Polymer flooding is a mature EOR technique successfully applied in both sandstone and carbonate reservoirs and it is expected to have much wider applications in the future. However, it is currently limited mainly by a combination of reservoir temperature and make-up brine salinity and hardness, as synthetic polymers can chemically and thermally degrade at high temperature and salinity. This paper reports the results of an ongoing study aimed at finding polymers that can enlarge the application envelope of polymer flooding to, for example, high-temperature and high-salinity Middle Eastern carbonate reservoirs. In this study thermal stability of a number of commercially available polymers was tested at 120°C in various brines. The polymers investigated are partially hydrolyzed polyacrylamide (HPAM) based co- and ter-polymers functionalized with 2-Acrylamido-2-Methylpropane Sulfonate (AMPS) and/or n-Vinyl Pyrrolidone (n-VP) monomers. These monomers provide tolerance to divalent ions and protection to hydrolysis at higher temperatures. The thermal stability tests showed a clear relationship between the polymer stability and the concentration of the functionalizing monomer. Incorporation of the AMPS monomer alone does not stabilize the polymer in brines which contain divalent ions. The additional incorporation of n-VP demonstrates a stabilizing effect which is optimal at a concentration of 35-50%. The optimal ter-polymer is stable at 120°C in brines with salinity up to 200,000 ppm TDS and divalent ion concentration up to 18,000 ppm for more than 180 days. Another challenge to polymer flooding is the adsorption of polymers onto the reservoir rock. The adsorption of the terpolymers on carbonate core material was investigated in this study as a function of the polymer type and pH. This is the first work to prove the feasibility of polymer flooding at temperatures up to 120°C in high-salinity reservoirs in the presence of a high concentration of divalent ions. These results will significantly enlarge the application envelope for polymer flooding.

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Most fields around the world suffer from formation heterogeneities that significantly reduce the sweep efficiency of waterfloods. For over five years xanthan gum/trivalent chrome gels have been used successfully in North American oil fields to improve injection well flow profiles. The process involves selectively placing the complexed biopolymer into water thief zones which, after it has developed gel strength, diverts subsequent water flow to underswept oil bearing zones. This paper discusses the general theories behind this technology, the features and benefits of the xanthan /Cr(III) gels, and actual field results.

SPE Members Abstract A new polymer, previously evaluated in the laboratory, has been successfully tested to shut off water production in two offshore high temperature gravel packed wells in the Gulf Coast. The polymer is shear resistant, thus easy to handle, and, since it maintains good permeability to oil in the zones into which it is injected, it does not require zone isolation during injection into the well. After treatment, a strong reduction in WOR was observed in both wells. The effect lasted over 2 years in one well and for several months in the second well. These treatments show that the polymer is stable in field applications at 190 and 200 F (88 and 93 C). Introduction In many reservoirs, heterogeneity and bottom water coning are responsible for early water brealotluough, which reduces total oil recovery and increases operating costs. Over the years these mechanisms have been well documented. When two or more layers of differing permeability are producing together, production is naturally favored by the layers with the highest permeability. After oil has been produced from these layers, water encroachment occurs which hinders oil production from the lower permeability layers. Reservoirs with strong bottom water drive are subjected to breakthrough of this water which reduces the oil production as the water moves into the bottom of the perforated interval. Once the water reaches the perforations, it begins to move up further into the perforations rapidly. This type of mechanism, coning, has been well studied in the literature. Where possible, mechanical zone isolation, cement squeezes, or plugging type gels can be the easiest way to shut off the water corning from watered out layers. However, in many wells the oil and water producing zones are not separated or identifiable, or the completion of the well is not suitable for such workovers. In these cases the only way to reduce the permeability in the watered out zones is by the injection of a polymer or gel with the entire perforated interval open. In most cases this requires a polymer or gel that is a relative permeability modifier in order to reduce the risk of plugging the lower permeability oil saturated zones. These polymers and gels are known to selectively reduce the permeability to water relative to the oil permeability and they can be injected directly into a well without the expense of a major workover to pull the existing completion. The mechanisms of the polymer action are complex - non-Newtonian rheology, unsteady-state effects, adsorption, retention, wettability, etc. - and have been studied both theoretically and in laboratory experiments. The question of gel placement is a key factor for success of any gel system and it has been studied by Seright and co-workers. In practice, polymer and gel technology has been proven to be successful in many areas, thus focusing the interest of operators. P. 387^

The Marmul field in Oman is exhibiting a low oil recovery caused by the high oil viscosity (80 mPa.s) and the moderate to strong edge water drive. The poor mobility ratio has resulted in early increased water production through water channeling and coning. The technology evaluated to reduce the water production made use of a so-called relative permeability modifier system which was composed of a cationic polyacrylamide and the crosslinker glyoxal. This gel system reduces the relative permeability for water, while only marginally affecting the relative permeability for oil. The aim of a relative permeability modifier system is a decreased water production and potentially an increased oil production. The major advantages for such a system are that the treatment is bullheaded down the well and detailed information on the inflow performance is not required. This was advantageous for the Marmul field in which all the wells have been gravelpacked. Selection criteria were used to establish which wells would be treated and the final candidates were randomly located over the field. The treatment design consisted of the injection of three equal sized polymer/crosslinking stages with increasing polymer concentration. Five of the initially six treated wells showed a positive response to the gel treatment, i.e. (large) water-cut reduction and increased oil production. A simulation study on one of these treatments was performed to understand the behaviour of these treatments. Initial results could not match the observed field behaviour and only after introduction of flow barriers (shale layers) in the reservoir model a match between simulation and field could be achieved showing the significance of small details in local geology around the well. However, these flow barriers could not be seen on the open hole logs. Subsequently eight treatments have been performed. However, they were disappointing and no clear explanation for the deviating behaviour could yet be given. The causes for the poor performance could be poor candidate selection and/or a poor understanding of the gel system. Poor candidate selection is considered doubtful because the wells in the first six and the last eight treatments were randomly chosen throughout the field. Therefore, the emphasis is now on the gel system to determine more accurately its chemistry (e.g. polymer/crosslinker concentrations needed) and the volumes required to obtain an optimum result with respect to decreased water production and increased oil production. P. 307