You must log in to edit PetroWiki. Help with editing

Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. More information

Immiscible gas injection in oil reservoirs

Jump to navigation Jump to search

A variety of gases can and have been used for immiscible gas displacement, with lean hydrocarbon gas used for most applications to date. Historically, immiscible gas injection was first used for reservoir pressure maintenance. The first such projects were initiated in the 1930s and used lean hydrocarbon gas (e.g., Oklahoma City field and Cunningham pool in the US[1] and Bahrain field in Bahrain[2][3]). Over the decades, a considerable number of immiscible gas injection projects have been undertaken, some with excellent results and others with poor performance.

This page discusses gas injection into oil reservoirs to increase oil recovery by immiscible displacement. The use of gas, either of a designed composition or at high-enough pressure, to result in the miscible displacement of oil is not discussed here; for a discussion of that topic, see Miscible injection enhanced oil recovery (EOR).


Gas injection projects are undertaken when and where there is a readily available supply of gas. This gas supply typically comes from produced solution gas or gas-cap gas, gas produced from a deeper gas-filled reservoir, or gas from a relatively close gas field. Such projects take a variety of forms, including the following:

  • Reinjection of produced gas into existing gas caps overlying producing oil columns.
  • Injection into oil reservoirs of separated produced gas for pressure maintenance, for gas storage, or as required by government regulations.
  • Gas injection to prevent migration of oil into a gas cap because of a natural waterdrive, downdip water injection, or both.
  • Gas injection to increase recoveries from reservoirs containing volatile, high-shrinkage oils and into gas-cap reservoirs containing retrograde gas condensate.
  • Gas injection into very undersaturated oil reservoirs for the purpose of swelling the oil and hence increasing oil recovery.

The primary physical mechanisms that occur as a result of gas injection are:

  1. Partial or complete maintenance of reservoir pressure
  2. Displacement of oil by gas both horizontally and vertically
  3. Vaporization of the liquid hydrocarbon components from the oil column and possibly from the gas cap if retrograde condensation has occurred or if the original gas cap contains a relict oil saturation
  4. Swelling of the oil if the oil at original reservoir conditions was very undersaturated with gas

Gas injection is particularly effective in high-relief reservoirs where the process is called "gravity drainage" because the vertical/gravity aspects increase the efficiency of the process and enhance recovery of updip oil residing above the uppermost oil-zone perforations.


The decision to apply immiscible gas injection is based on a combination of technical and economic factors. Deferral of gas sales is a significant economic deterrent for many potential gas injection projects if an outlet for immediate gas sales is available. Nevertheless, a variety of opportunities still exist. First are those reservoirs with characteristics and conditions particularly conducive to gas/oil gravity drainage and where attendant high oil recoveries are possible. Second are those reservoirs where decreased depletion time resulting from lower reservoir oil viscosity and gas saturation in the vicinity of producing wells is more attractive economically than alternative recovery methods that have higher ultimate recovery potential but at higher costs. And third are reservoirs where recovery considerations are augmented by gas storage considerations and hence gas sales may be delayed for several years.

Nonhydrocarbon gases such as CO2 and nitrogen can and have been used.[4] In general, calculation techniques developed for hydrocarbon-gas injection and displacement can be used for the design and application of nonhydrocarbon, immiscible gas projects. Valuing the use of such gases must include any additional costs related to these gases, such as corrosion control, separating the nonhydrocarbon components to meet gas marketing specifications, and using the produced gas as fuel in field operations.

Related topics include:

The topics listed include discussions on the physical criteria that separate the successful gas injection operations from the unsuccessful ones, describing the reservoir and process variables that must be defined and quantified, and demonstrating some of the simple techniques available for predicting and evaluating field performance. Some of these calculations can be performed with spreadsheets or, more tediously, with hand-held calculators. Modern numerical reservoir simulators are commonly used to calculate the projected performance of applying immiscible gas injection to a particular reservoir. For reservoirs with several years of immiscible gas injection, these same simulators can be used to history match past performance and to project future performance under various scenarios (e.g., continuing current operations, evaluating various new producing wells options, or comparing surface facility operational alternatives).

Specifically not included in this page is any discussion of the factors to consider in implementing a gas injection project, such as gas compression needs, gas distribution systems, wellbore configurations, and vessel selection and sizing for handling produced fluids.

Gas sources for injection

The first consideration in any immiscible gas injection project is where to get the volume of gas necessary for the project. Historically, produced and processed residue gas from that particular oil field has been used. This is the most satisfactory solution if the economics of the additional oil recovery justify deferred gas sales. In some locations, this is not an issue because there is no current market outlet for the produced gas. Generally, reinjection of this local gas supply is sufficient to nearly maintain the current reservoir pressure.

