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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.

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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...

Abstract. We present a local-scale atmospheric inversion framework to estimate the location and rate of methane (CH4) and carbon dioxide (CO2) releases from point sources. It relies on mobile near-ground atmospheric CH4 and CO2 mole fraction measurements across the corresponding atmospheric plumes downwind of these sources, on high-frequency meteorological measurements, and on a Gaussian plume dispersion model. The framework exploits the scatter of the positions of the individual plume cross sections, the integrals of the gas mole fractions above the background within these plume cross sections, and the variations of these integrals from one cross section to the other to infer the position and rate of the releases. It has been developed and applied to provide estimates of brief controlled CH4 and CO2 point source releases during a 1-week campaign in October 2018 at the TOTAL experimental platform TADI in Lacq, France. These releases typically lasted 4 to 8 min and covered a wide range of rates (0.3 to 200 g CH4/s and 0.2 to 150 g CO2/s) to test the capability of atmospheric monitoring systems to react fast to emergency situations in industrial facilities. It also allowed testing of their capability to provide precise emission estimates for the application of climate change mitigation strategies. However, the low and highly varying wind conditions during the releases added difficulties to the challenge of characterizing the atmospheric transport over the very short duration of the releases. We present our series of CH4 and CO2 mole fraction measurements using instruments on board a car that drove along roads ∼50 to 150 m downwind of the 40 m × 60 m area for controlled releases along with the estimates of the release locations and rates. The comparisons of these results to the actual position and rate of the controlled releases indicate ∼10 %–40 % average errors (depending on the inversion configuration or on the series of tests) in the estimates of the release rates and ∼30–40 m errors in the estimates of the release locations. These results are shown to be promising, especially since better results could be expected for longer releases and under meteorological conditions more favorable to local-scale dispersion modeling. However, the analysis also highlights the need for methodological improvements to increase the skill for estimating the source locations.

Resorcinol/formaldehyde gels are used to show that gel performance in porous rocks depends critically on the pH at which gelation occurs. The gels generally reduced the permeability of low-permeability sandstone more than in high-permeability sandstone. However, residual resistance factors can be greater in sandstones than in less permeable carbonate cores. A simple mathematical model is used to assess whether pH effects can be exploited to optimize gel placement in injection wells .

Summary This paper presents results of laboratory studies on mechanical degradation of partially hydrolyzed polyacrylamide (HPAM) solutions in core samples from several different carbonate reservoirs. Studies in carbonates are of particular importance because several of the larger polymer projects are in carbonate reservoirs and because data on carbonate polymer projects are in carbonate reservoirs and because data on carbonate rocks have not previously been available. Many of the data in the literature were obtained with solutions of polymer-in-brine. Because HPAM polymers are generally more efficient in fresh waters, lower-salinity polymers are generally more efficient in fresh waters, lower-salinity waters were used for the bulk of the present study. Investigated variables included polymer molecular weight, polymer concentration, and salinity of the aqueous solvent. HPAM samples used were commercial products of various molecular weights. Results were compared with correlations previously developed for sandstone core plugs and unconsolidated sands. The extent of induced degradation was monitored by comparison of viscosities and screen factors before and after flow through the core plugs at various flow rates. During injection of low-salinity polymer solutions through low-permeability carbonate core plugs, the extent of induced mechanical degradation was higher than values estimated with existing correlations obtained with higher-permeability porous media. Severe nonuniformities in the low-permeability carbonate core caused difficulties in our attempts to relate the degradation of existing correlations. Thin sections of the core materials were very helpful in the qualitative understanding of the differences in injectivity and mechanical degradation for cores from the various reservoirs. Cores with relatively uniform porosity performed differently from those that were very nonuniform, even though the permeabilities were similar. permeabilities were similar. The induced mechanical degradation of the polymer reduced the viscoelastic and pseudoplastic nature of the HPAM solutions. As expected, the extent of mechanical degradation increased as the polymer molecular weight increased. Residual viscosities and screen factors of the sheared solutions, however, were often greater for the higher-molecular-weight HPAM polymers. Higher salinities or calcium concentrations of the solvent polymers. Higher salinities or calcium concentrations of the solvent resulted in increased degradation. Thus, use of low-salinity water or softened fresh water can reduce the level of irreversible shear degradation. Introduction Two types of water-soluble polymers have been used extensively for enhanced recovery of crude oil: HPAM and xanthan gum polysaccharide (XGPS). The purpose of either polymer is to reduce the mobility of injected fluids during flow through a reservoir. Aqueous XGPS solutions reduce mobility principally by increasing the viscosity of the injected water. On the other hand, HPAM solutions reduce mobility by increasing viscosity and also by decreasing the permeability of the reservoir to water. The magnitude of mobility reduction with either polymer has been expressed in terms of a dimensionless quantity, the resistance factor, FR 1: (1) where k is relative permeability, u is viscosity, and the subscripts w and p refer to water (or brine) and polymer solution, respectively. The resistance factor is a measure of the resistance to flow caused by the polymer relative to the resistance to flow of the water without the polymer present. Any permanent degradation of the polymer present. Any permanent degradation of the polymer molecules will be reflected in a loss of mobility control. At high-flowrate conditions, the synthetic HPAM is much more susceptible to mechanical degradation than the XGPS biopolymer, and several early papers identified the potential for shear degradation of HPAM in both laboratory and field tests. Injection rates are frequently high enough to cause significant mechanical degradation of HPAM as the polymer solution enters the formation matrix adjacent to the injection wellbore. The most probable cause for the degradation process is fragmentation probable cause for the degradation process is fragmentation of some of the high-molecular-weight polymer molecules when stretching deformations in the converging flow regions (pore constrictions or throats) of the porous matrix exceed a critical stretch rate. Although the fragmentation of polymer molecules is caused by elongational flow fields, "shear degradation" will be used interchangeably with "mechanical degradation" throughout this paper. SPEFE P. 139

