PEH:Immiscible Gas Injection in Oil Reservoirs: Difference between revisions

}}<br/>This chapter concerns 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 the chapter on miscible flooding in this section of the ''Handbook''. 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 United States<ref name="r1">Muskat, M. 1949. Physical Principles of Oil Production, 470-502. New York City: McGraw-Hill Book Co. Inc.</ref> and Bahrain field in Bahrain<ref name="r2">_</ref><ref name="r3">_</ref>). Over the decades, a considerable number of immiscible gas injection projects have been undertaken, some with excellent results and others with poor performance. Reasons for this range of performance are discussed in this chapter. At the end of this chapter, a variety of case studies are presented that briefly describe several of the successful immiscible gas injection projects.<br/><br/>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:

The purposes of this chapter include listing 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). See the chapter on reservoir simulation in this section of the ''Handbook''.<br/><br/>Specifically not included in this chapter 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. These subjects are covered in various chapters in the Production Operations Engineering and Facilities and Construction Engineering sections of the ''Handbook''.<br/>__TOC__<br/>

One must first understand the viscosity and density differences between gas and oil to appreciate why the gas/oil displacement process can be very inefficient. Gases at reservoir conditions have viscosities of ≈0.02 cp, whereas oil viscosities generally range from 0.5 cp to tens of centipoises. Gases at reservoir conditions have densities generally one-third or less than that of oil. Thus, gas is generally one to two orders of magnitude less viscous than the oil it is trying to displace. Regarding the fluid density difference, gas is always considerably "lighter" than the oil; hence, gas, when flowing, will segregate by gravity to the top of the reservoir or zone and oil will "sink" simultaneously to the bottom of the reservoir or zone.<br/><br/>Another gas/oil property that must be known for calculations at reservoir conditions is the interfacial tension (IFT) between the oil and gas fluid pair. This value is needed at reservoir conditions for the conversion of gas/oil capillary pressure data from surface to reservoir conditions. A number of technical papers discuss the calculation of IFT from compositional information about the oil and gas phases.<ref name="r5">_</ref><ref name="r6">_</ref><ref name="r7">_</ref><ref name="r8">Firoozabadi, A. and Katz, D.L. 1988. Surface Tension of Reservoir CrudeOil/Gas Systems Recognizing the Asphalt in the Heavy Fraction. SPE Res Eng 3 (1): 265-272. SPE-13826-PA. http://dx.doi.org/10.2118/13826-PA.</ref><ref name="r9">_</ref> '''Table 12.1''' from Firoozabadi ''et al.''<ref name="r8">Firoozabadi, A. and Katz, D.L. 1988. Surface Tension of Reservoir CrudeOil/Gas Systems Recognizing the Asphalt in the Heavy Fraction. SPE Res Eng 3 (1): 265-272. SPE-13826-PA. http://dx.doi.org/10.2118/13826-PA.</ref> shows several reservoir oil-gas fluid-pair IFT values (measured and calculated) as a function of temperature and pressure. As the pressure increases, the IFT values decrease, although not low enough for miscible displacement to occur. Although not illustrated in the table, it should be noted that the IFT between nitrogen and oil is higher than that between a lean natural gas and the same oil.<br/><br/><gallery widths="300px" heights="200px">

The other key aspect of the oil relative permeability (''k''_''ro'') is the determination of its value as the oil saturation decreases. Because oil relative permeability becomes quite low but nonzero, the time to reach equilibrium in laboratory core plug measurements can be very long. '''Fig. 12.1''' presents experimental results for cumulative oil recovery as a function of drainage time and shows that the oil continues to flow but more and more slowly (linearly as a function of the logarithm of ''t''_''D''); Hagoort<ref name="r10">Hagoort, J. 1980. Oil Recovery by Gravity Drainage. SPE J. 20 (3): 139–150. SPE-7424-PA. http://dx.doi.org/10.2118/7424-PA.</ref> found similar behavior for the four different rock types he tested.<br/><br/>If the gas/oil relative permeability data were measured with the viscous displacement technique (the extended Welge technique as described by Johnston ''et al''.),<ref name="r11">_</ref> extra care is needed in applying these data. First, the displacement of oil by gas is at an unfavorable mobility ratio (see discussion below) that makes the process unstable. Second, a displacement is adversely affected by capillary end effects that, for the gas/oil system, cannot be overcome by high gas throughput rates. At low oil saturations, the region of most interest, the capillary end effect is the greatest.<ref name="r10">Hagoort, J. 1980. Oil Recovery by Gravity Drainage. SPE J. 20 (3): 139–150. SPE-7424-PA. http://dx.doi.org/10.2118/7424-PA.</ref><br/><br/>Finally, one method developed to affect the gas/oil relative permeability and to reduce gas mobility is to inject water alternately with gas (WAG). This procedure was proposed by Caudle and Dyes.<ref name="r12">_</ref> Although the method was proposed for use in miscible gasfloods, the concept applies equally to immiscible gas displacements. This technique has been used in many west Texas CO₂ miscible gas projects, in the Prudhoe Bay miscible flood,<ref name="r13">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. http://dx.doi.org/10.2118/38847-MS.</ref> and in the Kuparuk immiscible and miscible gas injection processes.<ref name="r14">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.</ref><ref name="r15">Stoisits, R.F., Scherer, P.W., and Schmidt, S.E. 1994. Gas Optimization at the Kuparuk River Field. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 25-28 September 1994. SPE-28467-MS. http://dx.doi.org/10.2118/28467-MS.</ref> The three-phase gas, oil, and water relative permeabilities are calculated in numerical reservoir simulators with algorithms developed over the past several decades.<ref name="r16">_</ref>

