Over 7.8 meters of seafloor subsidence has occurred at the Ekofisk Field in the Norwegian sector of the North Sea since the start of production in 1971. Full field water injection was initiated at Ekofisk on a limited scale in 1987. The surface subsidence is a result of reservoir compaction, which is considered primarily to be due to pressure depletion until the early 1990's and water weakening thereafter. Rock compressibility was input as a function of initial porosity and increasing net effective stress (i.e. declining reservoir pressure) in earlier Ekofisk studies. In 1994, under a voidage balancing reservoir management program, water injection was increased sufficiently to stabilize reservoir pressure. However, no reduction in surface subsidence rate was seen. This, in combination with other field and lab observations, led to the conclusion that water was weakening the reservoir chalk and necessitated revising the rock compressibility functions at Ekofisk to include the effect of additional compaction due to the water weakening. The development and implementation of the water induced compaction functions at Ekofisk is presented in this paper. Rock compressibility is now input into the model as a function of initial porosity, net effective stress, and water saturation. As water saturation increases in a model cell due to water injection or water influx, the model cell transitions to a weaker stress-strain curve. The effect of increasing water saturation, and the resulting water weakening of the chalk, is that compaction and subsidence may continue in spite of stable or increasing reservoir pressure. Both laboratory and field data are presented which support the use of the water weakening functions. The development and calibration of these curves is presented, which includes the effects of fracturing, creep, water dispersion effects, hysteresis logic, and strain hardening. A comparison of the calculated and measured compaction and subsidence bowls is also presented.
Matrix permeability and pore volume compressibility are fundamentally important characteristics of hydrocarbon reservoirs because they provide measures of reservoir volume and reservoir producibility. In most laboratories these quantities are measured under hydrostatic (isotropic) loads that do not truly reflect the deviatoric stress state that exists in most reservoirs and do not adequately simulate the evolution of effective stresses in the reservoir as the reservoir is produced. Compression tests on reservoir sandstones show that both the compressibility and matrix permeability vary markedly with stress path (defined as the change in effective horizontal stress/change in effective overburden stress from initial reservoir conditions). Hence, changes in reservoir properties measured under hydrostatic loading conditions may be very misleading if applied to a reservoir that follows a non-hydrostatic stress path. Representative measurements of reservoir properties should be measured in the laboratory under loading paths that duplicate the stress path followed by the reservoir during production. Consequently, optimum reservoir management may require that the reservoir stress path be determined by measuring in situ stresses early in the production history of a reservoir and periodically thereafter as the reservoir pore pressure is reduced. Introduction Due to their fundamental importance in reservoir evaluation and management, matrix permeabilities and compressibilities of reservoir rocks are routinely measured in the laboratory using procedures intended to simulate the reservoir environment. The most commonly used procedure is to compress the specimen in a hydrostatic test, in which the sample is subjected to an isotropic stress state (i.e., horizontal stresses equal the overburden stress) by a confining fluid. As the effective confining fluid pressure is increased, changes in the rock pore volume are measured and are used to calculate pore volume compressibility. Similarly, specific permeability is measured at incremental confining pressures by flowing a fluid of known viscosity through the specimen at a known rate and stabilized pressure difference. Matrix permeabilities are then calculated from measured values of specific permeability. Although simple and convenient to run, the hydrostatic test has a major drawback; hydrostatic loading conditions are rarely encountered in real reservoirs. For example, in situ stresses measured in sequences of fluvial and marine sandstones, mudstones, and shales typical of many hydrocarbon reservoirs show that stresses in the sandstones are distinctly anisotropic. The minimum horizontal stresses can be predicted from the rock material properties in some cases but not others. Jaeger and Cook present theoretical arguments showing that the volumetric response of an elastic material to application of three dissimilar principal stresses is similar to that produced by an isotropic stress that is nominally identical to the mean of the three stresses. P. 965^
A case study of the Ekofisk field. a naturally fractured chalk reservoir in the North Sea, demonstrates the strong influence of horizontal stress anisotropy on fracture conductivity and reservoir permeability. Directions and magnitudes of horizontal in situ stresses, as well as the distribution and orientations of natural fractures, vary locally across the structural dome that forms the Ekofisk reservoir. Fracture permeability is stress-sensitive and decreases as effective stresses in the reservoir increase due to pore pressure reduction resulting from production of oil and gas. Changes in fracture permeability also depend on the orientation of fractures relative to the evolving anisotropic stress field in the reservoir. Steeply dipping fractures aligned parallel to the local maximum horizontal stress direction show the smallest decline in permeability as the reservoir is depleted and can control permeability anisotropy in a naturally fractured reservoir containing multiple fracture sets. Introduction Fractures are present in almost all hydrocarbon reservoirs. but it is only when fractures form an interconnected network that their effect on fluid flow becomes important. Fractures not only enhance the overall permeability of many reservoirs. they also create significant permeability anisotropy. Knowledge of the orientation and magnitude of the horizontal permeability anisotropy has significant economic importance in developing and managing a reservoir. Such knowledge allows optimization of (1) location of production wells for maximum primary oil recovery and drainage of the reservoir with the fewest number of wells. and (2) placement of waterflood injection wells to prevent early water breakthrough in producing wells. thereby achieving optimum sweep efficiency and maximum oil recovery. In order to assess the role of fractures on hydrocarbon production and permeability anisotropy, characterization of naturally fractured reservoirs has focused primarily on the distribution and orientation of fractures and the fluid-flow properties of individual representative fractures in a given reservoir volume. For reservoirs with only one set of fractures (e.g.. regional vertical extension fractures across a sedimentary basin) the horizontal direction of preferred fluid flow is parallel to the trend of the fractures. For reservoirs with more than one set of fractures in different orientations it is often assumed that the intensity of fracturing controls reservoir permeability anisotropy and that maximum permeability direction is closely aligned with the dominant fracture trend. Considerable work has been conducted over the past decade to develop new statistical techniques and numerical simulations to predict distributions and orientations of subsurface fractures from cores and geophysical logs. The assumption being that a better statistical description of a reservoir's fracture system provides a better prediction of fracture interconnectivity and fluid-flow characteristics of the reservoir. However, fluid flow in a naturally fractured reservoir is not only a function of the spacing and interconnectivity of the fracture system, it is also dependent on the conductivity of individual fractures.
The subsidence occurring in the Ekofisk field originates from the compaction of the reservoir rock due to the increasing stress placed upon it as reservoir pressure is reduced with production from the field. The mechanical properties of the reservoir rock determine how much compaction will take place for given conditions in the field and are therefore a key factor in determining the degree to which subsidence will occur. These mechanical properties can be combined with other reservoi r informati on (pressure, overburden load, structure, etc.) in simulators to predict the amount of compaction and surface subsidence that will occur in the life of the field. For this to be done accuratel'y, there must be sufficient information to describe the compaction behavior of all the rock within the reservoir for all conditions encountered.
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