47 - chemical flooding

Mobility control processes inject a low-mobility displacing agent to increase volumetric and displacement sweep efficiency. The two main techniques are (I) polymer flooding. whereby a small amount of polymer is added to thicken brine and (2) foam flooding, through which low mobilities are attained by injecting a stabilized dispersion of gas in water. Polymer or mobility buffer drives also

ams icel- foam sol- bili- s in

-situ

minus ROS] since they displace oil only in excess of ROS. The mobility ratio concept illustrates how lowering the mobility improves oil recovery.

The mobility ratio, M, between a displacing agent and a displaced fluid is

M=hDlh,,, ._____.____................ ._.(l)

where AD is the mobility of displacing agent(s) and A,, is the mobility of displaced fluid(s). Practical use of Eq. 1 requires specific definitions of the quantities in the numerator and denominator and of the conditions at which these quantities are evaluated.

For two-phase waterflooding, common specializations of Eq. 1 are the endpoint mobility ratio, M. the average mobility ratio, M, and the shock mobility ratio. M*. Each definition has been used in particular applications in the are used to displace micellar and high-pH slugs. Fohave been used or proposed as driving agents for mlar. solvent, and steam slugs also. For these reasons tlooding could be discussed easily in the chapters onvent and thermal EOR processes; however. foam stazation requires surfactants. whose discussion belongthis chapter.

Low-IFT methods rely on injecting or forming inChapter 47

Chemical Flooding Larry W. Lake, U. of Texas

Introduction Chemical flooding is any isothermal EOR process whose primary goals are to recover oil by (1) reducing the mobility of the displacing agent (mobility control process), and/or (2) lowering the oil/water interfacial tension (low- IFT process).

These classifications do not exclude processes where both effects are important, such as micellar/polymer (MP) flooding, nor do they imply that other effects, such as wettabiiity alteration, extraction, or oil swelling. are not present. a surface-active agent (surfactant) which lowers oil/water IFT and, ultimately. residual oil saturation (ROS). Proc- esscs that inject the surfactant are called MP floods because of the tendency for surfactants to form micelles in aqueous solutions and the inevitable need to drive the micellar solution with polymer. High-pH or alkaline processes produce a surfactant in situ, since these processes rely on reactions with acidic components of the crude to generate the surfactant.

This chapter is divided into sections corresponding to mobility control and low-IFT processes. Each section begins with a general discussion of how the particular mechanism recovers oil, followed by material on the individual processes, and concludes with typical oil displacement results. The chapter concludes by giving comparative screening parameters for each chemical flooding process.

Mobility Control Processes Effect of Low Mobility on Oil Recovery

Mobility control processes are most applicable to reservoirs that have substantial movable oil [oil in place (OIP) literature: M has been used to correlate areal sweep relations, M* is the most direct indicator of viscous instability, and M is the most widely cited value in the literature for waterfloods. Z For the special case of a piston-like displacement all three definitions are identical. From the general definition of Eq. I, lowering the mobility of the displacing fluid is equivalent to lowering any of the mobility ratios. This recovers oil by increasing both volumetric and displacement sweep efficiency.

Volumetric sweep efficiency, EV. is the PV of a reservoir contacted by a displacing agent div,ided by the total PV. Et, is composed of two parts: areal, E/r, and inva- sion (vertical) sweep efficiency, El.

ing propathey are growing poor oil bility coil conventof an oth

Displacsweep cfplacementplacementsweep efLeverett ering onfactors thEl,: howrecovery

Loweriincreahinscicncics. tcrminc in any ooil rccokeivcre IOUclcncIc\. control peupensc agent.

link subsequently injected polymer molccutes with ones

or Xn. proc- e poly-

EOR the one

ood in- a low- itself: a from

. Many ecreas-

fects ot ter and of the

through

ter that olymer. brine. ly for is the phase.

lly all rations @on. Such tingcrs also form when M< I. but damped out by the~~~\~cl&le mobility ratio. The viscous fingers can contribute substantially to

rocovcry because of large-scale bypassing. Mo- ntrol agents prevent viscous fingering cithcr in ional waterflood (polymer flooding) or ah a part erwise inherently unstable EOR process. ement efficiency. El, (local or microscopic ticicncy). is the volume of oil recovered in a dis- divided by the oil volume just before the dis- . the displacement having maximum volumetric ficiency. The classical solution by Buckley and can be used to describe the effect of mobility low- En. Because of the dependence on several ere i+ no unique correspondence between M and ever. lowering M or An results in improved oil

through larger Eo. ng M. then. results in improved oil recovery by areal. vertical. and displacement sweep effi-

Since it is the products of these factors that dc- overall oil recovery. this implies that an incrcasc ne may not r-csutt in a larfc overall incrcaso in ry. particularly if one of the other efficiencies . Even with the combination of the three effi- the incremental oil recovered with ;I mobility

rocess must he balanced against the additional

already bound to solid surfaces. 3. The other mode is use as agents to lower MThe first mode is not truly a chemical flooding

ess. since the actual oil-displacing agent is not thmer. The overwhelming majority of polymer projects have been in the third mode, which is emphasized here.

Fig. 47. I is a schematic of a typical polymer fljection sequence: a preflush, usually consisting ofsalinity brine: an oil bank; the polymer solution freshwater buffer to protect the polymer solutionbackside dilution; and, finally. chase or drive watertimes the freshwater buffer contains polymer in ding amounts (a grading or taper) to lessen the efunfavorable mobility ratio between the chase wathe polymer solution. Because ofthe driving natureprocess. polymer tloods always arc performed separate sets of in.jection and production wells.

M is lowered in a polymer tlood by in.jecting wacontains a high-molecular-weight. water-soluble pSince the water is usually a dilution of an oillicldinteractions with salinity are important. particularcertain classes of polymers. Salinity in this chaptertotal dissolved solids (TDS) content of the aqueous Typical values are shown in Fig. 47.2. Virtuachemical flooding propertics dcpcnd on the concent47-2

Fig. 47.1-Schematic

For more &tailed discuxsions of E,, and El XC Chaps. 30. 43. and 44 and Refs. 1 through 1 I. Both quantities dcpcnd on throughput and on several fluid. petrophyai- cal. and geometric factors. usually expressed as dimen- sionlcsa groups. However. E,.( and El both increase as Mdecrea~-i.e.. as the mobility of the displacing agent, A,,. decreases.

When the displacement is piston-like in a homogcnc- ous. isotropic. horizontal medium and M> I (an UI+I\YIU- hlr mobility ratio). the displacement front forms small perturbations. called viscous fingers. which grow dur- rcquircd to in.jcct the viscous mobility control PETROLEUM ENGINEERING HANDBOOK

of polymer flooding

Polymer Flooding

Polymers have been used in oil production in three modes. I. They have been used as near-well treatments to in-

prove the performance of waler injectors or high-watercut producers by blocking off high-conductivity Loncs.

2. Polymers also are used as agents that may be cross- linked in situ to plug high-conductivity zones at depth in the reservoir. These proccsscs require that polymer be in.jected with an inorganic metal cation. which will cross- ofspccific ions rather than salinity only. It is partcularly important to monitor the aqueous phahcs total divalcnt

Fig. 47.2-Salinities from representallve oilfield brines

cation content (hardness) separately. since the latter are usually more crltical to chemical llood properties than the same TDS concentration. Fig. 47.2 also shows typical brine hardncsscs.

Bccauxc of the high molecular weight ( I to 3 million is typical) only a small amount (typically about 500 ppm) of polJ,mer will bring about a substantial increase in water viscosity. Furthcrmorc. several types ofpolymcrs lower mobility by lowcring water relative pcrmcability (pcrme- ability reduction effect) in addition to incrcaxing the water viscosity. How polymer lowers mobility. and the interactions with salinity may be qualitatively illustrated with some di5cusslon of polymer chemistry.

Polymer Types. Several polymers have been considered for polymer tlooding: xanthan gum, hydrolyzed polyacrylamide (HPAM). copolymers of acrylic acid and acrylamide. copolymers ofacrylamide and 2-acrylamide-2 Imethyl propane sulfonatc (AM/AMPS). hydrouyethyl- cellulose (HEC). carboxymethylhydroxycthyIccllulose (CMHEC). polacrylamide (PAM). polyacrylic acid, flu- can. dextran polycthylencoxide (PEO). and polyvinyl alcohol (PA). Only the first three have actually hccn field tested: however. the variety of entries in this partial list- ing emphasizes that there arc many potentially suitable chcmlcals. some of which may prove more cfkctivc than thoxc currently LIW~. Ncvcrthclcsj. virtually all 01 rhe commercially attractive polymers fall into two gcncric classes: polyacrylamidcs and poly\accharide\ (hiopolyme1

Fig. 47.3B-Molecular structure for polysaccharlde jbiopolymer).

Polyacrylamides. PAMs are polymers whose mono- meric unit is the acrylamide molecule. As used in polymer flooding, PAMs have undergone partial hydrolysis. which causes anionic (negatively charged) carboxyl groups (-COO-) to be scattered along the chain. The polymers are called partially hydrolyzed polyacrylamidcs (HPAMs) for this reason. Typical degrees of hydrolysis arc 30% or more of the acrylamide monomers: hence. the HPAM molecule is quite negatively charged. which accounts for many of its physical properties. The viscosity-increasing feature of HPAM lies in its large molecular weight. which is accentuated by the anionic repulsion between polymer molecules and also between segments on the same molecule. The repulsion causes the molecule in solution to elongate or uncoil and snag on others similarly elongated, an effect that accentuates the mobility reduction at higher concentrations.