The equations that characterize the mechanics of oil displacement by an immiscible fluid were developed by Buckley and Leverett<ref name="r17">_</ref> using relative permeability concepts and Darcy’s law describing steady-state fluid flow through porous media. The resulting fractional flow equation describes quantitatively the fraction of displacing fluid flowing in terms of the physical characteristics of a unit element of porous media. Assumptions inherent in their work are steady-state flow, constant pressure, no compositional effects, no production of fluids behind the gas front, no capillary effects, movement of advancing gas parallel to the bedding plane, immobile water saturation, and uniform cross-sectional flow (no gravity segregation of fluids within the element). Subsequent work by Welge<ref name="r18">Welge, H.J. 1952. A Simplified Method for Computing Oil Recovery by Gas or Water Drive. Trans., AIME 195: 91.</ref> made solving the displacement equations easier.<br/><br/>The Welge equation for the fractional flow of gas at any gas saturation (''S''_''g'') is calculated as follows:<br/><br/>[[File:Vol5 page 1108 eq 001.png|RTENOTITLE]]....................(12.5)<br/><br/>where

The fractional-flow and material-balance equations discussed above are important for understanding the effects on the efficiency of the gas/oil displacement process of (1) initial saturation conditions, (2) fluid viscosity ratios, (3) relative permeability ratios, (4) formation dip, (5) capillary pressure, and (6) factors of permeability, density difference, rate of injection, and cross section open to flow.<br/><br/>'''''Initial Saturation Conditions.''''' If gas injection is initiated after reservoir pressure has declined below the bubblepoint, the gas saturation will decrease the amount of displaceable oil. If the free gas saturation exceeds the breakthrough saturation, no oil bank will be formed. Instead, oil production will be accompanied by immediate and continually increasing gas production. Laboratory investigations and mathematical analyses have demonstrated this influence of gas saturation on gas displacement performance.<ref name="r20">_</ref><br/><br/>''S''_''wi'' has been shown to have no influence on displacement efficiency at gas breakthrough, but it directly affects the displaceable oil volume.<ref name="r21">_</ref> If ''S''_''wi'' is mobile, the displacement equations are not directly applicable because they were developed for two-phase flow. Approximations of gas displacement performance can usually be made when three phases are mobile by treating the water and oil phases as a single liquid phase. Displacement calculations can then be made with ''k''_''rg'' and ''k''_''ro'' data determined from core samples containing an immobile water saturation. Oil recovery can be differentiated from total liquid recovery on the basis of material balance calculations incorporating an estimated minimum interstitial water saturation.<br/><br/>'''''Fluid Viscosities.''''' The effect of oil viscosity on fractional flow is illustrated in '''Fig. 12.4'''. In this plot, the ''S''_''g'' at breakthrough increases from 12 to 38% with a 10-fold decrease in oil viscosity.<br/><br/><gallery widths="300px" heights="200px">

In both of these illustrations, the cause of the viscous fingering was a slight perturbation in the flow field that grew into the viscous finger once the perturbation occurred. In real reservoir situations, there are two physical aspects that enhance the viscous-fingering phenomenon. First, real reservoirs are very heterogeneous, so a variety of styles of permeability heterogeneities can initiate viscous fingering. Second, in a cross-section immiscible gas/oil displacement process, gas is always less dense than oil. Hence, there is a gas/oil density difference, and the force of gravity causes the gas to override the oil and initiate a viscous finger of the high-mobility gas phase along the top of the reservoir interval.<br/><br/>If the gas/oil displacement is occurring vertically with gas generally displacing oil downward, gravity will work to stabilize the flood front between the gas and oil, although if the rate is too high, instabilities in the form of gas cones or tongues can occur.<br/>

