12069

SPE Society of PetroIeurri Engi1eers of A.IME

SPE 12069

Technical Screening Guides for the Enhanced Recovery of Oil by J.J. Taber and F.D. Martin, New Mexico Inst. of Mining & Technology Members SPE-AIME

Copyright 1983 Society of Petroleum Engineers of AIME

This paper was presented at the 58th Annual Technical Conference and Exhibition held in San Francisco, CA, October 5-8, 1983. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write SPE, 6200 North Central Expressway, Drawer 64706, Dallas, Texas 75206 USA. Telex 730989 SPEDAL.

ABSTRACT

The technical screening guides which are used to select enhanced oil recovery methods are described. The background and logic behind the various criteria are covered, and a brief description of each method is included. Economics are discussed, but the emphasis is on the technical guidelines.

A distinction is made between the oil properties and reservoir characteristics required for each process. Generally, steamflooding is applicable for viscous oils in relatively shallow formations. At the other extreme, CO2 , nitrogen, and hydrocarbon miscible flooding work best with very light oils at depths great enough for miscibility to be achieved. Both steamflooding and in-situ combustion require reservoirs of fairly high permeability. Chemical flooding processes (polymer, alkaline or surfactant) are applicable for low-to-medium viscosity oils where depth is not a major consideration. However, at great depths, the higher temperature may present problems in the degradation or consumption of some of the chemicals.

Current values of the technical screening guides for the more common enhanced recovery procedures are given in tabular and graphical form. By the use of a simple graphical technique, it is shown that there is a complete spectrum of enhanced oil recovery methods available for all oils, ranging from the very lightest to the heaviest oil or tar sand.

INTRODUCTION

Screening guides or criteria are among the first items considered when a petroleum engineer evaluates a candidate reservoir for enhanced oil recovery (EOR). The source most often quoted for screening criteria is the 1976 National Pefroleum Council (NPC) report on Enhanced Recovery, which lists the criteria for six enhanced recovery

References and illustrations at end of paper.

methods. The NPC report will continue to be the authority on technical screening criteria, especially when th~ new edition is published within the next year. Other guidelines have been suggested for the appli:t!on of a range of enhanced fe~9very methods 1 and for individual processes. 0 26

Most companies have their own technical screening criteria for enhanced recovery. The company guidelines are often a combination of the NPC values and parameters which have been adjusted to include the latest data from the laboratory and field. After the technical screening guides have been applied to a given prospect, the more stringent economic screening process must take place before the final decision is made. Experienced engineers may be adept at utilizing both kinds of screening guides; however, newer engineers often need a systematic presentation of the technical screening criteria. This paper is our attempt to fulfill this need and provide the reasons for the specific parameters which are listed.

Our approach is to present the technical screening criteria in tables and graphs along with discussion of the pr inciples or basic recovery mechanisms which limit the technical success of each method. We draw a distinction between the criteria which are related to oil properties and to those which depend on reservoir characteristics. In the literature, the desired oil or reservoir values are usually given as either an upper or lower limit for each characteristic. However, these values are not absolute; a number of field projects are underway with oil or rocks which are outside the published limits. Therefore, to give a more realistic picture, we have developed graphs which show a desired range of values for some of the more important characteristics such as oil viscosity. The figures show that there is a variety of enhanced recovery methods available for all oils, from the very lightest to the heaviest oil or tar sand.

2 TECHNICAL SCREENING GUIDES FOR THE ENHANCED RECOVERY OF OIL SPE 12069 RATIONALE FOR USING SCREENING GUIDES

Implementation of enhanced recovery projects is expensive, time-consuming, and people-intensive. Substantial costs are often involved in the assessment of reservoir quality, the amount of oil that is potentially recoverable, laboratory work associated with the EOR process, computer simulations to predict recovery, and the performance of the project. One of the first steps in deciding to consider EOR is, of course, to select reservoirs with sufficient recoverable oil and areal extent to make the venture profitable.

With any of the processes, the nature of the reservoir will play a dominant role in the success or failure of the process. Many of the failures with EOR have resulted because of unknown or unexpected reservoir problems. Thus, a thorough geological study is usually warranted.

While we agree with Prats27 and Farouq Ali21 that each reservoir must be evaluated individually, we feel the technique of using cursory screening guides is convenient for gaining a quick overview of all possible methods before selecting the best one for an economic analysis. Common sense and caution must be exercised since the technical guides are based on laboratory data and results of enhanced recovery field trials, and are not rigid guides for applying certain processes to specific reservoirs. Additionally, the technical merits of recent field projects are clouded by various incentive programs that make it difficult to discern true technical applications. Some projects may have been technical misapplications or failures, but economic successes. Certainly, there have been enough technical successes, but economic failures.

Nevertheless, some EOR processes can be rejected quickly because of unfavorable reservoir or oil properties, so the use of preferred criteria can be helpful in selecting methods that may be commercially attractive. If the criteria are too restrictive, some feasible method may be rejected from consideration. Therefore, the guidelines that are adopted should be sufficiently broad to encompass essentially all of the potential methods for a candidate reservoir. The best methods can then be arrived at in later evaluations. The technical guidelines presented in this paper represent a consensus of many of the experts in this field. Economics of the processes will be discussed later in the paper.

CLASSIFICATION OF ENHANCED RECOVERY METHODS

Before turning to the detailed screening guides, it may be useful to classify the many enhanced recovery methods which have been discussed in the literature and tried in the field. Fig. 1 is a general schematic of enhanced recovery, and it can apply to either tertiary or enhanced secondary projects. The special enhanced recovery fluid can be any substance that does a better job of recovering oil than plain water or gas. The quantity of injected fluid can range from a small fraction of the reservoir pore volume to more than the total pore volume of the reservoir. ObViously, if the material is expensive, only a small amount can be used, and it must be very effective in terms

of additional barrels of oil produced per barrel of substance injected. If large volumes are required, the replacement fluids must be limited to water or one of the inexpensive gases.

On the other hand, the choice of materials for enhanced recovery is very wide, and an enormous number of things have been tried in the laboratory and pumped into the ground in the fond hope of recovering more oil. Table 1 lists eighteen enhanced recovery methods which have been thoroughly tested in the laboratory or the field. The use of microbes for enhanced recovery is not included because of the lack of documented field trials or conclusive laboratory tests. Although Table 1 lists many choices, all of the methods can be grouped into processes that involve either the injection of water, gas or heat; or as a last resort, the mining of the rock to recover the oil.

For sorting out the screening criteria, it is also useful to classify the methods according to the recovery mechanism. Table 2 shows that there are really just three basic mechanisms for recovering oil from the rock more effectively than by water alone. The methods are grouped according to those which rely on a reduction of the interfacial tension between oil and water, the extraction of the oil with a solvent, the reduction of oil viscosity, or an increase in water viscosity. In practice, of course, both heat and pressure in the thermal methods are needed for the production of viscous oils which could not be produced by any other method.

In a later section, it will be shown that viscosity provides a good way to classify the methods in a sequence from those which work best on light (or less viscous) oils up through those which are needed for the heavy (or very viscous) oils or even tar sands. Since oil viscosity affects recovery much more than does the oil gravity, we use viscosity as our primary reference in listing all of the methods. However, the API gravity is reported more commonly than the viscosity, and published screening criteria often emphasize the gravity requirements for enhanced recovery. Fig. 2 shows a very general correlation by Beal28 which can be used to provide a rough estimate of gravity or viscosity if only one is known. The actual oil viscosity in the reservoir is normally somewhat lower than that in Fig. 2 because of dissolved gases, and the temperatures may differ significantly from the 1000 F shown.