If the brine salinity and/or hardness arc high. however, this repulsion is decreased greatly through ionic shielding as the freely rotating carbon/carbon bonds allow the molecule to ball up or coil. (Fig. 47.3 shows the molccu- lar structure of hydroxyethylcellulose.) This causes a corresponding decrease in the effectiveness of the polymer, since the snagging effect is rcduccd greatly. Virtually all HPAM properties show a large sensitivity to salinity and hardness. This is an obstacle to usiiyg,HPAM in many reservoirs. On the other hand, HPAM 15 inexpensive. relatively resistant to bacterial attack. and exhibits permea- CHEMICAL FLOODING

I

1,000 a0 d3 r @ Oo 0 I L

I )

,oc

TOTAL DISSOLVED SOLIDS, mg/l or xanthan gum ). The remainder of this discussion deals with these cxclu\ively. Representative molecular struc- turn\ are given in Fig. 47.3. . 47-3

POLYACRYLAMIDE

fT-J-

i I

I 2 I HYDROLYZED

POLYACAYLAMIDE

Fig. 47.3A-Molecular structure for partially hydrolyzed polyacrylamide. bility reduction.

Polysaccharides. A second major class of polyniers arc the polysaccharidcs. which are formed from the polymers-

47-4

Fig. 47.4-Polymer solution viscosity vs. shear rate and polymer concentration.

zation of saccharide molecules (Fig. 47.3). Polysaccha- rides or biopolymers are formed from a bacterial fermentation process. This process leaves substantial debris in the polymer product that must be removed before the polymer is injected. I6 The polymer is also susceptible to bacterial attack after it has been introduced into the reservoir. These disadvantages are offset by the insensitivity of polysaccharide properties to brine salinity and hardness. The origin of this insensitivity is seen in Fig. 47.3, which shows the polysaccharide molecule to be relatively nonionic and, therefore, free of the ionic shielding effects of HPAM. Polysaccharides are more branched than are HPAMs and the oxygen-ringed carbon bond does not rotate fully; hence, the molecule increases brine viscosity by snagging and by adding a more rigid structure to the solution. Polysaccharides do not exhibit permeability reduction, however.

At the present time HPAM is less expensive per unit amount than polysaccharides; however, when compared on a unit amount of mobility reduction, particularly at high salinities, the costs are close enough so that the preferred polymer for a given application is site-specific. Histori- cally, HPAMs have been used in about 95% of the reported field polymer floods. I7 Both classes of polymers tend to degrade chemically at elevated temperatures.

Polymer Properties. Because of the complexity of the subject, a comprehensive treatment of polymer properties is not possible. However. qualitative trends, a few quantitative relations and representative data are presented on these properties: viscosity relations, non-Newtonian effects, retention, permeability reduction, and chemical, biological, or mechanical degradation.

Viscosity Relations and Non-Newtonian Effects. Fig. 47.4 shows polymer solution viscosity. p,,, vs. shear rate measured in a laboratory viscometer at fixed salinity. I8 At low shear rates, p,, is independent of shear rate. P(~,,=~,,), and the solution is a Newtonian fluid. At higher i. p,, decreases, approaching a limiting (p,, =p, ) value not much greater than the water viscosity, p,,., at some critical high shear rate (not shown

on Fig. 47.4). A fluid whose viscosity decreases with increasing ? is shear thinning. The shear thinning behavior of the polymer solution is caused by the uncoiling and PETROLEUM ENGINEERING HANDBOOK

Fig. 47.5-Polymer solution viscosity vs. shear rate at various brine salinities.

unsnagging of the polymer chains when they are placed in a shear flow. Below the critical shear rate the curve is reversible.

Fig. 47.5 shows a viscosity/shear-rate plot at fixed polymer concentration with variable NaCl concentration for an AMPS polymer. I9 Note the profound sensitivity of the viscosity to salinity: as a rule of thumb the polymer solution viscosity decreases a factor of 10 for every factor- of-10 increase in NaCl concentration. The viscosity of HPAM polymers and HPAM derivatives is even more sensitive to hardness, but viscosities of polysaccharide solutions are relatively insensitive to both.

The behavior in Figs. 47.4 and 47.5 is favorable because for the bulk of a reservoirs volume, P is usually low (about 1 to 5 seconds -I), making it possible to attain a design M with a minimal amount of polymer. Near the injection wells, however, i can be quite high, which causes the polymer injectivity to be greater than that expected on the basis of ~1 The relative magnitude of this enhanced injectivity ef ect can be estimated once quan- P titative definitions of shear rate in permeable media and shear-rate/viscosity relations are given.

The polymer solution viscosity/shear-rate relationship may be described by a power law model.

pp =K(iy , . . (2)

where K and n are the power-law coefficient and expo- nent, respectively. Eq. 2 applies only over a limited range of shear rates: below some low shear rate the polymer solution viscosity is constant at pp O, and above the critical shear rate the polymer solution viscosity is also constant p,O. The truncated nature of the power law is awkward in calculations; hence, another useful relationship is the Meter model. 22

PLp O-P,, m P p = P p m+ .

If L c >

a~,,............

p 1%

where 01 is an empirical coefficient and > ,,? is the shear

rate at which CL,, is the average of pLr, and p,, -. As with all polymer properties, all empirical parameters are functions of salinity, hardness, and temperature.

CHEMICAL FLOODING

When applied to permeable media flow thcsc gcncral trends and equations continue to apply. cc,, is usually called the r(17/u.~rr viscosity and the effective shear rate. in,. . is based on capillary tube concepts.

ic = u ii

, . . . . . . . . . . . . . . . . . (4)

4&G%

where II,,. = superficial flux of polymer-rich (water)

phase. k,,. = permeability to polymer-rich (water) phase. S,,. = saturation of polymer-rich (water) phase.

fraction, and $ = porosity of medium, fraction.

Polymer Retention. All polymers experience retention on solid surfaces because of adsorption or mechanical trapping within a permeable medium. Polymer retention varies with polymer type, molecular weight, rock composition, brine salinity and hardness, flow rate, and temperature. Field-measured values of retention range from 20 to 400 Ibm polymer/acre-ft bulk volume with desir- able retention level being less than about 50 lbm/acre-ft. Retention causes the loss of polymer from solution, which can cause the mobility control effect to be destroyed-an effect that is particularly pronounced at low polymer concentrations. Polymer retention also causes a delay in the rate of polymer propagation.

Offsetting the delay caused by retention is an accelera- tion of the polymer solution through the permeable medium. which is caused by inaccessible PV (IPV). The most common explanation for IPV is that the smaller portions of the pore space will not allow polymer molecules to enter because of their size. Thus, a portion of the total pore space is uninvaded or inaccessible to polymer. and ac- celerated polymer flow results. Large as they arc, however, most polymer molecules will fit easily into all but the smallest pore throats. Hence, a second explanation of IPV ih based on a wall exclusion effect whereby the polymer molecules aggregate in the center of a narrow channel. The polymer pore fluid layer near the wall has a lower viscosity than the fluid in the center. which causes an apparent fluid slip.

IPV depends on polymer molecular weight, media permeability, porosity, and pore size distribution, becoming more pronounced as molecular weight increases and the ratio of permeability to porosity (characteristic pore size) decreases. IPV can be 30% of the total pore space or greater,

Permeability Reduction. As mentioned previously HPAM polymers can cause lowered mobility through a permeability reduction effect. This phenomenon has been described through three factors. 24 The resistuncc~,fuctor. FR, is the ratio of the injectivity of a single-phase polymer solution to that of brine flowing under the same conditions: A,,. k,,/tL,,, FR=-= x,, k,,cl,, . 47-5

where k,, = permeability to polymer solution.

h,, = mobility of water-rich phase. and h,, = mobility of polymer solution.

For constant-flow-rate experiments. FR is the inverse ratio of pressure drops; for constant-pressure-drop experiments, FR is the ratio of flow rates. F, is an indication of the total mobility-lowering contribution of a polymer. To describe the permeability reduction effect alone. a prl-- mwhilit~, rcductiorl ,firctor-. F,.k , is defined as

A final definition is the residual resistctnw jirctor. FRr . which is the mobility of a brine solution before and after polymer injection.

FR,-=- . _. (7)

where A,,.,, is the mobility of water-rich phase before polymer injection and A,,,(, is the mobility of water-rich phase after polymer injection. F,Q is a measure of the permanence of the permeability reduction effect caused by the polymer solution. It is the primary measure of the performance of a channel-blocking application of polymer solutions. For many cases, F,k and FR,- are nearly equal; however. FR is usually much larger than F,.,: because the former contains the viscosity-enhancing effect as well as the permeability-reduction effect.

The most common measure of permeability reduction is F,.k. Frk is sensitive to polymer type, molecular weight. degree of hydrolysis, shear rate, and permeable media pore structure. Polymers that have undergone even a small amount of mechanical degradation seem to lose most of their permeability reduction effect. For this reason. qualitative tests based on screen factor devices are common to estimate polymer quality. F,.k has been correlated to polymer adsorption and rheological properties by Hirasaki and Pope.

Chemical and Biological Degradation. The average polymer molecular weight can be decreased, to the detri- ment of the overall process, by chemical. biological, or mechanical degradation. Chemical degradation can be minimized by restricting polymer usage to low- temperature applications, and by adding oxygen scavengers (e.g., sodium sulfate or sodium sulfite) to the polymer solution. Biological degradation can be elim- nated by adding oxygen scavengers and biocides (e.g.. formaldehyde or isopropyl alcohol). In fact, nearly all applications contain some of these chemicals. usually in very small quantities (see Ref. 16 or 26).

