3 Improved Oil Recovery.pdf x1914

Improved Oil Recovery The use of reservoir energy to produce oil and gas generally results in a recovery of less than 50% of the original oil in place. The primary recovery mechanisms of solution gas drive, gas cap drive and water drive, or a combination of one or more of these and gravity drainage, for most of the world's oil production. Secondary recovery techniques, in which external energy is added to a reservoir to improve the efficiency of the primary recovery mechanisms, have been in use for many years. The injection of water to supplement natural water influx has become an economical and predictable recovery method and is applied worldwide. Less commonly, gas injection has been used to displace oil downdip in "attic" oil recovery projects or to maintain gas cap pressure. Still, both primary and secondary recovery techniques have only been effective in producing roughly one third of the oil discovered. The remaining two thirds, more than 300 billion barrels (4.7696 × 1010 m3) in the United States alone, is a target for more sophisticated processes. Such processes, developed to increase recovery from reservoirs considered depleted by primary mechanisms and secondary methods of water or gas injection, were historically termed tertiary recovery techniques. However, because some of these processes may be applied earlier in the life of a reservoir, perhaps even in the first day of production, the "tertiary" term is no longer appropriate here, and as a result, the term enhanced oil recovery methods has been introduced as the term to be used for all processes that attempt to alter the physical forces that control the movement of oil within the reservoir. Both conventional water and gas injection, and the more unconventional enhanced oil recovery methods can collectively be termed improved oil recovery methods.

Waterflooding and Recovery Efficiency All improved recovery methods involve the injection of fluids into the reservoir via one or more wells, and the production of oil (and perhaps ultimately the injected fluid) from one or more other wells. The methods differ in the nature of the fluids used and the physical changes they bring about in the reservoir, but water usually plays a part in helping to displace the oil. The amount of oil recovered (and obviously the success of the project) is dependent upon the percentage of oil in place that is ed and moved by the displacing fluid. This concept is represented by the equation: Np = N EV ED

(1)

where : EV = EAS EVS The oil recovered (Np) is the product of the volume of the oil in place (N), the fraction that is ed (EV), and the fraction of the oil ed that is displaced (ED). The volumetric sweep efficiency (EV), given as a fraction, is the product of the areal sweep efficiency (EAS), and the vertical sweep efficiency (EVS). Usually all of these values (except N) increase during the life of an improved recovery project, until an economic limit is reached. Enhanced recovery methods differ in the manner in which they attempt to improve either EV or ED. We will discuss each factor separately. VOLUMETRIC SWEEP EFFICIENCY: The volumetric sweep efficiency (EV), at a given point in time, is the fraction of the total reservoir volume ed by the injected fluid during an improved recovery project. It is the composite of the areal sweep efficiency (EAS), and the vertical sweep efficiency (EVS). When oil is swept from a reservoir by water, an important factor in determining the areal and vertical sweep efficiencies is the difference in the mobilities of the two fluids. The mobility of any fluid in a porous medium such as reservoir rock is directly proportional to its velocity of flow and is equal to the effective permeability to that fluid divided by the fluid viscosity. For oil this would be equal to k0/0. Because our reservoir permeability information is available in of relative permeability, the mobility is expressed as:

(2) The mobility ratio is defined as the mobility of the displacing phase in the portion of the reservoir ed by the injected fluid, divided by the mobility of the displaced phase in the non-invaded portion of the reservoir. In the case of water displacing oil (waterflooding):

If M is less than or equal to one, it means that the oil is capable of traveling at the same or greater velocity than the water, under the same conditions. The water, therefore, will not by the oil and will instead push it ahead. If M is greater than one, the water is capable of moving faster than the oil and will by some of the oil, leaving unswept areas behind. We can see that an increase in the viscosity of the oil will cause the mobility ratio to increase. This is logical, as we can imagine attempting to push a viscous, heavy oil through a pore system and having the less viscous water "finger" through or around the slow moving oil. An obvious approach to improving

the mobility ratio would be to decrease the difference in oil and water viscosities, by increasing the water viscosity and/or decreasing the oil viscosity. We can also imagine that the areal sweep of water through an oil reservoir would also depend upon where the water is injected relative to where the oil is produced. A wide variety of flooding patterns have been used in the oil field and some of these are reproduced in Figure 1 and Figure 2 .

