PHASE BEHAVIOR AND RELATIVE PERMEABILITY OF GAS-WATER-HYDRATE SYSTEM

N.J. Jaiswal¹, J.V. Westervelt¹, S.L. Patil¹, A.Y. Dandekar¹, N.R. Nanchary¹, P. Tsunemori¹, and R.B. Hunter²
¹University of Alaska, Fairbanks, Alaska
²ASRC Energy Services, Anchorage, Alaska

Potentially large natural gas hydrate accumulations with some associated free gas exist in the Eileen trend of the Prudhoe Bay Unit (PBU), the Kuparuk River Unit (KRU) and the Milne Point Unit (MPU) areas on the Alaska North Slope (ANS). The evaluation of this potential unconventional gas resource is aligned with increasing industry interest in ANS conventional gas resources. The Eileen trend may contain as much as 37 to 44 trillion cubic feet of in-place gas hydrate (Collett, 1993). Although the formation of natural gas-hydrate is imprecisely known, permeability measurements of laboratory sediment samples containing gas hydrate may help clarify the natural processes. To help bring this potential resource to production requires study of the ANS gas hydrate stability and reliable measurement of relative permeability functions for gas hydrate systems. The study of these gas hydrates is part of an ongoing effort to solve technical issues and to help determine if gas hydrates may become a viable energy alternative.

While there is not a lack of data available on the phase behavior of gas hydrates, there is relatively little information on gas hydrate formation and dissociation within porous media. In this study, formation and dissociation of gas hydrates with and without the presence of porous media is characterized at or near reservoir conditions. The measurements were carried out in high-pressure cells, using fresh water and typical formation brines to form the water-lattice structures. Pressure results are converted to depth and then used to develop gas hydrate stability zones. In addition to the phase behavior study, an experimental apparatus is designed and developed for measurements of two-phase (gas- gas hydrate-water) relative permeabilities. The equipment and test procedures used to form gas hydrate in sediment can affect these types of measurements. Measurement of relative permeabilities on synthetic or model gas hydrate core plugs is done by the unsteady-state technique with formation water saturated core plugs. In addition to the novel method to form gas hydrates in presence of confining pressure, the relative permeability characteristics of gas hydrate specimens are reported.

Experiments were conducted for pressures of 1500, 1200, 900, 600, and 300 psia by sapphire and porous media testing cells to characterize the formation/dissociation of gas hydrates. Gas hydrates were formed using pure methane and 2 or 4% of brine under controlled P-T conditions. During gas hydrate formation without the presence of porous media, a mixer mixed the fluids to ensure the methane was well mixed with the water. Once the gas hydrates were formed, the airbath temperature was gradually increased by 0.2°F every 15 minutes to understand the decomposition behavior. This study was based on measuring pressure and temperature conditions for gas hydrate formation and dissociation. In addition to this, formation/decomposition experiments on the synthetic gas hydrate-bearing porous media were carried out in a porous media cell. The methane was injected into the cell and temperatures were set 5° to 10° F below the predicted equilibrium temperatures for a given pressure anywhere from 6 to 12 hours. The amount of time was dependent on analyzing the pressure change to ensure that gas hydrates had indeed formed. With the formation of gas hydrates, the temperature was set to raise by 0.2° F every 15 minutes. As gas dissociates from the gas hydrates, produced methane increases the pump pressure. To maintain a constant pressure requires decreasing the pump displacement. The two most important variables that were recorded were the pump displacement used to maintain pressure and the time. These two variables were cross-plotted. The point in the graph illustrating a sudden change in slope corresponds to the initiation of gas hydrate dissociation. The P-T data for the gas hydrate phase behavior experiment was obtained by analyzing pressure maintenance during the gas hydrate dissociation. At each pressure multiple experiments were conducted to show repeatability and reproducibility. Using the geothermal gradients of given well-log data and an average pressure gradient of 0.433 psia/ft, the gas hydrate stability zones (GHSZ) were determined.

The phase diagrams in Westervelt (2004) illustrate typical conditions in a region of arctic permafrost (with depth of permafrost assumed to be 1600 ft). The overlap of the phase boundary and temperature gradient indicates that the GHSZ should extend from a depth of approximately 650 ft to slightly more than 2000 ft. In the presence of a porous media typically found on the ANS, the maximum depth of the gas hydrate stability zone was 2550 ft and was at the eastern most well (NHST). The minimum depth of 1900 feet was located at the northern most well (WK-11). The results from this study also show that the HSZ in the Alaska North Slope (ANS) thins to the west. Experiments carried out on a porous media sample provided by Anadarko Corporation showed that a 2% increase in formation brines only decreases the thickness of the gas hydrate stability zone by 35 to 50 feet. Problems arose in achieving reliable results when conducting experiments below 400 psia. This was assumed to be attributed to the formation/dissociation temperature being below the freezing point of water.

GHSZ for the NW Eileen State 2 well drilled by ARCO and Exxon in 1972 (see Collett, 1983; Mathews, 1985, for details) ranges from 1900-2550 feet and by Collett (1993) exists between 1890-2210 feet. In this study, the predicted GHSZ ranges from approximately 650-2425 feet and is in agreement with Lachenbruch’s data (1987) as shown in Figure 1.