Mechanical Degradation. Mechanicaldegradation, on the other hand, is potentially present under all applications. Mechanical degradation occurs when polymer solutions are exposed to high-velocity flows. These can be present in surface equipment (valves. orifices, pumps. or

tubing), downhole conditions (perforations or screens). or in the sandface itself. Perforated completions. particularly, are a cause for concern. since large quantities of

47-6 HANDBOOK

PLAC

ON P

oil rate be- . Polymer

arrested a The oil rate substantial- l oil recov- e between hich would

od. Thus. important to an accurate

Burbank is

n more than nsive sur-

vcy by Manning rt rrl. I7 The table emphasizes oil recov-

Fig. 47.6-Tertiary polymer flood response from North Burbank

Unit, Osage County, OK.

polymer solution arc being forced through a number of small holes. For this reason. most polymer in,jections are done through openhole or gravel-pack completions. Be- cause flow velocity falls off quickly with distance from an injector. little mechanical degradation occurs within the reservoir itself.

All polymers mechanically degrade under high enough flow rates. However. HPAMs are most susceptible under normal operating conditions. particularly if the salinity or hardness ofthe brine is large. Evidently, the ionic coupling of these anionic molecules is relatively fragile compared with the polysaccharide chains. Also. clonga- tional stress is ar destructive to polymer solutions as is shear stress, although the two generally accompany each other. Maerker and others have correlated permanent viscosity of a polymer solution loss to an elongational stretch rate times length product. 273 On a viscosity/shear-rate plot (purely shear flow), mechanical degradation usually begins at shear rates greater than the minimum-viscosity critical shear rate.

Field Results. Fig. 47.6 shows a tertiary polymer tlooding field response from the North Burbank unit, Osage

TABLE 47.1-POLYMER

Oil recovery, O/o remaining OIP Oil recovery, STB/lbm Oil recovery, STBlacre-ft Permeability variation, fraction Mobile oil saturation, fraction Oil viscosity, cp Resident brine salinity,

g TDSlL Water-to-oil mobility ratio, dimensionless Average polymer concentration, ppm Temperature, OF

Number of Projects*

50 80 88

118 62

153

10

87

93 172 Average permeability, md Average porosity, fraction

187 193 cry data and screening parameters used for polymer flooding. Approximately one-third of the statistics arc from commercial or field-scale floods. The oil recovery statistics in Table 47. I show average polymer tlood recov- cries of 3.56% remaining (after watertlood) oil in place. and 2.69 STB of IOR for each pound of polymer itljcct- cd. with wide variations in both numbers. The large varia- bility reflects the emerging nature of polymer tlooding in the previous decades. Considering the STB IOR per pound of polymer average and the average costs of crude and polymer, it appears that polymer flooding could be a highly attractive EOR process. However. such costs always should be compared on a discounted basis rctlcct- ing the time value of money. which will decrease the apparent attractlvencss of polymer flooding because of the decreased injectivity of the polymer solutions.

Foam Flooding

Gas/liquid foams offer an alternative to polymers for providing mobility control in chemical floods, and have been both proposed and field tested as mobility control agents in steamfloods.

Foams are dispersions of gas bubbles in liquids. Gas/liquid dispersions are normally unstable and usually will break in less than I second. If surfactants are added to the liquid, however, stability is improved greatly so that some foams can persist indefinitely. To understand foam

FLOOD STATISTICS

5.86 0.1 51.8 11.05

339 51 3,700 343 115 46 234 85 349 1.5 7,400 720

Mean Minimum Maximum

3.56 0 25.3 2.69 0 36.5

24.0 0 188.7 0.70 0.06 0.96 0.27 0.03 0.51

36 0.072 1,494

40.4 5.0 133.0

Standard Deviation

5.63 4.86

36.65 0.19 0.12

110.2

33.4 PETROLEUM ENGINEERING

ED 40. I 53000 BARRELS

RODUCTION -

EARS

County, OK. The figure shows WOR andfore and immediately after polymer injectioninjection began in late 1970, which quickly declining oil rate and an increasing WOR. then resumed its prepolymer decline but at aly higher level. The polymer oil or incrementaery (IOR) from a polymer flood is the differencthe cumulative oil actually produced and that whave been produced by a continuing waterflofor a technical analysis of the project it is establish a polymer flood oil rate decline andwaterflood decline rate. The IOR for North the shaded area in Fig. 47.6.

Table 47. I summarizes other field results o250 polymer tloods on the basis of a comprehe0.20 0.07 0.38 0.20

CHEMICAL FLO

propertie rcqutheir classificatiosurfact~nts 3s

Surfxtant Chcomposed of astrong affinit~~~i.e.. strong attmamphtphile (has affinity for both oil and vvater) because

47-7

_ g _ o- No+

I 0

A

iacheofthis dual nature. Fig. 47.7 shows the molecular structure of two common surfactanta (top two panels) and illustrates (lowest panel) a shorthand notation for surfactant monomers: the monomer is represented by a tadpole sy~dx~l with the nonpolar portion being the tail and the polar the head. Surfactants are classified into four groups that depend on their polar portions (see Table 47.1)3.

Anionic.s. As required by electroneutrality. the an ionic aurfactant molecule is uncharged with an inorganic metal cation (usually sodium) associated with the monomer. In an aqueous solution the ~~dx~~le ioniLcs to free cations and the anionic monomer. Anionic surfactants are the most common in EOR because they are good surfactants. rclativelv resistant to retention. stable. and relatively inexpensive.

Cationics. In this case the surfactant ~~dxulc contains a cationic hydrophilc and an inorganic anion to bal- ancc the charpc. Cationic surfactants have little use in EOR bccausc they are adsorbed highly by the anionic surfaces of interstitial clays.

Nonionics. These surfactants do not form ionic bonds, but when dissolved in aqueous solutions. they cx- hibit surfactant properties simply by electronegativity con- trasts betvveen their constituents. Nonionics arc much less sensittve to high salinities than anionics or cationics.

Anzphoterics. A final class of surfactants are those that contain aspects of two or more of the previous classes. For example. an amphoteric may contain both an anionic group and a nonpolar group. These surfactants have not been used in EOR.

Within any one class there is a huge variety of possible surfactants. Fig. 47.7 illustrates differences in Iipophile molecular weight IC t2 for the sodium dodecyl sulfate (SDS) vs. C th for Texas No. I]. hydrophilc identity (sulfate vs. sulfonate), and tail branching (straight chain for SDS vs. two tails for Texas No. 1) all within the same class of anionic surfactants. In addition to these. there are variations in the position ofthe hydrophile attachment and the number of hydrophiles (monosulfonates vs. disul- fonatcs. for example). Even small variations can change surfactant properties drastically (e.g.. sulfates tend to be less thermally stable than sulfonatcs). For details on the

Table 47.2-CLASSIFICATION OF

4-M -eM Anionics Cationics

Sulfonaies Quaternary ammonium AmSulfates Pyridinum Carboxylates lmidazolrnrum OtPhosphates Piperidinium Others Sulfononium Compounds Others COMMERCIAL PETROLEUM SULFONATES

0 I

R-S -O-Nat-

A

R - HYDROCARBON GROUP (non - polar)

Fig. 47.7-Typical surfactant molecular structures

effect of structure on surfactant propertics see Refs. 31 and 32.

Most commercial surfactants contain distributions of surfactants and surfactant types that further add to their complexity. In the following. distinctions between surfactant types are ignored by simply treating the surfactant as the tadpole structure of Fig. 47.7.

Foam Stability. The stability of a foam may be under- stood by viewing the liquid film separating two gas hub- bles in cross section as in the lower panel of Fig. 47.8. ? The hydrophiles of the surfactant are oriented into the interior of the film and the lipophiles toward the bulk gas phase. Suppose that some external force causes the film to thin as in the lower panel. Since capillary pressure is inversely proportional to interfacial curvature. the pressure in the thinned portion of the film is lower than in the ad,iacent flat portion. This causes a pressure differ- cnce within the film. liquid flow. and healing. The pressure in the gas phase is assumed constant because of its relatively low density if the foam is static. or low viscosity if in motion.

SURFACTANTS AND EXAMPLES

-e+ d- mphoterics Nonionics

nocarboxyltc Alkyl- ids Alkyl-aryl rs Acyl

Acylamindo- Acylaminepolyglycol ethers ODING

lrcc wnc ili5cusvon of surtactunts and ns. Moat of the discussion applies to MP well.

emistq. A typical xurfactant monomet- is nonpolar portion (lipophi1c~i.c.. having for oil) and a polar portion (hydrophile- ity for water): the entire monomer is an

SODIUM DODECYL SULFATE

c: c

/ \,/ \cA,i\p\cAo

TEXAS NO.1 SULFONATE Polyol ethers Alkanolamides Others

three permeabilities in Fig. 47.9, but the effect of foam 47-a

SURFACE TENSION

/I----- _ ADSORPTION

/ / /

/ /

/ / I

/ J I

C.Y.C. CONC.

3 Hii

FlllIl

Film 0

Thlnner, Lou adrorptlon, Larger aurfece tencllon, Contractlon

Fig. 47.8-Upper panel shows surface tension and adsorption of a surfactant vs. concentration. Lower panel is the Gibbs-Marangoni effect.

