|Comparative Assessment of Advanced Gas Hydrate Production Methods||Last Reviewed 09/23/2009|
The goal of this project is to compare and contrast, through numerical simulation, conventional and innovative approaches for producing methane from gas hydrate-bearing geologic reservoirs. Numerical simulation is being used to assess the production of natural gas hydrates from geologic deposits using three production technologies: 1) depressurization, 2) direct CO2 exchange, and 3) dissociation-reformation CO2 exchange.
Battelle Pacific Northwest Division, Richland, Washington 99352
There are relatively few published studies of commercial production methods for gas hydrates, and all of these studies have examined essentially conventional production concepts; principally depressurization coupled with some form of thermal stimulation. An Enhanced Gas Hydrate Recovery (EGHR) process that utilizes a microemulsion of liquid CO2 and water to decompose methane hydrate in situ and produce free gas (see Fire in the Ice Newsletter, Winter 2005, "New Method May Hold Promise For Gas Hydrate Production and Carbon Sequestration") has been successfully demonstrated in laboratory-scale experiments with gas hydrate bearing sediments. While these laboratory-based studies are extremely encouraging, the technology will remain a laboratory curiosity unless the necessary work is performed to scale up the process and an optimum injection strategy at reservoir scale is developed. Hence, this project will conduct a reservoir modeling assessment that compares and contrasts the EGHR process with conventional methods of gas hydrate production. The results will provide an evaluation of the merits of the process relative to conventional production methods, from energy balance and reservoir engineering perspectives. This is an essential intermediate step that is required before substantial DOE and industry investment can be made in the design, engineering, manufacturing, and testing of a full-scale downhole tool suitable for field deployment in pilot-scale production tests.
This project will provide two important contributions towards understanding methane hydrate production. First, basic reservoir modeling of hydrate production under various parametric combinations will provide a much better understanding of the process of methane hydrate dissociation and the migration of methane towards the wellbore. Second, modeling of the application of a variety of production augmentation methods will support continued evaluation of the potential for economic production of natural gas from methane hydrates.
The STOMP-HYD simulator was applied to a series of one- and two-dimensional simulations that investigated the production of CH4 hydrates in geologic media using CO2 injection. Effectively there are two approaches to producing CH4 hydrate in geologic media using CO2 injection: 1) hydrate dissociation and reformation, and 2) direct molecular exchange. In the hydrate dissociation and reformation approach, the injected CO2 first dissociates CH4 hydrate. This stage is followed by reformation of a mixed gas hydrate, which is predominately comprises CO2. In the direct molecular exchange approach, the injected CO2 exchanges with the CH4 in the hydrate structure, maintaining the hydrate integrity. The dissociation-reformation approach has the advantage of releasing CH4 in both the small and large cages. In the direct-exchange approach only the CH4 in the large cages is released. Co-injection of CO2 and N2 has been shown to allow molecular exchange of CH4 in both the small and large cages. Because the STOMP-HYD simulator does not track small- and large-cage occupancies, it is not currently capable of limiting CO2 exchange with CH4 to large cages. The principal conclusion from this series of simulations was that both CO2 exchange approaches yielded faster production times, but lower CH4 recoveries over pure water injections. Without consideration of the cage occupancies, the direct-exchange yielded faster production times over the dissociation-reformation approach, with nearly equivalent CH4 recoveries. CO2 to water ratios in the injectant primarily affected production rates, with higher ratios yielding faster productions.
One- and two-dimensional simulations have been completed. Whereas, the 1-dimensional simulations were directed at understanding the thermodynamic and transport processes associated with the EGHR process for producing CH4 gas hydrates, the 2-dimensional simulations are more concerned with formation properties and well configurations. The petrophysical parameters for the simulations are based on those determined from the MDT flow and recovery tests in the C Unit of the Mount Elbert Well and the subsequent simulations of those experiments using STOMP-HYD.