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.<br/><br/>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.<br/><br/>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.<ref name="r14">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.</ref><ref name="r25">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.</ref><ref name="r26">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.</ref> 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).<br/><br/>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.<br/><br/>'''''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.<br/><br/>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.<br/><br/>'''''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 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.<ref name="r27">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.</ref><br/><br/>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. See the chapters in the Facilities and Construction Engineering section of the ''Handbook'' for additional discussion of oilfield surface separators and gas-processing plants.<br/><br/>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 United States 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 U.S. Gulf Coast. In other parts of the world, as the number of liquefied petroleum gas 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.<br/>

'''''Structure.''''' The structural aspects of a particular reservoir consist of several parts: the closure or vertical thickness of the hydrocarbon column, dip angle of the beds, and 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.<br/><br/>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<ref name="r26">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.</ref> and to some with very large gas caps.<ref name="r29">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. http://dx.doi.org/10.2118/57251-MS.</ref> 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.<br/><br/>'''''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.<br/><br/>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.<br/><br/>'''''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.<br/><br/>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.<br/><br/>'''''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.<br/><br/>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.<ref name="r26">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.</ref><br/><br/>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.<br/><br/>'''''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.<br/><br/>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.<ref name="r30">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. http://dx.doi.org/10.2118/35309-MS.</ref><ref name="r31">_</ref> The fractures can be up to a tenth of an inch wide, so the effective interwell permeabilities are very high.<br/><br/>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) the interaction of the fractures with the matrix along the faces of vertical fractures, (2) the interaction of one matrix block with its neighboring matrix blocks if capillary continuity exists along such surfaces (see '''Fig. 12.8''' for the schematic oil saturation profiles for cases without and with capillary continuity), and (3) possible fluid transfer along matrix/fracture surfaces if portions of the fracture system are inclined planes and neither vertical nor horizontal. Also, 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.<br/><br/><gallery widths="300px" heights="200px">

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<ref name="r32">_</ref><ref name="r33">_</ref><ref name="r34">_</ref><ref name="r35">_</ref><ref name="r36">_</ref><ref name="r37">_</ref> have developed theories, made calculations, and performed experiments to explore aspects of these types of reservoirs. Saidi<ref name="r30">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. http://dx.doi.org/10.2118/35309-MS.</ref> 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 the Case Studies section of this chapter.<br/>

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.<br/>

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.<br/>

Applicability of the basic displacement equations to a given reservoir is governed by whether the underlying assumptions are reasonable. Several authors have reported modifications that eliminate the need to make certain assumptions. Modifications that take into consideration the swelling effects experienced from injection into an undersaturated reservoir and production of fluids from behind the gas front have been presented by Welge,<ref name="r18">Welge, H.J. 1952. A Simplified Method for Computing Oil Recovery by Gas or Water Drive. Trans., AIME 195: 91.</ref> Kern,<ref name="r19">Kern, L.R. 1952. Displacement Mechanism in Multi-well Systems. Trans., AIME 195.</ref> Shreve and Welch,<ref name="r40">_</ref> and others. Jacoby and Berry,<ref name="r41">_</ref> Attra,<ref name="r42">_</ref> and others have presented equations and simple analytical procedures for calculating performance to account for some of the compositional interchange between the displacing gas and the reservoir oil.<br/><br/>These works are mentioned for completeness. If significant deviations from the basic assumptions of the Buckley-Leverett method are a concern, the more practical approach is to use numerical reservoir simulation to account for reservoir heterogeneities and gravity, capillary, and compositional effects. These simulators are discussed in the numerical simulation chapter in this section of the ''Handbook''.

Some techniques for estimating the volumetric, vertical, and areal sweep efficiency of an immiscible gas/oil displacement are discussed below.<br/><br/>'''''History Matching.''''' If there are sufficient data concerning the location of the gas front and oil recovery as a function of time, past reservoir performance can be used to calculate the volumetric sweep efficiency by dividing observed recovery at various times by the theoretical recovery determined from displacement efficiency calculations.<br/><br/>If there are adequate data to reliably describe spatial variations in reservoir rock and fluid characteristics, numerical reservoir simulation is the best way to predict sweep efficiency, particularly after the historical production and pressure data are matched. If data or sufficient economic justification to undertake a full numerical reservoir simulation study is lacking, the following methods are presented as useful for screening studies and in situations when more detailed studies are inappropriate.<br/><br/>'''''Vertical Sweep Efficiency.''''' Several authors have presented methods for determining vertical sweep efficiency based on statistical treatments of routine core analysis data. Some of the most frequently used methods are adaptations of the Stiles<ref name="r43">_</ref> method for evaluating the effect of permeability variations on waterflood performance. The same assumptions and calculation procedures may be used for immiscible gas/oil displacements. The relative permeability ratio used in such calculations is considered to be a constant equal to the relative permeability to gas at residual oil saturation (''k''_''rg@Sor'') divided by the relative permeability to oil at initial gas saturation (''k''_''ro@Sgi'').<br/><br/>'''''Areal Sweep Efficiency.''''' Several investigators have shown that areal sweep efficiency is primarily a function of injection/production well pattern arrangement, mobility ratio, and volume of displacing phase injected. Various studies have confirmed what would be expected intuitively, that areal sweep efficiency increases with the volume injected and with a lower mobility ratio. Data from model studies that show the influence of mobility ratio and displacement volume on areal sweep efficiency in a regular five-spot pattern are illustrated in '''Fig. 12.12'''.<ref name="r44">Dyes, A.B., Caudle, B.H., and Erickson, R.A. 1954. Oil Production After Breakthrough as Influenced by Mobility Ratio. J Pet Technol 6 (4): 27-32. SPE-309-G. http://dx.doi.org/10.2118/309-G.</ref><br/><br/><gallery widths="300px" heights="200px">

