Geomechanical Controls on Multiphase Fluid Flow in Naturally Fractured Carbonate Reservoirs

• Author / Creator

  Haghi, Amir Hossein

• Carbonate formations host 50% of the world’s oil and gas reserves and a major portion of the world’s groundwater resources. Additionally, 85% of carbonate reservoirs are naturally fractured. Porous rock matrix and fractures in carbonate formations can be greatly influenced by the effective stress-induced deformation. Fluid production or injection in subsurface porous media will locally change pore pressures and in-situ stresses. These stress changes will, in turn, lead to pore and fracture deformation in naturally fractured carbonate reservoirs (NFCR) in response to the pore pressure/stress coupling effect. Similarly, pore volume has been shown experimentally in the literature to directly impact on absolute permeability and relative permeability of porous media. Relative permeability and capillary pressure are the governing parameters that characterize multiphase fluid flow mechanism (e.g. forced drainage and spontaneous imbibition) in porous media for diverse natural and industrial applications, including surface water infiltration into the ground, CO2 sequestration, and hydrocarbon enhanced recovery. Although the drastic effects of deformation of porous media on single-phase fluid flow have been well established, the stress dependency of flow in multiphase systems is not yet fully explored.
  This research has started with geomechanical investigation of an NFCR case study, Bangestan Reservoir, in SW of Iran. A wide ranges of field data including image logs, XLOT, acid fracturing, density logs, hydraulic fracturing tests, sonic wave velocity, and transient flow test were collected, analyzed, and used to quantify and model the state of in-situ stress, pore pressure and mechanical properties of the reservoir. The study suggested that the contemporary state of stress in the reservoir was characterized by normal faulting (NF) stress regime.
  A novel semi-analytical model was then developed to study the influence of stress-dependent effects on porosity, absolute permeability, relative permeability, and capillary pressure on the imbibition and oil recovery mechanisms of both intact rock and fracture in a cubic block model. To capture the geomechanical interactions involved, pure compliance poroelastic definitions and nonlinear joint normal stiffness equations were used to assess the deformation of intact rock and fracture, respectively. To evaluate the accuracy of the model, database from the Bangestan reservoir and some stress-dependent multiphase flow properties from the literature were used. It was shown how shifts in multiphase flow properties in response to an increase in effective stress from 0MPa to 30MPa decreased the oil recovery by 50%. For confirmation, multiphase flow simulation and coupled geomechanical and dual permeability flow simulation techniques were used to study the stress-dependent spontaneous imbibition and cumulative oil production in a block-scale and reservoir-scale models, respectively.
  Finally, changes in the hydrodynamic properties of Berea sandstone, Indiana limestone, and an artificially fractured carbonate specimen from the middle Devonian Calumet member of the Waterways formation (Foster Creek North project, Alberta) at a constant temperature of 40⁰C were reported as isotropic effective confining stress was increased from 10MPa to 30MPa. Through a novel consecutive approach, porosity, absolute permeability, drainage relative permeability, and drainage capillary pressure were shown to change, systematically, with increases in effective stress. The relative permeability measurements were taken using a steady-state method for the N2/water fluid pair. A second method, in which a saturated core/fracture with the wetting phase was flushed with the non-wetting phase at an increasing flow rate, was used to determine the drainage dynamic capillary pressure. Gas separation units and mass balance were used to determine core saturation. Additionally, we used X-ray computed micro-tomography and micro-scale proxy model to quantify the stress-dependent structure and shape of the pores, together with the pore size distribution and two metrics (fractal dimension and degree of anisotropy). Using micro-scale investigation techniques, we recognized a leftward shift in pore size distribution and closure of micro-channels to be responsible for the systematic core-scale changes in multiphase flow properties with effective stress.

• Subjects / Keywords

  • Capillary Pressure
  • Geomechanics
  • Multiphase Fluid Flow
  • Fractured Carbonate Reservoir
  • Relative Permeability

• Graduation date

  Spring 2020

• Type of Item

  Thesis

• Degree

  Doctor of Philosophy

• DOI

  https://doi.org/10.7939/r3-zar3-xn07

• License

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