In the following section, we present screening guides for the eight common methods in Tables 3-11 and for ten possible methods in Fig. 3. The methods are arranged according to the viscosity of the oil to be recovered. Enhanced recovery can then be classified as three gas injection methods, three water related processes, three thermal techniques, and mining and extraction when all else fails.

GUIDELINES FOR MAJOR METHODS

For convenience, a thumbnail sketch is given for the eight most common enhanced recovery methods in Tables 3-10 which list the salient features of each method along with the important screening guides. A few general comments are offered here on

SPE 1Z069 J.J. TABER and F.D. MARTIN the relative importance of some individual screening guides to the overall success of the various methods. In addition, we will make some observations on the method itself and its relationship to other enhanced recovery choices which may be available.

Some reservoir considerations apply to all enhanced recovery methods. Because drilling costs increase markedly with depth, shallow reservoirs are preferred, as long as all necessary criteria are met. For the most part, reservoirs that have extensive fractures, gross heterogeneities, thief zones, or are highly faulted should be avoided. Ideally, relatively uniform reservoirs with reasonable oil saturations, minimum shale stringers, and good areal extent are desired.

Gas Injection Methods

Hydrocarbon Miscible Flooding

Gas injection is certainly one of the oldest methods utilized by engineers to improve recovery, and its use has increased recently, although most of the new expansion has been coming from the non-hydrocarbon gases. 13 Because of the increasing interest in COZ and nitrogen or flue gas methods, we have separated them from the hydrocarbon miscible techniques even though other screening guides often lump them together as "Miscible Gas" projects.

Hydrocarbon miscible flooding can be sub-divided further into three distinct methods, and field trials or extensi2~_~~erations have been conducted in all of them. For LPG slug or solvent flooding, enriched (condensing) gas drive and high pressure (vaporizing) gas drive, a range of pressures (and therefore, depths) are needed to achieve miscibility in the systems. Thus, there is a minimum depth requirement for each of the processes as shown in Table 3. The permeability is not critical if the structure is relatively uniform; permeabi1ities of the reservoirs for the cur~lnt field projects range from 0.1 to 25,800 md. On the other hand, the crude oil characteristics are very important. A high-gravity, low-viscosity oil with a high percentage of the C2 - C7 intermediates is essential if miscibility is to be achieved in the vaporizing gas drives.

Unless the reservoir characteristics were favorable, early breakthrough and bypassing of large quantities Sf oil have plagued many of the field projects. Z9 ,3 In addition, the hydrocarbons needed for the processes are valuable, and there is increasing reluctance to inject them back into the ground when there is some question about the percentage that will be recovered the second time around. Therefore, in recent years the emphasis has been shifting to less valuable non-hydrocarbon gases such as CO 2 , nitrogen and flue gases. Although nitrogen and flue gases do not recover oil as well as the hydrocarbon gases (or liquids), the overall economics may be somewhat more favorable. A good example of a direct switch is the ongoing recovery project in University Block 31, Crane County, Texas. This high pressure gas drive which started more than 30 years ago was changed to flue gas i~~eii~~ in 1966 and is still going strong today. ' ,

Nitrogen and Flue Gas Flooding

As mentioned above, nitrogen and flue gas (about 87% NZ and lZ% CO2 ) are being used increasingly in place of hydrocarbon gases because of economics. Nitrogen also competes with CO 2 in some situations for the same reason. The economic appeal of nitrogen stems not only from its lower cost on a standard Mcf basis, but also because its compressibility is much lower. Thus, for a given quantity at standard conditions, nitrogen will occupy much more space at reservoir pressures th~9 CO2 or even methane at the same conditions.

36,

However, both nitrogen or flue gas are inferior to hydrocarbon gases (and much inferior to CO2 ) from an oil recovery point of view. Nitrogen has a lower viscosity, poor solubility in oil and requires a much higher pressure to generate or develop miscibility. The increase in the required pressure is significant compared to methane and very large (4-5 times) when compared to CO2 ' Therefore, nitrogen will not reduce the displacement efficiency too much when used as a chase gas for methane, but it can cause a significant drop in the effectiveness of a CO2 flood if the reservoir pressures are geared to the miscibility requirements for CO2 displacements. Indeed, even methane counts as a desirable "light end" or "intermediate" in nitrogen flooding, 37 but methane is quite deleterious to the achievement of miscibility in CO 2 flooding at modest pressures.

As shown in Table 4, the screening criteria for flooding with nitrogen or flue gas are similar to those for the high pressure gas drive. Pressure and depth requirements, as well as the need for a very light oil, are even greater if full miscibility is to be realized in the reservoir. The nitrogen and flue gas method is placed between hydrocarbon miscible and CO2 flooding in the tables and in Figs. 3-5 because the process can also recover oil in the immiscible mode. It can be economic because much of the reservoir space is filled with low cost gas.

Carbon Dioxide Flooding

The thumbnail sketch of carbon dioxide flooding given in Table 5 shows that CO2 is effective for recovery of oil for a number of reasons. In general, carbon dioxide is very soluble in crude oils at reservoir pressures; therefore, it swells the net volume of oil and reduces its viscosity even before miscibility is achieved by the vaporizing gas drive mechanism. As miscibility is approached, both the oil phase and the CO2 phase (which contains many of the oil's intermediate components) can flow together because of the low interfacial tension and the relative increase in the total volumes of the combined CO2 and oil phases compared to the water phase. However, the generation of miscibility between the oil and CO 2 is still the most important mechanism, and it will occur in CO2-crude oil systems as long as the pressure is high enough. This so-called "minimum miscibility pressure" or MMP has been the target of several laboratory investigationy and is no longer a mystery. The 1976 NPC report showed that there is a rough correlation between the API gravity and the required MMP, and that the MMP increased with temperature. Various workers have

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4 TECHNICAL SCREENING GUIDES FOR THE ENHANCED RECOVERY OF OIL SPE 12069

presented much additional data and improved on the understanding.38-49 Some have shown that a better correlation is obtained with the molecular weight of the Cs+ fraction of the oil than with the API gravity. In general, the recent work shows that the required pressure must be high enoug~ ~~ achieve a minimum density in the CO2 phase. 8, At this minimum density, which varies with the oil composition, the CO2 becomes a good solvent for the oil, especially the intermediate hydrocarbons, and the required miscibility can be generated or developed to provide the efficient displacement normally observed with CO2 Therefore, at higher temperatures, the higher pressures are needed only to increase the CO2 density to the same value as observed for the MMP at the lower temperature.

Because of the minimum pressure requirement, depth is an important screening criteria, and C02 floods are normally carried out in reservoirs that are more than 2000 ft deep. The oil composition is also important, and the API gravitY3~ceeds 300 for most of the active CO2 floods. A notable exception is the Lick Creek, Arkansas, CO2 /waterflood project which is being conducted successfully, not as a ~bscible project, but as an immiscible displacement.

Although the mechanism for CO2 flooding appears to be the same as that for hydrocarbon miscible floods, CO2 floods may give better recoveries even if both systems are above their required miscibility pressures, especially in tertiary floods. Compared to hydrocarbons, CO2 has a much higher solubility in water, and it has been observed .in laboratory experiments to diffuse through the water ph~fe to swell bypassed oil until the oil is mobile. Thus, not only are the oil and depth screening criteria easier to meet in CO2 flooding, but the ultimate recovery may be better than with hydrocarbons when above the MMP. It must be noted, however, that this conjecture has not been proved by rigorous and directly comparable experiments.