Figure 1

Laboratory models have enabled researchers to measure the areal sweep efficiencies for different mobility ratio/flood pattern combinations.

Figure 2

For example, if we have wells spaced in a five-spot pattern and are producing from a homogeneous uniform reservoir, the areal sweep efficiency at the point in time when the displacing phase breaks through to the producing well has been shown to be about 68% to 72% for a mobility ratio of 1.0. Figure 3 (M=1.0) shows, in stages, the sweep of a five-spot model as the injected fluid moves to breakthrough.

Figure 3

Figure 4 shows how the areal sweep efficiency at breakthrough for this pattern changes with mobility ratio.

Figure 4

We are interested in the sweep efficiency at breakthrough because, generally, little additional oil is recovered by injecting water after a channel of water flow exists between injector and producer. It should also be pointed out that areal variations in permeability will have a major effect on the ability of the displacing phase to sweep the reservoir. For this reason, the reservoir engineer now works closely with the development geologist to define the reservoir environment. Vertical sweep efficiency (EVS) also depends upon the mobility ratio and, in addition, on the vertical distribution of permeability within the reservoir. The laboratory determined areal sweep efficiencies mentioned above assume a homogeneous reservoir. If the permeability varies vertically, as is often the case in a real reservoir, an injected fluid will move through the reservoir with an irregular vertical front, moving more rapidly in the more permeable sections. The sweep efficiency at breakthrough will depend on the degree of difference in permeabilities and on the mobility ratio. Figure 5 shows how changes in the mobility ratio can affect vertical sweep.

Figure 5

When the mobility ratio is greater than 1.0, the displacing phase has more mobility than the displaced phase. Thus, as displacing fluid enters the high permeability zone, the total resistance to flow decreases in that zone and the flow in that zone increases. When breakthrough eventually occurs, a greater portion of the lower permeability zone is left unswept. When M is less than 1.0, the channeling effect is less pronounced. DISPLACEMENT EFFICIENCY: Unfortunately, simply getting the injected fluid to a given volume of the reservoir does not mean that all the oil in that volume will be displaced. The displacement efficiency refers to the fraction of the oil in place that is swept from a unit volume of the reservoir. Displacement efficiency is a function of fluid viscosities and the relative permeability characteristics of the reservoir rock (mobility ratio), of the "wettability" of the rock, and of pore geometry. Wettability pertains to whether water or oil preferentially "wets" the reservoir rock grains. In an oil-wet reservoir, oil is preferentially adsorbed on the grain surface. For a water-wet reservoir, the converse is true. Oil reservoirs range from strongly oilwet, through intermediate gradations to strongly water-wet. Most are water-wet. In a water-wet system, the oil exists in the middle of the pore system with water distributed between it and the rock surfaces. As water displaces oil through the

porous medium, some of the oil is left in globules at the center of the pores. In an oil-wet system, the residual oil clings to the rock grains and is left as a film on the pore walls. Figure 6 ((a) water-wet rock (b) oil-wet rock) illustrates the difference between these two extremes.

Figure 6

We can also see the role of wettability in the capillary effects in a reservoir. Figure 7 shows a microscopic view of a water-wet pore system.