The next best alternative in some locations is to develop deeper gas horizons as a gas supply. This is particularly true in the Middle East where massive volumes of gas are often found in the deeper formations, such as the Khuff, underlying some major oil reservoirs. The third alternative is to look to nearby fields for a source of gas; this alternative has been used at the Swanson River field in Alaska[5] and the Haft Kel and other Iranian fields.[6]

If there is no source for lean hydrocarbon gas, then possibly flue gas (88% N2, 12% CO2) or nitrogen might be used. Both of these options require that a plant be constructed at the field to generate these gases in the large volumes needed. This approach requires the economics of the project to justify the large capital expenditure for such facilities, additional operating costs, and future impact of the produced gas becoming increasingly contaminated with nonhydrocarbon components with time.

Sometimes, the solution to the gas supply problem is to use a combination of sources to provide the required volume of gas. At the Hawkins field, both residue hydrocarbon gas and flue gas initially were injected. More recently, nitrogen from a cryogenic nitrogen rejection plant has been injected.[4][7][8]

Immiscible gas injection techniques

Immiscible gas injection is usually classified as either crestal or pattern, depending on the location of the gas injection wells. The same physical principles of oil displacement apply to either type of operation; however, the overall objectives, type of field selected, and analytical procedures for predicting reservoir performance vary considerably by gas injection method. This pages discusses the general technical features of the various immiscible gas injection projects.

Crestal gas injection

Crestal gas injection, sometimes called external or gas-cap injection, uses injection wells in higher structural positions, usually in the primary or secondary gas cap. This manner of injection is generally used in reservoirs with significant structural relief or thick oil columns with good vertical permeability. Injection wells are positioned to provide good areal distribution and to obtain maximum benefit of gravity drainage. The number of injection wells required for a specific reservoir depends on the injectivity of individual wells and the distribution needed to maximize the volume of the oil column contacted.

Crestal injection, when applicable, is superior to pattern injection because of the benefits of gravity drainage. In addition, crestal injection, if conducted at gravity-stable rates—e.g., less than the critical rate (see Eq. 1 in Immiscible gas injection performance)—will result in greater volumetric sweep efficiency than pattern injection operations. There are many examples of ongoing crestal injection projects throughout the world, including some very large projects in the Middle East.

Pattern gas injection

Pattern gas injection, sometimes called dispersed or internal gas injection, consists of a geometric arrangement of injection wells for the purpose of uniformly distributing the injected gas throughout the oil-productive portions of the reservoir. In practice, injection-well/production-well arrays often vary from the conventional regular pattern configurations—e.g., five-spot, seven-spot, nine-spot (see Waterflood design for more description of these patterns)—to irregular injection-well spacing. The selection of an injection arrangement is a function of reservoir structure, sand continuity, permeability and porosity levels and variations, and the number and relative locations of existing wells.

This method of injection has been applied to reservoirs having low structural relief, relatively homogeneous reservoirs with low permeabilities, and reservoirs with low vertical permeability. Many early immiscible gas-injection projects were of this type. The greater injection-well density results in pattern gas injection, rapid pressure and production response, and shortened reservoir depletion times.

There are several limitations to pattern-type gas injection. Little or no improvement in recovery is derived from structural position or gravity drainage because both injection and production wells are located in all areas of the reservoir. Low areal sweep efficiency results from gas override in thin stringers and by viscous fingering of gas caused by high flow velocities and adverse mobility ratios. High injection-well density increases installation and operating costs. Typical results of applying pattern injection in low-dip reservoirs are:

  • Rapid gas breakthrough
  • High producing GORs
  • Significant gas compression costs to reinject the gas into the reservoir
  • An improved recovery of < 10% of original oil in place (OOIP)

Note that gas inefficiently displaces oil in gas-swept areas. Attempts to subsequently waterflood such areas result in rapid water breakthrough and little, if any, additional oil displacement.

Few pattern gas injection projects have been implemented in recent years because this method is not as attractive economically as alternative methods for increasing oil recovery.

Optimum time to initiate gas injection operations

The optimum time to begin gas injection is site specific and depends on a balance of risks, gas market availability, environmental considerations, and other factors that affect project economics. When only oil recovery and improvements in reservoir producing characteristics are considered, reservoir conditions for gas injection operations are usually more favorable when the reservoir is at or slightly below the oil bubblepoint pressure, unless the bubblepoint pressure is low compared with the initial reservoir pressure. Near the oil bubblepoint pressure, nonrecovered oil represents the smallest volume of stock-tank oil, oil relative permeability is high, and oil viscosity is low.

