Partially hydrolyzed polyacrylamide solutions are highly shear degradable and may lose much of their effectiveness in reducing water mobility when sheared by flow through porous rock in the vicinity of an injection well. Degradation is investigated by forcing polymer solutions, prepared in brines of various salinities, through consolidated sandstone plugs differing in length and permeability, over a plugs differing in length and permeability, over a wide range of flow rates. A correlation for degradation based on a theoretical viscoelastic fluid model is developed that extends predictive capability to situations not easily reproduced in the laboratory. Mobility-reduction losses in field cores at reservoir flow rates are measured following degradation and are found to depend strongly on formation permeability. Consideration of field applications shows that injection into typical wellbore geometries can lead to more than an 80-percent loss of the mobility reduction provided by undegraded solutions. Also discussed are consequences for incremental oil recovery and the possibility of injecting through propped fractures. possibility of injecting through propped fractures Introduction Susceptibility of commercially available, partially hydrolyzed polyacrylamides to mechanical, or shear, degradation represents a serious problem regarding their applicability as mobility-control fluids for secondary and tertiary oil recovery applications. The approach taken in this work assumes that surface handling equipment in the field (pumps, flow controllers, etc.) have been adequately designed to minimize effects of shear degradation in all operations preceding actual delivery of the polymer solution to the sand face. The remaining problem is to assess the mechanical degradation a polymer solution experiences when it enters the porous matrix at the high fluxes prevailing around injection wells. Ability to predict the degree of mobility-control loss based on a laboratory investigation of the relevant parameters is desirable. White et al. were the first to attempt prediction of matrix-induced degradation, but the result was only a recommended injection-rate limit for minimizing polymer degradation for two specific wellbore completions. More recent papers offer limited data supporting the contention that matrix-induced degradation of polyacrylamide solutions results in significant loss polyacrylamide solutions results in significant loss of mobility control . This paper investigates the cause of mechanical degradation in dilute polymer solutions and presents experimental data on the effects of polymer concentration, water salinity, permeability, flow rate, and flow distance. permeability, flow rate, and flow distance. Several interesting and unexpected conclusions are drawn from the results. BACKGROUND - THEORETICAL CONCEPT The mechanical degradation of polymer solutions occurs when fluid stresses developed during deformation, or flow, become large enough to break the polymer molecular chains. Historically, the feeling has been that shearing stresses in laminar shear flow or turbulent pipe flow were responsible for chain scission. However, recent data reported by Culter et al. suggest that degradation of viscoelastic polymer solutions in capillary tubes may be dominated by large elongational or normal caresses occurring at the entrance to the squared-off capillaries. Such stresses result from Lagrangian unsteady flow, or elongational deformation, at the tube entrance. Flow through porous media also generates velocity fields that are sufficiently unsteady, in the Lagrangian sense, to lead one to anticipate large viscoelastic normal stresses. Viscoelastic fluids are materials that behave like viscous liquids at low rates of deformation and partially like elastic solids at high rates of partially like elastic solids at high rates of deformation. Several constitutive models are available for describing the stress-strain behavior of such fluids. SPEJ P. 311

Glover, C.J.,* SPE-AIME, Exxon Production Research Puerto, M.C., SPE-AIME, Puerto, M.C., SPE-AIME, Exxon Production Research Co. Maerker, J.M., SPE-AIME, Exxon Production Research Co. Sandvik, E.L., SPE-AIME, Exxon Production Research Co. Abstract Surfactant retention in reservoir rock is a major factor limiting effectiveness of oil recovery using microemulsion flooding processes. Effects of salinity and surfactant concentration on microemulsion phase behavior have a significant impact on relative phase behavior have a significant impact on relative magnitudes of retention attributed to adsorption vs entrapment of immiscible microemulsion phases.Surfactant retention levels were determined by effluent sample analyses from microemulsion flow tests in Berea cores. Data for single surfactant systems containing NaCl only and multicomponent surfactant systems containing monovalent and divalent cations are included. Retention is shown to increase linearly with salinity at low salt concentrations and depart from linearity with higher retentions above a critical salinity. This departure from linearity is shown to correlate with formation of upper-phase microemulsions. The linear trend, therefore, is