Estimating Geomechanical Properties Using an Integrated Flow Model
- J.R. Fanchi (Colorado School of Mines)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- April 2003
- Document Type
- Journal Paper
- 108 - 116
- 2003. Society of Petroleum Engineers
- 1.2.2 Geomechanics, 5.1.1 Exploration, Development, Structural Geology, 5.8.3 Coal Seam Gas, 5.1.7 Seismic Processing and Interpretation, 5.5.2 Core Analysis, 5.5.3 Scaling Methods, 5.1 Reservoir Characterisation, 5.5.7 Streamline Simulation, 4.1.5 Processing Equipment, 5.5.8 History Matching, 5.4.2 Gas Injection Methods, 5.5 Reservoir Simulation, 5.6.4 Drillstem/Well Testing, 5.6.1 Open hole/cased hole log analysis, 5.4 Enhanced Recovery, 5.1.10 Reservoir Geomechanics, 1.2.3 Rock properties, 5.3.4 Integration of geomechanics in models, 4.1.2 Separation and Treating, 5.2.1 Phase Behavior and PVT Measurements
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We show how to obtain inexpensive estimates of geomechanical parameters by explicitly coupling a petrophysical model with a traditional flow simulator. The usefulness of development geophysical information from the resulting integrated flow model is illustrated for improved recovery and coalbed methane production processes.
Geomechanical properties give us insight into the behavior of the reservoir structure and the impact of structural changes on fluid flow. One of the problems with the routine use of geomechanical calculations in flow models is the difficulty of incorporating the calculations into a flow simulator. The most widely used geomechanical procedures require a substantial increase in computer processing time to perform the calculations.1-3 The purpose of this paper is to show how to obtain inexpensive estimates of geomechanical parameters with an integrated flow model.
We use the phrase "integrated flow model" to describe a flow simulator that combines a petrophysical model with a traditional flow simulator. This combination of petrophysical model and flow model gives us a simulator that generates information that ordinarily is provided by separate disciplines. The first integrated flow model was originally devised to assist in the design and analysis of time-lapse seismology4-6 because the petrophysical model can calculate such development geophysical attributes as acoustic impedance, reflection coefficient, shear velocity, and compressional velocity. We have found that integrated flow models have other important uses.
Using the integrated flow model, we can readily calculate such geomechanical properties as Poisson's ratio, Young's modulus, and uniaxial compaction. These properties are calculated from a minimal input data set and are provided throughout the life of the reservoir. Although the estimated properties are approximate, they provide information that can help guide the engineer without a significantly greater investment of resources. The engineer can then decide if more detailed analysis is justified.
The usefulness of development geophysical information from an integrated flow model is discussed for the following scenarios: forecasting the reservoir geophysical response to CO2 injection in a mature oil field; estimating subsidence during depletion of an oil reservoir with a gas cap; and predicting the change in geomechanical properties during the life of a coalbed methane reservoir. The petrophysical algorithm used in the integrated flow model is described before presenting the examples. We then discuss the relative merits of the integrated-flow-model estimation of geomechanical properties.
A prototype integrated flow model (IFLO) based on a widely used petrophysical model has been developed and applied to a range of reservoir systems.6,7 The petrophysical model must be able to calculate reservoir geophysical attributes that can be compared with seismic velocity and impedance measurements. The algorithm for calculating seismic velocities is a rock physics model.8 We refer to the algorithm used in the integrated flow model as a petrophysical algorithm because of its dependence on rock physics properties and petroleum fluid properties.
Bulk density for a porous rock with porosity f is given by ?B = (1-f)?m+f?f. Rock matrix density ?m and initial porosity are user-specified input data. Porosity depends on fluid pressure p and porosity compressibility cf=(1/f) (?f/?p)T at constant temperature T. Oil, water, and gas densities (?o, ?w, ?g) and saturations (So,Sw,Sg) are needed to calculate fluid density ?f. Phase densities are obtained from the fluid-properties model in the traditional flow simulator, and saturation distributions are obtained as solutions of the flow equations.
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