Efficiency of oil recovery by immiscible gas displacement

It is customary in most displacement processes to relate recovery efficiency to displacement efficiency and volumetric sweep efficiency. The product of these factors provides an estimate of recoverable oil expressed as a percentage of OOIP. Analytical procedures are available for evaluating each efficiency factor. The two components describing the overall recovery efficiency are defined as follows:

  • Displacement efficiency is the percentage of oil in place within a totally swept reservoir rock volume that is recovered as a result of viscous displacement and gravity drainage processes.
  • Volumetric sweep efficiency is the percentage of the total rock or PV that is swept by gas. This factor is sometimes divided into horizontal and vertical components, with the product of the two components representing the volumetric sweep.

Recovery efficiencies increase with continued gas injection, but the rate of recovery diminishes after gas breakthrough occurs as the GOR increases. The overall result is that the ultimate oil recovery efficiency is a function of economic considerations, such as the cost of gas compression and the volume and availability of lean residue gas or potentially more expensive alternatives like N2 from a nitrogen rejection plant.


Key points concerning immiscible gas/oil displacement are:

  1. Immiscible gas/oil viscous displacement is an inefficient oil displacement process because gas is a highly mobile fluid.
  2. Gas-oil capillary pressure data indicate that in many situations the residual oil saturation to gas displacement is significantly lower than the residual oil saturation to water displacement.
  3. The immiscible gas/oil process becomes efficient and desirable when gravity works to keep the very-low-density gas on top of the higher-density oil and/or there is significant mass transfer of components from the oil to the gas.
  4. The most successful immiscible gas/oil injection projects are the vertical gravity drainage projects in which gas is injected into the crestal primary or secondary gas cap, with the oil wells producing from as far downdip as possible to maximize this distance from the gas cap both vertically and laterally. To maximize the efficiency of this approach, the overall oil production rate has to be restricted to the critical displacement rate.
  5. One gas/oil compositional mass-transfer effect is oil swelling. If an oil field contains a very undersaturated oil, then oil swelling by contact with the injected gas can be a very significant effect. However, if a reservoir has an original gas cap, the oil swelling effect is minimal because the oil is already fully saturated or nearly saturated with gas.
  6. The other gas/oil compositional mass-transfer effect is stripping or vaporization of intermediate hydrocarbon components from the oil by the lean injected gas. The importance of this effect increases as the producing gas-oil ratio (GOR) rises. Toward the end of the life of an immiscible gas injection project, the stripping effect can contribute many of the liquid hydrocarbons produced in the surface facilities and associated gas plants. This effect occurs with all types of oils but is more significant for lighter, or higher American Petroleum Institute (API) gravity, oils.
  7. A few immiscible gas injection field projects have been undertaken that are not vertical gas/oil gravity drainage projects but in which compositional effects have led to project success. An excellent example of this approach is the Swanson River field in Alaska.
  8. Gas coning into producing wellbores’ perforated intervals occurs with thin oil columns or as the gas/oil interface moves downward. Horizontal wells are a method of further reducing the height of the remaining oil column by lowering pressure drawdown and thus minimizing the effects of gas coning.
  9. Numerical reservoir simulators are the best tool to evaluate all the technical aspects of an immiscible gas injection project, either historical performance and/or projections of future performance. Simple mathematical techniques have been developed to analyze some types of immiscible gas/oil displacements.


  1. Muskat, M. 1949. Physical Principles of Oil Production, 470-502. New York City: McGraw-Hill Book Co. Inc.
  2. Cotter, W.H. 1962. Twenty-Three Years of Gas Injection into A Highly Undersaturated Crude Reservoir. J Pet Technol 14 (4): 361-365. SPE-82-PA.
  3. Shehabi, J.A.N. 1979. Effective Displacement of Oil by Gas Injection in a Preferentially Oil-Wet, Low-Dip Reservoir. J Pet Technol 31 (12): 1605-1613. SPE-7652-PA.
  4. 4.0 4.1 Kuehm, H.G. 1977. Hawkins Inert Gas Plant: Design and Early Operation. Presented at the SPE Annual Fall Technical Conference and Exhibition, Denver, Colorado, 9-12 October 1977. SPE-6793-MS.
  5. Miscible Processes, Vol. 8, 197. 1965. Richardson, Texas: Reprint Series, SPE.
  6. 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.
  7. 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.
  8. Langenberg, M.A., Henry, D.M., and Chlebana, M.R. 1995. Performance and Expansion Plans for the Double-Displacement Process in the Hawkins Field Unit. SPE Res Eng 10 (4): 301-308. SPE-28603-PA.

Noteworthy papers in OnePetro

Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read

External links

Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro

See also