Chemical Flooding Methods

Chemical oil recovery methods include polymer, surfactant/polymer (variations are called micellar-polymer, microemulsion, or low tension waterflooding), and alkaline (or caustic) flooding. All of these methods involve mixing chemicals (and sometimes other substances) in water prior to injection. Therefore, these methods require conditions that are very favorable for water injection: low-to-moderate oil viscosities, and moderate-to-high permeabilities. Hence, chemical flooding is used for oils that are more viscous than those oils recovered by gas injection methods, but less viscous than oils that can be economically recovered by thermal methods. Reservoir permeabilities for chemical flood conditions need to be higher than for the gas injection methods, but not as high as for thermal methods. Since lower mobility fluids are usually injected in chemical floods, adequate injectivity is required. If previously waterflooded, the chemical flood candidate should have responded favorably by developing an oil bank. Generally, active water-drive reservoirs should be avoided because of the potential for low remaining oil saturations. Reservoirs with -gas caps are ordinarly avoided

since mobilized oil might re-saturate the gas cap. Formations with high clay contents are undesirable since the clays increase adsorption of the injected chemicals. In most cases, reservoir brines of moderate salinity with low amounts of divalent ions are preferred since high concentrations interact unfavorably with the chemicals that are injected. Specific screening guidelines are discussed for each of the chemical methods that follow.

Surfactant/Polymer Flooding

Surfactant use for oil recovery is not a recent development. Patents in the late 1920's and early 1930's proposed the use of low concentrations of detergents to reduce the interfacial tension between water and oil. To overcom~ the slow rate of advance of the detergent, Taber52 proposed very high concentrations (- 10%) of detergent in aqueous solution.

During the late 1950's and early 1960's, several different present-day methods of using surfactants for enhanced recovery were developed. A review of these methods is beyond the sco~3 g{ this paper and is available in the literature. ' In some systems, a small slug (> about 5% PV) was proposed that included a high concentration of surfactant (normally 5-10%). In many cases, the microemulsion includes surfactant, hydrocarbon, water, an electrolyte (salt), and a cosolvent (usually an alcohol). These methods ordinarily used a slug (30-50% PV) of polymer-thickened water to provide mobility control in displacing the surfactant and oil-water bank to the producing wells. The polymers used are the same as those discussed in the next section of the paper. In most cases, low-cost petroleum sulfonates or blends with other surfactants have been used. Intermediate surfactant concentrations and low concentration systems (low tension waterflooding) have also been proposed. The lower surfactant concentration systems mayor may not contain polymer in the surfactant slug, but will utilize a larger slug (30-100% PV) of polymer solution.

A brief description of the surfactant/polymer method is provided in Table 6. Oil viscosities of less than 30 cp are desired so that adequate mobility control can be achieved. Good mobility control is essential for this method to make maximum utilization of the expensive chemicals. Oil saturations remaining after a waterflood should be more than 30% PV to ensure that sufficient oil is available for recovery. Sandstones are preferred because carbonate reservoirs are heterogeneous, contain brines with high divalent ion contents, and cause high adsorption of commonly used surfactants. To ensure adequate injectivity, permeability should be greater than 20 md. Reservoir temperature should be less than 1750 F to minimize degradation of the presently available surfactants. A number of other limitations and problems are mentioned in Table 6, including the general requirement for low salinity and hardness for most of the commercially available systems. Obviously, this method is very complex, expensive, and subject to a wide range of problems. Most importantly, the available systems provide optimum reduction in interfacial tension over a very narrow salinity range. Preflushes have been used to attempt to provide optimum conditions, but they have often been ineffective.

SPE 12069 J.J. TABER and F.D. MARTIN Polymer Flooding

Dilute aqueous solutions of water-soluble polymers can reduce the mobility of water in a reservoir. Partially hydrolyzed polyacrylamides (HPAM) and xanthan gum (XG) polymers both reduce mobility by increasing Viscosity. In addition, HPAM can alter the flow path by reducing the permeability of the formation to water. The reduction achieved with HPAM solution can be fairly permanent while the permeability to oil can remain relatively unchanged. Polymer flooding is viewed as an improved waterflooding technique since it does not ordinarily recover residual oil that has been trapped and isolated by water. However, polymer flooding can produce additional oil over that obtained from waterflooding by improving the displacement efficiency and increasing the volume of reservoir contacted. The ultimate oil recovery at a given economic limit may be 4-10% higher with a mobility-controlled flood than with plain water. The literature contains numerous references to polymer floOding, including several overview papers. 25,55,)6 Additionally, reference 57 cites many of the previous papers and documents problem areas with the commercially available polymers.

A properly sized polymer treatment may require the injection of a minimum of 15-25% of a reservoir pore volume; polymer concentrations may normally range from 250 to 2000 mg/L. For very large field projects, millions of pounds of polymer may be injected over a 1-2 year period. The project then reverts to a normal waterflood. Variations in the use of polymers in waterflooding include several methods of crosslinking or gelling polymers to divert the flow of water in reservoirs with permeability stratification or minor fracture systems.

The screening guidelines and a description of polymer flooding are contained in Table 7. Since the objective of polymer flooding is to improve the mobility ratio without necessarily making the ratio favorable, the maximum oil viscosity for this method is 100 or possibly 150 cpo If oil viscosities are very high, higher polymer concentrations are needed to achieve the desired mobility control, and thermal methods may be more attractive. As discussed earlier, polymer flooding will not ordinarily mobilize oil that has been completely trapped by water; therefore, a mobile oil saturation of more than 10% is desired. In fact, a polymer flood is normally more effecti~~ when started at low producing water-oil ratios. Although sandstone reservoirs are usually preferred, several large polymer floods are underway in carbonate reservoirs. Lower molecular weight polymers can be utilized in reservoirs with permeabilities as low as 10 md (and, in some carbonates, as low as 3 md). While it is possible to manufacture even lower molecular weight polymers to inject into lower permeability formations, the amount of viscosity generated per pound of polymer would not be enough to make such 'products of interest. Wi th current polymers, reservoir temperature should be less than 2000 F to minimize degradation; this requirement limits depths to about 9000 ft. A potentially serious problem with polymer flooding is the decrease in injectivity which must accompany an increase in injection fluid

viscosity. If the decreased injectivity is prolonged, oil production rates and project costs can be adversely affected. Injection rates for polymer solutions may be only 40-60% of those for water alone, and the reduced injectivity may add several million dollars to the total project costs. Other problems common to the commercial polymers are cited in Table 7.

Alkaline Flooding

As described in Table 8, alkaline or caustic flooding consists of injecting aqueous solutions of sodium hydroxide, sodium carbonate, sodium silicate or potassium hydroxide. The alkaline chemicals react wi th organic acids in certain crude oils to produce surfactants in situ that dramatically lower the interfacial tension between water and oil. The alkaline agents also react with the reservoir rock surfaces to alter wettability--either from oil-wet to water-wet, or visa versa. Other mechanisms include emulsification and entrainment of oil or emulsification and entrapment of oil to aid in mobility control.

Since an early patent in the 1920's described the use of caustic for improved recovery of oil, much research and some field tests have been conducted. A review of the early ~lkaline work is descrig~ in the literature,5 and a status report updates the known field tests. Slug size of the alkaline solution is often 10-15% PV; concentrations of the alkaline chemical are normally 0.2 to 5%. Recent tests are using 3rg e amounts of relatively high concentrations. A preflush of fresh or softened water often precedes the alkaline slug, and a drive fluid (either water or polymer-thickened water) follows the alkaline slug.

