Reservoir Stimulation
Karri Weston
The third edition has been completely rewritten to reflect the changingtechnologies in the industry and contains 20 chapters written by 44 authors. Itcontinues to provide an overview of reservoir stimulation from anall-encompassing engineering standpoint. Reservoir Stimulation sets forth arationalization of stimulation using reservoir engineering concepts, andaddresses topics such as formation characterization, hydraulic fracturing andmatrix acidizing. Formation damage, which refers to a loss in reservoirproductivity, is also examined comprehensively.
This extensive reference work remains essential reading for petroleumindustry professionals involved in the important activities of reservoirevaluation, development and management, who require invaluable skills in theapplication of the techniques described for the successful exploitation of oiland gas reservoirs. Contributors to this volume are recognized authorities intheir individual technologies.
The first case, low formation permeability, requires a reservoir stimulation technique, which can be either hydraulic fracturing or acid fracturing. The second case, formation damage, requires a damage removal technique, which is usually matrix acidizing but may occasionally involve hydraulic fracturing. Solvent or surfactant treatments are sometimes used for damage removal.
Figure 1 illustrates the division of well stimulation problems on the basis of formation permeability. Formations having an average effective permeability of 1 mD (millidarcy) or less generally require reservoir stimulation methods, while those having effective permeabilities of 10 md or greater generally require damage removal methods. Those formations in between these two permeabilities may require either type of treatment.
The purpose of hydraulic fracturing is to change the flow pattern in the reservoir from one that converges radially on the well bore (Figure 2) with flow resistance concentrated near the wellbore, to one where flow in the reservoir is linear to a highly conductive fracture that conducts fluid to the wellbore with minimal flow resistance (Figure 3). The success of this operation depends upon the conductivity of the hydraulic fracture and how successfully this conductivity can be retained following the treatment. These, in turn, depend largely upon the design and execution of the fracturing treatment.
A hydraulic fracture is created in a subsurface formation when a fluid is pumped into that formation at a rate faster than the formation can accept the fluid through its matrix permeability. For example, Figure 4 illustrates the pressure versus time behavior at the surface of a well that is being fractured. As fluid is pumped into the target formation at a rate sufficient to fracture the well, the pressure at the formation face builds up rapidly to the point that the formation fails and a fracture is developed.
As fracture width grows, a point is soon reached where the fracture can accept a propping agent, and the proppant is added to the fracturing fluid (Figure 5). Typically, proppant is added initially at a low concentration (about weight::1 lb of proppant per gallon of fracturing fluid), then the concentration is subsequently increased as it becomes apparent that the lower concentrations of proppant are being accepted by the fracture. The purpose of the proppant is to hold the fracture open. Common proppant materials include sand, resin-coated sand, and ceramic beads.
Rather, the success or failure of the fracturing treatment depends more upon how successfully the proppant was placed in the fracture, the conductivity of the proppant within the fracture after the treatment, and the potential of the well as an appropriate stimulation candidate, in other words, its remaining reservoir pressure, reserves, and other considerations. In some formations, where the hydrocarbon is located predominantly in natural fractures, the success of the treatment depends upon the orientation of the hydraulic fracture relative to the preferred direction of the natural fractures.
A hydraulic fracture will propagate in a plane perpendicular to the least principal earth stress. For example, consider a well at depth::1000 ft in a tectonically relaxed area with a terrastatic gradient of 1.0 psi/ft of depth. In such a shallow well, the overburden stress can be overcome more easily than either of the two principal horizontal stresses. If an attempt is made to fracture such a well by pumping into it at high injection rates, the pressure adjacent to the exposed formation will increase rapidly. When that pressure becomes 1000 psi or slightly greater, there is sufficient pressure to lift the overburden. At this point, a horizontal fracture occurs (that is, a fracture perpendicular to the vertical wellbore or parallel to the surface of the earth).
