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Difference between revisions of "Compositional effects during immiscible gas injection"

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This page briefly discusses the various mass transfer compositional aspects of the immiscible gas/oil displacement process. The implications of these compositional effects are very dependent on the oil composition, the composition of the injected gas, and the surface facilities and pipelines available in a particular field situation. The injected gas/oil composition interactions can be categorized as either swelling effects (gas dissolving into the oil phase) or stripping effects (various components from the oil transferring to the gas phase).

Swelling compositional effects

The most obvious compositional effect in the immiscible gas/oil displacement process is that, if the oil is not saturated with gas at the reservoir pressure or if the reservoir pressure is increased as a result of the gas injection, the volume of gas dissolved in the oil will increase until the oil is saturated at that pressure. At the same time and because of the increased volume of gas in solution in the oil, the oil formation volume factor (FVF) will increase. This phenomenon, commonly called swelling, can increase the efficiency of the gas/oil displacement process.

The significance of the swelling effect is dependent on the oil reservoir situation. For an oil reservoir in which there is a gas cap, the underlying oil column will already be fully or nearly saturated with gas at the reservoir pressure. Hence, there will be very little impact on the gas/oil displacement process as a result of the interaction between the reservoir oil and injected gas. However, for an oil reservoir in which there is no gas cap and where the oil bubblepoint pressure is very low compared with the original reservoir pressure, the swelling effect can be a very significant part of the gas/oil displacement process. The Swanson River field (Cook Inlet, Alaska) is an example of this latter situation (original reservoir pressure, 5,580 psi; oil bubblepoint pressure, 1,350 psi).[1] The change in oil FVF from a bubblepoint of 1,350 psi to being saturated at 5,580 psi is from 1.21 to ≈1.80 RB/STB. The application of immiscible gas injection to the Swanson River field is discussed in Immiscible gas injection case studies.

In some of the simple calculation techniques discussed below, the swelling effect is included. In a "black oil" type of numerical reservoir simulator, the swelling effect is taken into account because, although there are only two hydrocarbon components (gas and oil) for the two hydrocarbon phases, the swelling effect is incorporated by means of the entered table of oil pressure/volume/temperature (PVT) properties (e.g., FVF, gas in solution, oil viscosity) as a function of pressure. In other words, in this type of reservoir simulator, the gas hydrocarbon component exists either as a free-gas phase or as gas dissolved in the oil; the oil hydrocarbon component exists only as part of the liquid phase. A compositional numerical reservoir simulator will automatically take the swelling phenomenon into account in its equation-of-state phase-behavior calculations. For detailed discussion of the various types of numerical reservoir simulators and their applications, see Compositional simulation of miscible processes.

Stripping compositional effects

The other key compositional aspect of the immiscible gas/oil displacement process is the vaporizing (or stripping) by the lean injected gas of some hydrocarbon components of the oil, particularly the intermediate hydrocarbon components (C3 through C8). In most cases, the injected gas is very lean natural gas that is the residue gas from a nearby gas processing plant and composed primarily of methane. At such gas processing plants, the propane and heavier hydrocarbon components typically have been condensed from the entering produced gas; in some cases, ethane is also extracted from the gas. Such a lean injected gas will, when in contact with the oil at reservoir conditions, vaporize various hydrocarbon components from the oil until the gas and oil phases have reached compositional equilibrium.

In immiscible gas/oil displacements using nitrogen (N2), carbon dioxide (CO2), or some combination of these gases (such as flue gas, 88% N2, 12% CO2), these nonhydrocarbon injected gases can also vaporize various hydrocarbon components until gas/oil equilibrium is reached at reservoir conditions. This phenomenon has been observed in the Hawkins nitrogen injection project. Nitrogen is not as efficient as methane at stripping hydrocarbon components from the oil. Carbon dioxide, because its phase behavior is much like that of propane, can vaporize a considerable amount of hydrocarbon components from the oil at reservoir conditions.

The significance of the stripping effect depends on the oil composition. Immiscible gas/oil injection projects have been applied to reservoirs with oil gravities from 24 to 43°API or more.[2][3][4] In all cases, the stripping effect increases the recovery of hydrocarbons from the oil reservoir, but lighter oils have a much greater percentage of their components vaporized by cycling gas through the reservoir and operating at higher gas/oil ratios (GORs).

