Screening criteria have been proposed for all enhanced oil recovery @OR) methods. Data from EOR projects around the world have been examined and the optimum reservoir/oil characteristics for successful projects have been noted. The oil gravity ranges of the oils of current EOR methods have been compiled and the results are presented graphically. The proposed screening criteria are based on both field results and oil recovery mechanisms. The current state of the art for all methods is presented briefly, and relationships between them are described. Steamflooding is still the dominant EOR method. All chemical flooding has been declining, but polymers and gels are being used successfully for sweep improvement and water shutoff. Only C02 flooding activity has increased continuously.

Summary For applications in which enhanced-oil-recovery (EOR) polymer solutions are injected, we estimate injectivity losses (relative to water injectivity) if fractures are not open. We also consider the degree of fracture extension that may occur if fractures are open. Three principal EOR polymer properties are examined that affect injectivity:debris in the polymer,polymer rheology in porous media, andpolymer mechanical degradation. An improved test was developed to measure the tendency of EOR polymers to plug porous media. The new test demonstrated that plugging tendencies varied considerably among both partially hydrolyzed polyacrylamide (HPAM) and xanthan polymers. Rheology and mechanical degradation in porous media were quantified for a xanthan and an HPAM polymer. Consistent with previous work, we confirmed that xanthan solutions show pseudoplastic behavior in porous rock that closely parallels that in a viscometer. Xanthan was remarkably resistant to mechanical degradation, with a 0.1% xanthan solution (in seawater) experiencing only a 19% viscosity loss after flow through 102-md Berea sandstone at a pressure gradient of 24,600 psi/ft. For 0.1% HPAM in both 0.3% NaCl brine and seawater in 573-md Berea sandstone, Newtonian behavior was observed at low to moderate fluid fluxes, while pseudodilatant behavior was seen at moderate to high fluxes. No evidence of pseudoplastic behavior was seen in the porous rock, even though one solution exhibited a power-law index of 0.64 in a viscometer. For this HPAM in both brines, the onset of mechanical degradation occurred at a flux of 14 ft/d in 573-md Berea. Considering the polymer solutions investigated, satisfactory injection of more than 0.1 pore volume (PV) in field applications could only be expected for the cleanest polymers (i.e., that do not plug before 1,000 cm3/cm2 throughput), without inducing fractures (or formation parts for unconsolidated sands). Even in the absence of face plugging, the viscous nature of the solutions investigated requires that injectivity must be less than one-fifth that of water if formation parting is to be avoided (unless the injectant reduces the residual oil saturation and substantially increases the relative permeability to water). Since injectivity reductions of this magnitude are often economically unacceptable, fractures or fracture-like features are expected to open and extend significantly during the course of most polymer floods. Thus, an understanding of the orientation and growth of fractures may be crucial for EOR projects in which polymer solutions are injected. Introduction Maintaining mobility control is essential during chemical floods (polymer, surfactant, alkaline floods). Consequently, viscosification using water soluble polymers is usually needed during chemical EOR projects. Unfortunately, increased injectant viscosity could substantially reduce injectivity, slow fluid throughput, and delay oil production from flooded patterns. The objectives of this paper are to estimate injectivity losses associated with injection of polymer solutions if fractures are not open and to estimate the degree of fracture extension if fractures are open. We examine the three principal EOR polymer properties that affect injectivity:debris in the polymer,polymer rheology in porous media, andpolymer mechanical degradation. Although some reports suggest that polymer solutions can reduce the residual oil saturation below values expected for extensive waterflooding (and thereby increase the relative permeability to water), this effect is beyond the scope of this paper.