Alternatively, consider a well that is depth::5000 ft deep in a formation having an average terrastatic gradient of 1.0 psi/ft and is also in a tectonically relaxed area. When an attempt is made to fracture this well hydraulically, it is found that a fracture can be propagated with a bottomhole pressure of 3500 psi. Since this pressure is inadequate to lift the overburden weight of the earth, it is inferred that the fracture is not horizontal but rather vertical (that is, in the plane of the vertical axis of the wellbore). Consequently, a good rule of thumb is that in wells deeper than about depth::2000 ft, in tectonically relaxed areas, most hydraulic fractures will be vertical.
The azimuth direction of the hydraulic fracture depends upon the relative magnitude of the two principal horizontal stresses. Contrary to certain folk lore, there is no effective method for redirecting the direction of a vertical fracture in a deep well (2000 ft or deeper). It depends entirely upon the relative magnitude of the two principal horizontal stresses in the neighborhood of the wellbore. The hydraulic fracture will propagate perpendicular to the least principal stress. Fracture orientations tend to remain roughly the same over large geographical areas. East of the Rocky Mountain area, vertical fractures tend toward a northeasterly direction. This orientation is altered somewhat in the Gulf Coast area where fractures seem to parallel the coast line. In the Rocky Mountain area, fractures occur in unpredictable directions that are highly dependent upon the direction of local tectonic forces.
The effectiveness of a fracturing treatment is largely dependent upon how successfully the proppant has been placed within the productive zone and how much conductivity the propped fracture has relative to that of the formation being stimulated.
Placement of the proppant within the fracture is governed by the properties of the fracturing fluid. Certain fluids totally suspend the proppant during its transit down the wellbore and into the fracture. Other fluids allow the proppant to drop through the fluid after the fluid and proppant enter the fracture. The first category of fluids is often referred to as perfect support fluids, whereas the second is described as equilibrium bank fluids.
In very hot wells, especially those treated at high pumping rates, cross-linked fluids will lose most of their viscosity by shear degradation during the pumping process and through exposure to high temperatures. If these fluids lose viscosity, they also lose their ability to suspend the proppant. This problem has been corrected with the development of delayed, cross-linked gelled fracturing fluids. Such fluids first became available during the early 1980s. They are capable of retaining their viscosity within the fracture even under the severe conditions described.
The second type of fracturing fluid, equilibrium bank fluids, allow the proppant to fall through the fracturing fluid and settle in an equilibrium bank that builds away from the wellbore. Such fluids may provide a fracture completely filled with proppant near the wellbore, but the height of the proppant bank decreases rapidly with distance away from the wellbore. These fluids have application in damage removal treatments where short, highly conductive fractures are required, but they have limited utility in creating long fractures with high conductivity.
An important factor affecting the success or failure of a hydraulic fracture treatment is the conductivity (in situ) of the fracture developed. The role of this variable can be illustrated by a graph (Figure 7), first presented by McGuire and Sikora in 1960. This graph shows how the productivity index ratio (J/Jo shown on the vertical axis) developed by the treatment relates to the fracture length and the permeability contrast between the propped fracture and the permeability of the formation.
Suppose a well that is depth::6000 ft deep is fractured and the confining stress on the proppant under the most severe producing condition will be 4000 psi. If a 20/40 mesh Ottawa sand is used during the treatment, the permeability of this sand will be about 100 D (darcys). Suppose that the width of the propped fracture created is only length::0.1 in. after fracture closure and that a 0.1-mD formation is being stimulated. Assume that the well is on 40-acre spacing; therefore, the scale factors in Figure 7 are 1.0 for both the vertical and horizontal axes. Also assume that a propped fracture length of length::660 ft has been created. This means the fracture extends to the radius of drainage for this well.
The McGuire-Sikora graph indicates that this treatment will result in a relative conductivity of 105, L/re = 1.0 (where L is the length of the fracture and re the drainage radius), and a stimulation ratio of about 11.5. That is, the well after fracturing should have a stabilized production rate of about 11.5 times the production rate prior to stimulation. This prediction assumes that the value of skin prior to the fracture treatment was zero (that is, no stimulation and no damage).
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