Abnormal Treating Pressures in Massive Hydraulic Fracturing Treatments

Abstract

Summary Abnormal treating pressures were observed during massive hydraulic fracturing (MHF) treatments in the Mesa Verde formation of the Piceance basin, CO. Data from three widely separated wells and in several zones per well showed a pressure increase during MHF treatments that we call "pressure growth." This pressure growth was at least semipermanent. The elevated instantaneous shut-in pressures (ISIP's) did not return to initial values over periods of pressures (ISIP's) did not return to initial values over periods of several days. The magnitude of this pressure growth is highly variable. When its value is less than about 2,300 psi [15.9 MPa], the MHF treatments are usually completed and results are obtained that are within normal expectations. When its value exceeds 2,300 psi [15.9 MPa), sandout occurs and the fracture length estimated from production data is much less than that calculated with crack production data is much less than that calculated with crack propagation models. Temperature logs indicate little or only propagation models. Temperature logs indicate little or only modest vertical extension of the fractures above the perforations. These data, along with sandouts, point to a large increase in fracture width in response to pressure growth. One possible cause of pressure growth is fracture branching. A multiplicity of branches could produce a plastic-like effect. Laboratory measurements have ruled out plasticity as the cause. The stress/strain behavior of the rock is similar to that of rocks where no pressure growth occurs. Pressure growth seems to depend on both pumping rate and Pressure growth seems to depend on both pumping rate and fluid viscosity. Thus, there is some hope for its mitigation through treatment design. Also, pressure growth appears to correlate negatively with pay-zone quality. This suggests that the phenomenon can be exploited as a fluid-diversion technique. phenomenon can be exploited as a fluid-diversion technique. Introduction Because of its large resource, the Piceance basin has been one of the more promising prospects for MHF applications in tight-gas sands. In this promising prospects for MHF applications in tight-gas sands. In this basin, the Mesa Verde and adjacent overlying formations provide several hundred feet of sand thickness at depths between 5,000 and 12,000 ft [1525 and 3650 m]. Porosity in much of this sand thickness ranges from 5 to 8%. The gas resource in the basin has been estimated at 33 Bcf [934 × 10(6) m3]. Massive fracturing methods have been tested extensively within the Piceance basin by Mobil and others. Results of these tests have shown that, with market conditions of earlier times, commercial wells can be developed in the Piceance basin using massive fracturing methods. MHF experience in these tight-gas sands shows an unusual characteristic. Fracturing treatments are always accompanied by large increases in treating pressure. This phenomenon, or pressure growth, has adverse effects on pressure. This phenomenon, or pressure growth, has adverse effects on fracture effectiveness. It appears to produce undesirable width/length aspect ratios as judged by fracture height and production data. It limits the size of massive fracturing treatments by causing premature sandout. And it increases the pumping horsepower requirements by as much as a factor of two. Understanding and finding ways to avoid this problem are clearly matters of practical importance. Pressure growth inhibits the generation of very long practical importance. Pressure growth inhibits the generation of very long fractures, which are needed for successful application of MHF methods in the Piceance basin. It is likely to be important in other basins where tight-gas sands are lenticular on the scale of Mesa Verde lenses in the Piceance basin. Pressure growth is not to be confused with any of the pressure changes treated by Nolte and Smith in their analysis of fracturing pressures. The pressure-growth phenomenon considered here begins with the first injection pressure-growth phenomenon considered here begins with the first injection of fluid into the fracture and continues throughout the treatment. It produces dramatic effects, typically resulting in a doubling of the surface produces dramatic effects, typically resulting in a doubling of the surface treating pressure in a massive fracturing treatment. In this paper, we present field data that help define the nature of pressure growth. We present a model based on fracture branching that may pressure growth. We present a model based on fracture branching that may explain the cause of pressure growth and is consistent with field observations. Other explanations should also be investigated. We suggest a possible way of avoiding or minimizing the problem and propose a method of using the pressure-growth phenomenon as a fluid-diversion technique.

A Study of the Interaction Mechanism between Hydraulic Fractures and Natural Fractures in the KS Tight Gas Reservoir

“…Hydraulic fracture complexity has been directly observed from mine-back experiments and core-through (Warpinski and Teufel 1987;Warpinski et al 1991, Jeffrey et al 1992Warpinski et al 1993;Fast et al 1994;Jeffery et al 1995;Branagan et al 1996, Cipolla et al 2008, and inferred from microseismic monitoring (Fisher et al 2002;Maxwell et al 2002a;Maxwell et al 2002b) and treating pressure analysis (Barree 1998;Medlin and Fitch 1988;Davidson et al 1993;Sato et al 1999). Similar phenomenon was inferred from the initial stimulation efforts in the KS reservoir that rebuked the traditional single planar bi-wing fracture paradigm.…”

The Behaviour of Fracture Growth in Sedimentary Rocks: A Numerical Study Based on Hydraulic Fracturing Processes

“…Isolated fractures generated from weak elements also open within the rock mass. The observation that hydraulic fractures developing with offsets in their path require high fluid pressures to sustain fracture growth has been suggested by Medlin and Fitch [54]. Based on numerical studies of small-scale models, Zhang et al [15] and Hossain and Rahman [55] also demonstrated that the complex fracture growth in field may lead to the requirement of a higher treatment pressure.…”

“…While for the other two cases, the growth of the top and bottom fractures is evidently asymmetric, particularly for the case with a lower deviatoric confining stress. Once branches and offsets appear during the hydraulic fracturing process, the fractures that develop such offsets in their path require higher fluid pressure to sustain fracture growth, as was suggested by previous studies [15,54,55]. In the practical engineering of hydraulic fracturing of beach-bar sandstone reservoirs in Shengli Oilfield, unusual high pressures are often recorded [67,68].…”

Evaluation and Modification of Fracture Treatments Showing Near-Wellbore Effects

“…where Q is the total flow rate, p is the fluid density, number of active perforations, d is the perforation (2) n is the diameter and C is the discharge coefficient. The number of active perforations will be determined when qu,aatifying perforation friction in the field ex,amples presented later in this paper.…”