Figure 7

As the invading water reaches the intersection of the large diameter and smaller diameter pore channels, the individual pores "pull" the water phase ahead in a manner similar to that of water rising in a capillary tube. The advance is greatest in the pore with the smallest radius. Once the water-oil interface has reached a capillary equilibrium position in a pore, the pressure gradient pushes it along toward the outlet. The interface reaching the outlet first (probably the smaller capillary) rushes through the outlet to the next pore and isolates the oil in the other capillary. On a three-dimensional level, the isolated oil is referred to as ganglia and collectively it makes up the residual oil saturation in the swept portions of the reservoir. The isolated oil will not be moved by normal pressure gradients in the reservoir unless the resistance of the water-oil interface can be broken down by reducing the interfacial tension at the interface. The relative permeability characteristics of a reservoir rock and the fluid viscosities are the properties used to determine the displacement efficiency. As we mentioned in section 2.1.2, relative permeability is a measure of the rock's ability to conduct one fluid when two (or more) fluids are present. It reflects the composite effect of pore geometry, wettability, fluid distribution, and saturation history on the fluid flow behavior of the rock-fluid system. Figure 6 shows examples of relative permeability curves for both strongly water-wet and strongly oil-wet rocks.

The displacement efficiency for a waterflood can be calculated using the fluid viscosities and the water-oil relative permeability characteristics. The procedure is to construct a fractional flow curve, the fractional flow of water versus water saturation. If this approach is utilized, it can be shown that the displacement efficiency at breakthrough is higher the lower the oil viscosity. For a strongly water-wet reservoir with relative permeability characteristics, as shown in Figure 8 ,

Figure 8

if the oil viscosity is about 2.0 (0.002 Pa s) or lower, the displacement of oil by the water is "piston-like"; that is, all the recoverable oil in the swept portion is displaced at breakthrough . Usually the displacement is not so efficient, and the average water saturation in the invaded portion of the rock increases with continued injection ( Figure 9 ) .

Figure 9

Figure 10 and Figure 11 shows schematically the difference between ideal and nonideal displacement.

Figure 10

The flood front is shown as a vertical line representing the discontinuity of water saturation behind and ahead of the front.

Figure 11

We might find that, based on measurements of relative permeability, fluid viscosities, and permeability distributions, the expected sweep efficiency factors for a proposed waterflood are: ED = 0.75; EAS = 0.85; EVS = 0.80 Our overall recovery efficiency is then: ED EAS EVS = 0.75 x 0.85 x 0.80 = 0.51 or 51 % and we might expect to recover 51% of the oil in place as a result of water-flooding. This means that only half the oil can be recovered even when we have a good level of efficiencies. The task of recovering the balance of the oil is formidable! Enhanced oil recovery methods attempt to improve these efficiency factors by: • reducing the mobility ratio by increasing water viscosity; • reducing the mobility ratio by decreasing oil viscosity; • altering the interfacial tension of the water-oil interface; and • improving the relative permeability characteristics.

Table 1 (below) lists the enhanced recovery methods that are of importance today. Enhanced oil recovery methods: Chemical Recovery Processes • Polymer flooding • Surfactant-polymer flooding (microemulsion flooding) • Caustic flooding Thermal recovery processes

• Steam flooding • In-situ combustion Miscible recovery processes

• Miscible hydrocarbon displacement • Carbon dioxide injection • Inert gas injection Table 14 (above)

Enhanced Oil Recovery (EOR) Enhanced oil recovery processes attempt to alter the physical forces holding oil in a reservoir by improving the volumetric sweep efficiency through mobility ratio control, and by improving the displacement efficiency through surface active agents, heat, and miscible displacement. Regardless of laboratory performance, the value of all enhanced oil recovery techniques ultimately is determined by the degree to which they are economically applicable in the field. It may be possible to maximize recovery by initiating an enhanced recovery project early in the life of a field, but the additional early capital cost with delayed return may make it economically unattractive. Economic applicability is critically dependent on an accurate geological interpretation of the reservoir. By providing guidance throughout the development of a reservoir, geologists can help provide for the maximum recovery of the oil they have found.