Although no laboratory method can approach the time required to form natural gas hydrate, our experiment design allows gas hydrate to form in porous media over relatively long periods of time and allows measurement of relative permeability.

Initially, the consolidated sand core was completely water saturated at 150 psia external pressure. The system was closed from both ends and confining pressure was increased to around 1400 psia. High pressure, cold (41°F) methane gas was slowly percolated into the water saturated sediment until a predetermined amount of water was displaced and then the temperature was lowered by 39.2-41°F/hour rate until reaching 34.7°F. This temperature was maintained for 10-12 hours. Internal sediment pore pressure was maintained at lower values relative to the external confining pressure to impart an isotropic consolidation stress, thereby simulating in situ overburden pressure. As the temperature moved closer to gas hydrate equilibrium condition, the gas hydrate formation is initiated, corresponding to a sudden consumption of methane. Since the reaction was carried out at T>32°F, the reaction system clearly consists of only three phases at any time. Methane forms the gas phase, water forms the liquid phase, and the product gas hydrate forms the solid phase. After sufficient laboratory time, the lower end valve was opened to remove un-reacted water by gas flooding. The system is then water flooded (Winters et al, 2002) to measure effective permeability. Relative permeability measurements are performed by the unsteady state method. Cold methane was injected to displace water. Pressures, flow rate and fluid volumes from the syringe pumps, and the pressure drop through the specimen were measured with a variable range differential pressure transducer or by comparing pressure differences between syringe pumps and back pressure. After experiment completion, the system temperature was raised to dissociate gas hydrate and additional gas was injected to remove dissociated water. The recorded increase in weight of sand from initial dry weight was adjusted for irreducible water saturation (12%). Both constant flow rates and constant head methods were used for this study.

Results from the relative permeability experiment are presented in Figure 2. The effective permeability and relative permeability data for different saturation values were measured. Although some dissociation of gas hydrate occurs due to differential pressure across the core, the low temperature decreases the rate of gas dissociation. A gas flow meter was continuously monitored to ensure gas hydrates were not dissociating. To confirm that the gas hydrates were not dissociated during the experiment, after the conclusion of the relative permeability experiment, the system temperature was allowed to increase above the gas hydrate dissociation temperature. High rates of gas produced from core above the dissociation temperature confirmed the presence of gas hydrates during the preceding relative permeability experiment.

In summary, a new method for measuring gas-water relative permeability for laboratory synthesized hydrate has been developed. Considerable additional experimental and theoretical work is needed to develop an analytical or generalized model to predict relative permeability for gas hydrate reservoir simulation. The experimental data obtained from this work will allow us to identify gas hydrate stability zones, determine flow behavior and develop techniques for safe production of natural gas from gas hydrates.

Acknowledgements and Disclaimer:

The University of Alaska Fairbanks contribution is part of a larger collaborative program that includes researchers from the University of Arizona and the U.S. Geological Survey. BP Exploration (Alaska), Inc. provides overall project coordination and provided data for reservoir characterization and modeling efforts. Reservoir modeling software was made available through support from Computer Modeling Group for CGM STARS. This research was funded by the Department of Energy (Award # DE-FC-01NT41332). The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.

References

Collett, T.S., 1983, Detection and evaluation of natural gas hydrates from well logs, Prudhoe Bay, Alaska: University of Alaska, Fairbanks, unpublished M.S. thesis, 78 p. Also published in 1983 in condensed form, in 4th international permafrost conference proceedings: National Academy Press, Washington, D.C., p. 169-174.

Collett, T.S., 1993. "Natural Gas Hydrates of the Prudhoe Bay and Kuparuk River Area, North Slope, Alaska", The American Association of Petroleum Geologist Bulletin, Vol. 77, No. 5, pp. 793-812.

Lachenbruch, A.H., Galanis Jr., S.P., and Moses Jr., T.H., 1987." A Thermal Cross Section for the Permafrost and Hydrate Stability Zones in the Kuparuk and Prudhoe Bay Oil Fields", Geologic Studies in Alaska by the U.S. Geological Survey during 1987, 1988, pp. 48-51.

Mathews, M.A., and von Huene, R., 1985, Site 570 methane hydrate zone, in S. Orlofsky, ed., Deep Sea Drilling Project Initial Reports, v. 84: U.S. Government Printing Office, p. 773-790.

Westervelt, J.V., 2004. "Determination of methane hydrate stability zones in the Prudhoe Bay, Kuparuk River, and Milne Point units on the North Slope of Alaska". MS Thesis, University of Alaska Fairbanks, Fairbanks, AK.

Winters, W. J.,Waite, W. F., Mason, D. H., and Pecher, I. A., 2002. “Sediment Properties Associated With Gas Hydrate Formation”, Proceedings of the fourth International Conference on Gas Hydrates, Yokohama, May 19-23.

Figure 1. A Comparison of predicted GHSZ by various authors.