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Geology impact on immiscible gas displacement

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Many aspects of reservoir geology interplay with the immiscible gas/oil displacement process to determine overall recovery efficiency. Because there is always a considerable density difference between gas and oil, the extent to which vertical segregation of the fluids occurs and can be taken advantage of or controlled is critical to the success of gas displacing oil.

As with any oil recovery process involving the injection of one fluid to displace oil in the reservoir, the internal geometries of the reservoir interval have a controlling effect on how efficiently the injected fluid displaces the oil from the whole of the reservoir. For the immiscible gas/oil displacement process, the key factors are:

  • Stratigraphy
  • Structure


The stratigraphy of a reservoir is determined primarily by its depositional environment. First and foremost is how layered the reservoir is in terms of both how heterogeneous the various sand intervals are and the scale at which shales or other barriers to vertical flow are interbedded with the sands. Another very important aspect is how continuous the shale intervals are. With fully continuous shales, a reservoir interval should be divided into compartments that will not interact with each other. Unless the reservoir has a steep dip, such shales will negatively affect the gas/oil displacement process.

Less continuous shales can result in better distribution of injected gas without a strong negative impact on the gas/oil gravity drainage process (see Fig. 1 for an illustrative cross-sectional view of sands interbedded with discontinuous shales). Richardson et al.[1] analyzed the effects of such limited-size shales. First, they determined geologic factors that control shale dimensions and continuity for sandstone deposits. There is a wide range of shales whose dimensions depend on the depositional environment, with marine shales being the most extensive and flood-plain and interdistributary shales being of smaller areal dimensions (1,300 to 5,250 ft wide by 5,250 to 10,500 ft long). Next, simple 2D calculations of oil drainage off small shales were made, assuming that the various beds were horizontal. They concluded that, "The time required for oil drainage from a barrier is proportional to its width squared and viscosity, and inversely proportional to the horizontal permeability and density difference. Lateral drainage off small barriers can be rapid, and recoveries may be reduced only slightly." [1]


The structural aspects of a particular reservoir consist of several parts:

  • Closure or vertical thickness of the hydrocarbon column
  • Dip angle of the beds
  • Size and relative thickness of the gas cap compared with the oil column

Thick reservoirs (> 600 ft of oil column) are the best for application of the immiscible gas/oil drainage process with gas injection at the crest of the structure and oil production from as far downdip as possible. Dip angle is important to the efficiency of the displacement process because a higher dip angle generally means that the effective vertical permeability is increased.

The relative size of the oil column compared with the gas cap affects the performance of a particular reservoir. The gas/oil gravity drainage process has been applied to reservoirs that have, relative to the size of the oil column, very small gas caps[2] and to some with very large gas caps.[3] Success has been achieved over the full range of ratios of gas cap to oil column size. The advantage of having a large initial gas cap is that the reservoir pressure drops very slowly as the oil is produced compared with a situation with a relatively small gas cap in which the reservoir pressure falls quite rapidly until the secondary gas cap grows sufficiently.

Other geological factors

Within the reservoir sandstone layers, the nature of the sand layering can strongly affect the efficiency of the gas/oil displacement. In those depositional environments in which the highest-permeability sands are on the bottom of the reservoir interval, the gas/oil displacement process will be far more efficient, especially compared with the situation in which the depositional environment results in the highest permeability toward the top of the reservoir interval. The reason is that, in the first situation, the gravity override of the gas is slowed by the vertical distribution of permeability, but in the latter situation, the gas gravity override is enhanced.

Even if the reservoir were totally homogeneous, a horizontal gas/oil displacement process would not be very efficient because the gas will strongly override the oil and, because of its high mobility, will rapidly travel from the injection wells to the production wells. For reservoirs with many "random" heterogeneities, the gas/oil displacement process will be aided because heterogeneities inhibit growth of low-viscosity fingers by forcing them to travel a more circuitous path between the injector and producer.

Vertical permeability at various scales

The challenge in making calculations for the immiscible gas/oil displacement process at the reservoir scale is to quantify properly the vertical permeability of the reservoir as a whole. There are several scales at which vertical permeability affects the gas/oil displacement process. The engineer has quantitative data on the vertical permeability from routine core analysis performed foot by foot on small core plugs from the reservoir interval. The next larger scale concerns the areal extent of any impermeable layers observed in the cores, be they 1 in., 6 in., or several feet thick. Geologists typically estimate the areal dimensions of these impermeable layers from their training, experience, and studies of outcrops from similar depositional environments.

Despite all the technical work performed before this process is applied to a particular reservoir, the actual effective vertical permeability and its distribution will not be fully known until some years later. The vertical permeability can be quantified by observing reservoir performance. Typically, gravity-drainage immiscible gas/oil displacements are undertaken with the assumption of good vertical permeability so that if actual reservoir performance matches the projections, then the vertical permeability is as high as previously assumed. However, if the reservoir performance is poorer than expected, a likely cause is lower vertical permeability and/or heterogeneities in the vertical permeability distribution over the reservoir.

Carbonate reservoirs

The geologic discussion above primarily concerns sandstone reservoirs, although many of the general concepts also apply to carbonate reservoirs. Because diagenetic changes often alter the original framework of a carbonate reservoir far more than what occurs in sandstone reservoirs and because some types of carbonate reservoirs do not have sandstone equivalents, this section briefly discusses some differences in carbonate reservoirs.