Chemical Recovery Processes Several approaches that improve the mobility ratio in a waterflood and reduce the interfacial tension at the oil-water interface have involved the addition of chemical agents to injected water. POLYMER FLOODING: An obvious approach to improving the mobility ratio would be to increase the effective viscosity of the injected water before injection into the reservoir. This can be done by the addition of long chain molecules, called polymers (the jelly-like component in your tube of shampoo). Although there are many polymers available for this approach, the most economically attractive examples are polysaccharides (xanthan gum) and polyacrylamides. The polysaccharides are produced by microbial action while the polyacrylamides are synthetically produced chemicals with a wide range of molecular weights and chain lengths. Polyacrylamides are relatively economical and stable, but are sensitive to shear and salinity. Polysaccharides stand up to salinity and shearing rates but are prone to bacterial and thermal degradation. A commercial polymer solution is a non-Newtonian fluid. Its behavior is generally characterized as pseudoplastic; that is, its resistance to flow and its apparent viscosity is lower at low flow velocities than at high flow velocities. However, at very high velocities, such as those that may exist near the injection wells, the polymer solution can act as a dilatant fluid and its apparent viscosity will increase. (Where high velocities might cause bying, the polymer solution increases viscosity and slows down!) Figure 1 (comparison of viscosities of two types of polymers at 1000 ppm in 1.0% NaCl at 74° F) shows the effect of polymer solution concentration on viscosity at a given shear rate. (Normal formation water viscosity is about .2 to 2 .) In addition to increasing water viscosity and thereby reducing the mobility ratio, polymer flooding also improves areal and vertical sweep efficiency by reducing the relative permeability to the polymer solution. Apparently this is accomplished by adsorption of the polymer onto the rock grains, by entrapment of polymer molecules in pore throats, and by the inability of the polymer-laden solution to enter small pore channels. Overall, the reduction in permeability allows the preferential filling of the high permeability streaks or zones in the reservoir with a viscous slug, lowering the velocity of flow and increasing the sweep of the lower permeability zones. Polymer flooding does not decrease the residual oil saturation significantly in the swept zone. Its primary importance is in the improvement of the areal and vertical sweep efficiencies and the acceleration of oil production before the economic limit of water-oil production ratio is reached. Polymer flooding is most efficient when begun early in the life of a waterflood, particularly when mobility ratios are poor (2 to 20) and significant permeability variations exist. SURFACTANT POLYMER FLOODING: Surface active agents, or surfactants, are compounds that can act to reduce the interfacial tension at the interface between the oil and water in the reservoir. Detergents are examples of an everyday use of surfactants to allow water to displace oil (and the accompanying dirt) from clothing, dishes, etc. Reduction in interfacial tension improves the displacement efficiency of the flood and reduces the residual oil saturation. Surfactants are usually introduced to a waterflood as components in a water-oilsurfactant solution. This solution is also called a microemulsion, or a micellar solution, because of the existance of micelles, aggregates of surfactant molecules surrounding microscopic oil droplets in water, or

