High-Permeability Fracturing: "Carter" Fluid Loss or Not

Abstract

Frac-packs, and hydraulic fracturing, have become accepted, successful completion procedures for high permeability formations. To some extent, this success has come despite less than full understanding of the processes. Statements such as "fracture models cannot predict net pressure behavior in soft rocks" are heard. Inconsistencies are blamed on radical departures from "classical" theories of fracturing, and in some instances, this may be warranted. However, it is best to first examine simpler possibilities (Occam's Razor). Radical departures should not be postulated until fracture models routinely address 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) this is valid. High loss is accounted for by high fluid loss coefficients, but using high values for something does not describe the process. One possible cause of the inconsistency might be non-1D, i.e., non-Carter type, loss behavior. Non-1D fluid loss occurs in water injection/water disposal fractures (though "normal" fracture models are still mistakenly utilized in these situations). 1D loss is valid if the fracture propagation is greater than loss velocity, and this condition is NOT true for water flood induced fracturing. Is this true for high permeability fracturing - with fluid efficiency < 10%, even in propped fracturing treatments using viscous fluids? This paper examines this question using a coupled 3D fracture-reservoir model (as described in Appendix A) to accurately simulate 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-Carter fluid loss is significant, and how to modify designs appropriately. Introduction In what has to be the most quoted "Appendix" in history, Carter1 laid out the basis for "1-D", or "Carter", or "C/Time" fluid loss behavior. This theoretical development has certainly stood the test of time, and has been the mainstay of fracture models and treatment designs for near five decades. Since that work, fracturing has moved from relatively small treatments in moderate-to-high permeability formations (where actually the use of "Carter" fluid loss might have been questionable), to massive fracturing of very low permeability formations (where the "Carter" fluid loss assumption was absolutely justified), to propped fracturing in very high permeability formations for stimulation and sand control (where once again the use of "Carter" fluid loss should be questioned). That is the subject of this presentation, to review the use of this fluid loss assumption by looking at existing work, by studying case histories, and to try to set some limits on when/where "1-D" fluid loss calculations are appropriate.

Coupled discrete element modeling of fluid injection into dense granular media

“…[6] However, questions remain on whether the mechanism of tensile fracturing is applicable in the unconsolidated formations with weak or no cementation and high permeability [Keck, 2002;Smith et al, 2004]. Using the concept of energy release rate, the condition of fracture initiation and propagation, central to the fracture mechanics theory, can be stated as the fracture extends if the energy release rate reaches a critical value [Irwin, 1957].…”

Better Reservoir Management Through Improved Water-Injection Methods With Data Analysis and Detailed Fracture/Reservoir Modeling

“…The details of the model for fluid flow in the fracture and fracture propagation are presented in [2], and the details of the coupled fracture-reservoir model are presented in [3]. An overview is included in Appendix A.…”