0 km, = 4.41 OMCY

* k,,, * 0.42 DARCY

0 km 0.22 DARCY

\ 0

0.10 !- * A

0 0.01 60

QUA&Y OF F&i, PLRCESOf

Fig. 47.9-Effective permeability-viscosity ratio vs foam quality for consolidated oorous media.

The upper panel in Fig. 47.8 shows that the gas/liquid surface tension is a decreasing function of surface adsorption as required by the Gibbs theory. According to this view the thinned portion of the film will have less specific adsorption (since the surface area is locally greater) and greater surface tension. This locally high surface tension also causes healing.

Clearly. the surface tension at the gas/liquid interfaces play an important role in film stability. Very low surface tension would not be favorable; fortunately gas/liquid surface tensions are rarely lower than 20 dynes/cm even with

0 the best foaming agents. In the absence of external forces. the film is at an equilibrium thickness caused by a bal- ance between the repulsion forces of the electrical dou- PETROLEUM ENGINEERING HANDBOOK

ble layer on the interior of the film boundary and the attractive Van der Waal forces bctwccn the molecules in the film. If the film becomes substantially smaller than the equilibrium thickness. the fret energy barrier between the repulsive and attractive contributions is breached and the film will collapse.

Such thinning can be caused spontaneously by diffusion of the gas from small to large bubbles and by gravity drainage. Patton et al. reported on the rate of spontaneous collapse of a large number of foams as a function of surfactant type. temperature, and pH. tl The half- life of the foam heights reported in their static tests ranges from 1 to about 45 minutes. They report that anionic surfactants have greater stability than nonionics. and that the stability of sulfonate foams is affected greatly by water hardness. Foams were generally more unstable at high temperatures, and many could be stabilized by adding a second surfactant.

External effects that may cause the foam to collapse are the presence of a foam breaker (oil or a high clcctrolyte concentration could do this). local heating. or contact with a hydrophobic surface.

Foam Physical Properties. Physically, foams arc char- acterized by three measures.

Qua&. Foam quality, r, is the percentage of the total (bulk) foam volume that is gas volume. The quality can increase with increasing temperature and decreasing pressure both because the gas volume can increase. and also because gas dissolved in the bulk liquid phase can evolve from solution. Foam qualities can bc quite high, approaching 97% in many cases. A foam with quality greater than 90% is a dry foam.

Texture. This measure is the average bubble size. The texture determines how the foam will flow through a permeable medium. If the average bubble size is larger than the average pore diameter. the foam flow5 as a progression of films separating individual gas bubbles. Given typical foam textures and pore sizes, this condition is most nearly realized in permeable flow. particularly for high foam qualities.

Bubble Size Range. Foams with a large distribution range are more likely to be unstable because of the gas diffusion from large to small bubbles.

Mobility Lowering. Foams can reduce the mobility of a gas phase drastically. Fig. 47.9 shows the steady-state mobility of foams of differing quality in Berea cores at three different permeabilities as a function of quality. On the extreme right of this figure (r- 100%). the mobility should approach the respective air permeability divided by the air viscosity: this mobility is two to three factors of 10 greater than any of the experimental points on the figure. When r-0 the mobility should approach the water permeability divided by CL,, Thus. the mobility of the foam is lower than that of either of its constituents alone. The mobility of the foam decreases with increasing quality until the films between the gas bubbles begin to break and the foam collapses (not shown on Fig. 47.9). Foams are effective in reducing the mobility at all quality is more pronounced at the highest permeability. This is a consequence of the contrast between the tcxturc of the foam and the mean pore size of the mcdium.36

CHEMICAL FLOODING

The mobility reduction caused by the foam can be viewed as an increase in a single-phase viscosity or as a decrease in the gas-phase permeability. Representative data of the second type are in Fig. 47.10, which shows the gas-phase permeability, both with and without foam, and

f as saturation plotted against the liquid injection

rate. - Note that the foam causes a great decrease in gas permeability at the same rate and even at the same gas saturation compared to the nonfoaming displacement. The analogous analysis performed on the aqueous-phase relative permeability shows that neither the gas saturation nor the presence of the foaming agent affects the aqueous- phase relative permeability. j8

The low foam mobilities in permeable media flow are postulated to be caused by at least two different mechanisms: (I) the formation of or the increase in a trapped residual gas phase saturation and (2) a blocking of pore throats caused by the gas films. From Fig. 47.10 the effect of a trapped gas saturation, which would lower the gas mobility through a relative-permeability lowering, is much smaller than the pore-throat-blocking effect. The trapped gas-phase saturation effect may become important. however, during the later stages of a displacement where the lower pressures could cause more gas to come out of solution.

The mobility reduction of foams, viewed as a viscosit enhancement. has been studied in capillary tubes. 38

General observations on these data are that foams are generally shear-thinning fluids whose power law coefficient increases with the capillary tube radius. Using the- oretical arguments based on a Newtonian fluid and an inviscid gas, Hirasaki and Lawson showed that the film thickness of a single moving bubble increases as the bubble velocity to the two-thirds power. 4o Since shear stress in a capillary is inversely proportional to film thickness. the apparent viscosity of a foam in a capillary tube decreases with increasing velocity. Thus, the shear- thinning effect observed in capillary tubes is actually a consequence of the film thickening as velocity increases. A second implication in the Hirasaki-Lawson theory is that foam texture occupies as great an importance in de- termining rheological behavior as does foam quality.

Field Results. Field tests of foam injection alone have been scarce. Holm reports on the injection of an air/brine foam into a single well in the Siggins field. Though there was no measureable oil response, the mobility to both air and brine were reduced significantly, and the injection profile into the central well became more uniform.

Low-IFT Processes In addition to stabilizing gas dispersions, surfactants used in MP flooding or generated in situ can recover oil by lowering oil/water IFT.

Lowering ROS

The basic tool for illustrating how lowering IFT reduces ROS is the capillary desaturation curve (CDC) shown in Fig. 47.1 I. The CDC is a plot of nonwetting- or wetting- phase residual saturation on the y axis vs. a dimcnsion-

less ratio of viscous to local capillary forces on a logarith- mic .Y axis. On Fig. 47.1 I, S,,,.,, is the residual oil (assumed nonwetting), and S,,,. is the irreducible water- (wetting)-phase saturation. The CDC has been calculat- 47-9

l.T Ii iiiiiii iiiiil II:

-?-d---GAS PERYEABILITY k--t+sRI 3

3

0.1 0 I 2 3 4 5 6 7 8 9 IO II 12 13 14

LIQUID INJECTION RATE, BARRELS PER. DAY/ SO. FT.

Fig. 47.10-Effect of liquid flow rate and gas saturation on gas permeability with and without foam

Fig. 47.11--Schematic capillary desaturatjon curves

ed theoretically, 4-w but the most common source of this curve is experimental measurement. . The ratio of viscous to local capillary forces is the capillary number, N,. 1 one form of which is

N,. =N ,, p ,,,/u,,.

flogarithmic .Y axis. a decrease by several factors of IO in N, is necessary IO significantly change either residual phase IFT ccausindyne/cmaurfact

An idealized version of a MP flooding sequence is in ry im- ff).

nge ent the

size ses sur- . in

ent. I al- are

f a MP ch

gn-

in- of ck. saturation. Ofthc three quantities in Eq. 8 only the an be changed this drastically; a typical value for g good ROS reduction is in the range of IO

. a value that can be obtained only with a good ant.

Fig. 47.12. The process is applied invariably to tertiafloods (those producing at high WORs) and is always plemented in the drive mode (not cyclic or huff n puThe complete process consists of the following.

Prejlush. A volume of brine whose purpose is to cha(usually lower) the salinity and hardness of the residbrine so that mixing with the surfactant will not cause loss of interfacial activity. Pretlushcs have ranged in from 0 to 100% of the reservoir PV. In some procesa sacrificial agent is added to lessen the subsequent factant retention and also to precipitate divalent cation

MP Slug. This volume. ranging from 5 to 40% PVfield applications. contains the main oil-recovering agthe prituut:\~ surfactant, in concentrations ranging fromto 20 ~0170. Several other chemicals (cosurfactants. cohols. oil. polymer. biocide, and oxygen scavcnger) usually necessary for good oil recovery.

LJ40~i~i~ Buffeer. This fluid is a dilute solution owater-soluble polymer whose purpose is to drive the \lug and banked-up fluids to the production wells. Muof polymer flooding technology carries over to dcsiing and implcmcnting the mobility buffer.-18

Freshwater Buffer. This i\ a volume of brine containg a concentration of polymer grading between thatthe mobility buffer at the front end and zero at the ba47-10

Fig. 47.12-Schematic o

originally trapped phase occurs. The shape of the CDC is determined by the pore geometry of the medium and the wetting behavior of the two phases. The wetting phase rcquircs a larger N,. for complete recovery. To a lesser extent. the CDC shape is affected by the mean pore size and pore size distribution of the medium. and the initial saturations. Typical N, s for watertlooding are quite small. which indicates that ROS and S,,, may be assumed constant for this purpose (XC Fig. 47. I I). Because of the Fig. 47.13-Schematic of the CMC PETROLEUM ENGINEERING HANDBI 30K

an MP flooding process.

IMP Flooding

MP flooding has appeared in the technical literature under many names: detergent. surfactant, low-tension. soluble oil. microemulsion. and chemical flooding. There are also several company names that imply a specific sequence and type of injected fluids as well as the specific nature of the oil-recovering MP slug itself. Though there are differences among company processes. the common aspects are more numerous and important. The gradual concentration decrease mitigates the effect of the unfavorable mobility ratio between the chase water and mobility buffer.