Moderately low gravity oils (13-350 API) a~B normally the t~rget for alkaline flooding.l,b These oils are heavy enough to contain the organic acids, but light enough to permit some degree of mobility control. The upper viscosity limit 200 cp) is slightly higher than for polymer flooding. Some mobile oil saturation is desired, the higher the better. The minimum average permeability is about the same as for surfactant/polymer (> 20 md). Sandstone reservoirs are preferred since carbonate formations often contain anhydrite or gypsum which react and consume the alkaline chemicals. The alkaline materials also are consumed by clays, minerals, or silica; this consumption is high at elevated temperatures 61 ,6Z so the maximum desired temperature is 2000 F. Caustic consumption in field projects has beeu higher than indicated by laboratory tests. 6U- b2 Another potential problem in field applications is scale formation ~ich can result in plugging in the producing wells.

Thermal Methods

In-Situ Combustion

The theory and practice of in-situ combustion or fireflooding is covered comprehensively in the recent SPE monograph on Thermal Recovery by Prats. 27 In addition, the continuing evolution of screening criteria for firefiooding has been reviewed and evaluated by Chu. 18 ,19

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6 TECHNICAL SCREENING GUIDES FOR THE ENHANCED RECOVERY OF OIL SPE 12069

Part of the appeal of fireflooding comes from the fact that it uses the world's cheapest and most plentiful fluids for injection: air and water. However, significant ilmoun ts of fuel must be burned, both above the ground to compress the air, and below ground in the combustion process. Fortunately, the worst part of the crude oil is burned; the lighter ends are carried forward in advance of the burning zone to upgrade the crude oil.

For screening purposes (see Table 9), steamflooding and fireflooding are often considered together. In general, combustion should be the choice when heat losses from steamflooding v70uld be too great. In other words, combusti.on can be carried out in deeper reservoirs and thinner, tighter sand sections where heat losses for steamflooding ilre excessive. The ability to inject at high pressures is usually important so 500 ft has been retained as the minimum depth, but we note that there are three curren~3projects underway at depths of less than 500 ft. There appears to be no maximum depth as long as the economics are satisfactory. The ,vest Heidelburg (Cotton Valley) project is still producing profitably from 11,500 ft. This project may also hold the combustion record for the lowest oil viscosity (6 cp in the reservoir). Since the fuel and air consumption decrease with higher gravity oils, there is a tendency to try combustion in lighter oils if the fire can be maintained, but no projects are now operating in reservoirs with oil gravities greater than 350 API. 33

In summary, if all screening criteria are favorable, fireflooding appears to be an attractive method for reservoirs which cannot be produced by methods used for the lighter oils. However, the process is very complicated and beset with many practical problems such as corrosion, erosion and poorer mobility ratios than steamflooding. Therefore, we do agree with Prats, "when the economics are the same (laying aside considerations of risk), steam in~ection is to be preferred to a combustion drive ... 2

Steamflooding

Of all of the enhanced oil recovery processes currently available, only the steam drive (steamflooding) process is routinely used on a commercial basis. In the United States, a majority of the field testing with this process has occurred in California, where many of the shallow, high-oil-saturation reservoirs are good candidates for thermal recovery. These reservoirs contain high-viscosity crude oils that are difficult to mobilize by methods other than thermal recovery.

In the steam drive process, steam is continuously introduced into injection wells to reduce the viscosity of heavy oil and provide a driving force to move the more mobile oil towards the producing wells. In typical steam drive projects, the injected fluid at the surface may contain about 80% steam and 20% water (80% quality).l \Vhen steam is injected into the reservoir, heat is transferred to the oil-bearing formation, the reservoir fluids, and some of the adjacent cap and base rock. As a result, some of the steam condenses to yield a mixture of steam and hot water flowing through the reservoir.

The steam drive may work by driving the water and oil to form an oil bank ahead of the steamed zone. Ideally this oil bank remains in front, increasing in size until it is produced by the wells offsetting the injector. However, in many cases, the steam flows over the oil and transfers heat to the oil by conduction. Oil at the interface is lowered in viscosity and dragged alo~ with the steam to the producing wells. 6 Recoverability is increased because the steam (heat) lowers the oil viscosity and improves oil mobility. As the more mobile oil is displaced, the steam zone expands vertically, and the steam-oil interface is maintained. This process is energy-intensive since it requires the use of a significant fraction (25-40%) of the energy in the produced petroleum for the generation of steam.

Screening criteria for steamflooding are listed in Table 10. Although steamflooding is commonly used with oils ranging in gravity from 10-250 API, some gravities have been lower, and there is recent interest in steamflooding light oil reservoirs. 21 ,64 Oils with viscosities of less than 20 cp are usually not candidates for steamflooding because waterflooding is less expensive; the normal range is 100-5000 cpo A high saturation of oil-in-place is required because of the intensive use of energy in the generation of steam. In order to minimize the amount of rock heated and maximize the amount of oil heated, formations with high porosity are desired; this means that sandstones or unconsolidated sands are the primary target, although a steam drive pilot has been conducted in a gighly fractured carbonate reservoir in France. 6 The product of oil saturation 1imes porosity should be greater than about 0.08. 2 The fraction of heat lost to the cap and base rocks varies inversely with reservoir thickness. Therefore, the greater the thickness of the reservoir, the greater the thermal efficiency. Steamflooding is possib~g ~9 thin formations if the permeability is high.' High permeabilities (>200 md or preferably > 500 md) are needed to permit adequate steam injectivity; transmissibility should be greater than 100 md ftlcp at reservoir conditions. Depths shallower than about 300 ft may not permit good injectivity because the pressures required may exceed fracture gradients. Heat losses become important at depths greater than about 2500 ft, and steamflooding is not often considered at depths greater than 5000 ft. Downhole steam generators may have potential in deeper formations if operational problems can be overcome.

In steamflooding, the rate of steam injection is initially high to minimize heat losses to the cap and base rock. Because of reservoir heterogeneities and gravity segregation of the condensed water from the steam vapor, a highly permeable and relatively oil-free channel often develops between injector and producer. Many times this channel occurs near the top of the oil-bearing rock, and much of the injected heat is conducted to the caprock as heat loss rather than being conducted to oil-bearing sand where the heat is needed. In addition, the steam cannot displace oil efficiently since little oil is left in the channel. Consequently, neither the gas drive from the steam vapor nor the convective heat transfer

SPE 12069 J.J. TABER and F.D. MARTIN mechanisms works as efficiently as desired. As a result, injected steam will tend to break through prematurely into the offset producing wells without sweeping the entire heated interval.

GRAPHICAL REPRESENTATION OF SCREENING GUIDES

All of the screening guides are summarized in Table 11; the viscosity, depth, and permeability criteria are presented graphically in Figs. 3-5. The figures have some features which permit the quick application of screening criteria, but they cannot replace the tables for detailed evaluations. In a sense, the figures present a truer picture than the tables because there are few absolutes among the numbers presented as screening guides in the tables. Different authors and organizations may use different parameters for the same process, and most of the guidelines are subject to change as new laboratory and field information evolves. We have pointed out field exceptions to some of the accepted criteria, and the graphs accommodate these nicely. The "greater than" and "less than" designations of the tables can also be displayed better graphically. The range of values are indicated on the graphs by the open areas, and by cross-hatching along with general words such as

more difficult," "not feasible," etc. The "good" or "fair" ranges are those usually encompassed by the screening parameters in the table. However, the notation of "good" or "very good" does not mean that the indicated process is sure to work; it means simply that it is in the preferred range for that oil or reservoir characteristic.

