Direct Relative Permeability Measurement Method from Transient Saturation Profiles

Physical Sciences : Petroleum

Available for licensing

Inventors

  • David DiCarlo, Ph.D.
  • Amir Kianinejad, M.S. , Center for Petroleum and Geosystems Engineering
  • Xiongyu Chen , Center for Petroleum and Geosystems Engin

Background/unmet need

The cost-effective recovery of remaining oil in place from previously water-flooded reservoirs is dependent upon accurate subsurface modeling and subsequent simulation of the expected flow of fluids in-situ.

Simulation and modeling of complex multiphase flow processes such as enhanced oil recovery requires exact determination of relative permeability of the reservoir rock with regards to the different existing liquid phases (water/oil/gas). Routine steady-state measurement methods are time-consuming, expensive, and require assumptions and/or interpretations which may not necessarily hold. Current methods provide only a limited number of data points on a produced relative permeability curve. Results produced by these steady-state methods also suffer from data corruption caused by capillary end effects, which cause relative permeability data to be smaller than the actual value.

Consequently, it is necessary to develop an efficient and accurate unsteady-state measurement method for relative permeability that avoids data corruption by capillary end effects and provides a more detailed relative permeability curve.

Invention Description

Researchers at The University of Texas propose a new experimental design and fractional flow analysis that address existing shortcomings. Measurement of reservoir permeability from in-situ saturations along core samples during unsteady-state flooding experiments accurately determine relative permeability by allowing problematic sections of a saturation profile, such as capillary end effects and organic saturation changes, to be detected and discarded from data.

The invented methodology also caters to measurement of phase fluxes in multiphase core flood experiments, in which capillary end effects are a prominent factor in data distortion. Relative permeability is measured from the upstream sections of a core rather than its capillary-dominated exit section. Measurements of pressure drop, saturation, and phase flux during the unsteady-state portion of two-phase core flood experiments are the key parameters from which a more accurate relative permeability can be determined without capillary end effects.

Ultimately, a relative permeability curve can be produced in a shorter amount of time and with accurate data that is consistent with that of steady-state methods but available in greater quantities.

Benefits/Advantages

  • Improved simulation of real-life reservoir processes
  • Accounts for freely changing organic phase saturations
  • Accounts for capillary end effects, especially in low viscosity fluids such as carbon dioxide
  • Produces relative permeability curves with 10X more data points than those produced by steady-state methods
  • Greater control of saturation paths over a three-phase saturation space
  • Can determine individual relative permeabilities for each flowing phase in a multiphase core
  • Rapid and inexpensive measurements

Features

  • Obtains fractional flow profiles along a core over time
  • Measurement of in-situ saturation profiles allows for discarding of corrupted data
  • Direct calculation with no assumptions/interpretations required
  • Can be used for any type of rock and/or fluid
  • Equally applicable to two- and three-phase systems
  • Allows measurements of extremely small relative permeability values (0.0001 to 0.00001 darcy)

Market potential/applications

The U.S. Department of Energy (DOE) reports that primary and secondary recovery methods leave over 60% of the original oil in the ground. Petroleum and environmental companies seek out enhanced oil recovery methods in a rapidly growing market to produce this remaining oil from mature reservoirs to meet the increasing demand for oil and gas. All the enhanced oil recovery processes involve multiphase flow in complex environments, and relative permeability of each flowing phase is essential to model and predict the performance of such processes. Consequently, methods for quick, accurate, and representative determination of relative permeabilities are essential for the industry.

Development Stage

Proof of concept