A capacity to reduce water permeability much more than oil permeability is critical to the success of gel treatments in production wells if zones cannot be isolated during gel placement. Although several researchers have reported polymers and gels that provide this disproportionate permeability reduction, the explanation for the phenomenon was unclear. In this paper, we examine several possible explanations for why some gels reduce water permeability more than oil permeability. Our experimental results indicate the disproportionate permeability reduction is not caused by gravity or lubrication effects. Results also indicate that gel shrinking and swelling are unlikely to be responsible for the phenomenon. Although wettability may play a role in the disproportionate permeability reduction, it does not appear to be the root cause for water permeability being reduced more than oil permeability. Results from an experiment with an oil-based gel suggest that segregation of oil and water pathways through a porous medium (on a microscopic scale) may play the dominant role in the disproportionate permeability reduction. However, additional work will be required to verify this concept. Experimental Procedures Gelants Studied. The study included four types of gels: (1) resorci-noVformaldehyde, (2) Cr(II1) acetatelpartially hydrolyzed polyacrylamide (HPAM), Marcit supplied by Marathon Oil Co., (3) glyoxaV cationic polyacrylamide (CPAM), Floperm 500 supplied by Pfizer Chemical Co., and (4) 12-hydroxystearic acid/Soltrol 130 (an oilbased gel)-2% 12-hydroxystearic acid obtained from Johnson Wax Co. Two formulations of the oil-based gel were examined. Table 1 lists the compositions of these gelants. The HPAM had a molecular weight of = 2 million daltons and a 2% degree of hydrolysis. The other chemicals used in this study were reagent grade. Coreflood Sequence. In each coreflood, the core was saturated with brine and the porosity and permeability determined. Then, the core went through a cycle of oilflooding followed by waterflooding (Flow Direction 1). The endpoint oil and water permeabilities were determined at the irreducible water saturation after the oilflood and at the irreducible oil saturation after the waterflood, respectively. A constant pressure drop was maintained across the core during the process. To simulate the "pump-in, pump-out" sequence during gel

At elevated temperatures in aqueous solution, partially hydrolyzed polyacrylamides (HPAMs) experience hydrolysis of amide side groups. However, in the absence of dissolved oxygen and divalent cations, the polymer backbone can remain stable so that HPAM solutions were projected to maintain at least half their original viscosity for more than 8 years at 100°C and for approximately 2 years at 120°C. Within our experimental error, HPAM stability was the same with and without oil (decane). An acrylamide-AMPS copolymer [with 25% 2-acrylamido-2-methylpropane sulphonic acid (AMPS)] showed similar stability to that for HPAM. Stability results were similar in brines with 0.3% NaCl, 3% NaCl, or 0.2% NaCl plus 0.1% NaHCO 3 . At temperatures of 160°C and greater, the polymers were more stable in brine with 2% NaCl plus 1% NaHCO 3 than in the other brines. Even though no chemical oxygen scavengers or antioxidants were used in our study, we observed the highest level of thermal stability reported to date for these polymers. Our results provide considerable hope for the use of HPAM polymers in enhanced oil recovery (EOR) at temperatures up to 120°C if contact with dissolved oxygen and divalent cations can be minimized.Calculations performed considering oxygen reaction with oil and pyrite revealed that dissolved oxygen will be removed quickly from injected waters and will not propagate very far into porous reservoir rock. These findings have two positive implications with respect to polymer floods in high-temperature reservoirs. First, dissolved oxygen that entered the reservoir before polymer injection will have been consumed and will not aggravate polymer degradation. Second, if an oxygen leak (in the surface facilities or piping) develops during the course of polymer injection, that oxygen will not compromise the stability of the polymer that was injected before the leak developed or the polymer that is injected after the leak is fixed. Of course, the polymer that is injected while the leak is active will be susceptible to oxidative degradation. Maintaining dissolved oxygen at undetectable levels is necessary to maximize polymer stability. This can be accomplished readily without the use of chemical oxygen scavengers or antioxidants.