microscopic water droplets in oil. A slug of this solution is injected into the reservoir, usually in a high volume (15% to 60% of reservoir pore volume) with a low concentration, or in a low volume (3% to 20% of reservoir pore volume) with a high concentration. In the low concentration case, the reduction in interfacial tension increases oil recovery gradually with the age of increasing volumes of surfactant solution. In the high concentration case, the surfactant solution rapidly displaces water and almost all the oil ed, but it reverts to a low-concentration flood as the surfactant slug becomes diluted by formation fluids. Figure 2 shows schematically how a microemulsion and a polymer solution, followed by water injection, are used in sequence to improve the mobility of the flood. Some surfactant solutions have cosurfactants (usually alcohol), electrolytes, or inorganic salts added to improve performance. Surfactant slug size and composition must be tailored to the specific reservoir rock and fluid properties. Adsorption of surfactants onto the rock surface can be an important reason for slug breakdown. The subject of surfactant solutions is complex and their behavior in the reservoirs is not easily predicted. CAUSTIC FLOODING: The fact that the addition of sodium hydroxide (caustic) to injection water improves oil recovery for many reservoirs has been recognized for many years. Although the process appears simple and relatively inexpensive, the mechanisms involved in displacement of the oil are complicated. At present, at least five methods are believed to act in the process: • lowering of interfacial tension by reaction of the caustic with acidic crude oil components usually found in heavier, viscous crudes, to create surfactants in situ; — reversal of rock wettability; — emulsification of residual oil and entrapment in small pore throats to reduce water mobility, and improve areal and vertical sweep efficiency; — in-situ emulsification and entrainment of residual oil into the flowing caustic water phase, carrying the oil out of the rock; — solubilization of rigid films, which form at the oil-water interface, allowing mobilization of the residual oil. The most commonly used caustic chemical is sodium hydroxide, although sodium orthosilicate, ammonium hydroxide, and others have been suggested. The reaction of the reservoir rock with the chemical is an important factor that must be considered in deg a caustic flood. Crude oil acidity is also important. Also, the hardness of the injection water must be controlled, or else precipitates of calcium hydroxide may form, plugging the injection wells. Low concentration caustic solutions (0.5 to 2.0 wt%) appear to offer the best results for interfacial tension reduction.

Chemically enhanced oil recovery processes act to improve mobility ratio, increase volumetric sweep, and improve displacement efficiency. Compared with other methods, recovery costs can be somewhat high, except for caustic flooding. Table 1 (below) shows some generalized reservoir criteria for screening reservoir candidates. Screening criteria for chemical processes: Surfactant/Polymer Oil properties • Gravity ° API >25 • Viscosity <30 • Composition light intermediates desired Reservoir • Oil saturation >30% characteristics • Formation type sandstone preferred • Net thickness ft (m) >10 (3) • Average >20 permeability md • Depth ft (m) <8000 (2400) • Temperature ° F (K) <175 (353) Polymer Alkaline (caustic) Oil properties • Gravity ° API >25 13-35 • Viscosity <150 <200 • Composition not critical some organic acids

Reservoir characteristics • Oil saturation >10% mobile oil above waterflood residual

• Formation type sandstone preferred; sandstone carbonate preferred possible • Net thickness ft (m) not critical not critical • Average permeability >10 (normally) >20 • Depth ft (m) <9000 (2700) <9000 (2700) • Temperature ° F (k) <200(367) <200 (367) Table 1 (Taber and Martin, 1983)

Thermal Recovery Processes Thermal processes attack the problem of an unfavorable mobility ratio by heating the reservoir and its fluids, either by adding heat via steam or hot water, or by generating heat within the reservoir by burning some of the oil in the formation. The most important effect of adding heat is the sharp reduction in the oil viscosity and the resulting decrease in the mobility ratio. Figure 1 shows the effect of temperature on oil viscosity.

Figure 1

Note that the viscosity of a heavy, 10API crude oil at 60 F (288.7 K) is about 100,000 (100 Pa s), but drops to about 10 at 360¡F (0.01 Pa s at 455.4 K). Increasing the reservoir fluid temperature also reduces interfacial tension and increases the relative permeability to oil. It also vaporizes some of the oil (lighter ends) as it moves forward in the formation where it condenses to form an "improved" oil. STEAM FLOODING: Steam flooding consists of the continuous injection of steam into a reservoir with an injection-production well pattern similar to a waterflood. As the steam moves out into the reservoir away from the injection well, its temperature

drops from heat losses and it begins to condense as hot water ( Figure 2 ). In the steam zone, oil is actually vaporized. In the hot water zone, the oil expands, its viscosity drops, the residual saturation is lowered, and the relative permeability increased. All of these effects improve oil recovery.