The influence of viscosity on the technical feasibility of different enhanced recovery methods is illustrated in Fig. 3. Note the steady progression, with increasing viscosity, from those processes which work well with very light oils (hydrocarbon miscible or nitrogen) to oils which are so viscous that no recovery is possible unless the "ore" is mined and the oil extracted from the rock.

We have included the two "last resort" methods (special steamflooding techniques with shafts, fractures, drainholes etc., and mining plus extraction) for completeness in Fig. 3. We have not included them in Figs. 4 and 5 because these unconventional techniques are not considered in most reservoir studies.

Fig. 4 shows that those enhanced recovery processes which work well with light oils have rather specific depth requirements. As discussed, each gas injection method has a minimum miscibility pressure for any given oil, and the reservoir must be deep enough to accommodate the required pressure.

Fig. 5 shows that the three methods which rely on gas injection are the only ones which are even technically feasible at extremely low permeabilities. The three methods which use backup waterflooding need a permeability of greater than 10 md in order to inject the chemicals or emulsions and to produce the released oil from the rock. Although most authors show a minimum permeability requirement of 20 md for polymers, we indicate a possible range down as low as 3 md for low molecular weight polymers, especially in some carbonate reservoirs.

The screening guides in the figures can perhaps be summarized by stating a fact well-known to petroleum engineers: oil recovery is easiest with light oil in very permeable reservoirs and at shallow or intermediate depths. Unfortunately, nature has not been kind in the distribution of hydrocarbons, and it is necessary to select the recovery method which best matches the oil and reservoir characteristics.

ECONOMICS AND RECOVERY EFFICIENCIES

In the foreseeable future, the economics of EOR processes will be tenuous. If the experience of the late 1970's can serve as an example, increases in the price of crude oil will not automatically improve the economics of EOR projects since the price of fuel and chemicals will also increase. It seems reasonable that both process improvements and a more favorable tax treatment may be necessary before oil production via EOR increases substantially beyond present levels.

With the exception of steamflooding, EOR techniques are still in the developmental stage. Table 12 shows the API figures for 1980 crude oil production and the EOR p~Qdu~ti8n by process at that time compared to 1982.jj,6~-7 Oil production from enhanced recovery amounts to less than 5% of the total production. Increased interest in steamflooding, carbon dioxide flooding, and polymer flooding is apparent when the act~3e EOR projects in the U.S. are listed in Table 13. The increase in oil production resulting from the recent activity in polymer and CO 2 flooding will not occur until several years after the projects have been initiated. The full impact of CO 2 flooding will not be felt until a few years after the construction of CO 2 pipelines into the west Texas area. The processes using surfactants are still in the research phase and probably will not generate a significant amount of oil production for at least 5-10 years. However, if improved chemicals are developed, the ultimate potential for surfactant flooding is large.

Recent surveys71-77 of the costs involved for EOR processes are given in Table 14. Costs in the first column represent the total process including the injectant, investment, operating, royalties, all taxes (severance, windfall profits, state, and federal) ,nd capital cost (with a 15% rate of return).'l, 2 Figures in the second column jnclude injectant, operating, and investment costs7 whi7~ the third column represents injectant costs only. The costs of producing oil by steamflooding and polymer flooding are the lowest; they are the highest with surfactant/polymer flooding. Some experts argue that many of the reported costs may be high because a number of the projects were small pilots initiated primarily as research and learning tools. Nevertheless, with current crude oil pricing, only steamflooding and polymer flooding appear to be on firm ground. It should be emphasized that many of the costs should come down when the methods become more routine or if significant technological breakthroughs occur. Economics of CO2 flooding in west Texas and eastern New Mexico may improve when low-cost CO 2 is available from one of the pipelines in the area.

7

8 TECHNICAL SCREENING GUIDES FOR THE ENHANCED RECOVERY OF OIL SPE 12069 Incremental production that may typically be

expected is provided in Table 15. The incremental recovery with many of the chemical and CO2 projects could have been greater had they been implemented earlier in a secondary production mode. We feel that the additional oil that can be obtained with polymer flooding may be more than 4% of the remaining oil in place, and that proper applications should recover 7-10% or more. In our opinion, the use of conventional polymer flooding in a tertiary mode is a misapplication of the process. As stated earlier, much better results with polymers will be obtained if the polymer flood is started before the waterflood water-oil ratio becomes too high. It also appears that the efficiency of CO 2 flooding should be higher than reported in this table -- especially in relation to surfactant/polymer flooding (possibly the latter may be unrealistically high with present technology). A current paper78 is updating the efficiency of EOR projects from an extensive literature survey; however, it may be several more years before results of some of the large, recently started projects are available.

Table 16 was prepared as a brief summary of the profitabi11jY of EOR methods as reported in a recent survey. This table shows that a high percentage of steamfloods of heavy oils are profitable. The majority of the steamflood projects are in the shallow, high permeability, California reservoirs that contain very viscous crudes. A high percentage of the polymer floods were also reported as profitable. A majority of these projects are located in Oklahoma, Texas, and Wyoming, and characteristics of the successful projects fall within the preferred criteria. While the characteristics of the surfactant/polymer projects are in the preferred range, the field projects are not showing profitability because of the high costs of chemicals and the lower than anticipated production response. A large number of the CO2 projects listed in the survey are in the west Texas carbonates and Louisiana sandstones; all of the miscible projects are in very low viscosity crudes. While only 21% of the CO2 projects were listed as profitable, some were promising and many were too early to evaluate. At present, most field results indicate that approximately 8 Mcf of CO2 is required to produce an additional barrel of oil; the high costs in Table 14 reflect that requirement. While CO2 flooding is showing a profit in some cases, future projects will need adequate sources of low-cost CO2 and reasonably high flooding efficiencies. Insufficient data are available to assess the fewer number of remaining methods.

OVERCOMING LIMITATIONS AND PROBLEMS

One of the major problems with steamflooding in California is the channeling of steam which promotes poor sweep efficiency and caus=s high steam-oil ratios. Several investigators'Y ~6 are studying the use of surfactants to create a foam in situ for improving sweep efficiency, and preliminary results are encouraging. Another potential problem in a few steamfloods is steam injectivity or propagation. In a very viscous (about 20 million cp) crude oil reservoir, Conoco

has been successful in combining fracturing and steamfloodi~ (Fracture-Assisted Steamflood Technology). 7 Poor injectivity of steam has been observed ig a thin, low permeability sandstone in New Mexico 8; the use of solventsA surfactants, or tailored-pulse fracturing~9,~0 are being considered. If multiple, radial fractures are extended 20-30 ft out from the injector, steam injectivity should incr'ease considerably.

Reduced injectivity is often a major problem in polymer floods when viscous solutions are injected. Since polymers do not ordinarily displace oil trapped by prior waterflooding, the use of solvents or surfactants to remove residual oil near the injector should increase the relative permeability to water and thus the injectivity of water or polymer solution. This technique has been successful in increasing the in~~ctivity of water by 30-40% in a waterflood and should be applicable in polymer floods as well. Several organizations ~re investigating improved polymers, and recent workYl suggests it should be possible to develop polymers that are better than the commercially available products. More work is needed before the feasibility of marketing such polymers is known.

For the surfactant processes, more effective surfactants are required, especially in salty and hard waters. Exxon has field tested a n~w surfactant that holds promise in this regard. 2 Economics of the system are unknown, and more developmental work is planned.

A number of organizations are studying ways of providi~ better mobility control in CO2 floods. -96 At least one field test using a foam-like dispersion of surfactant-water-C02 is planned. Y7

For many of the processes, more accurate predictive methods are being sought. This requires a better fundamental understanding of how each process works, more realistic correlations between laboratory and field results, and improved mathematical models that simulate the process more effectively.

