An Analytic Model for Analyzing the Effects of Dissociation of Hydrates on the Thermal Recovery of Heavy Oils
- Vidyadhar A. Kamath (U. of Alaska) | Sanjay P. Godbole (U. of Alaska)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- May 1988
- Document Type
- Journal Paper
- 449 - 456
- 1988. Society of Petroleum Engineers
- 5.4.6 Thermal Methods, 5.9.2 Geothermal Resources, 5.2.1 Phase Behavior and PVT Measurements, 5.4.10 Microbial Methods, 5.9.1 Gas Hydrates, 6.5.5 Oil and Chemical Spills, 4.6 Natural Gas, 5.4.1 Waterflooding, 1.2.3 Rock properties, 4.3.1 Hydrates, 5.8.5 Oil Sand, Oil Shale, Bitumen, 2.4.3 Sand/Solids Control
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Summary. This paper presents an analytic model that includes the effects of the presence of hydrates in a thermal recovery process. The model considers continuous injection of steam into a reservoir containing an oil zone overlain by a hydrate zone. The model results indicate that, although part of the steam is consumed in dissociation of hydrates to gas and water and the dissociated hydrate zone acts as a thief zone for steam, there is a reduction in heat losses to the overburden because of the "insulation" effect of overlying hydrates. Thus, the net reservoir heat efficiency is not significantly affected by the presence of hydrates. Although the model does not address the effect of gas generated from hydrate dissociation, it is speculated that the dissolution of the gas will cause oil swelling, oil-viscosity reduction, and improved steamflood performance. performance. Introduction
The possibility of sharing the existing Kuparuk River Unit, North Slope, Alaska, facilities has made the future recovery of the heavy-oil sand in West Sak and tar sands in Ugnu a near-term target. West Sak sands alone contain about 15 x 10(9) to 25 x 10(9) bbl [2.4 x 10(9) to 4 x 10(9) m3] of Class 1 heavy crude (16 to 23API (0.96 to 0.92 g/cm3]), whereas the shallower, lower Ugnu formation contains 6 x 10(9) to 11 x 10(9) bbl [0.95 x 10(9) to 1.7 x 10(9) m3] of heavier Class 2 crude characterized as tar-sand bitumen. Recent studies indicate that the gas hydrates may also coexist with the shallower oils in the southwest updip portion of these reservoirs. The objective of this study was to develop an analytic model to evaluate the effects of the presence of gas hydrates on heavy-oil recovery during a steamflooding process. A steamdrive model has been modified to incorporate hydrate dissociation. For modeling purposes, a layered hydrate/oil configuration was considered. Various possible effects caused by the presence of gas hydrates are qualitatively discussed. An approximate analytic solution has been obtained for the complex hydrate dissociation heat-transfer problem. Temperature profiles in the hydrate zone, volume of dissociated hydrates, profiles in the hydrate zone, volume of dissociated hydrates, steam-zone volume, and moving hydrate-dissociation fronts have been determined analytically. To quantify the effects of the presence of gas hydrates on steamflood performance, three cases were studied. In the first case, a layered hydrate/oil configuration was considered. In the other two cases, a conventional steamflood without hydrates was considered. For all the cases, steam-zone growth, reservoir heat efficiency, cumulative oil recovery, and oil/steam ratios (OSR's) are computed and compared.
The shallow West Sak and Ugnu sands in the Kuparuk River Unit contain 26 X 10(9) to 44 x 10(9) bbl [4.1 x 10(9) to 7 x 10(9) m3] of heavy crude. Because these heavy crude oils are not recoverable by primary and secondary recovery techniques, oil companies have developed BOR techniques. Arco Alaska, one of the major operators in the West Sak field, is concentrating on developing a commercial thermal recovery technique and has carried out a hot-waterflooding pilot. pilot. Features of Heavy-Oil Reservoirs, West Sak and Ugnu are the primary heavy-oil-bearing reservoirs in the Kuparuk River region. primary heavy-oil-bearing reservoirs in the Kuparuk River region. Oil-trapping mechanisms and geology for these reservoirs are described in Refs. 8 through 10. The deeper West Sak reservoir, a thin Cretaceous sand overlying the Kuparuk River pay zone, encompasses a 200- to 250-sg-mile [518- to 647-km2] area and is estimated to contain 15 x 10(9) to 25 x 10(9) bbl [2.4 x 10(9) to 4 x 10(9) m3] of heavy crude. These sands have been characterized as finegrained, quartzose, well-sorted, subangular, and very friable. This transitional unit extends from the underlying Upper Cretaceous marine shales of Seabee formation to the younger Upper Cretaceous nonmarine sandstone of Prince Creek formation. In West Sak Well 1, these sands occur in the interval at a measured depth of 3,744 to 4,040 It [1140 to 1230 m]. West Sak crudes exhibit very high sulfur content (1.82%), a C4 and lighter hydrocarbon yield of 0.63%, and API gravities of from 16 to 23API [0.96 to 0.92 g/cm3]. The reservoir porosity is less than 20%, and the permeability is 10 to 140 md. permeability is 10 to 140 md. The shallower Ugnu sands have been described as tar sands and are predominantly fine-to-medium-grained, well-sorted, quartz, chert, and volcanic rock fragments. The Ugnu sands are divided into two zones: the deeper zone (Lower Ugnu), estimated to contain 6 x 10(9) to 11 x 10(9) bbl [0.95 x 10(9) to 1.7 x 10(90 m3], and the shallower zone (Upper Ugnu), estimated to contain 5 x 10(9) to 8 x 10(9) bbl [0.8 x 10(9) to 1.3 x 10(9) m3] of tar-sand bitumen. The crude in these sands is much heavier (8 to 12API [1 to 0.99 g/cm3]) and biodegraded. The reservoir is highly permeable and has a porosity of 25%.
Gas-Hydrate/Heavy-Oil Relationship. Gas hydrates are crystal-line, solid compounds composed of natural gas and water in which the gas molecules are enclathrated in the solid water lattice. The pressure and temperature conditions on the North Slope are suitable for gas-hydrate formation. Godbole et al. and Kamath et al. have determined the hydrate stability field on the North Slope. Although the areal extent of gas hydrate's in Ugnu and West Sak has not been delineated, several wells in these reservoirs have indicated the presence of gas hydrates. Holder et al., in a laboratory study, obtained crude oil samples from West Sak Well 1 and mixed it with natural gas, hexane, and decane. The gas/oil mixture was placed in a pressure cell, and hydrate-forming conditions and bubblepoint pressures were determined. Their study demonstrated that the loss of C1 to C4 fractions in the West Sak crude could have occurred as a result of gas-hydrate formation. Recently, Collett examined interrelationships between gas hydrates and heavy-oil occurrence in this field. His study showed that the gas hydrates are in conjunction with heavy oils in the southwest updip continuation of West Soak and Ugnu reservoirs. For these reasons, this study is aimed at determining the implications of the presence-of gas hydrates on heavy-oil recovery by thermal recovery techniques.
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