Figure 2

An alternative to pattern steam flooding is to inject steam into a well, shut it in for a period of time, and then back-produce the less viscous hot oil and water located near the wellbore. This cycle is repeated many times and is termed cyclic steam injection, "huff and puff," or steam stimulation. Operators can begin with this procedure but later must ultimately convert to a pattern steam flood to maintain oil production rates. Steam flooding is currently the principal enhanced oil recovery technique. As of 1995, the world’s largest steamflood project was in the Duri field in Indonesia, producing 300,000 STB of oil per day. Other major steamflood areas include the United States (particularly California) and Venezuela. The primary factors limiting the application of steam injection to oil reservoirs are depth and thickness; depth because of the critical pressure of steam (3202 psia or 22,086 kPa), and thickness because of excessive heat loss to underlying and overlying rock formations in the reservoir. Table 1 (below) gives some data comparing successful steam floods worldwide. One of the California examples, the

South Belridge field, was developed in the 1940s, but by 1952, production of the heavy 13 API, 1600 viscosity crude using normal production methods had peaked. Cyclic steam injection was introduced and increased rates during the late 1960s, but the effectiveness of successive steam cycles diminished. Continuous steam injection began in 1969, and within 4 1/2 years, the oil recovery exceeded the total oil recovered during the preceding 25 years by both primary recovery and cyclic steam stimulation (Van Poollen 1980). Field- Sand Depth Reservoir h (ft) Pressure Net Pay (psig) (ft) Kern River, CA 900 35 60 Inglewood, CA 1,000 120 43 Brea B, CA 4,600 100 189 Coalinga, CA 1,500 300 35 Yorba Linda, CA 2,100 200 32 San Ardo Auginac, CA 2,350 250 150 Mount Poso, CA 1,800 100 60 Yorba Linda, CA 650 325 South Beldridge, CA 1,100 180 91 Midway-Sunset, CA 1,600 50 350 Schoonebeck, Holland 2,600 120 83 Slocum, TX 535 110 40 Smackover, AR 2,000 5 20 Tia Juana, Venezuela 1,600 300 125 Winkleman Dome, WY 1,200 210 73 Field- Sand

0

k, kh/0

Oil Vis- Permeability (md-ft/) cosity () (md)

Kern River, CA 4,000 4,000 60 Inglewood, CA 1,200 6,000 220 Brea B, CA 6 70 2,200 Coalinga, CA 100 5,000 1,750 Yorba Linda, CA 600 500 27 San Ardo Auginac, CA 2,000 3,000 225 Mount Poso, CA 280 15,000 3,210 Yorba Linda, CA 6,400+ 600 South Beldridge, CA 1,600 3,000 170 Midway-Sunset, CA 4,000 4,000 350 Schoonebeck, Holland 180 5,000 2,300 Slocum, TX 1,300 3,500 1,080 Smackover, AR 75 5,000 1,330 Tia Juana, Venezuela 5,000 2,800 70 Winkleman Dome, WY 900 600 50 Field- Sand Oil Content Steam/Oil Oil Steam (bbl/acre-ft) Ratio Ratio (bbl/bbl) (bbl/bbl) Kern River, CA 1,360 4.0 0.25 Inglewood, CA 1,580 2.0 0.50 Brea B, CA 940 4.8 0.21 Coalinga, CA 1,250 2.8 0.36 Yorba Linda, CA 1,070 4.8 0.21 San Ardo Auginac, CA 1,690   Mount Poso, CA 1,480 4.8 0.21

Yorba Linda, CA    South Beldridge, CA 1,820 3.6 0.28 Midway-Sunset, CA    Schoonebeck, Holland 1,980 2.7 0.37 Slocum, TX 1,400 5.6 0.18 Smackover, AR 1.960 3.0 0.33 Tia Juana, Venezuela 1,660 1.2 0.83 Winkleman Dome, WY 1,450 5.0 0.20 Table 1 (above) IN-SITU COMBUSTION: Another way of obtaining the beneficial effects of heat in the reservoir is to generate the heat in situ, or within the reservoir itself. This can be done by injecting oxygen (air) into the reservoir by using compressors, and then igniting the crude oil-oxygen mixture. Continued injection of air will cause the burning front or combustion zone to propagate out into the reservoir, heating the oil ahead of it, and producing steam and hot gases that drive the oil out of the reservoir. There are three basic forms of in-situ combustion: dry forward combustion, reverse combustion, and wet combustion. Figure 3 shows schematically how the combustion zone is propagated outward in the direction of the injection in the dry forward combustion process.