Numerical simulation represents the best way to predict the performance of immiscible gas injection if there are sufficient data to characterize the reservoir rocks and fluids adequately. Even simple 2D and 3D black-oil models provide insight into the more important aspects of oil recovery for reservoirs in which compositional effects are not a major concern. When adequate data are unavailable or when screening work is being done, simple models may suffice.<br/><br/>The immiscible displacement of oil by gas is described with fractional flow theory. Muskat<ref name="r1">Muskat, M. 1949. Physical Principles of Oil Production, 470-502. New York City: McGraw-Hill Book Co. Inc.</ref> presented the basics of this theory more than 60 years ago. Since then, additional work has been done to develop various mathematical calculation methods based on fractional flow theory. A few of the more recent papers discussing these techniques are listed in the References section.<ref name="r45">_</ref><ref name="r46">_</ref><ref name="r47">_</ref><ref name="r48">_</ref><ref name="r49">_</ref><ref name="r50">_</ref><ref name="r51">_</ref><br/><br/>As discussed above, pattern gas injection is seldom used now because waterflooding performance is much better in those types of reservoirs where pattern gas injection has historically been tried. Therefore, the remainder of this section discusses a simple model used for reservoirs in which stabilized gravity drainage controls the gas/oil displacement process and increases the ultimate oil recovery.<ref name="r13">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. http://dx.doi.org/10.2118/38847-MS.</ref><br/><br/>Viscous, gravitational, and capillary forces and diffusion are involved in the displacement of oil by gas, complicating technical analysis of a particular reservoir if each of these forces and flow in all three dimensions are important. Fortunately, there are instances in which one force is dominant and only one dimension is involved in the rate-limiting step. In these circumstances, engineering solutions can be direct and simple. One such circumstance is that of thick reservoirs with high permeabilities.<br/><br/>In steeply dipping oil reservoirs containing sands with high vertical permeabilities, gravity drainage of the oil can be more effective than is calculated from the Buckley-Leverett assumptions alone, as illustrated in '''Fig. 12.13'''.<ref name="r52">_</ref> When sufficient vertical permeability exists, even at lower oil saturations, oil behind the gas front can continue to flow vertically downward through the reservoir. Thus, the displacement process occurs in two steps. First, gas invades the originally oil-saturated sand as the GOC moves downdip because of oil production farther downdip. Second, oil drains vertically downward through the gas-invaded region and forms a thin layer with high oil saturation (with high ''k''_''ro'') that drains along the base of the reservoir interval to the remaining downdip oil column.<br/><br/><gallery widths="300px" heights="200px">

