Improving Shale Gas Production Using Geomechanics a report by Daniel Moos GeoMechanics International
A steadily increasing percentage of the gas currently produced in the US is from shale plays. While the majority of this production is from the Barnett shale in central Texas, production from a number of new plays is rapidly coming on-line, in particular from the Haynesville of east Texas and Louisiana and the Marcellus, which underlies most of Pennsylvania as well as large areas of the surrounding states. A number of shale gas plays in Canada, most prominently the Montney and the Horn River, are also under active development. Worldwide, shale and tight gas plays have been identified in China and eastern Europe, and it is likely that other shale plays will be identified over the coming years. Shale plays have several attributes in common. First, their matrix permeability is extremely low. Second, they are both the source and the reservoir from which hydrocarbons are produced. All shale plays also contain natural fractures, perhaps generated during the process of in-place kerogen maturation. Other than that, they can be quite different as their depositional environment, age, mineralogy, maturity, temperature, pore fluid pressure, depth of burial, natural fracture distribution and in situ state of stress all vary, both between and even within a single play.
As shale reservoirs have vanishingly small intrinsic (matrix) permeabilities, they must be fracture stimulated to produce economically. Techniques to achieve economic production that were developed by operators in the Barnett shale, involving the drilling of long laterals in the direction of the minimum in situ horizontal stress, which are then multiply stimulated at intervals along their length, have become the de facto standard for development of many of the newer plays. These techniques have had to be modified based on experience in other shale plays because of variations in the response of those plays to stimulation. These variations include both the highly variable initial production of otherwise identical wells and the shape and extent of the cloud of microseismic events that are generated at a given net pressure. This cloud can be long and narrow or short and wide. Events can nucleate either close to or at a distance from the currently stimulated perforations, and whereas large numbers of events are often detected by downhole or surface geophone arrays, sometimes few events are observed. As it is generally assumed that the microseismic event cloud defines the volume that has been stimulated and will subsequently be drained by production, it is important to understand the reasons for these differences.
Large volumes of fluid are injected during stimulation; this fluid can be a gel or slick water or a combination of both. Whereas proppant is often required to enhance and maintain fracture conductivity, proppant size is often smaller than in traditional stimulations, and in fact proppant is sometimes not used at all when the reservoir is stimulated with slick water. The best stimulation design in one shale gas play is often ineffective in others.
© TOUCH BRIEFINGS 2011
A better understanding of the cause of the highly variable shale gas reservoir response to stimulation is required for a number of reasons. In particular, a better understanding of what controls the shape (width, length and height) and effectiveness (improved access to hydrocarbons and increase in reservoir permeability) of the stimulated volume would help to guide selection of fluids, proppants, flow rates and volumes to achieve the desired result. In addition, this would help to optimise well lengths and separations as well as to determine how far apart in a well to place each fracture stage. In addition to enabling improved well placement and stimulation design, such an understanding would enable better decline curve prediction, make it possible to determine whether the typically very large reduction in productivity of wells during their first year could be reduced by controlling initial production and allow prediction of when and where to re-stimulate wells that are in decline.
It is now generally accepted that stimulation in shale gas reservoirs occurs through a combination of shear slip and opening of pre-existing (closed) fractures and the creation of new hydraulic (tensile) fractures.
In wells that are drilled along the minimum horizontal stress (Shmin) direction, stimulation generally creates a primary radial hydraulic
fracture that is perpendicular to Shmin. Then, pressure changes caused by fluid diffusion into the surrounding rock and the modified near- fracture stress field induced by fracture opening cause shear slip on pre- existing natural fractures and, if the horizontal stress difference is small enough, may open new hydraulic fractures perpendicular to the main fracture. Each slip or oblique opening event radiates seismic energy, which, if the event is large enough, can be detected using downhole or surface geophones.
Fractures fail either by opening or by shear slip, as illustrated in Figure 1. The pressure required to cause pre-existing fractures to fail depends on the fracture orientation, the in situ stress orientations and magnitudes and the fracture strength. To open a fracture requires an internal fluid pressure that is greater than the stress acting normally on the fracture surface. Fractures perpendicular to the minimum stress open at the lowest pressure; the pressure required to open fractures with other orientations depends on the relative magnitudes of the other two principal stresses. Fractures that open in pure normal mode must be propped to maintain their conductivity.
Slip can occur on pre-existing fractures at pressures well below what is required to open those same fractures, or even to extend or create new hydrofractures. When shear failure occurs, open pathways for fluid flow are created by the poor fit of the newly offset fracture walls. These pathways stay open even after the pressure in the fracture drops back to its pre-stimulation value. Thus, the conductivity and resistance to closure (stiffness) of a shear fracture will be larger after stimulation than before. If the shale matrix is stiff enough to hold shear fractures open, the result is the creation of a persistent stimulated zone with enhanced
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Natural Gas
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