One type of carbonate deposits that results in reservoirs with thick vertical dimensions, especially compared with their areal dimensions, is the carbonate reef deposit. The style of this deposit with the greatest vertical-to-horizontal aspect is called a pinnacle reef. Reef deposits typically contain large vugs. The key question is, How interconnected are these vugs? Diagenetic processes can isolate these vugs or can provide various types of pore-to-pore interconnections. For example, in New Mexico, the Abo reef trend developed on the northern margin of the Delaware basin. The original reef framework of hydrocorals, sponges, and algae has been totally dolomitized to create a pore system consisting only of vugs, fractures, and fissures.[2]

In carbonate reservoirs, the diagenetic process includes both chemical alteration, such as dolomitization, and cementing and leaching processes. Cementation with calcite, anhydrite, or other insoluble chemicals can have a significant negative impact on the reservoir’s pore system. Leaching has the opposite effect and generally enhances the reservoir quality, although leaching may increase the range of heterogeneities and lead to some superconductive flow paths in portions of a reservoir. As carbonate rocks become more brittle because of chemical alteration, fracturing commonly occurs. The geologist and petrographer must examine the cores in great detail to determine the number and sequence of cementation, leaching, and fracturing events that have altered a particular rock interval over geologic time.

Middle East carbonate matrix/fracture-system reservoirs

A particular style of reservoir in which a considerable number of immiscible gas/oil gravity drainage projects have been applied is the Middle East carbonate matrix-block/fracture-system reservoirs. Most of these reservoirs are very large folded anticlinal structures with dimensions of tens of miles long by several miles wide and with hydrocarbon columns hundreds of feet to several thousand feet thick.

In these carbonate reservoirs, the matrix is high porosity but low permeability (generally ≤1 md), and the fracture system created matrix blocks with dimensions ranging from a few feet to > 10 ft.[4][5] The fractures can be up to a tenth of an inch wide, so the effective interwell permeabilities are very high.

The geologic complications of these matrix-block/fracture-system reservoirs concern the way that the matrix and fractures are interconnected and fluid is transferred between these two portions of the pore system. This combines

  1. Interaction of the fractures with the matrix along the faces of vertical fractures
  2. Interaction of one matrix block with its neighboring matrix blocks if capillary continuity exists along such surfaces (see Fig. 2 for the schematic oil saturation profiles for cases without and with capillary continuity)
  3. Possible fluid transfer along matrix/fracture surfaces if portions of the fracture system are inclined planes and neither vertical nor horizontal

The presence of cementation along some of the fracture surfaces is very important to fluid transfer because the fractures will rapidly transport fluid, but for overall high recovery efficiency, the matrix blocks must exchange oil and gas with the surrounding fracture system. The geological aspects of such matrix-block/fracture systems are difficult to quantify because their dimensions and fracture characteristics cannot be easily discerned from cores and logs. Descriptions of nearby outcrops of the reservoir formation can often be helpful in understanding the macrodimensions of the matrix-block/fracture system.

A number of technical papers have explored aspects of the geology/fluid-flow interactions of such matrix-block/fracture network carbonate reservoirs. Firoozabadi and coworkers[6][7][8][9][10][11] have developed theories, made calculations, and performed experiments to explore aspects of these types of reservoirs. Saidi[4] has discussed the physical phenomena affecting the performance of the Haft Kel field (Iran) and analyzed its performance; more discussion of the Haft Kel field is found in Immiscible gas injection case studies.


  1. 1.0 1.1 1.2 Richardson, J.G., Harris, D.G., Rossen, R.H. et al. 1978. The Effect of Small, Discontinuous Shales on Oil Recovery. J Pet Technol 30 (11): 1531–1537. SPE-6700-PA.
  2. 2.0 2.1 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.
  3. Selamat, S., Goh, S.T., and Lee, K.S. 1999. Seligi Depletion Management. Presented at the SPE Asia Pacific Improved Oil Recovery Conference, Kuala Lumpur, Malaysia, 25-26 October 1999. SPE-57251-MS.
  4. 4.0 4.1 4.2 Saidi, A.M. 1996. Twenty Years of Gas Injection History into Well-Fractured Haft Kel Field (Iran). Presented at the International Petroleum Conference and Exhibition of Mexico, Villahermosa, Mexico, 5–7 March. SPE 35309.
  5. O’Neill, N. 1988. Fahud Field Review: A Switch from Water to Gas Injection. J Pet Technol 40 (5): 609–618. SPE-15691-PA.
  6. Horie, T., Firoozabadi, A., and Ishimoto, K. 1990. Laboratory Studies of Capillary Interaction in Fracture/Matrix Systems. SPE Res Eng 5 (3): 353–360. SPE-18282-PA.
  7. Firoozabadi, A. and Hauge, J. 1990. Capillary Pressure in Fractured Porous Media (includes associated papers 21892 and 22212). J Pet Technol 42 (6): 784-791. SPE-18747-PA.
  8. Firoozabadi, A., Ishimoto, K., and Dindoruk, B. 1994. Reinfiltration in Fractured Porous Media: Part 2 - Two Dimensional Model. SPE Advanced Technology Series 2 (2): 45-51. SPE-21798-PA.
  9. Dindoruk, B. and Firoozabadi, A. 1997. Crossflow in Fractured/Layered Media Incorporating Gravity, Viscous, and Phase Behavior Effects. SPE J. 2 (2): 120-135. SPE-35457-PA.
  10. Dindoruk, B. and Firoozabadi, A. 1996. Crossflow in Fractured/Layered Media Incorporating Gravity, Viscous, and Phase Behavior Effects: Part II - Features in Fractured Media. Presented at the SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma,
  11. Ghorayeb, K. and Firoozabadi, A. 2000. Numerical Study of Natural Convection and Diffusion in Fractured Porous Media. SPE J. 5 (1): 12-20. SPE-51347-PA.

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See also

Immiscible gas injection in oil reservoirs

Immiscible gas injection case studies