'''''Mathematical Model.''''' A simple mathematical model can be used to describe the displacement of oil by gas drive and gravity drainage when the rate is less than one-half the critical rate. The critical rate is given by<br/><br/>[[File:Vol5 page 1126 eq 001.png|RTENOTITLE]]....................(12.8)<br/><br/>where ''q''_''T'' = total volumetric flow rate through area ''A'', ft³/D, and ''k'' = permeability, darcies.<br/><br/>The first calculation determines the gas saturation just above the GOC by using '''Eq. 12.5''', plotting ''F''_''g'' vs. ''S''_''g'', and finding the tangent to the curve passing through the origin, as shown in '''Fig. 12.2'''. For ease of calculation, the GOC is assumed to move at a constant rate. The next calculation determines the quantity of oil that drains from the region invaded by gas in a given time increment. For ease of calculation, this region is divided into arbitrary lengths, and the amount of oil produced by vertical gravity drainage is calculated for the average time since passage of the gas front.<br/><br/>For vertical drainage of oil, the rate is given by Darcy’s law, with the driving force proportional to the density difference between gas and oil. The assumption is made that resistance to flow of gas and capillary effects are negligible<ref name="r53">_</ref>:<br/><br/>[[File:Vol5 page 1127 eq 001.png|RTENOTITLE]]....................(12.9)<br/><br/>where ''u''_''ov'' = vertical oil flow per unit area, res ft³/ft²-D.<br/><br/>From continuity considerations,<br/><br/>[[File:Vol5 page 1127 eq 002.png|RTENOTITLE]]....................(12.10)<br/><br/>where ''z'' = vertical distance, ft; ''t'' = time, days; ''ϕ'' = porosity, fraction; and ''S''_''o'' = oil saturation, fraction.<br/><br/>The rate of movement of a particular saturation, (d''z''/d''t'')_''So'', can be determined by plotting ''u''_''ov'' calculated from '''Eq. 12.9''' vs. saturation, taking the slope to determine d''u''_''ov''/d''S''_''o'' and dividing by porosity, as indicated in '''Eq. 12.10'''. The amount of oil drained from each region since passage of the gas front can be calculated by graphical integration of the height vs. saturation plot.<br/><br/>As a first approximation, the time for oil to flow downdip in the thin layer along the base of the reservoir interval can be neglected, as can the volume of oil in this layer. If the displacement rate exceeds one-half the critical rate, oil tends to accumulate rather than flow away along the bottom of the reservoir. More accurate calculations also include consideration of the thickness of the gas/oil transition zone arising from capillary effects above this layer of oil, especially if the transition zone is < 10 ft thick.<br/><br/>Recoveries calculated by this technique are quite sensitive to the values of ''k''_''ro'' at low oil saturations.<ref name="r10">Hagoort, J. 1980. Oil Recovery by Gravity Drainage. SPE J. 20 (3): 139–150. SPE-7424-PA. http://dx.doi.org/10.2118/7424-PA.</ref> Ways to extrapolate measured information are discussed next. First, conventional laboratory data can be extended to low oil saturations by plotting measured values of ''k''_''ro'' vs. (''S''_''o'' − ''S''_''org''*)/(1 − ''S''_''wi'' − ''S''_''org''*), in which ''S''_''org''* is the irreducible oil saturation in the presence of gas and connate water. ''S''_''org''* can be calculated by material balance for areas of a reservoir that have been invaded by gas if good data are available on GOC movement and oil recovery from the area. A second source is the oil saturation in an associated gas cap as determined in cores from that region. If the gas cap was originally filled with oil, drainage of oil over geologic time as gas migrates into the reservoir establishes an endpoint relict oil saturation. For instance, the Prudhoe Bay Sadlerochit reservoir was originally filled with oil. Gas then migrated into the reservoir several million years later, creating the gas cap.<ref name="r54">Erickson, J.W. and Sneider, R.M. 1997. Structural and Hydrocarbon Histories of The Ivishak (Sadlerochit) Reservoir, Prudhoe Bay Field. SPE Res Eng 12 (1): 18-22. SPE-28574-PA. http://dx.doi.org/10.2118/28574-PA.</ref> Water-based mud cores from the gas cap interval showed an average routine core analysis oil saturation at discovery of 7% PV. The dip of the reservoir is 1 to 3°, but vertical permeabilities throughout the gas and oil columns are generally very high. Interestingly, oil saturations above small shale lenses in the gas cap averaged more than 7% PV, indicating that more time may be required to reach irreducible oil saturations when oil drainage is limited by the dip of this reservoir. A third source is drainage capillary pressure vs. saturation measurements. Experience has indicated that ''S''_''org''* should be < 10% PV and sometimes approaches zero. Although these endpoint saturations are seldom realized in the depletion time of a reservoir, it is important to have the correct value for predicting flow behavior and ultimate oil recovery. A benefit of even simple, multidimensional simulation models is that the inclusion of capillary effects controls the oil flow rate and conditions under which irreducible saturations are approached.<br/><br/>If a measured value of ''S''_''org''* is unavailable, a value is chosen to yield a straight line through the data, so for<br/><br/>[[File:Vol5 page 1128 eq 001.png|RTENOTITLE]]....................(12.11)<br/><br/>the slope of the line n should be ≈4 according to the theory of Corey ''et al.''<ref name="r55">_</ref> but may be as large as 6 and as small as 2. Recovery data can be correlated by the dimensionless parameter [[File:Vol5 page 1128 inline 001.png|RTENOTITLE]], which is derived by dividing the time required for vertical drainage,<br/><br/>[[File:Vol5 page 1128 eq 002.png|RTENOTITLE]]....................(12.12)<br/><br/>by the time required for flow along the bedding plane,<br/><br/>[[File:Vol5 page 1128 eq 003.png|RTENOTITLE]]....................(12.13)<br/><br/>where ''k''_''v'' = vertical permeability, darcies, and ''h''_''v'' = vertical thickness, ft.<br/><br/>'''''Example Gas/Oil Gravity-Drainage Problem.''''' The utility of this simple model can be illustrated by predicting recovery by gas drive and gravity drainage for an actual reservoir, in this case the Hawkins field in east Texas.<ref name="r56">King, R.L., Stiles, J.H. Jr., and Waggoner, J.M. 1970. A Reservoir Study of the Hawkins Woodbine Field. Presented at the 1970 SPE Annual Meeting, Houston, 4–7 October 1970. SPE-2972-MS. http://dx.doi.org/10.2118/2972-MS</ref><br/><br/>''Given:'' Average Hawkins Woodbine reservoir properties as presented in '''Table 12.2 and Fig. 12.14'''.<br/><br/><gallery widths="300px" heights="200px">