Figure 3

Behind the combustion zone the sand is "burned out" and the combustion zone is the hottest portion of the flood. Immediately ahead of the combustion zone is the coke region, where the heavier portions of the crude oil are all that remain to be burned, after the heat from the approaching combustion zone has "cooked" the oil. Ahead of the coke zone are steam and hot water generated by heat from the combustion zone, light hydrocarbons distilled from the reservoir crude, and a bank of oil being pushed ahead by the front. In the reverse combustion process, the air is injected from the opposite direction but ignition is at the same point, now the producing well. This approach forces the oil to move through the preheated reservoir, allowing easier flow of extremely heavy crudes. However, more of the lighter portions of the crude are consumed by the process. Wet combustion is an attempt to transfer the heat from the burned out portion of the reservoir behind the combustion front in a dry forward process to the oil ahead of the burning zone. Water is injected after the front has been propagated and is converted into steam in the reservoir by the hot rock behind the combustion zone. This partially quenches the combustion zone and spreads the generated heat more evenly through the reservoir. Important considerations in selection of reservoirs for in-situ combustion and steamflooding processes are generalized in Table 2 (below) . Vertical sweep in very thick formations is likely to be poor due to segregation of the steam and combustion gases. In-situ combustion is particularly appropriate when there is less rock to heat; that is, when the porosity and oil saturations are high. Economic comparisons of in-

situ combustion versus steam injection depend heavily on the cost of fuel to produce steam. Screening criteria for thermal processes: Combustion Steamflooding Oil properties Gravity API <40 <25 (10-25 normally) • Viscosity <1000 >20 • Composition some asphaltic not critical components Reservoir • Oil saturation >40%-50% >40%-50% characteristics • Formation type sand or sandstone sand or sandstone with high porosity with high porosity • Net thickness ft(m) >10(3) >20(6) • Average permeability md >100* >200** • Depth ft (m) >500 (150) >300-5000 (90-1500) • Temperature >150 (340) F (K) not critical *Transmissibility>20 md ft/ **Transmissibility>100 md ft/ Thermal processes rely on heat primarily to reduce oil viscosity but also to reduce interfacial tension, improve relative permeability, and vaporize and expand portions of the oil. Both volumetric sweep efficiency and displacement efficiency are improved.

Miscible Recovery Processes Washing one's hands with detergent after an oil change will get the worst of it off, but a little gasoline (while not recommended) will clean up every trace of oil. That's the difference between surfactants and miscible displacement. Miscibility means that the interface between the displacing and displaced fluids disappears, so that the oil is dissolved, and the result is 100% displacement efficiency. Of course, a gasoline flood is absurd from an economic standpoint, but several other methods approach the goal of complete oil displacement. These methods differ primarily in the type of solvent used to achieve miscibility: refined hydrocarbons, liquified hydrocarbon gases, carbon dioxide, or inert gases. MISCIBLE HYDROCARBON DISPLACEMENT: There are three different miscible hydrocarbon displacement processes: the Miscible Slug Process, the Enriched Gas Process, and the High-Pressure Lean Gas Process. In the Miscible Slug Process, a propane slug of perhaps 5% of the reservoir pore volume is injected, followed by natural gas, or gas and water, to drive the solvent through the reservoir. In the Enriched Gas Process, a slug of hydrocarbon gas with large amounts of C2-C6 components is injected in place of the propane slug. The High-Pressure Lean Gas Process substitutes a lean natural gas mixture in order to cause vaporization of the C2-C6 components from the oil to the gas, forming a miscible phase at high-pressure. Figure 1 shows schematically what happens sequentially in a Miscible Slug Process.