CHEMICAL FLOODING

Chase Water. The purpose of the chase water is sirn- ply to reduce the expense of continually injecting polymer. If the mobility and freshwater buffers have been designed properly. the MP slug will be dcplcted before it is penetrated,by the chase water.

Surfactant Solutions. If an anionic surfactant is dissolved in brine, the surfactant disassociates into a cation and a monomer. If the surfactant concentration then is increased, the lipophilic portions of the surfactant begin to associate among themselves to form aggregates or micelIes containing several monomers each. A plot of surfactant monomer concentration vs. total surfactant concentration (Fig. 47.13) is a curve that begins at the origin, increases with unit slope, then levels off at the critical micelle concentration (CMC). Above the CMC all further increases in surfactant concentration cause increases only in the micelle concentration. CMCs are typically quite small (about 10 - to IO p4 mol/L). At nearly all practical concentrations for MP flooding the surfactant is predominantly in the micellc form; hence. the name micellar/polymer flooding. The representations of the micelles in Fig. 47.13 and elsewhere are schematic. The actual micelle structures can take on various forms, which can fluctuate with time.

When this solution contacts an oleic phase (the term olcic indicates that this phase can contain more than oil) the surfactant tends to accumulate at the intervening interface. The lipophilic tail dissolves in the oleic phase, and the hydrophilic in the aqueous phase. The accumula- tion at the intcrfacc causes the IFT between the two phases to lower. The extent of the IFT lowering is proportional to the cxccss surface concentration of the surf;lctant-the difference between the surface and bulk surfactant concentration-from Gibbs theory. as was the case in Fig. 47.X. The surfactant itself and the attending conditions should bc adjusted to maximize the excess surface concent]-ation; however, in doing so the solubility of the surtactant in the bulk oleic and aqueous phases also is affected. Since this solubility also impinges on the mutu- al volubility of brine and oil, which also affects IFTs, this discussion leads naturally to the topic of surfactanti brine/oil phase behavior. Curiously, and this is true of many micellar properties. the surfactant concentration itself plays a rather minor role in what follows, compared with the temperature. brine salinity, and hardness.

SurfactantlBrineiOil Phase Behavior. Surfactanti hrinc/oil phase behavior is illustrated conventionally on a ternary diagram. A ternary diagram is an equilateral triangle whose apexes represent pure components. bound- arlcs represent two-component mixtures, and interior represents three-component mixtures. For complicated mixtures the three apexes must represent pseudocom- poncnts whose composition remains constant throughout the diagram. The pressure and temperature are also fixed. The diagram can represent both the overall composition of a surfactantibrineioil mixture. and the equilibrium composition of each phase if the mixture forms more than one phase. Tcrnarica and their accompanying definitions are discussed in Chap. 23.

MP phase behavior is affected strongly by the salinity

of the brine pseudocomponent. Consider the sequence of phase diagrams (Figs. 47.14 through 47.16) as the brine salinity is incrcaxcd. The phase behavior about to bc dc- 1 _(

I S WA TEf? EXTERNAL

A

EXCESS hffCROE~LS/ON 011

I

47-11

OVERALL 0 COMPOSITtW

Fig. 47.14-Schematic of low-salinity surfactantlbrineioil phase behavior.

scribed was presented originally by Winsor and adapted to MP flooding later.50.5

At low brine salinity, a typical MP surfactant will exhibit good aqueous (water-rich) phase solubility and poor oleic (oil-rich) phase solubility. Thus, an overall composition near the brine/oil boundary of the ternary will split into two phases: an e,xcess oil phase that is essentially pure oil and a (water-external) rnicroemulsio~~ phase that contains brine surfactant, and some solubilized oil. The solubilized oil occurs when globules of oil occupy the central core of the swollen micelles. The tie lines within the two- phase region have a negative slope. This type of phase environment is called variously a Winsor Type I system. a lower-phase microemulsion (because it is more dense than the excess oil phase), or a Type II system. The latter terminology is adopted here-11 means that no more than two phases can (not necessarily will) form and (-) means that the tie lines have negative slope (Fig. 47.14). The right plait point in such a system. PK. usually is lo- cated quite close to the oil apex. Any overall composition above the binodal curve is single phase.

For high brine salinities (Fig. 47. IS) electrostatic forces

drastically decrease the surfactants solubility in the aqueous phase. An overall composition within the two-phase Iregion now will split into an UUJ,S.\ hr-i/~c phase and an

47-12

SWOLLEN MICELLE

-

Na+ Na+

NO+

COMPOSITION

Fig. 47.15-Schematic of surfactant/brine/oil high-salinity phase behavior.

(oil-external) microemulsion phase, which contains most of the surfactant and some solubilized brine. The brine is solubilized through the formation of inverted swollen micelles (Fig. 47.15) with brine globules at their cores. The phase environment is a Winsor Type II system, an upper-phase microemulsion, or a Type II( +) system. The plait point, PI,. is now close to the brine apex.

The two extremes presented thus far are roughly mir- ror images; note that the microemulsion phase is water- continuous in the Type II( -) systems and oil-continuous in Type II(+) systems. The induced solubility of oil in a brine-rich phase, Type II( -). suggests an extraction mechanism in oil recovery. Though extraction does play some role. it is dwarfed by the IFT effect discussed later. particularly when phase behavior at intermediate salini- tics is considered.

At salinities between those of Figs. 47. I4 and 47.15. there is a continuous change between Type II( -) and II( +) systems and a third surfactant-rich phase is formed. as shown in Fig. 47.16. An overall composition within the three-phase region separates into excess oil and brine

phases as in the Type II(-) and II( +) environments. and into a microemulsion phase whose composition is represented by an ;U~U~;LUU point. This environment is called PETROLEUM ENGINEERING HANDBOOK

COMPOSITION

Fig. 47.16-Schematic of surfactant/brine/od phase behavior at optimal salinity.

a Windsor Type III, a middle-phase microemulsion. or a Type III system. Above and to the right and left of the three-phase region are Type II( -) and II( +) lobes wherein two phases will form as before. Below the three-phase region there is a third two-phase region (as required by thermodynamics) whose extent is usually so small that it is neglected. In the three-phase region there are now two IFTs between the microemulsion and oil, a,,,,, , and the microemulsion and water, u,~~,,..

Fig. 47.17, a prism diagram, shows the entire progression of phase environments from Type II( -) to II( +). The Type III region forms through the splitting of a critical tie line that lies close to the brine/oil boundary as the salinity increases to C,, (low effective salinity limit for Type III phase environment). 53 A second critical tie line also splits at C,, (high effective salinity limit for Type III phase environment) as salinity is decreased from a Type II( +) environment. Over the Type III salinity range the invariant point, M, migrates from near the oil apex to near the brine apex before disappearing at the appropriate critical tie lines. The migration of the invariant point implies

essentially unlimited solubility of brine and oil in a single phase, which has generated an Intense research interest into the nature of the Type III microemulsion.

I. At high surfactant concentrations and/or at low tempetants L 3observcrystaare deviscoulow- are adble videnseconcethe melimina

2. approtant anot pment surfacEffortscosurftation

3.

lent ratios also will cause electrolyte interactions with clay nate for by

ivalcnt in Fig.

rature es of

low. 6x entra- poly- surely

tech- with

posed antiat- sever-

on is can be asure- raturess.59 or even in the presence of pure surfac- 6. phases other than those on Fig. 47.17 have been ed. These phases tend to be high-viscosity liquid

ls or other condensed phases. The large viscosities trimental to oil recovery since they can cause local s instabilities during a displacement. Frequently, to medium-molecular-weight alcohols (cosolvents) ded to MP formulations to melt these undesira-

scosities. When the brine contains polymer. a con- d phase can be observed at low surfactant ntration because of exclusion of the polymer from icroemulsion phase. Cosurfactants can be used to te this polymerisurfactant incompatibility. When cosurfactants are present it is frequently in- priate to lump all of the chemicals into the surfac- pex of the Fig. 47.17 prism. If the cosurfactants do

artition with the primary surfactant during a displace- the benefit of adding the chemical is lost; hence.

tanticosurfactant separation effects are important. to account for the preferential partitioning of the

minerals through cation exchange. The disproportioeffects of the salinity and hardness are accounted defining a weighted sum of the monovalent and dconcentrations as an effective salinity. The C,.s 47. I7 imply effective salinities.

Phase Behavior and IFT. Early MP flooding litecontains considerable information about the techniqumeasuring IFTs and what causes them to be IFTs were found to vary with the types and conction of surfactant, cosurfactant, electrolyte, oil, andmer and with temperature. However, in what was one of the most significant advances in all of MPnology, all IFTs were shown to correlate directly the MP phase behavior. The correlation was prooriginally by Healy and Reed, theoretically substed by Huh, 6y and since verified experimentally by al others. I. The practical benefit of this correlatithat relatively difficult measurements of IFTs largely supplanted by simple phase behavior meCHEMICAL FLOODING

Fig. 47.17-Prism diagram showing se

Several variables other than salinity can bring about the Fig. 47.17 phase environment shifts. In general, chang- ing any condition that enhances the surfactants oil solubility will cause the shift from Type Il( -) to II( +). Some of the more important are: (1) decreasing temperature, 5 (2) increasing surfactant molecular weight, (3) decreasing tail branching, (4) decreasing oil specific gravity55-57 and (5) increasing concentration of high- molecular-weight alcohols. 58 Decreasing the surfactants oil solubility will cause the reverse change. Thus, Fig. 47.17 could be redrawn with any of the above variables (and several others) on the base of the prism with the variable C,, (effective salinity) increasing in the direction of increased oil solubility.

