Polymer flooding plugging

In the next run, a core pack was saturated with 8.6 cp (at 50° C) Ranger-zone crude oil and water flooded to residual oil saturation. Polymer flood was then initiated and about 1.2% of the original oil in place (OOIP) was recovered. The results are shown in Figure 4. The pressure profiles show behavior essentially similar to the previous run except that the pressure drop across the core increased to 100 psi within 4 PV of injection of polymer. The steady state values of pH and viscosity were 7.0 and 0.7 cp. respectively. The oil ganglia retained in larger pores resisting displacement probably reduced the amount of polymer adsorbed and reduced the number of pores that the polymer molecules needed to seal off in order to block the core. This could explain the more rapid plugging of the core. Effluent pH and viscosities remained much lower than influent values. 

In this paper, a new technique for plugging fractures is also presented. Also, surfactant-enhanced alkall/polymer flood is alternated with water injection in order to optimize oil production. This technique uses a shorter sequence of chemical injection and therefore increases the possibility of plugging the fractures. 

In this section, the relevant laboratory tests that should be carried out on polymers in support of a proposed polymer pilot will be described. Virtually all of the actual technical points concerning polymer properties—such as compatibility/stability, filterability and formation plugging, polymer solution preparation, adsorption in porous media, in-situ rheology—have been discussed in detail elsewhere in this book. However, earlier the objective was to present an explanation and a view on the science of the various phenomena involved in polymer physics and chemistry both in bulk solution and in flow through porous media. Here, the intention is to abstract the much more limited subset of experiments that should be carried out in support of a practical polymer flood application in the field. In all of the discussion below, it is assumed that a range of commercially available off-the-shelf polymers... 

This paper presents the results o a study of the factors involved in wellbore plugging by clean polymer solutions. Plugging of injection wells can have a very detrimental effect on the economics of polymer flooding. Polymer plugging was found to be a function of the following four factors ... 

Most laboratory design studies of a polymer flood involve the measurement of the effective viscosity of polymer solutions in representative field cores. Polymer plugging often may not be observed because such a test typically involves only a relatively small number of pore volumes of polymer injection. There is little information in the literature about polymer plugging in cores, or polymer related field injectivity loss. Omar indicated that shaly sands adsorb more polyacrylamide per unit of surface area than do clean sands. He suggested that the difference was due to the platelet edge charges of shaly sands. Duane and his coworkers reported that Shell s Coalinga polymer demonstration project had loss of polymer injectivity. 

Polymer selection for the offshore polymer flood was made by comparing three emulsion polyacrylamides during a 30-day injectivity test. ATI three polymers were chosen for field testing based on laboratory studies. The chosen polymer was selected based on lower overall cost and ease of injection even though some samples failed the core plug test for injectivity. Polymer injectivity was a critical parameter because of the severe pressure limitations of the shallow reservoir. No additional chemicals were required to assist the inversion of the chosen polymer, as were needed for the other candidates. This feature requires one less pump per skid and substantially reduces the possibility of injecting uninverted polymer into the well, which can result in major formation damage. 

Filtration. Many of the plugging problems associated with flooding oil reservoirs with polymer solutions originate from inefficient preinjection procedures. The importance of dispersion was presented in the preceeding section. In this discussion, the importance and the consequences of filtration will be presented. 

For this reason we perform our injection tests on plugs of natural sandstone at temperatures of 130 - 170 °F (55 - 75 C). By continuous injection of polymer solution (1000 ppm polymer in brine) at a constant rate over the flood section, differences in pressure that develop are recorded and are used to judge the injectability. A product is considered to be good in this respect if the pressure gradient, after the injection of 10 x pore volume of solution, increases by less than 10 7o of the initial pressure gradient (after saturation ) (Fig. 6). 

The transient RF and concentration curves of polysaccharide G2 are illustrated in Figure 8. The transient RF curve reflects some plugging behavior but not to the degree indicated by the high retention factor (321 Ib/acre-foot). The high RRF of 9.3 reflects some polymer retention/adsorption phenomena. The large retention could have resulted from association of polysaccharide molecules with divalent ions such as Mg and Ca to form reversible complexes in the 80/20 connate water at the flood front. Such a... 

Polymers used for mobility control are non-Newtonian fluids, and thus, the polymer mobility in porous rock varies with frontal-advance rale, as illustrated in Fig. 5.95.By selecting polymer concen-tratian, it is usually possible to meet the design mobility. Data presented in Fig. 5.95 were obtained from laboratory tests on small reservoir core plugs. Polymer mobility tests should be conducted at the ROS expected for chemical flooding to include the effects of permeability reduction resulting from the chemical flood ROS. 

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