Loss of solution viscosity in water of increasing ionic strength is a major problem encountered in the use of the partially hydrolyzed polyacrylamide polymers for improved oil recovery. It is recognized widely that the viscosity loss is more drastic in the presence of multivalent cations than is observed for sodium ions. There is, however, little information available on the relationships between total ionic strength, concentrations of multivalent cations, and solution viscosities.The purpose of this study is to establish relationships between total ionic strength, concentration of calcium or magnesium ions, polymer concentration, and the resulting viscosity for partially hydrolyzed polyacrylamides with varying degrees of hydrolysis. Solutions at constant ionic strength with varying ratios of calcium or magnesium to sodium ions are compared, and the loss of viscosity as a function of the fraction of divalent cations in the system is determined. For shear rates in the power-law region, the fractional loss in viscosity is a function of the fraction of multivalent cations and, in the range studied, is independent of the total ionic strength. A more complicated relationship is found at lower shear rates where the fractional viscosity loss does vary with total ionic strength.The relationship in the power-law region should prove valuable in predicting viscosities on the basis of the dependence of viscosity on ionic strength and on multivalent cation concentration at a single ionic strength, eliminating the need for many individual measurements of viscosity. More work is needed before useful predictions will be possible at lower shear rates. Introduction Partially hydrolyzed polyacrylamide (HPAM) polymers are currently the most widely used mobility control polymers for secondary and tertiary oil recovery. Small quantities of HPAM can increase the viscosity of water by two or more orders of magnitude in the absence of added electrolytes. This phenomenal increase in viscosity results from the extremely high molecular weight of these polymers and repulsion between the negative charges along the polymer chain, resulting in maximum chain extension. The latter mechanism leads to one of the greater disadvantages of using HPAM in an oil reservoir. In the presence of the electrolyte molecules in typical oilfield brines, negative charges along the polymer chain are screened from each other by association with cations from the solution. The polymer chains no longer are extended fully, and solution viscosity decreases. Mungan observed that divalent cations have a more pronounced effect on viscosity than univalent cations when compared on the basis of equal weights of the chloride salts.Viscosities have been reported for HPAM solutions in sodium chloride brines of varying strength as well as for solutions in brines containing CaCl2 or MgCl2. Some viscosities also have been reported for solutions in brines containing both sodium and calcium ions, but no systematic study of the viscosity trends in brines with more than one type of cation has been reported.The purpose of this study is to investigate HPAM solutions with varying ratios of univalent to divalent cations and to establish trends of the solution viscosities for different values of degree of polymer hydrolysis, polymer concentration, and total ionic strength. Such trends are useful for predicting a wide range of viscosities from a few basic measurements. SPEJ P. 623^