CONCLUSIONS

Technical screening guides for matching enhanced recovery methods to different reservoirs have been evaluated and presented, along with brief descriptions of each method. From this work, we conclude:

1. The tables and graphs of the screening criteria show that there is a choice of enhanced recovery methods applicable to all crudes, from the very lightest to the heaviest oils or tar sands.

2. Light oils with viscosities of less than 10 cp may be recovered by hydrocarbon miscible, nitrogen, flue gas, or carbon dioxide flooding if the reservoir is deep enough and meets certain other criteria.

3. Intermediate range oils with relatively low viscosities can be recovered with the three chemical methods: polymer, alkaline or surfactant flooding. These use water as the main injection

SPE 12069 J.J. TABER and F.D. MARTIN

fluid, and permeabilities should be greater than 10 or 20 md; depth is not usually a problem except as it relates to temperature.

4. For heavy oils, with viscosities of more than 150-200 cp, heat needs to be added to the reservoir by in-situ combustion or steam drive. Because of injectivity and heat loss requirements, both methods need adequate permeability, a relatively thick pay section, and a minimum depth of at least a few hundred feet. Steam drives must not be too deep because of heat loss in the injection well. Thermal methods can also work on lighter oils, but economics may favor one of the other methods.

5. The technical screening guides are only the first step for matching the best recovery method to a given reservoir. The final decision will invariably depend on the economic evaluation of each individual reservoir situation.

ACKNOWLEDGEMENTS

The authors express their appreciation to Paula Bradley, Lorraine Valencia and Jessica McKinnis for their assistance in the preparation of this manusc ript.

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SI METRIC CONVERSION FACTORS

141.51(131.5 + API) bbl x 1.589 873 E-Dl

bbll acre-ft x 1.288 931 E+OO

cp x 1.0 E-D3 Pas

dyne/em x 1 mN/m

of (oF-32)/1.8

ft x 3.048 E-Dl m

md x 9.869 233 E-D4

Table 1

ENHANCED RECOVERY METHODS

Improved Waterflooding

Viscous or Polymer Flooding Low Interfacial Tension Waterflooding Alkaline Flooding

~1iscible-Type Waterflooding Alcohol Flooding Surfactant/Polymer (Micellar) Flooding

Hydrocarbon and Other !lGas" Methods

Miscible Solvent (LPG or Propane) Flooding Enriched Gas Drive High Pressure Gas Drive Carbon Dioxide Flooding Acid or Flue Gas Injection Inert Gas (Nitrogen) Injection

Thermal Recovery

Steam and Hot Water Injection Steamflooding Hot Water Flooding Steam Stimulation Vapor-Therm Methods

In-Situ Combustion Forward Combustion Wet Combustion Reverse Combustion

Mining and Extraction

Table 2

CLASSIFICATION OF ENHANCED RECOVERY BY THE MAIN MECHANISM OF OIL DISPLACEMENT

Solvent Extraction or "Miscible-Type" Processes

Hydrocarbon Miscible Methods Carbon Dioxide Flooding Nitrogen and Flue Gas Alcohol Flooding or Other Liquid Solvent Flooding Solvent Extraction of Mined, Oil-Bearing Ore

Interfacial Tension Reduction Processes

Surfactant (Low Interfacial Tension) Waterflooding Surfactant/Polymer (Micellar) Flooding (Sometimes

Included in Miscible-Type Flooding Above) Alkaline Flooding

Viscosity Reduction (of Oil) or Viscosity Increase (of Driving Fluid) Plus Pressure

Steamflooding Fireflooding Polymer Flooding

Table 3

HYDROCARBON MISCIBLE FLOODING

Description

Hydrocarbon miscible flooding consists of injecting light hydrocarbons through the reservoir to form a miscible flood. Three different methods are used. One method uses about 5% PV slug of liquified petroleum gas (LPG) such as propane, follow-ed by natural gas or gas and water. A second method, called Enriched (Condensing) Gas Drive, consists of injecting a 10-20% PV slug of natural gas that is enriched with ethane through hexane (eZ to C6)' followed by lean gas (dry, mostly methane) and possibly water. The enriching components are transferred from the gas to the oil. The third method, called High Pressure (Vaporizing) Gas Drive, consists of injecting lean gas at high pressure to vaporize C2 - C6 components from the crude oil being displaced.

Mechanisms

Hydrocarbon miscible flooding recovers crude oil by: generating miscibility (in the condensing and vaporizing gas drive) increasing the oil volume (swelling)

-- decreasing the viscosity of the 011

Limitations

TECHNICAL SCREENING GUIDES

Gravity Viscosity Compos ition

Oil Saturation Type of Formation

Net Thickness

Average Permeability Depth

Temperature

> 35 API < 10 cp High percentage of light hydrocarbons

(CZ

- C7

)

> 30% PV Sandstone or carbonate with a minimum of

fractures and high permeability streaks Relatively thin unless formation is steeply

dipping Not critical if uniform > ZOOO ft (LPG) to > 5000 ft (High

Pressure Gas) Not critical

The minimum depth is set by the pressure needed to maintain the generated misci-bility. The required pressure ranges from about 1200 psi for the LPG process to 3000-5000 psi for the High Pressure Gas Drive~ depending on the oil.

A steeply dipping formation is very desirable to permit some gravity stabiliza-tion of the displacement which normally has an unfavorable mobility ratio.

Viscous fingering results in poor vertical and horizontal sweep efficiency. Large quantities of expensive products are required. Solvent may be trapped and not recovered.

Table 4

NITROGEN AND FLUE GAS FLOODING

Description

Nitrogen and flue gas flooding are oil recovery methods which use these inexpen-sive non-hydrocarbon gases to displace oil in systems which may be either miscible or immiscible. depending on the pressure and oil composition. Because of their low cost, large volumes of these gases may be injected. Nitrogen or flue gas are also considered for use as chase gases in hydrocarbon-miscible and CO 2 floods.

Mechanisms

Nit rogen and flue gas flooding recover oil by: -- vaporizing the lighter components of the crude oil and generating

miscibility if the pressure is high enough -- providing a gas d'rive where a significant portion of the reservoir

volume is filled with low-cost gases

Limitations

TECHNICAL SCREENING GUIDES

Gravity Viscosity Composition

Oil Saturation Type of Formation

Net Thickness Average Permeability Depth Temperature

> 24API (> 3S for nitrogen) < 10 cp High percentage of light hydrocarbons

(C 1 - C7)

> 30% PV Sandstone or carbonate with few fractures

and high permeability streaks Relatively thin unless formation is dipping Not critical > 4,500 ft Not critical

Developed miscibility can only be achieved with light oils and at high pressures; therefore, deep reservoirs are needed.

A steeply dipping reservoir is desired to permit gravity stabilization of the displacement which has a very unfavorable mobility ratio.

Viscous fingering results in poor vertical and horizontal sweep efficiency. Corrosion can cause problems in the flue gas method. The non-hydrocarbon gases must be separated from the saleable produced gas.

Table 5

CARBON DIOXIDE FLOODING

Description

Carbon dioxide flooding is carried out by injecting large quantities of C02 (15% or more of the hydrocarbon PV) into the reservoir. Although CO 2 is not truly miscible with the crude oil, the CO

2 extracts the light-to-intermediate components

from the oil, and, if the pressure 1.S high enough, develops miscibility to displace the crude oil from the reservoir.

CO 2 recovers crude oil by: -- generation of miscibility

swelling the crude oil lowering the viscosity of the oil lowering ,the interfacial tension between the oil and the CO 2-oil phase in the near-miscible regions.

