Some Rock-Mechanical Aspects of Oil and Gas Well Completions

Abstract

Abstract Elementary borehole- and perforation-stability problems in friable clastic formations for unrestricted fluid flow between reservoir rock and underground opening are treated on the basis of linear poroelastic theory. Thermal stress effects caused by a temperature difference between reservoir and borehole fluids can be predicted from the mathematical similarity of poro- and thermoelasticity. A tension-failure condition applies for the prediction of hydraulic fracture initiation in a formation around injection wells. The resulting equations are partially well-known. Similarly, a uniaxial compression-failure condition should predict perforation failure leading to sand influx in production wells. The major difference between these situations is that, at sufficient depth of burial, the tensile strength of a friable rock mass has only a minor effect on the fracturing pressure level, but the actual value of the compressive strength plays a crucial role in the prediction of sand-influx conditions. Practical suggestions for resolving the latter are given. Introduction This paper discusses borehole- and perforation-stability problems as encountered in friable sandstone formations that have in common free fluid flow between a reservoir and an underground opening. Such a condition prevailsduring fluid production through either casing perforations or open hole andduring injection of fluids into a reservoir for pressure maintenance, gas conservation, tertiary oil recovery, or well stimulation. In the absence of a membrane (such as a filter cake) at the rock/hole interface, the effective stress normal to the rock surface is zero. Rock failure can result either in tension during fluid injection or in compression during fluid production. Because one of the principal effective stresses (the radial stress) is zero and the effect of the intermediate principal effective stress is small, failure is of either the unconfined tension or compression type. Rock failure resulting from fluid production from friable sandstones causes sand-particle influx. Failure caused by fluid injection means either planned or unintentional formation fracturing. The production technologist has to foresee such failure conditions as a function of changes in the stress regime with time. He has to start with a best possible estimate of the initial in-situ state of stress. On the basis of log data and core sample analysis, relevant rock deformation and strength properties must be determined next. Finally, an estimate of changes in the stress field resulting from prolonged production or injection must be made. Problem Areas Formation Particle Influx in Production Wells. Although significant improvements have been made in well-completion techniques aimed at sand-particle retention by both gravel packing and sand consolidation, straightforward production through casing perforations is the preferred production method because of minimum costs and maximum usage of well-flow potential. Moreoever, gravel packing long intervals of strongly deviated holes remains a difficult, expensive operation to perform, while sand consolidation processes for oil wells at temperatures above 75 degrees C [167 degrees F] are not available commercially. Friable formation sands i.e., formations that have some strength of their own-do not necessarily present a sand-influx problem initially. Sand production may develop gradually in time, once total drawdown increases and/or water breakthrough occurs. Deviated boreholes may encounter less favorable stress concentrations around perforations than vertical holes. All in all, it is necessary to predict the sand-influx potential of a well as soon as possible after drilling to serve as a basis for a completion policy. A perforation pattern that both results in production from only the more competent zones and enables delivery of the required well production capacity could be implemented. Formation Fracturing Around Injection Wells. A familiar type of formation failure is fracturing in tension around injection wells. Formation fracturing always occurs when the injection pressure surpasses the formation breakdown pressurei.e., the fluid pressure that brings the hoop stress around the opening in a tension equal to the tensile strength. Once initiated at or below this pressure level (because the formation may contain natural fractures), fracturing proceeds while the injection pressure surpasses the least principal in-situ total stress. The instantaneous shut-in pressure recorded during or after a fracturing job provides the best value of the least principal total stress component. The in-situ state of stress is not necessarily a constant during the production life of a reservoir. Changes both in reservoir pressure and in temperature adjacent to a well affect the local stress field in the formation. The effect of reservoir pressure variations on formation fracturing potential is well-known. Breckels and van Eekelen explicitly account for this effect. It is less recognized that in deeper formations cooling of the borehole surroundings by injection of liquids at near-surface temperature causes reservoir-rock shrinkage, leading to a reduction in both fracture initiation and propagation pressure. SPEJ P. 848^