</gallery><br/><br/>[[File:Vol5 page 1131 eq 001.png|RTENOTITLE]]<br/><br/>'''''Comparisons With Field Data.''''' A recovery of 87% of OOIP was observed in the Hawkins field for an area affected by an expanding gas cap.<ref name="r56">King, R.L., Stiles, J.H. Jr., and Waggoner, J.M. 1970. A Reservoir Study of the Hawkins Woodbine Field. Presented at the 1970 SPE Annual Meeting, Houston, 4–7 October 1970. SPE-2972-MS. http://dx.doi.org/10.2118/2972-MS</ref> The calculated recovery of 88% compares very favorably. A 2D two-phase reservoir simulation using similar relative permeabilities predicted 87% recovery at breakthrough. The recoveries observed in the field and predicted by models that permit flow in two dimensions are > 15% greater than those calculated by conventional 1D techniques that assume flow only along the bedding planes.<br/><br/>'''''Model Summary.''''' This section has shown how a simple gravity drainage model can be readily applied to predict recoveries by gas drive and gravity drainage when flow rates are less than one-half the critical rate and permeabilities in the vertical direction are high. Some applications of the model have been unsuccessful because of lower-than-expected vertical permeabilities. As a practical matter, the simple model should be used to predict reservoir behavior only when it can be shown to match history or when applied to a field analogous to one that the model fits.<br/>

<br/>There are a variety of methods for monitoring immiscible gas injection projects. Some apply both to the pattern type of gas injection projects and to the vertical gravity-drainage type of gas injection projects; others apply only to the gravity-drainage projects. In all cases, individual well production and pressure performance as a function of time must be recorded.<br/><br/>The most obvious monitoring method is to track the GORs of the individual production wells as a function of time. The GOR will be approximately flat at the oil’s solution GOR until there is gas breakthrough. Then the GOR will climb. The timing of gas breakthrough and the rate of GOR climb will indicate how efficiently, or inefficiently, the gas/oil displacement is progressing. Field engineers should have made preliminary calculations, possibly using a numerical reservoir simulator, so that they have projections of what should be expected regarding gas breakthrough timing and GOR increases at the individual well locations (and as a function of the volume of gas injected at the individual injection wells).<br/><br/>The other methods concern primarily the monitoring of the vertical movement of the gas/oil interface (the current GOC) in gravity-drainage-type projects. Two techniques are generally used: cased-hole logging programs and monitor-well observations. Both help track the GOC movement as a function of time. By mapping the GOCs from the individual wells, engineers can determine whether the GOC is staying reasonably horizontal. By comparing the GOC movement as a function of time to the projected GOC behavior, engineers can determine how efficient the gas/oil displacement is and whether the project’s expectations are being met.<br/><br/>For some reservoirs, other unique techniques can be used. For example, if a reservoir has a natural oil gravity variation as a function of depth, then the production wells’ oil gravity can be tracked as a function of time.<br/><br/>Another technique is to take periodic gas samples and perform gas chromatograph analyses to determine the produced gas composition. To use this technique, baseline gas samples should be taken early and periodically from all wells. There are two circumstances in which gas chromatography is a useful tool for gas-injection project monitoring. The first is those projects in which flue gas (88% N₂, 12% CO₂) or pure N₂ is injected. In that type of project, it is important to track the BTU value of the gas from each well and how the nonhydrocarbon content of the produced or residue gas changes as a function of time. This is important with respect to the use of that gas for field fuel and the marketability of the residue gas stream.<br/><br/>Second, this technique can be important late in the life of a gas-injection project when wells are operating at very high GORs. This technique is useful for determining whether some of the very lean injection gas is breaking through into some of the wells without becoming saturated with light and intermediate hydrocarbon components from the residual oil phase in the gas-swept region above the current GOC. Such lean gas can actually strip intermediate hydrocarbon components from the produced oil in the field gas/oil separators. If there is no gas plant as part of the field facilities, then those hydrocarbons will be lost to the downstream owner of the gas plant that processes the field gas.<br/><br/>One other aspect of the monitoring activities is to track from which of the perforated intervals most of the gas flow is entering the wellbores. This can be accomplished with periodic spinner or temperature surveys. Depending on the nature of the reservoir interval, it may be possible to temporarily plug off some of the perforations to reduce wells’ producing GOR.<br/><br/>The purpose of all these monitoring activities is to perform real-time analysis of reservoir performance and to consider any remedial actions. These actions include such alternatives as rebalancing the gas rates into the various injectors, rebalancing the flow rates of the various producers, and potentially drilling a few new injection or production wells into areas of the reservoir determined to require more drainage points or to improve the overall sweep efficiency.<br/>