TECHNICAL SCREENING Gl:lDES

Gravity Viscosity Composition

Oil Saturation Type of Formation

Net Thickness

Average Permeability

Depth

Temperature

> 26 API (preferably> 30) < 15 cp (preferably < 10 cp) High percentage of intermediate hydrocarbons

(C5 - C20), especially C5 - C12

> than 30% PV Sandstone or carbonate with a minimum of

fractures and high permeability streaks Relatively thin unless formation is steeply

dipping Not critical if sufficient injection rates

can be maintained Deep enough to allow high enough pressure

(> about 2000 f t), pressure required for optimum production (sometimes called minimum miscibility pressure) ranges from about 1200 psi for a high gravity (> 30 API) crude at low temperatures to over 4500 psi for heavy crudes at higher temperatures.

Not critical but pressure required increases with temperature

Limitations

Very low viscosity of C02 results in poor mobility control. Availability of CO 2 ,

Problems

Early breakthrough of C02 causes several problems: corrosion in the producing wells; the necessity of separating C02 from saleable hydrocarbons; repressuring of C02 for recylirig; and a high requirement of C02 per incremental barrel produced.

Table 6

SURFACTANT/POLYMER FLOODING

Description

Surfactant/polymer flooding, also called micellar/polymer or rnicroemulsion flooding, consists of injecting a slug that contains water, surfactant. electrolyte (salt). usually a cosolvent (alcohol), and possibly a hydrocarbon (oil). The size of the slug is often 5-15% PV for a high surfactant concentration system and 15-50% PV for low concentrations. The surfactant slug is followed by polymer-thickened water. Concentrations of the polymer often ranges from 500-2000 mg!L; the volume of polymer solution injected may be 50% PV, more or less, depending on the process design.

Mechanisms

Surfactant/polymer flooding recovers oil by: -- lowering the interfacial tension between oil and water -- solubilization of oil -- emulsification of oil and water -- mobility enhancement

TECHNICAL SCREENING GUIDES

Limitations

Gravity Viscosity Composition

Oil Saturation Type of Formation Net Thickness Average Permeability Depth Temperature

> 25 API < 30 cp Light intermediates are des~ - ... tole

> 30% PV Sandstones preferred > 10 ft > 20 md < about 8000 ft (see Temperature) < 175F

An areal sweep of more than 50% on waterflood is desired. Relatively homogeneous formation is preferred. High amounts of anhydrite, gypsum, or clays are undesirable. Available systems provide optimum behavior over a very narrow set of conditions. With commercially available surfactants. formation water chlorides should be

< 20,000 ppm and divalent ions (Ca++ and Mg++) < 500 ppm.

Complex and expensive system. Possibility of chromatographic separation of chemicals. High adsorption of surfactant. Interactions between surfactant and polymer. Degradation of chemicals at high te~perature.

Table 7

POLYMER FLOODING

Description

The objective of polymer flooding is to provide better displacement and volu-metric sweep efficiencies during a waterflood. Polymer augmented waterflooding consists of adding water soluble polymers to the Water before it is injected into the reservoir. Low concentrations (often 250-2000 mg!L) of c.ertain synthetic or biopolymers are used; properly sized treatments may require 15-25% reservoir PV.

Mechanisms

Polymers improve recovery by:

Limitations

increasing the viscosity of water decreasing the mobility of water contacting a larger volume of the reservoir

TECHNICAL SCREENING GUIDES

Gravity Viscosity Composition

Oil Saturation Type of Formation

Ne t Thickness Average Permeability Depth Temperature

25 API 150 cp (preferably < 100)

Not critical

10% PV mobile oil Sandstones preferred but can

be used in carbonates Not critical

10 md (as low as 3 md in some cases) < about 9000 ft (see Temperature)

200F to minimize degradation

If oil viscosities are high. a higher polymer concentration is needed to achieve the desired mobility control.

Results are normally better if the polymer flood is started before the water-oil ratio becomes exceSSively high~

Clays increase polymer adsorption. Some heterogeneities are acceptable but. for conventional polymer flooding,

reservoirs with extensive fractures should be avoided. If fractures are present, the crosslinked or gelled polymer techniques may be applicable.

Lower injectivity than with water can adversely affect oil production rate in the early stages of the polymer flood.

Acrylamide-type polymers lose viscosity due to shear degradation, or increases in salinity and divalent ions.

Xanthan gum polymers cost more. are subject to microbial degradation, and have a greater potential for wellbore plugging.

120hf

Description

Table 8

ALKALINE FLOODING

Alkaline or caustic flooding involves the injection of chemicals such as sodium hydroxide, sodium silicate or sodium carbonate. These chemicals react with organic petroleum acids in certain crudes to create surfactants in situ. They also react with reservoir rocks to change wettability. The concentration of the alkaline agent is normally 0.2 to 5%; slug size is often 10 to 50% PV, although one successful flood only used 2% PV. (but this project also included polymers for mobility control). Polymers may be added to the alkaline mixture, and polymer-thickened water can be used following the caustic slug.

Mechanisms

Alkaline flooding recovers crude oil by: -- a reduction of interfacial tension reSUlting from

the produced surfactants -- changing wettability from oil-wet to water-wet

changing wettability from water-wet to oil-wet emulsification and entrainment of oil

-- emulsification and entrapment of oil to aid in mobility control -- solubilization of rigid oil films at oil-water interfaces

(Not all mechanisms are operative in each reservoir.)

Limitations

TECHNICAL SCREENING GUIDES

Gravity Viscosity Composition

Oil Saturation Type of Formation Net Thickness Average Permeability Depth Temperature

13 0 to 35 0 API < 200 cp Some organic acids required

Above waterflood residual Sandstones preferred Not critical > 20 md < about 9000 ft (see Temperature) < 200F preferred

Best results are obtained if the alkaline material reacts with the crude oil; the oil should have an acid number of more than 0.2 mg KOH/g of oil.

The interfacial tension between the alkaline solution and the crude oil should be less than 0.01 dyne/cm.

At high temperatures and in some chemical environments, excessive amounts of alkaline chemicals may be consumed by reaction with clays, minerals, or silica in the sandstone reservoir.

Carbonates are usually avoided because they often contain anhydrite or gypsum which interact adversely with the caustic chemical.

Scaling and plugging in the producing wells. High caustic consumption.

Table 9

IN-SITU COMBUSTION

Description

In-situ combustion or fireflooding involves starting a fire in the reservoir and injecting air to sustain the burning of some of the crude oil. The most common technique is forward combustion in which the reservoir is ignited in an inj ection well, and air is injected to propagate the combustion front away from the well. One of the variations of this technique is a combination of forward combustion and waterflooding (COFCAW). A second technique is reverse combustion in which a fire is started in a well that will eventually become a producing well, and air injection is then switched to adjacent wells; however, no successful field trials have been completed for reverse combustion.

Mechanisms

In-situ combustion recovers crude oil by: the application of heat which is transferred downstream by conduction and convection, thus lowering the viscosity of the crude

-- the products of steam distillation and thermal cracking which are carried forward to mix with and upgrade the crude

-- burning coke that is produced from the heavy ends of the crude oil the pressure supplied to the reservoir by the injected air

TECHNICAL SCREENING GUIDES

Crude Oil

Gravity Viscosity Composition

Reservoir

Limitations

Oil Saturation Type of Formation Net Thickness Average Permeability Transmissibility Depth Temperature

< 40 0 API (normally 10-25 0 ) < 1000 cp

Some asphaltic components to aid coke deposition

> 500 bbl/acre-ft (or> 40-50% PV) Sand or sandstone with high porosity > 10 ft > 100 md > 20 md ft/cp > 500 ft > 150F preferred

If sufficient coke is not deposited from the oil being burned, the combustion process will not be sustained.