attributed to surfactant adsorption, and retention levels in excess of this trend are attributed to phase trapping.Divalent cations are shown to influence microemulsion phase behavior strongly through formation of divalent-cation sulfonate species. A useful method for predicting phase behavior in systems containing divalent cations is described. This method combines equilibrium expressions with a relationship defining the contribution of each surfactant component to optimal salinity. Observed experimental data are compared with predicted data. Introduction Two essential criteria that must be met for successful recovery of residual oil by chemical flooding arevery low interfacial tensions between the chemical bank and residual oil and between the chemical bank and drive fluid andsmall surfactant retention losses to reservoir rock. If retention is excessive, interfacial tensions eventually will become high enough to retrap residual oil in the remainder of the reservoir.Previous studies have described several mechanisms responsible for surfactant retention in porous media. These include adsorption, porous media. These include adsorption, precipitation, partitioning into a residual oil phase, precipitation, partitioning into a residual oil phase, and entrapment of immiscible microemulsion phases. Of particular interest is Trushenski's discussion of microemulsion phase trapping as a consequence of surfactant-polymer interaction, and a supporting statement that similar behavior often was observed when microemulsions were diluted with polymer-free brine. Here, we attempt to provide some understanding of this surfactant dilution phenomenon by examining phase behavior as a function of salinity, divalent-ion content, and surfactant concentration. Experimental Procedures Surfactant Systems Two surfactant systems were used in this study. (Specific microemulsion compositions are discussed later.) One system was the 63:37 volumetric mixture of the monoethanol amine salt of dodecylorthoxylene sulfonic acid and tertiary amyl alcohol (MEAC12OXS/TAA) described by Healy et al. The oil component for these microemulsions was a mixture of 90% Isopar M TM and 10% Heavy Aromatic Naptha.(TM)** The brine contained NaCl only. SPEJ P. 183

SynopsisSolutions of poly(vinyl alcohol) (PVA) and polysaccharide with sodium borate (SB) are investigated as a model system for associating polymers which exhibit shear-induced fluid structure and shear-thickening rheology. Certain combinations of PYA and SB concentrations are shown to result in fluids that exhibit a viscosity maximum followed by shear thinning as shear rate is increased. Stress saturation is often observed in the shear-thinning region. A significant hysteresis is also reported in which higher viscosities and lower shear rate for the viscosity maximum are observed in steady-state measurements made while decreasing shear rate in a stepwise manner. Boron nuclear magnetic resonance spectra are shown to be useful for elucidating the nature of the borate/hydroxyl-dyad complexes, including their stereoselectivity. Boron resonance peaks allow quantitative determination of the number of complexes. Dynamic mechanical properties are included, and a physical picture of network structure building and breaking during flow of associating polymers is discussed.

Summary Laboratory steps required to design a successful surfactant flooding processfor the high-salinity Loudon field are described. These steps involved (1)phase-behavior tests to identify two synthetic surfactant components; (2) Bereacoreflood tests to establish the desirability of incorporating polymer in themicroemulsion and to optimize blend ratio, microemulsion salinity, drive-watersalinity, and bank size; and (3) Loudon rock corefloods to provide a finalcheck in reservoir core material. The process recovered significant quantitiesof residual oil in two 1-acre-pilot tests without the use of a cosurfactant, acosolvent alcohol, or a low-salinity preflush. Introduction The Loudon field, operated by Exxon Co. U.S.A. in Fayette County, IL, is aprime tertiary recovery target from a technical standpoint. The field is in anadvanced stage of depletion after 13 years of primary production and 38 yearsof waterflooding. After waterflooding is completed, nearly one-half theoriginal oil in place will likely remain unrecovered. Most of the reservoircharacteris-tics are favorable for state-of-the-art microemulsion (surfactant)flooding-i.e., low temperature (78 deg. F), moderate permeability (140 mdaverage), low oil viscosity (5 cp), and fairly low clay content (- 3 %). Thehigh salinity of the resident brine-about 104,600 ppm (10.5%) total dissolvedsolids (TDS), including more than 4,000 ppm of divalent ions (see Tablel)-represents a significant challenge for surfactant flooding. An earlier surfactant flood pilot I conducted at Loudon in 1969 used alarge-volume low-salinity preflush to displace resident brine and to reducesalinity to a level required for efficient oil displacement by the petroleumsulfonate surfactant system. The main conclusion reached from petroleumsulfonate surfactant system. The main conclusion reached from that test, whichrecovered only