Because of the concentration of producing wells downdip, the gas cap draped downdip along the top of the reservoir. The Empire Abo field overall performance was excellent because of its very high vertical permeability; however, gas coning was a major issue, with the overall relatively low reservoir permeability of approximately 50 md. In 1979, Empire Abo was the site of one of the first applications of horizontal wellbores to minimize gas coning.<ref name="r59">_</ref> The field is currently being blown down to recover as much gas as possible. On the basis of production data through 2002, on a stock-tank-oil basis, approximately 74% of the OOIP has been recovered from this field by application of the immiscible gas/oil gravity drainage process.<br/><br/>'''''Heft Kel Field (Iran)'''''<ref name="r30">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. http://dx.doi.org/10.2118/35309-MS.</ref> An example of the application of immiscible gas/oil displacement in a large Middle East matrix-block/fracture-system reservoir is the Heft Kel field. Its Asmari reservoir structure is a strongly folded anticline that is 20 miles long by 1.5 to 3 miles wide with an oil column thickness of approximately 2,000 ft. The most probable OOIP was slightly > 7 × 10⁹ STB with about 200 million STB in the fissures; numerical model history matching resulted in a value of 6.9 × 10⁹ STB. The matrix block size determined from cores and flowmeter surveys varied from 8 to 14 ft. The numerical simulation model considered matrix permeabilities from 0.05 to 0.8 md. The overall horizontal and vertical permeabilities are approximately equal. There was an initial gas cap on the oil column. The oil gravity is approximately 37°API. The IFT at the bubblepoint pressure (1,412 psi and 116°F) is approximately 9 dynes/cm.<br/><br/>The field was discovered and put on production in 1928. It was produced on primary production from then until 1976 with a plateau rate of 200,000 BOPD for several early years. In 1976, gas injection began at a rate of 400 MMcf/D using gas from the nearby NIS gas dome. Recently, the field has been producing at approximately 35,000 BOPD.<br/><br/>Saidi<ref name="r30">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. http://dx.doi.org/10.2118/35309-MS.</ref> describes the many oil recovery mechanisms at work in this oil-wet reservoir as gravity drainage at constant IFT and reservoir pressure; oil swelling in the present gas-invaded zone because of the increase in reservoir pressure; oil swelling in the present oil zone through thermal convection/diffusion process; oil imbibition within the oil column; oil gravity drainage from the partially saturated blocks within the gas-invaded zone; and oil gravity drainage from the fully oil-saturated block in the oil zone and the blocks between that and the present GOC.<br/><br/>The flow behavior developed from the history match is that the oil-drainage performance follows that of stacks of discontinuous blocks, supporting practically no vertical capillary continuity between the matrix blocks (see '''Fig. 12.8''').<br/><br/>By going to immiscible gas injection, oil recovery is increased by about 500 × 10⁶ bbl by returning to the original reservoir pressure and could be increased by another 100 × 10⁶ bbl if the reservoir pressure is increased an additional 100 psi because of the reduction in gas/oil IFT with increasing reservoir pressure.<br/><br/>Overall, the application of immiscible gas injection to the Haft Kel field has been considered a success. The estimated displacement efficiency by water was 17%, whereas that estimated for immiscible gas displacement was 32%.<br/><br/>'''''Swanson River Field (Cook Inlet, Alaska)'''''<ref name="r24">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.</ref> A very different style of successful immiscible gas/oil displacement project is that applied to the Swanson River field’s Hemlock reservoir. '''Figs. 12.21 and 12.22''' show an areal view of this reservoir and a type log through the Hemlock formation, respectively. This field is a north/south-trending anticlinal flexure about 6 miles long by 1 to 3 miles wide with as much as 600 ft of closure. The Hemlock formation consists of interbedded fine- to coarse-grained sandstone, conglomerate, siltstone, and coal, with numerous thin, impermeable, calcareous stringers of somewhat limited areal extent. Field experience has confirmed that these calcareous stringers are effective barriers to the vertical migration of fluids in the vicinity of producing wells. There are 10 Hemlock intervals, and the H1 through H5, H8, and H10 intervals have been engineered and managed separately (see '''Fig. 12.22''').<br/><br/><gallery widths="300px" heights="200px">