Simulations that assume a five-spot well configuration (100-m spacing on production wells) of a 1 meter thick hydrate-bearing sandstone reservoir with zero flux upper and lower boundary conditions have been completed. To inhibit hydrate dissociation via thermal stimulation from heat transfer into the domain, the upper and lower boundaries were considered to be adiabatic. Pure CO2 was injected in the center well and CH4 was produced at the perimeter wells. To increase the formation permeability and lower the formation pressure, the initial stage of production involved depressurization of the formation from 6 MPa (at 3°C) to 3 MPa, which keeps the formation above the freezing point of water. This depressurization stage causes hydrate dissociation, which produced gas at all five of the wells. Following depressurization, pure CO2 is injected at 15°C at 1) 4 MPa, 2) 5 MPa, and 3) 6 MPa. At 4 MPa, the CO2 is a gas (i.e., 5.3°C saturation temperature); at 5 MPa the CO2 is a gas near the saturation line (i.e., 14.3°C saturation temperature); and at 6 MPa the CO2 is a liquid (22.0°C saturation temperature). Preliminary simulation results indicate that:
Recently a series of investigations have been conducted that consider production of Class 1 natural gas hydrate accumulations. The production parameters include injectant form and temperature, well pressure, screened intervals and formation permeability. The most promising scenarios for producing Class 1 natural gas hydrate accumulations appear to be those that produce a hydrate-free zone around the injection and extraction wells, but force flow through the hydrate zone. Maintaining reduced pressures around the extraction well creates a hydrate free zone through conventional depressurization. Results from these investigations were presented at the 9th International Greenhouse Gas Control Technologies Conference in Washington DC, November 16-20, 2008. To complete the Class 1 investigations, a suite of 216 simulations has been initiated for the upcoming Mount Elbert special edition to be published in the Journal of Marine and Petroleum Geology. The objective of this paper will be to describe a suite of production simulations that consider a matrix of production options.
One critical finding of Battelle's simulation modeling work to investigate methane hydrate production using CO2 exchange has been that the formation of secondary CO2 hydrate has the potential to halt the production process by inhibiting fluid migration. Laboratory experiments conducted by ConocoPhillips have suggested that complete exchange of CO2 and CH4 is possible without forming excessive secondary hydrate and while maintaining elevated hydrate saturations. To explore the differences between the numerical simulation results and the experimental observations of ConocoPhillips, a scientific team from ConocoPhillips visited Battelle. The key finding from this meeting was that pore-water salinity may play a strong role in the inhibition of secondary hydrate formation beyond certain saturation levels, which agree with recently published experimental results (McGrail et al. 2007).
This research has investigated two distinct approaches for producing gas hydrates with CO2 injection: 1) dissociation-reformation, and 2) direct guest molecule exchange. The efficacy of these production approaches have been compared and contrasted for the four hydrate classes suggested by Moridis (2003):
This project is now completed and the results are available in the Final Technical Report listed below under "Additional Information".
Project Start: April 15, 2006
Project End: June 30, 2009
DOE Contribution: $311,291
Performer Contribution: $78,709
NETL ? Robert Vagnetti (Robert.Vagnetti@netl.doe.gov or 304-285-1334)
Battelle ? Dr. Peter McGrail (email@example.com or 509-376-9193)
In addition to the information provided here, a full listing of project related publications and presentations as well as a listing of funded students can be found in the Methane Hydrate Program Bibliography [PDF].
Fire in the Ice Newsletter, Winter 2005, "New Method May Hold Promise For Gas Hydrate Production and Carbon Sequestration"
Technology Status Assessment [PDF-44KB]
Quarterly Progress Report ? April-July 2006 [PDF-23KB]
Quarterly Progress Report ? August-September 2006 [PDF-22KB]
Quarterly Progress Report ? October-December 2006 [PDF-23KB]
Quarterly Progress Report ? January-March 2007 [PDF-23KB]
Quarterly Progress Report ? April-June 2007 [PDF-73KB]
Quarterly Progress Report ? August-September 2007 [PDF-60KB]
Quarterly Progress Report ? October-December 2007 [PDF-61KB]
Quarterly Progress Report ? January-March 2008 [PDF-66KB]
Quarterly Progress Report ? April-June 2008 [PDF-96KB]
Quarterly Progress Report ? July-September 2008 [PDF-237KB]
Numerical Simulation of Methane Hydrate Production from Geologic Formations via Carbon Dioxide Injection [PDF-2.77MB] - paper presented at the Offshore Technology Conference, Houston, Texas, U.S.A., 5-8 May 2008 (OTC19458)
Quarterly Progress Report ? October-December 2008 [PDF-182KB]
Quarterly Progress Report ? January - March 2009 [PDF-102KB]
Final Project Report [PDF-7.45] - September 2009
Bhangale, A., T. Zhu, B. McGrail, and M. White, 2006, A model to predict hydrate equilibrium and hydrate saturation inside porous media including mixed CH4-CO2 hydrates, paper SPE 99759, proceedings of the SPE-Improved Oil Recovery Symposium.
