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Vertical or gravity drainage gas displacement

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This page discusses the primary manner in which the immiscible gas/oil displacement process has been used in qualitative terms. This is the use of gas injection high on structure to displace oil downdip toward the production wells that are completed low in the oil column.

Drive mechanism

In many cases, an original gas cap was present, so the gas was injected into that gas cap interval (see Fig. 1[1] for cross-sectional view of anticlinal reservoir with gas cap over oil column with dip angle α and thickness h). In this situation, the force of gravity is at work, trying to stabilize the downward gas/oil displacement process by keeping the gas on top of the oil and counteracting the unstable gas/oil viscous displacement process. If the oil production rate is kept below the critical rate, then the gas/oil contact (GOC) will move downward at a uniform rate. In Immiscible gas injection performance, the simple engineering calculation techniques for estimating the rate for stable gravity drainage for a gas/oil system are discussed.

In normal oilfield operations, producing wells are drilled and perforated as far as possible from the gas cap, both vertically and laterally. Hence, many production wells may not have any of the gas cap directly over them initially. Until the gas cap extends over the whole of the oil column and its producing wells, because of the pressure differential between the gas cap and the area around the producing wells, the downdip oil production will result in the gas cap moving rapidly along the top of the structure to provide pressure support to the whole oil column. When this happens, if the reservoir is a dipping structure, the gas cap is described as "draping" over the oil column. If the oil reservoir is an anticlinal structure, then this process is often described as the gas cap having expanded to form an "umbrella" over the whole oil column. Once the gas cap drape or umbrella has formed, the continued downward movement of the gas cap at each location can be stabilized. Fig. 2[2] shows views of the Prudhoe Bay oil field (Alaska North Slope) in which the original gas cap was offset to the northeast of most of the oil column and where there has been gas cap underrunning of the top of structure until it draped over much of the downdip oil column where the hundreds of producing wells were located.

There are likely to be local variations in the GOC caused by reservoir heterogeneities and near-wellbore pressure gradients. The most notable of these results in gas coning caused by high pressure gradients around the perforated interval of each wellbore. Here, the controlling factors are the oil and gas production rates, the distance from the top of the perforations to the overlying GOC, and the horizontal and vertical permeabilities.[3] In this situation, the presence of a small shale interval between the GOC and the top of the perforated interval can have a very beneficial effect on the maximum oil production rate before gas coning occurs (see Fig. 11). For a particular reservoir situation, gas coning calculations are best made with a numerical reservoir simulation model.[3][4]

Complications with underlying aquifer

The gas/oil gravity drainage process is complicated if the oil column is underlain by an aquifer because the aquifer will provide pressure support to the oil column in response to any decrease from original reservoir pressure caused by oil production. If the aquifer is very strong, it will invade the lower portions of the oil column and may provide almost barrel-for-barrel voidage replacement. In this case, the original gas cap may not expand much. If the aquifer is weak or if there is a tar mat at the oil/water contact (OWC) inhibiting water influx, then the gas cap will be the primary means of pressure support for the oil column and the reservoir will perform almost as if there were no aquifer present. A problem sometimes experienced with oil reservoirs with both overlying gas caps and underlying aquifers is that the near-wellbore coning behavior is more complicated. The reason is that gas-cap gas is coning downward toward the perforated interval and aquifer water is trying to cone upward toward the same perforated interval. If water cones first into the perforated interval, then the gas coning will be more severe because, with three-phase relative permeability effects, the near-wellbore pressure gradients are greater, which causes gas coning to occur at lower oil production rates.

Use of horizontal wells

Horizontal wells are particularly suited for use in gravity drainage immiscible gas injection projects because they:

  • Maximize the distance between the producing wells’ perforations and the overlying gas cap
  • Minimize the pressure gradients in the near-wellbore region (the cause of near-wellbore gas coning)

At the Prudhoe Bay field, a large number of horizontal wells have been drilled for a variety of purposes, including the two mentioned above. For these reasons, in future immiscible gas gravity drainage projects, it is logical to consider using horizontal production wells. Fluid flow in horizontal wells discusses how to predict and to interpret the performance of horizontal wells.

Thin oil columns

One consideration in immiscible gas gravity drainage projects is the challenge of maximizing oil recovery from thin oil columns. The thin oil column may be what is found initially,[5] or in most cases, as the gas cap expands, it is all that is left to produce late in the life of the project. The field engineers have to monitor individual well performance and overall reservoir performance closely to optimize production under these circumstances. Obviously, if new wells are drilled, they should be either carefully targeted horizontal wells or wells with very limited perforated intervals.

A related consideration is when there is a thin oil column sandwiched between the expanding gas cap and the underlying aquifer.[5] In this situation, well perforations must be chosen to maximize recovery and to minimize the production of both gas and water. Although coning simulations with numerical reservoir simulators will provide insights into the best approach for a particular reservoir situation, actual field experience is necessary to optimize the operations.


  1. 1.0 1.1 Muskat, M. 1949. Physical Principles of Oil Production, 470-502. New York City: McGraw-Hill Book Co. Inc.
  2. 2.0 2.1 Simon, A.D. and Petersen, E.J. 1997. Reservoir Management of the Prudhoe Bay Field. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 5-8 October 1997. SPE-38847-MS.
  3. 3.0 3.1 3.2 Addington, D.V. 1981. An Approach to Gas-Coning Correlations for a Large Grid Cell Reservoir Simulator. J Pet Technol 33 (11): 2267-2274. SPE-8332-PA.
  4. Killough, J.E. and Foster Jr., H.P. 1979. Reservoir Simulation of the Empire Abo Field: The Use of Pseudos in a Multilayered System. SPE Journal 19 (5): 279-288. SPE-7418-PA.
  5. 5.0 5.1 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.

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See also

Immiscible gas injection in oil reservoirs

Geology impact on immiscible gas displacement

Compositional effects during immiscible gas injection

Displacement efficiency of immiscible gas injection