If excessive coke is deposited, the rate of advance of the combustion zone will be slow, and the quantity of air required to sustain combustion will be high.

Oil saturation and porosity must be high to minimize heat loss to rock. Process tends to sweep through upper part of reservoir so that sweep efficiency

is poor in thick formations.

Problems Adverse mobility ratio. Complex process, requiring large capital investment, is difficult to control. Produced flue gases can present environmental problems. Operational problems such as severe corrosion caused by low pH hot water. serious

oil-water emulsions, increased sand production, deposition of carbon or wax, and pipe failures in the producing wells as a result of the very high temperatures.

Gravity "API

Gas Injection Methods

Hydrocarbon > 35

Nitrogen & Flue Gas > 24 > 35 for N2

Carbon Dioxide > 26

Chemical Flood~

Surfactant/Polymer > 25

Polymer > 25

Alkaline 13-35

Thermal

< 40 Combustion (10-25

normally)

Steamflooding < 25

N.C .... Not Critical *Transmissibility > 20 md ft/cp

**Transmissibility > 100 md ftlcp

Table 10

STEAMFLOOD ING

Description

The steam drive process or steamflooding involves the continuous injection of about 80% quality steam to displace crude oil towards producing wells. Normal practice is to precede and accompany the steam drive by a cyclic steam stimulation of the producing wells (called huff and puff).

Mechanisms

Steam recovers crude oil by: -- heating the crude oil and reducing its viscosity

supplying pressure to drive oil to the producing well

Limitations

.TECHNICAL SCREENING GUlDl!.~

Gravity Viscosity Composition

Oil Saturation

Type of Formation

Net Thickness Average Permeability

Transmissibility Depth Temperature

< 25 API (normal range is 10-25 API) > 20 cp (normal range is 100-5000 cp) Not critical but some light ends for

steam distillation will help

> 500 bbl/acre-ft (or> 40-50% PV)

Sand or sandstone with high porosity and permeability preferred

> 20 feet > 200 md (see Transmissibility)

> lOO md ft/cp 300-5000 ft Not critical

Oil saturations must be quite high and the pay zone should be more than 20 feet thick to minimize heat losses to adjacent formations.

Lighter, less viscous crude oils can be steamflooded but normally will not be if the reservoir will respond to an ordinary waterflood.

Steamflooding is primarily applicable to viscous oils in massive. high perme-ability sandstones or unconsolidated sands.

Because of excessive heat losses in the wellbore, steamflooded reservoirs should be as shallow as possible as long as pressure for sufficient injection rates can be maintained.

Steamflooding is not normally used in carbonate reservoirs. Since about one-third of the additional oil recovered is consumed to generate

the required steam, the cost pet incremental barrel of oil is high. A low percentage of water-sensitive clays is desired for good injectivity.

Adverse mobility ratio and channeling of steam.

Table 11 SUMMARY OF SCREENING CRITERIA FOR ENHANCED RECOVERY METHODS

Oil ProEerties Reservoir Characteristics Net Average

Viscosity Oil Formation Thickness Permeability ~ ComEosition Saturatioll ~ ~ ~d_) __

High % of Sandstone or Thin unless < 10 > 30% PV C2 - C7 Carbonate dipping N.C.

High % of < 10 Sandstone or Thin unless C1 - C7 > 30% PV Carbonate dipping N.C.

< 15 High % of > 30% PV Sandstone or Thin unless N.C. C5 - C12 Carbonate dipping

< 30 Light inter- > 30% PV Sandstone mediates desired preferred > 10 > 20

< 150 N.C. > 10% PV Sandstone pre- N.C. > 10 Mobile 011 ferred; Carbon- (normally)

ate possible < 200 Some Organic Above Sandstone Acids Waterflood N.C. > 20

Residual preferred

Some

Depth ~

>2000 (LPG) to

>5000 (H.P. Gas)

> 4500

> 2000

< 8000

< 9000

< 9000

< 1000 Asphaltic >40-50% PV Sand or Sand-stone with

high porosity > 10 > 100* > 500

Components

> 20 N.C. >40-50% PV Sand or Sand-stone with

high porosity

> 20 > 200** 300-5000

Temperature ("F)

N.C.

N.C.

N.C.

< 175

< 200

< 200

> 150 preferred

N.C.

Table 12

u.s. OIL PRODUCTION

1980 Oil Production. miliions()f,;arr~r day Table ~3

Primary Recovery

Waterflood Recovery

Enhanced Oil Recovery

3.9 4.0 0.3

NUMBER OF ENHANCED

Steam Injection (Including Stimulation)

In-Situ Combustion

Carbon Dioxide Other Gas Injection Surf ac tant/Polymer

Alkaline Flooding

Polymer Flooding

Source: Ref s. 33, 68-70

Oil Production, thousan~b~er .~

1980 1982

243 288

12 10

22 22

53 50 0.9 0.9 0.6 0.6

0.9 2.6

Table 14

ENHANCED RECOVERY COSTS

.lJ.7.l Thermal Methods:

Steam 53 In-Situ Combustion 38

Gas Injection: Carbon Dioxide Hydrocarbon Miscible 21

Other Gases 0

Chemical Flooding: Surfactant /Polymer

Alkaline 0

Polymer 14

Source: Ref. 33

EaR ~hod Total Proce5ls* ~rocess** Injecta~Costs***

Steam (purchased fuel) 27-35 17-25 (lease crude) 21-28 10-17 8-16

In-Situ Combustion 25-36 14-25 5-12

Carbon Dioxide 26-39 16-27 12-30

Surfac tant/Polymer 35-46 20-30 15-35

Polymer 22-28 6-16 3-6

Alkaline 10-12

* Includes injectant, investment, operating, all taxes, and capital costs (15% ROR) 71,72

** 77 Injectant plus investment and operating costs but no financial costs

***Injectant costs only73-75

1974

64 19

12

RECOVERY PROJECTS

~ 1978 1980 1982

85 99 133 ll8 21 16 17 21

14 17 28

15 15 12

10

13 22 14 20 10

14 21 22 47

Table 15

INCREMENTAL PRODUCTION FROM ENHANCED RECOVERY

Incremental Production

EOR Method of Remaining Oil in Place

*

of Original Oil in Place

Steam (purchased fuel) (lease crude)

In-Situ Combustion

Carbon Dioxide

Surfae tant/Polymer

Polymer

Alkaline

Source: * Ref. 71

** Refs. 73, 74 *~\:* Ref. 77

fIlWATER OR GAS

DRIVING

FLUID

(WATER OR

GAS)

INJECTION WELL

36-64

25-45

28-39

15-19

30-43

4

** 5-35

5-25

5-15

10-20

< 5

SPECIAL

E DR

"FLUID"

OR

CHEMICAL

>

Fig. 1-Generalized technique for enhanced oil recovery.

*** 35-65

15-32

30-50

OIL

(AND WATER)

OIL PRODUCTION

~

PRODUCTION WELL

Table 16

CURRENT PROFITABILITY OF U.S. ENHANCED RECOVERY PROJECTS

Number of

Method "Floods" Number Reporting on Profitabilitr*

Reported as Profitable, %

Steam Soak 45 Steam Drive 74 Combustion 21

42 60 17

86 78 65

Hydrocarbon Miscible 12 Carbon Dioxide 28 Other Inert Gases 7

4 19

2

50 21

100

Polymer 47 25 Caustic 10 5 Sur