Frac-packs, and hydraulic fracturing, have become accepted,successful completion procedures for high permeability formations.To some extent, this success has come despite lessthan full understanding of the processes. Statements such as“fracture models cannot predict net pressure behavior in softrocks” are heard. Inconsistencies are blamed on radical departuresfrom “classical” theories of fracturing, and in someinstances, this may be warranted. However, it is best to firstexamine simpler possibilities (Occam’s Razor). Radical departuresshould not be postulated until fracture models routinelyaddress actual geologic/reservoir environments.What is the big difference for high permeability fracturing?Of course, it is not “soft” rock, it is permeability, thus,fluid loss. ALL fracture designs are based on the idea of 1D,I.e., Carter or C/√t, loss, and assume (with no justification) thisis valid. High loss is accounted for by high fluid loss coefficients,but using high values for something does not describethe process. One possible cause of the inconsistency might benon-1D, I.e., non-Carter type, loss behavior.Non-1D fluid loss occurs in water injection/water disposalfractures (though “normal” fracture models are still mistakenlyutilized in these situations). 1D loss is valid if the fracturepropagation is greater than loss velocity, and this condition isNOT true for water flood induced fracturing. Is this true forhigh permeability fracturing – with fluid efficiency < 10%,even in propped fracturing treatments using viscous fluids?This paper examines this question using a coupled 3Dfracture-reservoir model (as described in Appendix A) to accuratelysimulate fluid loss. We simulate several field cases,review the design/post-analysis based on “traditional” loss behavior,and examine the effect of rigorously simulating loss.The results are used to identify conditions where non-Carterfluid loss is significant, and how to modifydesigns appropriately.
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