Straightforward applications of fractional-flow theory and material-balance calculations demonstrate that, if zones are not isolated during gel placement in production wells, gelant can penetrate significantly into all open zones, not just those with high water saturations. Unless oil saturations in the oil-productive zones are extremely high, oil productivity will be damaged even if the gel reduces water permeability without affecting oil permeability. Also, in field applications, capillary pressure will not prevent gelant penetration into oil-productive zones. An explanation is provided for the occurrence of successful applications of gels in fractured wells produced by bottomwater drive. With the right properties, gels could significantly increase the critical rate for water influx in fractured wells. Introduction Coping with excess water production is always a challenging task for field operators. The cost of handling and disposing produced water can significantly shorten the economic producing life of a well. The hydrostatic pressure created by high fluid levels in the well also is detrimental to oil production. The two major sources of excess water production are coning and channeling. Water coning is common when a reservoir is produced by a bottomwaterdrive mechanism. Fractures and high-permeability streaks are the common causes of premature water breakthrough during waterfloods. Polymer gels have been applied to many wells to reduce excess water production without adversely affecting oil production. l-6 Moffitt reported that polymer gels are particularly effective in suppressing water coning. In many cases, however, gel treatments have not been successful. Part of the reason for the sporadic success was problems with gel placement. During gel placement in production wells, much of the gel formulation will enter zones responsible for the excess water production. However, some of this fluid may enter and damage oil-productive strata. The objectives of this study are to model gel placement in production wells mathematically and to examine the potential effect of gelant invasion into oil-producing zones. Particular attention is paid to the importance of two phenomena. The first is hysteresis of oil/water relative permeability curves during the "pump-in, pump-out" sequence used during gel placement in production wells. The second phenomenon is that gels (or polymers) can reduce the relative permeability to water more than to oil. Sensitivity studies covering most known field and laboratory applications are discussed. In particular, we study permeability contrasts from 1 to 1000, oil/water viscosity ratios ranging from 0.1 to 100, endpoint water relative permeabilities ranging from 0.1 to 0.7, water saturations ranging from 0.2 to 0.8, and fractured and unfractured wells. Therefore, our conclusions should be applicable to most field applications of gels in production wells. Examples are provided to illustrate and contrast situations where gels are or are not expected to damage oil productivity. In these example...

Screening criteria are useful for cursory examination of many candidate reservoirs before expensive reservoir descriptions and economic evaluations are done. We have used our C02 screening criteria to estimate the total quantity of C02 that might be needed for the oil reservoirs of the world. If only depth and oil gravity are considered, it appears that about 80% of the world's reservoirs could qualify for some type of C02 injection. Because the decisions on future EOR projects are based more on economics than on screening criteria, future oil prices are important. Therefore, we examined the impact of oil prices on EOR activities by comparing the actual EOR oil production to that predicted by earlier Natl. Petroleum Council (NPC) reports. Although the lower prices since 1986 have reduced the number of EOR projects, the actual incremental production has been very close to that predicted for U.S. $20/bbl in the 1984 NPC report. Incremental oil production from C02 flooding continues to increase, and now actually exceeds the predictions made for U.S. $20 oil in the NPC report, even though oil prices have been at approximately that level for some time. Utilization of Screening Guides With the reservoir management practices of today, engineers consider the various IOIUEOR options much earlier in the productive life of a field. For many fields, the decision is not whether, but when, to inject something. Obviously, economics always play the major role in "goho-go" decisions for expensive injection projects, but a cursory examination with the technical criteria (Tables 1 through 7) is helpful to rule out the less-likely candidates. The criteria are also useful for surveys of a large number of fields to determine whether specific gases or liquids could be used for oil recovery if an injectant was available at a low cost. This application of the C02 screening criteria is described in the next section. Estimation of the Worldwide Quantity of C 0 2 That Could Be Used for Oil Recovery. The miscible and immiscible screening criteria for C02 flooding in Table 3 of this paper and in Table 3 of Ref. 1 were used to make a rough estimate of the total quantity of C02 that would be needed to recover oil from qualified oil reservoirs throughout the world. The estimate was made for the IEA Greenhouse Gas R&D Program as part of their ongoing search for ways to store or dispose of very large amounts of C02 in case that becomes necessary to avert global warming. The potential for either miscible or immiscible C02 flooding for almost 1,000 oil fields was estimated by use of depth and oil-gravity data published in a recent survey.2 The percent of the fields in each country that met the criteria in Table 3 for either miscible or immiscible C02 flooding was determined and combined with that country's oil reserves to estimate the incremental oil recovery and C02 requirements. Assuming that one-half of the potential new miscible projects would be carried out as more-efficient enhanced secondary operations, an average recovery factor of 22% origi...

A new model was developed to describe water leakoff from formed Cr(III)-acetate-HPAM gels during extrusion through fractures. This model is fundamentally different from the conventional filter-cake model used during hydraulic fracturing. Even so, it accurately predicted leakoff during extrusion of a guar-borate gel. Thus, the new model may be of interest in hydraulic fracturing. Contrary to the conventional one, the new model correctly predicted the occurrence of wormholes and stable pressure gradients during gel extrusion through fractures.

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