppant coverage does not exceedthe lost aperture will be ineffective. Propped Aperture. The higher the slurryconcentration in the fracture, the greater the proportion of the createdaperture that will be propped open. However, even increasing the proppantconcentration from 13 to 18 lbm/gal (clean) would only increase the proppedaperture from 47 % to 58 % of the created aperture, and at propped aperturefrom 47 % to 58 % of the created aperture, and at a significantly increasedrisk of a near-wellbore screenout. SPEPE P. 252