Nonideal Effects. In much the same manner as the ideal gas law approximates the behavior of real gases, Fig. 47. I7 is an approximation to actual MP phase behavior. Some of the more important nonidealities are as follows. actant include a quaternary phase behavior represen- and a pseudophase theory. 62.63

The Type III salinity limits (C,, and C,,) are func- quence of phase environment transition.

tions of surfactant concentration. This dependency may be visualized by tilting the vertical triangular planes in Fig. 47.17 about their bases. This dilution effecth.h5 forms the basis for the salinity requirement diagram design procedure. UJ The dilution effect is particularly pronounced when the brine contains significant quantities of divalent ions.

4. The Fig. 47.17 phase-behavior shifts are specific to the exact ionic composition of the brine. not simply to the total salinity. For anionic surfactants. other anions in solution have little effect on the MP phase behavior: however. cations readily cause phase-environment changes. Divalent cations (calcium and magnesium are the most

common) are usually 5 to 20 times as potent as monovalent cations (usually sodium). Divalents arc usually present in oilfield brines in smaller quantities than monovalents as shown in Fig. 47.2, but their effect is so pronounced that it is necessary, as a minimum. to separately account for salinity and hardness. Nonconstant monovalentidiva- ments. Indeed, in the recent literature, the behavior of IFTs has been inferred by a narrower subset of phase- behavior studies based on the solubilization parameter. hs

Fig. 47.18--Correlation of solubilization ratios with IFT.

1 4 1 1 I 1 1 I I 1 I L I I 1 I 0 0.4 0.6 1.2 I.6 2.0 2.4 2 .a 3.2

SALINITY, /o NoCI

Fig. 47.19-IFT and solubilization ratios PETROLEUM ENGINEERING HANDBOOK

To investigate further the relation between IFTs and phase behavior, let V,,, V,, , and V, be the volume frac- tions of oil, brine. and surfactant in the microemulsion phase, respectively. According to Figs. 47. I4 through 47.16, the microemulsion phase is present at all salinities: hence. all three quantities are well-defined and continuous. Considering the Type II( -) behavior of Fig. 47.14, for example, V,,, V,,., and V,, are the coordinates of the microemulsion phase composition on the binodal curve.

Solubilization parameters between the microemulsion- oleic phases, F,,,, , for Type II( -) and III phase behavior. and between the microemulsion-aqueous phases. F,,,,,.. for Type II( +) and III are defined as

F,,,,,=V,,iV, . . . . . . . . . . . . . . . . . . . . . . . . . . . ..(9a)

and

F,,,,,.=l,,./l,. . . . . (9b)

The IFTs between the corresponding phases, u,,,(, and u ,?lMr are functions only of F,,, and F ,,,, ~. Fig. 47.18 shows a typical correlation.

The corresponding behavior of the solubilization parameters and IFTs are shown in Fig. 47.19 in a different manner. Consider a locus at constant oil, brine, and surfactant overall concentrations in Fig. 47. I7 but with a variable salinity. If the nonideal effects are unimpor- tant and the locus is at low surfactant concentration and intermediate brine/oil ratios, (T,~(, will be defined from low salinity up to C,,, and uInM. from C,,, to high salinities. Both IFTs are the lowest in the three-phase Type III region, between C,, and C,,, where both solubilization parameters are also large. There is, further, a pre- cise salinity where both IFTs are equal at values low enough ( - 10 -3 dyne/cm) for good oil recovery. This salinity is the optimal saliniv for this particular surfactant/brine/oil combination and the common IFT is the optimal IFT. Optimal salinities have been defined on the basis of equal IFTs, as in Fig. 47.19, equal solubilization parameters, maximum oil recovery in corefloods, and equal contact angles. 50*71~72 All definitions of optima1 salinity give roughly the same value; hence, since optimal phase behavior salinity is the same as maximum oil recovery salinity, generating an interfacially active MP slug translates into generating this optimal salinity in situ in the presence of the surfactant material.

Generating Optimal Conditions. Historically there have been three techniques for generating optimal conditions in an MP displacement.

I. The MP systems optimal salinity can be raised to that of the resident brine salinity in the candidate reservoir. This procedure philosophically is the most satisfy- ing of the three design procedures given here and usually the most difficult. Though it has been the sub.ject of in- tensive research, surfactants that have high optimal salinities that are not (at the same time) thermally unstable at reservoir conditions, excessively retained by the solid

surfaces, or expensive have not yet been discovered. Field successes with synthetic surfactants have demonstrated the technical feasibility of this approach. however. 73 A scc-

npretlush could be accomplished during the watertlood prece

3. ly lodisplaoverobuffeon itbe ingradimot crv vanraunccthe pand ctfcc

Surfone

I, monoinp aand higheclt~dc

with abov

reservoir clays just as inorganic cations do.

- )

s t -

- ding the MP flood. The salinity gradient design attempts to dynamical-

wer the resident salinity to an optimum during the cement by sandvviching the MP slug between the ptimal rcsidcnt brine and an underoptimal mobility- r salinity. hh.67 The \ucccss of this procedure relies being necessary that only a portion of the MP slug the active region for good oil rccovcry. For salinity ent tlonds the salinity of the mobility buffer is the

signiticant factor in bringing about good oil rccov x The salinity gradient design has several other ad- zes in being rcstlient to design and process

rtaintics. in providing a favorable cnv~ironmcnt for olymer in the mobility buffer. minimizing retention. being relatively indifferent to the surfactant dilution t.

actant Retention. Surfactants are retained through of at least four mechanisms. On metal oxide surfaces (Fig. 47.20) the surfactant mer will adsorb physically through hydrogen hond- nd micelle-like associations with the monomer tails. ionically bond vvith cationic surface sites (I). At

4. In the presence of oil in a II( +) phase environment the aurfactant will reside in the oil-external microemulsion phase. Because this region is above the optimal salinity, the IFT is relatively large (Fig. 47.18) and thisphase and its dissolved surfactant can be trapped. Asimilar phase trapping effect does not occur in the II( - environment because the aqueous mobility buffer misci-bly displaces the trapped aqueous-external microemulsion phase without permanent retention.

Most studies of surfactant retention have not made thepreviously mentioned mechanistic distinctions; thercforc, which mechanism predominates in a given application inot obvious. All mechanisms retain more surfactant ahigh salinity and hardness, which, in turn. can be attenu-ated by adding cosurfactants. Precipitation and phase trappin,g,can be eliminated by lowering the mobility buffersalimty, at which conditions the chemical adsorption mechanism on the reservoir clays is predominant. There-fore. there should be some correlation of surfactant rctcn-tion with reservoir clay content. Fig. 47.2 I is an attemptto make this correlation by plotting laborator

2 and field

surfactant retention data against clay fraction. ) The correlation is by no means perfect since it ignores variations CHEMICAL FLOODING

Fig. 47.20-Schematic of surfacta

ond way to make the optimal salinity of the MP formulation equal to the resident brine salinity is to add cosurfactant.

2. Resident salinity of a candidate reservoir can be lowered to match the MP slugs optimal salinity. This is the main purpose of the pretlush step illustrated in Fig. 37.12. A successful pretlush is appealing because. with the resident salmtty lowered. the MP slug would displace oil wherever it goes in the reservoir. Preflushes generally require quite large volumes to lower the resident SB- linity significantly owing to mixing effects and cation exchange. 7.75 With some planning, the function of the r surtactant concentrations. C,. this association in- ?~ tail-to-tail interactions with the solution monomers

proportionally greater adsorption (II and Ill). At and e the CMC (IV), the supply of monomers bccomcs 47-15

t adsorption on metal oxide surface

constant as does the retention (c, is the adsorbed surfactant concentration).

2. In hard brines the prevalence of divalent cations causes the formation of surfactantidivalent complexes, which have a low solubility in brine. * Precipitation of this surfactantidivalent complex will lead to retention. When oil is present this effect is lessened by the surfac- tams solubility in the oleic phase.

3. At hardness levels somewhat lower than those required for precipitation, the preferred multivalentisurfac- tmt complex will be a monovalent cation that can exchange chemically with cations originally bound to the in MP formulation and clay type distribution as well as salinity effects. HowevJer. the figure does capture a general trend that is useful for a first-order estimate of retention in a given reservoir.

47-16

or weak correlation. X3 The strong correlation in Fig. 0 LAB DATA 0 FIELD DATA

WEIQHT FRACTION CLAYS

Fig. 47.21-Surfactant retention and weight fraction of clays.

Fig. 47.22-MP production response from Well 12-l. Bell Creek Pilot

Et? 0.6

0.4 h

0.2

0 0 0.2-0:4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2 0. 3.2

MOBILITY BUFFER SIZE ( VM~ 1

Recovery Efficiency vs. Mobility Buffer Size

Fig. 47.23--Recovery efficiencies from 21 MP field tests PETROLEUM ENGINEERING HANDBOOK

A useful way to estimate the volume of surfactant required for an MP slug is through the dimensionless frontal advance lag, FL).

1-o Pr c FD=p----,

4 P,C, (10)

where FD = frontal advance lag, dimensionless, p,. = density of rock, mass/volume rock,

p\- = density of surfactant slug, mass/volume

solution,

C, = concentration of surfactant, mass

surfactantimass solution, and

6, = retained surfactant concentration, mass

surfactant/mass rock (includes all forms

of surfactants).