about 15 % of the residual oil in the test area, was thatpreflushes are likely to be ineffective unless the surfactant system iseffective over a broad range of salinities. Much of the subsequent surfactantflooding research was directed at surfactants that are effective inhigh-salinity reservoirs without requiring a preflush. preflush. This paperdescribes the final design stages of a high-salinity surfactant floodingprocess for the Loudon field. We include a brine discussion of phase behavior, but a complete treatment of phase behavior to identify the generic surfactantstructure is beyond the scope of this paper. The bulk of work reported here isdivided into two parts dealing paper. The bulk of work reported here is dividedinto two parts dealing with Berea coreflood tests and with Loudon rockcoreflood tests. The section concerned with Berea corefloods begins with adiscussion of mobility control, and this is combined with oil recoverycomparisons between small- and large-cross-section (wide-model) corefloods toestablish the desirability of incorporating polymer in the microemulsion. Subsequent stages of the process design are discussed essentially inchronological order, including optimization of surfactant blend, microemulsionsalinity, drive-water salinity, and bank size. Phase Behavior Phase Behavior The process design work detailed in this paperused surfactants selected from a group of compounds described in Ref. 3 andrepresented by the general formula R1O(C3H6O)m(C2H4O)nYX. In the specificmolecules considered here, R is an isotridecyl alcohol radical, m and n havevalues from 1 to 6, Y is the hydrophilic sulfate group, and X is the monovalentsodium cation. These compounds were manufactured by reacting propylene oxideand then ethylene oxide with isotridecyl alcohol in two separate steps, followed by sulfation and neutralization with sodium hydroxide. Two majoradvantages of these surfactants, detailed in the patent, are that (1) optimalsalinity is relatively high and is not a strong function of surfactantconcentration or divalent-ion concentration and (2) chromatographic separationof components is expected to be minimal with negligible effect on surfactantperformance. Fig. 1 shows optimal salinity contours on a grid representing differentnumbers of propoxyl and ethoxyl groups in the surfactant molecules. (The valuesm and n are actually averages for distributions of m and n in each singleproduct or blend of surfactants.) Generally, when other parameters are heldconstant, optimal salinity increases with more ethoxyl groups and decreaseswith more propoxyl groups. The contour lines are labeled as a percentage of TarSprings brine (TSB) composition (shown in Table 1). The salinity of TSB is verysimilar to that of the resident brine -M the Loudon reservoir. From the grid in Fig. 1, it is evident that an infinite number of combinations of m and n couldgive a surfactant system with an optimal salinity near 100% TSB. The systemselected for use in the Loudon microemulsion formulation consisted of a blendof the two surfactants identified on Fig. 1: i-C13H27O(PO)4(EO)2SO3Na andi-C13H27 O(PO)3(EO)4SO3Na. This selection was based on many preliminary phase-behavior tests andlaboratory corefloods conducted before the final design steps described in thispaper. A discussion of these tests is beyond the scope of this paper. A blendof surfactants provides a means for quality control through adjustment of theblend ratio to account for compositional differences that may result fromunintentional variations in manufacturing operations. Later sections in thispaper discuss situations where readjustment of the optimum blend ratio wasnecessary. A 60/40 blend of the surfactants PL612 and PL613 [(PO)4(EO)2 and (PO)3(EO)4tridecyl alcohol sulfates, respectively] was required to give an optimalsalinity near Loudon resident-brine salinity. Fig. 2 shows solubilizationparameters vs. salinity for microemulsions made with two different oils at a1:1 WOR and 2 % (wt/vol) of the 60/40 blend. To keep microemulsion costs low, diesel oil initially was selected as the oil component for microemulsionformulation. The diesel oil used to develop Fig. 1 gave an optimal salinitynear that obtained with Loudon crude oil at 78 deg. F. However, somesignificant differences in phase behavior were observed. Diesel oil producedclassical phase-behavior transitions of lower- to middle- to upper-phasemicroemulsions with increasing salinity, as shown in Fig. 2a. On the otherhand, Loudon crude oil produced nonclassical phase behavior; as salinityincreased, Loudon oil uptake by the lower-phase microemulsion increased andthen dropped abruptly, as shown in Fig. 2b. Further salinity increases produceda middle phase that contained little or no solubilized oil. Because no trueoptimal salinity exists for such nonclassical systems, we arbitrarily took" optimal salinity" to be the salinity where the discontinuity in oilsolubilization occurred. In Fig. 2b, this salinity is 105% TSB. At reservoirsalinity (100% TSB), the oil-solubilization parameter is about eight. Theoil-solubilzation parameter with diesel at reservoir salinity is about 17.

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