|Verification Of Capillary Pressure Functions And Relative Permeability Equations For Modeling Gas Production From Gas Hydrates||Last Reviewed 6/24/2013|
The goal of this project is to verify and validate the capillary pressure functions and relative permeability equations that are frequently used in hydrate numerical simulators. In order to achieve this goal, numerical simulation using a network model will be used to suggest fitting parameters, modify existing equations or, if necessary, develop new equations for better simulation results.
Wayne State University, Detroit, MI 48202-3622
Numerical simulation is used to estimate and predict long-term behavior of hydrate-bearing sediments during gas production [Kurihara et al., 2008; Moridis et al., 2009; Moridis et al., 2005; Moridis and Regan, 2007a; Moridis and Regan, 2007b; Anderson et al., 2011, Myshakin et al., 2011; Myshakin et al., 2012]. Numerical simulators for gas hydrate are very complicated programs that include many equations and parameters, and two of the most important ones are the capillary pressure function and relative permeability equation. Permeability is the most important characteristic for predicting the gas production rate during gas hydrate development [Johnson et al., 2011; Minagawa et al., 2004; Mingawaga et al., 2007; Kleinberg et al., 2003]. Permeability governs the production rate of water as well; therefore, enhancing the ability of hydrate simulators to predict gas and water production rates is predicated on determining the proper parameters for a capillary pressure function and generating a relative permeability equation.
Capillary pressure functions and relative permeability equations originate from unsaturated soil mechanics [Corey 1954; Brooks and Corey, 1964; Stone, 1970; van Genuchten, 1980]. These equations require empirical parameters and several studies have been conducted to experimentally determine these parameters in the laboratory [Wösten et al., 1999].
However, in all experiments performed in those conventional studies, water and gas were injected from one boundary of the specimen to the other (a completely different gas generation mechanism from that observed during hydrate dissociation). When gas hydrate dissociates, gas nucleates from several pores inside sediments. In other words, gas is generated from within sediments instead of being pushed into the sediments from without. This different gas generation mechanism may result in totally different gas permeabilities during gas invasion and nucleation.
A laboratory experiment to obtain fitting parameters for capillary pressure functions and relative permeability equations is very complex as it is difficult to control hydrate saturation and measure gas and water permeability at different saturations under high-pressure conditions [Kneafsey et al. 2011]. Conducting experiments under high-pressure conditions necessitates large-scale experimentation in a large, high-pressure chamber to produce more reliable data for gas flow.
An alternative method of estimating fitting parameters for capillary pressure functions and relative permeability equations during hydrate dissociation is history matching to in situ tests. A few short-term field-scale gas hydrate production tests were performed to evaluate depressurization and thermal stimulation methods at Mallik [Kurihara et al., 2005; Kurihara et al., 2008; Dallimore and Collett, 2005; Dallimore et al., 2008; Yamamoto and Dallimore, 2008]. Short-term field tests conducted in permafrost hydrate-bearing sediments such as Mallik [Hancock et al., 2005] and Mt. Elbert [Anderson et al., 2011] provided valuable information needed to derive parameters for relative permeability and characteristic curve (capillary pressure function) [Myshakin et al., 2011]. Because each hydrate reservoir has unique characteristic properties that affect gas production [Myshakin et al., 2012], it is not economical to conduct in situ testing at every hydrate-bearing reservoir to determine the fitting parameters. However, the parameters for relative permeability embedded in several numerical simulators could be verified to determine whether they correctly represent hydrate dissociation conditions.
This project will include a pore-network model simulation to predict the parameters for capillary pressure functions and relative permeability equations appropriate to simulate hydrate dissociation. The results of this research will support the collaborative efforts [e.g., Wilder et al., 2008; Anderson et al., 2011] to compare several existing numerical simulators.
The tools and values for numerical simulators produced through this research will help to determine bottomhole pressure, predict more accurate production rates of methane and water, and facilitate the selection of hydrate reservoirs for economic development. In addition, parameters obtained by numerical simulation could reduce the cost to perform in situ testing to calibrate numerical simulators.
The grain size distribution, effective stress, and porosity of hydrate-bearing sediments have been compiled from literature and used as input parameters for discrete element model (DEM) simulations to generate three-dimensional sediment packing similar to in situ hydrate-bearing sediments.
The project team extracted an image of pore space numerically from the three-dimensional sediment packing generated by DEM simulation. Then, using available algorithms [Al-Kharusi and Blunt, 2007; Dong and Blunt, 2009; Jiang et al., 2007], pore-network models were generated based on the image of the pore space. The generated pore-network models consist of several pores connected at pore throats.
Current Status (June 2013)
Researchers are using a generated pore network model to exactly represent the pore space of in situ hydrate-bearing sandy sediments. Currently, the project team is developing the algorithm to simulate gas invasion, gas expansion from hydrate dissociation, and relative permeability.
Project Start: October 1, 2012
Project End: September 30, 2014
Project Cost Information:
DOE Contribution: $177,315
Performer Contribution: $44,714
NETL ? John Terneus (John.Terneus@netl.doe.gov or 304-285-4254)
Wayne State University ? Jaewon Jang (firstname.lastname@example.org or 313-577-3854)
Quarterly Research Performance Progress Report [PDF-1.50MB] - Period ending 12-31-2012