F expresses the volume of surfactant retained at its injected concentration as a fraction of the PV. For best surfactant usage, the volume of surfactant injected should be large enough to contact all of the PV, but small enough to prevent excessive production of the surfactant. There- fore, the MP slug size, V,I,v, should be equal to or somewhat larger than FD.

Field Response. Fig. 47.22 shows the produced fluid analyses of Well 12- 1 in the Bell Creek (Carter and Pow- der River Counties, MT) MP flood. This tlood used a high oil content MP slug preceded by a pretlush that con- tained sodium silicate to lessen surfactant retention and reduce divalent cation concentration. Well 12-l was a producer in the center of a unconfined single 40-acre, five- spot pattern. Further details on the tlood are available in Refs. 47 and 82.

Before MP slug injection in Feb. 1979, Well 12-l was experiencing low and declining oil cuts. MP oil response beginning in late 1980 is superimposed on this decline, reaching peak cuts of about 13% about 6 months later. Note that. just as in polymer flooding, the pre-MP decline must be clearly established for accurate evaluation of the MP oil recovery. The surfactant is preceding the oil in Fig. 47.22 because of an excessively large content of water-soluble, inactive disulfonate in the MP slug. Simul- taneous oil and surfactant production is a persistent feature of field MP floods, probably because of heterogeneities and dispersive mixing. Other significant features in Fig. 47.22 are the evident presence of the pretlush preceding the MP slug, inferred from the maxima in the pH and silicate concentrations. and the very efficient removal of the calcium cations ahead of the surfactant.

Fig. 47.23 shows oil recovery efficiency, EK (incremental oil recovered/OIP at start of MP process), from a survey of more than 40 MP field tests correlated as a function of mobility-buffer slug size. As of the date of the survey there were no commercial projects reported. Similar analyses on other process variables showed no 47.23 indicates the importance of mobility control in MP design. Note also from this figure that ultimate oil recovery efficiency averages about 30% in field tests.

CHEMICAL FLOODING

Performance Prediction. Generally. three things must be achieved for efficient oil recovery. X4 ( I ) the MP surfactant slug must be propagated in an interfacially active mode, (2) enough surfactant must be injected so that some of it is unretained by the permeable media surfaces, and (3) the MP displacement must be designed so that the active surfactant sweeps a large portion of the reservoir without excessive dissipation (because of dispersion) or channeling.

Attaining the first goal is the result of formulation work based on the phase-behavior concepts discussed previously. The extent to which the second and third goals are satisfied depends on prevailing economics, which, in turn, depends on the oil-recovering ability of the entire process. The next few paragraphs describe a simple procedure by which oil recovery and oil rate-time curves may be estimated for an interfacially active MP process. Since there are innumerable ways in which interfacial activity may be lost. the procedure is most accurate for processes that clearly satisfy the first design goal.

Recovery Efficiency. This procedure has two steps: es- timating the recovery efficiency of an MP flood and then proportioning this recovery according to in.jectivity and fractional flow to give an oil rate-time curve. Space con- siderations will limit many of the details, which may be found in Ref. 80.

The recovery efficiency. ER, of an MP flood is the product of a volumetric sweep efficiency, E. a displacement efficiency. En, and a mobility buffer efficiency. E MB

ER=EDEVEMB, . . . (11)

Each quantity must be calculated independently. Displacement Efficiency. The displacement efficien-

cy of an MP flood is the ultimate (time-independent) volume of oil displaced divided by the volume of oil contacted.

S,, ED=1 -p, . .(l2)

S OM

where S,,, and S,,. are the ROS to an MP and waterflood, respectively. S,,,,. must be known, but S,,, can be obtained from a large slug (free from the effects of surfactant retention) laboratory coreflood. Low values of Sor indicate successful attainment of good interfacial activity in the MP slug. If coreflood results arent availa-

ble, S,, may be estimated from a CDC by using a field capillary number.

N,=0.565q~L,,y,~l(h~), .._.. ..(13)

where N,. = capillary number, dimensionless,

q = injection/production rate, CL 0 = oil viscosity,

h = net thickness, and

A = pattern area. Eq. 13 is in consistent units. For screening purposes, as- sume a controlling IFT of lop3 dyne/cm [ 1 pN/m]; the CDC curve chosen to estimate S ,,r should be consistent, 47-17

Fig. 47.24-Relationship between MP volumetric sweep efficiency, heterogeneity, and slug-size retention ratio.

as much as possible, with conditions of the candidate reservoir.

Volumetric Sweep Efficiency. Volumetric sweep efficiency, E v, is the volume of oil contacted divided by the volume of target oil. EV is a function of MP slug size, V ,,, , retention, FD, and heterogeneity based on the Dykstra-Parsons coefficient, KDP. Fig. 47.24 shows this relationship. KDP may be estimated from geologic study, from matching the previous waterflood, or from core data (a typical value would be 0.6). The FD is estimated from Eq. IO on the basis of the retention level, C,, . surfactant slug concentration, C,, porosity, and rock and fluid den- sities. C, can come from a laboratory coreflood, Fig. 47.21 (if clay fraction is known), or by using C, =0.4 mglg as a default. L,,s and C,, are from the proposed design.

MoKlity Buffeer Efficiency. The mobility buffer efficiency, EBB, is a function of EV and KDP.

E,+,Be=0.71-0.6KDP, . . (l4a)

where EMBr is the mobility buffer efficiency extrapolated to VM~ =0 and VM~ is the mobility buffer volume, fraction V,,. Eq. 14a was obtained from a numerical simu- lation.

The recovery efficiency now may be calculated from Eqs. 1 I through l4a. The reasonableness of the value may be checked with Fig. 47.23.

Calculation of q,, vs. t Plot. The production function (oil rate vs. time) is based on ER and the following procedure. The dimensionless production function is assumed to be triangular with oil production beginning at oil bank arrival time, increasing linearly to a peak (maximum) oil cut when the surfactant breaks through, and decreasing linearly to sweepout time. The triangular shape is imposed by the reservoir heterogeneity.

The first step is to calculate the dimensionless oil bank and surfactant breakthrough times for a homogeneous laboratory coreflood. (14b)

II I I b I J 0 100 roe 300 400 500 WO 700

TIME. DAYS

Fig. 47.25-Comparison between predicted and observed oil rate-ttme responses for the Sloss MP pilot.

t~,=l+F,-S,,,. , _. __ (14c)

where

t Lhh = oil bank arrival time, dimensionless.

s ,,,, = oil bank saturation, fraction,

S,,, = initial oil saturation, fraction,

fr,,, = oil bank oil fractional flow. fraction.

f,,, = initial oil fractional flow, fraction. and

tLl\ = surfactant arrival time, dimensionless.

S,,h andf,,,, may be estimated from the oil/water relative permeability curve as described previously in Refs. 80 and 85. or from laboratory experiment.

The second step is to correct these values for the heterogeneity of the candidate reservoir by using an effective mobility ratio. M,. where

(1%

The corrected breakthrough times are now

ttDoh =tDot,lMe . (16a)

and tD,=tDs/Mc. (16b)

where tD(,,, is the corrected oil bank arrival time, dimensionless, tlDr is the corrected surfactant arrival time. PETROLEUM ENGINEERING HANDBOOK

dimensionloss. and the peak oil cut. ,f&. i,

M,,-M,, tl)r,h c > ! ? .fy,n = tl)1

of,,--I) ,f;,,, (17)

The final step is to convert the dimensionless production function to oil rate, yo. vs. time. t. This follows from

q,,=qf;, ---- (l&i)

and

t=V,,tD/q, . .(18b)

wheref,, is the oil cut. tD is the dimensionless time. and .f;, and tn are any points on the triangular oil recovery curve, which begins at (t,,/, ,f;,;). peaks at (tljA .f;,,,k). and ends at (tn,t., 0). The dimensionless time at complete sweepout, tD,,,,., is selected to make the arca under thef;, -tlD curve equal to ER,

tD,,l.=tnoh +2E,$,,,.,,Jf;,,,,, (19)

A comparison of the results of this procedure with the Sloss field MP pilot is in Fig. 47.25. Details of this match and other matches are in the original references.

High-pH Processes The final chemical flooding EOR process is high-pH flooding (Fig. 47.26). As in polymer and MP flooding. there is usually a brine preflush to precondition the reservoir, a finite volume of the oil-displacing chemical, a graded mobility buffer driving agent. and the entire process is driven by chase water. Moreover. for both high- pH and MP flooding the oil-displacing chemical is a surfactant; however, for MP flooding the surfactant is injected while in high-pH flooding it is generated in situ.