Figure 1

Unfortunately, the solvent becomes con-cent rated with oil as it moves through the reservoir and its ability to dissolve the oil is reduced. Another major problem is the poor mobility ratio that exists between the solvent and the gas that follows it. Alternate injection of gas and water is used in an attempt to improve this situation. The lean gas or enriched gas processes are particularly suited for areas where there is no ready gas market and the necessary size of the propane slug is economically unattractive. CARBON DIOXIDE FLOODING: Carbon dioxide is soluable in both oil and water, and can be miscible with oil, making it a candidate for use in miscible floods. Miscibility of carbon dioxide and oil is pressure dependent, however, and not all carbon dioxide floods are miscible processes. In addition to miscibility, other factors that allow carbon dioxide to improve oil recovery include: reduction of crude oil viscosity; swelling of the crude oil; increased injectivity; and solution-gas drive effects. Carbon dioxide flooding can be applied in a variety of ways: continuous injection of carbon dioxide; carbon dioxide injection followed by a less expensive gas; carbon dioxide injection followed by water; and simultaneous or alternate injection of carbon dioxide and water (called the WAG process). Although carbon dioxide is not immediately miscible with crude oil, under the right conditions of temperature and pressure, the carbon dioxide will extract components from the oil in a manner similar to that mentioned earlier for lean gas displacement. This mixture forms a miscible front that efficiently sweeps the oil to the producing wells. The required pressure for miscibility varies with oil composition and temperature. For example a 30 API oil requires 1200 psi while a 27 API oil requires 4000 psi at 120F. Pipelines from Colorado to west Texas are now carrying CO2 to fields that are currently undergoing, or will soon undergo, CO2 injection. INERT GAS INJECTION: The use of nitrogen, or "flue gas," as a cheaper substitute for carbon dioxide, or light hydrocarbon mixtures, has been tested in the laboratory and the field. Combustion gases from boiler flues or gas engine exhausts are primarily nitrogen and carbon dioxide, and have a larger volume than the gas burned to produce them. Nitrogen does not achieve miscibility as easily as carbon dioxide, but it can effectively displace the reservoir gas for sale, leaving the inert gas in the reservoir at abandonment.

An inert gas injection project in the Hawkins field, Texas, is designed so that steam boiler exhaust gas is injected into the gas cap of a water drive reservoir to prevent loss of gas cap pressure. The steam boilers that produce the flue gas also drive turbines which, in turn, power compressors to inject the inert gas (Van Poollen 1980). Table 1 (below) gives some generalized criteria for the selection of candidate reservoirs for miscible recovery projects. While miscible displacement holds the promise of improving the displacement efficiency, in most applications the cost of the miscible fluid is high and much of it is not recoverable. Reservoir heterogeneity is an important factor in all improved recovery projects, but particularly so in miscible displacement processes where discontinuities can result in the bying of costly injectants. Screening criteria for miscible processes:

Hydrocarbon Oil properties

Reservoir characteristics

Gravity API

>35

Viscosity

<10

Composition

high % of C2 - C7

Oil saturation

>30% PV

Formation type

sandstone or carbonate

Net thickness ft (m) thin unless dipping

Oil properties

Reservoir characteristics

Average permeability md

not critical

Depth ft (m)

>2000 (600) for LPG to >5000 (1500) for H.P. Gas

Temperature F (K)

not critical Nitrogen & Flue Gas

Carbon Dioxide

Gravity API

>24 >35 for N2

>26

Viscosity

<10

<15

Composition

high % of C1 - C7

high % of C5 - C12

Oil saturation

>30% PV

>30% PV

Formation type

sandstone or carbonate

Net thickness ft (m) thin unless dipping

sandstone or carbonate thin unless dipping

Average permeability md

not critical

not critical

Depth ft (m)

>4500 (1370)

>2000 (6000)

Temperature F (K)

not critical

not critical

Table 2 (Taber and Martin, 1983)