McGrail, B., T. Zhu, and B. Hunter, 2005, New Method May Hold Promise for Gas Hydrate Production and Carbon Sequestration, U.S. DOE-NETL Fire in the Ice Newsletter, Winter, p. 8-11.
McGrail BP, S Ahmed, HT Schaef, AT Owen, PF Martin, and T Zhu. 2007. "Gas Hydrate Property Measurements in Porous Sediments with Resonant Ultrasound Spectroscopy." Journal of Geophysical Research - Solid Earth 112(B05202).
Phale H., T. Zhu, M. White, and B. McGrail, 2006, Simulation Study on Injection of CO2-microemulsion for Methane Recovery from Gas-Hydrate Reservoirs, paper SPE 100541, proceedings of the SPE Gas Technology Symposium.
White M. D, and B. P. McGrail. 2008. "Designing a Pilot-Scale Experiment for the Production of Natural Gas Hydrates and Sequestration of CO2 in Class 1 Hydrate Accumulations." In Proceedings of the 9th International Conference on Greenhouse Gas Control Technologies. PNWD-SA-8374, Battelle-Pacific Northwest Division, Richland, WA.
White, M.D. and B.P. McGrail. 2008. "Designing a pilot-scale experiment for the production of natural gas hydrates and sequestration of CO2 in Class 1 hydrate accumulations," Presented at the 9th International Greenhouse Gas Control Technologies Conference, November 18, 2008, Washington, D.C.
White, M.D. and McGrail, B.P., 2008, Numerical Simulation of Methane Hydrate Production from Geologic Formations via Carbon Dioxide Injection, presented at the Offshore Technology Conference, Houston, Texas, U.S.A., 5-8 May 2008 (OTC19458).
Zhu, T., B. McGrail, A. Kulkarni, M. White, H. Phale, S. Patil, and D. Ogbe, 2005, Development of a Thermodynamic Model and Reservoir Simulator for the CH4, CO2, and CH4-CO2 Gas Hydrate System, paper SPE 93976, proceedings of the AAPG/SPE Western Regional.
Bhangale, A., T. Zhu, B. McGrail, and M. White, 2006, A model to predict hydrate equilibrium and hydrate saturation inside porous media including mixed CH4-CO2 hydrates, Tulsa, OK, SPE-Improved Oil Recovery Symposium, April 22-26.
McGrail, B., H. Schaef, M. White, A. Owen, T. Zhu, and R. Hunter, 2005, Enhanced Gas Hydrate Recovery with CO2 Sequestration, Calgary, AB, Canada, The American Association of Petroleum Geologists Annual Convention, June 20.
McGrail, B., T. Zhu, R. Hunter, M. White, S. Patil, and A. Kulkarni, 2004, A New Method for Enhanced Production of Gas Hydrates with CO2, Vancouver, BC, Canada, The American Association of Petroleum Geologists Hedberg Research Conference, September 12-16.
Phale H., T. Zhu, M. White, and B. McGrail, 2006, Simulation Study on Injection of CO2-microemulsion for Methane Recovery from Gas-Hydrate Reservoirs, Calgary, AB, Canada, SPE Gas Technology Symposium, May 15-18.
Zhu, T., B. McGrail, A. Kulkarni, M. White, H. Phale, S. Patil, and D. Ogbe, 2005, Development of a Thermodynamic Model and Reservoir Simulator for the CH4, CO2, and CH4-CO2 Gas Hydrate System, Irvine, CA, AAPG/SPE Western Regional Meeting, March 30-April 1.