Cyclic Hysteresis of Three-Phase Relative Permeability Curves Applicable to WAG Injection under Low Gas/Oil IFT: Effect of Immobile Water Saturation, Injection Scenario and Rock Permeability

This study developed a data-driven forecasting tool that predicts petrophysical properties from rate-transient data. Traditional estimations of petrophysical properties, such as relative permeability (RP) and capillary pressure (CP), strongly rely on coring and laboratory measurements. Coring and laboratory measurements are typically conducted only in a small fraction of wells. To contend with this constraint, in this study, we develop artificial neural network (ANN)-based tools that predict the three-phase RP relationship, CP relationship, and formation permeability in the horizontal and vertical directions using the production rate and pressure data for black-oil reservoirs. Petrophysical properties are related to rate-transient data as they govern the fluid flow in oil/gas reservoirs. An ANN has been proven capable of mimicking any functional relationship with a finite number of discontinuities. To generate an ANN representing the functional relationship between rate-transient data and petrophysical properties, an ANN structure pool is first generated and trained. Cases covering a wide spectrum of properties are then generated and put into training. Training of ANNs in the pool and comparisons among their performance yield the desired ANN structure that performs the most effectively among the ANNs in the pool. The developed tool is validated with blind tests and a synthetic field case. Reasonable predictions for the field cases are obtained. Within a fraction of second, the developed ANNs infer accurate characteristics of RP and CP for three phases as well as residual saturation, critical gas saturation, connate water saturation, and horizontal permeability with a small margin of error. The predicted RP and CP relationship can be generated and applied in history matching and reservoir modeling. Moreover, this tool can spare coring expenses and prolonged experiments in most of the field analysis. The developed ANNs predict the characteristics of three-phase RP and CP data, connate water saturation, residual oil saturation, and critical gas saturation using rate-transient data. For cases fulfilling the requirement of the tool, the proposed technique improves reservoir description while reducing expenses and time associated with coring and laboratory experiments at the same time.

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Three-Phase Relative Permeability and Hystresis Model for Simulation of Water Alternating Gas (WAG) Injection

10.2118/152218-ms ◽

2012 ◽

Cited By ~ 8

Author(s):

Hamidreza Shahverdi ◽

Mehran Sohrabi

Keyword(s):

Relative Permeability ◽

Water Alternating Gas ◽

Three Phase ◽

Wag Injection

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Three-Phase Relative Permeability and Capillary Pressure Models With Hysteresis and Compositional Consistency

SPE Journal ◽

10.2118/191384-pa ◽

2018 ◽

Vol 23 (06) ◽

pp. 2394-2408 ◽

Cited By ~ 2

Author(s):

Sajjad S. Neshat ◽

Gary A. Pope

Keyword(s):

Capillary Pressure ◽

Relative Permeability ◽

Numerical Stability ◽

Physical Parameters ◽

Gas Oil ◽

Water Alternating Gas ◽

Three Phase ◽

Minimum Number ◽

Trapping Number ◽

New Formulation

Summary New coupled three-phase hysteretic relative permeability and capillary pressure models have been developed and tested for use in compositional reservoir simulators. The new formulation incorporates hysteresis and compositional consistency for both capillary pressure and relative permeability. This approach is completely unaffected by phase flipping and misidentification, which commonly occur in compositional simulations. Instead of using phase labels (gas/oil/solvent/aqueous) to define hysteretic relative permeability and capillary pressure parameters, the parameters are continuously interpolated between reference values using the Gibbs free energy (GFE) of each phase at each timestep. Models that are independent of phase labels have many advantages in terms of both numerical stability and physical consistency. The models integrate and unify relevant physical parameters, including hysteresis and trapping number, into one rigorous algorithm with a minimum number of parameters for application in numerical reservoir simulators. The robustness of the new models is demonstrated with simulations of the miscible water-alternating-gas (WAG) process and solvent stimulation to remove condensate and/or water blocks in both conventional and unconventional formations.

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Lowering the phase-trap damage in tight-gas reservoirs by using interfacial tension (IFT) reducers

The APPEA Journal ◽

10.1071/aj12031 ◽

2013 ◽

Vol 53 (1) ◽

pp. 363

Author(s):

Yangfan Lu ◽

Hassan Bahrami ◽

Mofazzal Hossain ◽

Ahmad Jamili ◽

Arshad Ahmed ◽

...

Keyword(s):

Relative Permeability ◽

Reservoir Simulation ◽

Water Saturation ◽

Tight Gas ◽

Gas Reservoirs ◽

Tight Gas Reservoirs ◽

Water Based ◽

Tight Formations ◽

Tight Reservoirs ◽

Relative Permeability Curves

Tight-gas reservoirs have low permeability and significant damage. When drilling the tight formations, wellbore liquid invades the formation and increases water saturation of the near wellbore area and significantly deceases permeability of this area. Because of the invasion, the permeability of the invasion zone near the wellbore in tight-gas formations significantly decreases. This damage is mainly controlled by wettability and capillary pressure (Pc). One of the methods to improve productivity of tight-gas reservoirs is to reduce IFT between formation gas and invaded water to remove phase trapping. The invasion of wellbore liquid into tight formations can damage permeability controlled by Pc and relative permeability curves. In the case of drilling by using a water-based mud, tight formations are sensitive to the invasion damage due to the high-critical water saturation and capillary pressures. Reducing the Pc is an effective way to increase the well productivity. Using the IFT reducers, Pc effect is reduced and trapped phase can be recovered; therefore, productivity of the TGS reservoirs can be increased significantly. This study focuses on reducing phase-trapping damage in tight reservoirs by using reservoir simulation to examine the methods, such use of IFT reducers in water-based-drilled tight formations that can reduce Pc effect. The Pc and relative permeability curves are corrected based on the reduced IFT; they are then input to the reservoir simulation model to quantitatively understand how IFT reducers can help improve productivity of tight reservoirs.

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Insights, Trends and Challenges Associated with Measuring Coal Relative Permeability

E3S Web of Conferences ◽

10.1051/e3sconf/20198901004 ◽

2019 ◽

Vol 89 ◽

pp. 01004

Author(s):

Dylan Shaw ◽

Peyman Mostaghimi ◽

Furqan Hussain ◽

Ryan T. Armstrong

Keyword(s):

Relative Permeability ◽

Effective Stress ◽

History Matching ◽

Water Saturation ◽

Laboratory Data ◽

Stress Regime ◽

Cross Point ◽

Irreducible Water Saturation ◽

Relative Permeability Curves ◽

The Right

Due to the poroelasticity of coal, both porosity and permeability change over the life of the field as pore pressure decreases and effective stress increases. The relative permeability also changes as the effective stress regime shifts from one state to another. This paper examines coal relative permeability trends for changes in effective stress. The unsteady-state technique was used to determine experimental relativepermeability curves, which were then corrected for capillary-end effect through history matching. A modified Brooks-Corey correlation was sufficient for generating relative permeability curves and was successfully used to history match the laboratory data. Analysis of the corrected curves indicate that as effective stress increases, gas relative permeability increases, irreducible water saturation increases and the relative permeability cross-point shifts to the right.

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