The OOIP of this field is 435 million STB. This oil was very undersaturated at discovery in 1957, with an original reservoir pressure of 5,580 psi but with a bubblepoint pressure of only 1,350 psi. The oil is 37°API gravity, had an initial FVF of 1.21, and had a viscosity of 1.1 cp.<br/><br/>From these reservoir characteristics, it was clear that at the start of production the reservoir pressure would fall rapidly and that some form of pressure maintenance needed to be applied quickly. Fortunately for this very undersaturated oil field, a Tcf-sized dry gas field was discovered nearby for which there was no immediate or large outlets for its gas. A gas rental contract was signed between the two fields owners, and starting in 1966, 400 MMcf/D of gas was delivered for injection into crestal wells in the Swanson River Hemlock reservoir.<br/><br/>Laboratory studies indicated that a number of mechanisms were at work when methane gas displaced the low-bubblepoint-pressure Swanson River oil. First, if operating at a 5,000-psi pressure, the oil would swell from an FVF of 1.21 to an FVF of 1.80 on contact with the injected gas. Second, free gas would become saturated with intermediate hydrocarbon components from the fairly light (37°API) reservoir oil. Laboratory experiments show that breakthrough recovery efficiency exceeded 60%.<br/><br/>Although the Swanson River field has operated at high GORs (> 10 Mscf/STB) after the first several years of production, reservoir performance has been excellent, with 38% of the OOIP recovered through the first 10 years of gas injection. To show that the oil vaporization mechanism is also at work in this reservoir, during these first 10 years of production after the start of gas injection, the produced oil gravity increased from 37 to 40°API.<br/><br/>The Swanson River field is currently being blown down to recover as much remaining gas as possible. From production statistics through 2002 and an updated OOIP of 390 × 10⁶ bbl, ultimate recovery from application of immiscible gas/oil displacement to this field is nearly 58% of OOIP. This has been achieved primarily through oil swelling and oil stripping, not vertical gas/oil gravity drainage.<br/><br/>'''''Kuparuk River Field, Alaskan North Slope.'''''<ref name="r14">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.</ref><ref name="r15">Stoisits, R.F., Scherer, P.W., and Schmidt, S.E. 1994. Gas Optimization at the Kuparuk River Field. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 25-28 September 1994. SPE-28467-MS. http://dx.doi.org/10.2118/28467-MS.</ref> Another type of immiscible gas/oil project is that applied to some areas of the Kuparuk River oil field. The Kuparuk River field contains approximately 5.9 × 10⁹ bbl of 24°API oil in two producing zones (zones A and C). The oil was slightly undersaturated at discovery (3,300-psi original reservoir pressure, with oil 300 to 500 psi undersaturated). The shallower C sand is more permeable than the A sand, but the A sand contains approximately 62% of the OOIP. The reservoir covers > 200 sq miles.<br/><br/>The field was discovered in the late 1960s and went on production in 1981. The maximum rate has exceeded 300,000 BOPD, producing from 42 drillsites with wells on 160-acre well spacing. The challenges in this field were that there was no initial gas cap on the reservoir into which to reinject the produced gas; the reservoir dip is very slight, and the reservoir intervals were not very thick, so gas/oil gravity drainage could not efficiently occur; the gas could not be flared; and there was no off-site location to which the residue gas could be sent. For these reasons, the gas had to be reinjected into one of the reservoir intervals for storage and to maintain the oil production rates. The challenge for the field engineers was how to reinject the residue gas in the most efficient way, given the various constraints.<br/><br/>After a few years of gas injection into the A sand in one area of the field in which the offsetting producers soon experienced rapidly increasing GORs, the engineers decided to go to an immiscible WAG injection process.<ref name="r14">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.</ref> WAG could be applied at minimal cost and with few operational complications because most of the field was already being waterflooded. Calculations indicated that there were three beneficial effects to this approach. First, there would be some swelling of the oil because of the free gas. Second, the residual oil saturation could potentially be reduced by the presence of trapped gas. Third, WAG injection was used to reduce the high mobility of the gas by means of three-phase relative permeability effects (simultaneously having mobile gas, oil, and water in the pore system); also, a tapered WAG scheme helped in this regard. The overall effect was that oil recovery could potentially be increased by 1 to 3% of OOIP without resulting in significant gas cycling problems. To date, immiscible WAG injection has worked as expected and has been a satisfactory solution to the Kuparuk River gas disposal problem.<br/>

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,<ref name="r29">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. http://dx.doi.org/10.2118/57251-MS.</ref> 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.<br/><br/>A related consideration is when there is a thin oil column sandwiched between the expanding gas cap and the underlying aquifer.<ref name="r29">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. http://dx.doi.org/10.2118/57251-MS.</ref> 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.<br/>

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Conversion factor is exact.</div></div>[[Category:PEH]]

 

[[Category:5.4.2 Gas injection methods]]