In some of the simple calculation techniques discussed below, aspects of the stripping of oil by lean injected gas can be approximated. Black-oil numerical reservoir simulators cannot handle the vaporization of hydrocarbon components from the oil into the gas phase. A compositional numerical reservoir simulator must be used to quantify this effect for a particular oil/injected-gas reservoir situation. These calculations are based on the use of an equation-of-state fluid characterization that is "tuned" to PVT laboratory data for the particular oil and potential injected-gas compositions. The compositional simulator also can quantify the effects of various surface facility configurations, including associated gas plants.

Calculation methods

These compositional effects are too complicated to be quantified with hand-calculation methods. The black-oil numerical reservoir simulator can be used in limited ways to make these calculations. The black-oil model can reasonably handle the swelling effect, but it cannot handle the stripping effect at all.

The compositional effects of immiscible gas injection are best calculated using a compositional numerical reservoir simulator. To use such a model most accurately, considerable gas/oil PVT data need to be taken with the reservoir oil mixed with a range of gas compositions. These measurements should include a variety of special measurements, such as swelling experiments and stripping experiments, that can be used to develop a more accurate equation-of-state fluid characterization. Then the reservoir model can be used to quantify the performance of possible immiscible gas injection projects and associated surface facilities that might be built.

Surface facility considerations

In most applications of immiscible gas injection, during the early years of the projects, hydrocarbons are produced at about the original solution gas/oil ratio (GOR). During this period, the impact of surface facility design on the volume of produced hydrocarbon liquids is relatively limited. Later in the life of the projects when the producing GOR rises, the surface facilities are far more important in terms of both the volume of gas that can be handled and the extent to which this gas is processed. During this late period, the rate of oil production will be limited by the surface facilities’ gas-handling capacity.[5]

The gas recovered from the typical series of oilfield separators will contain a large amount of ethane through butane components and decreasing but significant amounts of the various heavier hydrocarbon components. Early generations of gas-processing plants were capable of separating out components that would condense down to temperatures of -10 to -20°F. Modern gas-processing plants operate at temperatures of -40°F or considerably lower; at these low temperatures, essentially all the ethane and heavier hydrocarbons are recovered, leaving a residue gas consisting primarily of methane.

Another related factor is the type of pipeline networks available to transport the hydrocarbon products to market. In some geographical areas, only those hydrocarbon components that can be stabilized in a crude oil stream can be transported and sold because there are only crude oil pipelines in that area. In much of the US and Canada, a variety of crude oil and natural gas liquid (NGL) pipelines have been built so that the lighter, liquefied hydrocarbon components can also be marketed, particularly to the petrochemical industry of the US Gulf Coast. In other parts of the world, as the number of liquefied petroleum gas (LPG) tankers has increased, worldwide markets for the lighter hydrocarbons have developed. As a result, more oil fields have had large-scale gas processing projects built to recover and market propane and heavier hydrocarbons from the produced gas streams.

References

  1. Young, R.E., Fairfield, W.H., and Dykstra, H. 1977. Performance of a High-Pressure-Gas Injection Project, Swanson River Field, Alaska. J Pet Technol 29 (2): 99-104. SPE-5874-PA. http://dx.doi.org/10.2118/5874-PA
  2. Ma, T.D. and Youngren, G.K. 1994. Performance of Immiscible Water-Alternating-Gas (WAG) Injection at Kuparuk River Unit, North Slope, Alaska. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, 25–28 September. SPE 28602. http://dx.doi.org/10.2118/28602-MS
  3. Carlson, L.O. 1988. Performance of Hawkins Field Unit Under Gas Drive-Pressure Maintenance Operations and Development of an Enhanced Oil Recovery Project. Presented at the SPE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 16–21 April. SPE-17324-MS. http://dx.doi.org/10.2118/17324-MS
  4. Christianson, S.H. 1977. Performance and Unitization of the Empire Abo Pool. Presented at the SPE Permian Basin Oil and Gas Recovery Conference, Midland, Texas, 10-11 March 1977. SPE-6384-MS. http://dx.doi.org/10.2118/6384-MS
  5. Metz, W.P. and Elliot, R.A. 1991. Gas Handling Expansion Facilities at Prudhoe Bay, Alaska. Presented at the International Arctic Technology Conference, Anchorage, Alaska, 29-31 May 1991. SPE-22113-MS. http://dx.doi.org/10.2118/22113-MS

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See also

Immiscible gas injection in oil reservoirs

Displacement efficiency of immiscible gas injection

Immiscible gas injection case studies

PEH:Immiscible Gas Injection in Oil Reservoirs