High-pH Chemistry

High pHs indicate large concentrations of the hydroxide anions (OH -). The pH of an ideal aqueous solution is defined as

pH= -log ioc, + , . . (20)

where the concentration of hydrogen ions, CH + , is in mol/L. As the concentration of OH - is increased, the concentration of Hi decreases, since the two concentrations are related through the dissociation of water,

K,,, = ( OH-)(CH+)

, . . . . . . . . . . . . CH~O

(21)

and the water concentration is nearly constant. These con- siderations suggest two means for introducing high pHs into a reservoir: dissociation of a hydroxyl-containing species or adding chemicals that preferentially bind hydrogen ions. Many chemicals could be used to generate high pH. but the most commonly used are sodium hydroxide (caustic, NaOH). sodium orthosilicate. and sodium carbonate (Na2C03). NaOH generates OH by dissociation: the

hOH by itself is not a surfactant. since the absence of a lipophilic tail makes it exclusively water-soluble. If the crudeHA,,. phase

HA

The edepenions tion factanmost

If tle sucharafloodinis theto nement,specieHA,, the Kof ac(CO?an acas low

ies, the distinction among effects becomes important in

3 oil contains an acidic hydrocarbon component, some of this, HA,,., can partition to the aqueous

where it can react. Xh

,,F-?A,;+H+. _. __ . e-4

xact nature of HA,, is unknown and probably highly dent on crude oil type. The deficiency of hydrogen in the aqueous phase will cause the extent of this reac- to be to the right. The anionic species A,; is a sur- t that can have many of the properties and enter into of the phenomena described above for MP flooding.

there is no HA,, originally present in the crude. lit- rfactant can be generated. A useful procedure for

cterizing crudes for their attractiveness to high-pH g is through the acid number. The acid number

milligrams of potassium hydroxide (KOH) required utralize I gram of crude oil. To make this measure- the crude is extracted with water until the acldlc s HA is removed. The aqueous phase containing , A,;, and H is then brought to pH=7 by adding

OH. For a meaningful value, the crude must be free idic additives (e.g.. scale inhibitor) and acidic gases

high-pH flooding.

0 I 2 3 4 CHEMICAL FLOODING

Fig. 47.26-Schematic of

latter two through the formation of weakly dissociating acids (silicic and carbonic acid, respectively) that remove free H ions from solution. High-pH chemicals generally have been used in field applications in concentrations ranging up to 5 wt% (in.jected pHs of 1 I to 13) and with slug sizes up to 2O%PV. The resulting amounts of chemicals are quite comparable with the surfactant usage in MP flooding: however, high-pH chemicals are substantially less costly. This cost advantage must be discounted by the historically lower oil recoveries in high-pH flooding. or H?S). A good high-pH flooding crude will have id number of 0.5 mgig or greater. but acid numbers as 0.2 mgig may be candidates, since only a small 47-19

igh-pH flooding process

amount of surfactant is required to saturate oil/brine interfaces. Fig. 47.27 presents a histogram of acid numbers based on the work of Jennings.87.8x

Displacement Mechanisms

Oil recovery mechanisms in high-pH flooding have been attributed to eight separate phenomena. 89 This chapter concentrates on only three: IFT lowering. wettability reversal, and emulsion formation. The last two mechanisms also are present in MP flooding but are dwarfed by the low-IFT effect. With smaller ultimate oil recover- ACID INDEX INTERWL (E&Cl4 05mp. KOH/p RAffiE)

Fig. 47.27-Histogram of acid numbers

47-20

1 M 0.26 wt. 46 NaCI M 0.50 wt. % NaCI A 1.00 wt. 16 N&I

IO

SOLUSILIZATION

Y

I- \\ \\

z lOOr

\\ \\

E

\:

a

t

lo- -

IO- IO- IO-

WEIGHT % NaOH IC

Fig. 47.28-IFTs for caustic/crude/brine systems

The generated surfactant, A ,, aggregates at oil/water interfaces, which can lower IFT. 86 In general, such lowering is not as pronounced as in MP flooding but, under certain conditions, can be large enough to produce good oil recovery. Fig. 47.28 shows IFT measurements of caustic solutions against Long Beach crude oil at various brine salinities. The IFTs are sensitive to both NaOH concentration and salinity, showing minima in the NaOH concentration range of 0.01 to 0.1 wt %. The decrease in IFT in these experiments is limited by the spontaneous emulsification of the oil/water mixture when the IFT reaches a minimum.

There are many similarities in the low-IFT effects in MP and high-pH flooding. The data in Fig. 47.28 show a clear resemblance to the data in the upper plot of Fig. 47.19 except they are plotted vs. NaOH concentration (presumed proportional to A, concentration) instead of salinity. This suggests an optimal salinity of about I .O wt% NaCl for a 0.03 wt% NaOH solution. Indeed, the work of Jennings et al. 87 has shown that there is an optimal NaOH concentration for a given salinity in oil recovery experiments. Moreover, the presence of the emulsification effect when IFTs are low is exactly what one would expect from Fig. 47.17 at a surfactant concentration above the invariant point surfactant concentration. This suggests that the data in Fig. 47.28 showing a Type II( -) phase environment at low NaOH concentrations are Type II(+) at high (similar to what would be expected from the dilution effect in MP flooding). Fur-

ther work is necessary to establish the connection to MP phase-behavior definitively, since the actual surfactant concentration A; is likely to be much lower in a high- PETROLEUM ENGINEERING HANDBOOK

pH system. However, Nelson PI a!. )( show that a cosurfactant can increase the optimal salinity in a high-pH system much like in MP systems.

See Chap. 28 for a discussion of wettability and its effects on petrophysical properties. Owens and Archery showed that increasing the water wetness increased ultimate oil recovery, where the wettability was reported as decreasing the water/oil contact angle measured on polished synthetic surfaces. This has also been shown by others using high-pH chemicals.9.YX The increased oil recovery is the result of two mechanisms: a relative permeability effect, which causes the mobility ratio of a displacement to decrease, and a shifting of the CDC (see Fig. 47.1 I).

Cooke et al. 94 have reported improved oil recovery with increased oil wetness. Other data show that oil recovery is a maximum when the wettability of a permeable medium is neither strongly water- nor oil-wet. )5 Given the latter information, the important factor may be the change in the wettability rather than the actual wettability of the final state of the medium. In the original wetting state of the medium, the nonwetting phase occupies large pores and the wetting phase small pores. If the wettability of a medium is reversed, there will be nonwetting fluid in small pores and wetting fluid in large pores. The resulting fluid redistribution, as the phases attempt to return to their natural state, would make both phases vulnerable to recovery through viscous forces.

High-pH chemicals can cause improved oil recovery through the formation of emulsions. The emulsification produces additional oil in at least two ways: through a mobility ratio lowering since many of these emulsions have a substantially increased viscosity and through solubilization and entrainment of oil in a flowing aqueous stream. The first mechanism improves displacement and volumetric sweep as do the mobility control agents discussed previously. Local formation of highly viscous emulsions should be discouraged, however, as these would promote viscous fingering from the less viscous oil-free high-pH solution. The solubilization and entrainment mechanism would be more important when the IFT between the swollen water phase and the remaining crude is low. Fig. 47.28 shows that for certain conditions, emulsification and low IFTs occur simultaneously. McAuliffe showed that emulsions injected in a core and those formed in situ give comparable oil recoveries.96.97

Rock/Fluid Interactions

Interactions of the high-pH chemicals and the permeable media minerals can cause excessive retardation in the propagation of these chemicals throughout the permeable medium. This chapter discusses three aspects of rock- fluid interactions: formation of divalent/hydroxide compounds, cation exchange, and mineral dissolution.

OH - ions themselves are not appreciably bound to the solid surfaces; however, in the presence of multivalent cations they can form hydroxyl compounds,

M +-+x(OH -)FiM(OH),,, (23) which, being relatively insoluble, can precipitate from solution. This reaction, in turn, lowers the pH of the solution, and also can cause formation damage through pore

CHEMICAL FLOODING

blockage and fines migration. The anionic surf&ant species A,, can interact with the inorganic cations in solution just as in MP flooding; however, the interaction with the divalent cations usually takes precedence, particularly in hard brines (see Fig. 47.3) or where there are substantial quantities of soluble multivalent minerals. Because of these interactions and those involving the surfactants A ,;. high-pH processes are as sensitive to brine salinity and hardness as are MP processes.

Other high-pH rock/fluid interactions are intimately associated with the clay minerals. Clays are hydrous aluminum/silicate compounds that occupy the smallest (less than 2 microns) particle size in typical media. Macroscop- ically. clays occur as segregated streaks of variable degree of continuity throughout a typical reservoir, or as distributed clays. which can line pore walls or fill pore throats. Distributed clays are of most concern here, since these have quite large surface areas (15 to 40 mig clay), and therefore can exhibit considerable reactivity. 9X Chemi- cally, clays can take on a variety of formulas that differ substantially in their reactivity even though the differences in their molecular formulas are apparently minor.

The ability of a clay mineral to exchange divalent cations with an aqueous solution can drastically change the ionic environment of a solution with which it is in contact. Clays have excess negative charges caused by the substitution of +2-valence minerals for +3-valence minerals within the octahedral or tetrahedral crystal lattice. 99 The cation exchange capacity, Zv, is a measure of this excess negative charge; typical Zvs are I to 10 meqi 100 g clay for kaolinite and 100 to 180 meq/lOO g clay for mont- morillonite. These free anionic sites are covered with cations from the solution, each of which has a specific degree of selectivity for the particular clay site. In general, H + has high clay selectivity, and divalent cations are bound more strongly than are monovalents. This means that the anionic sites can be occupied predominantly by H+ and/or divalents even when clays are in contact with relatively soft brines. Any subsequent change in the electrolyte environment of the contacting solution can cause the clays to take or give up these cations with a possible detrimental effect on high-pH (and MP) flooding.

H cations can exchange on the clay sites with the injected sodium according to

clay-HfNa Sclay-NafH. .(24)

where clay represents a mineral exchange site. I) The rcverxiblc reaction Eq. 24 will clearly cause the H concentration to increase with a resulting pH decline. Fig. 47.29 shows the extent of the OH - retardation caused by cation exchange in laboratory tloods. Note that many of the lower pHs may require more than 3 PV of fluid in-jection to attain the injected pH.

Unlike MP flooding. high-pH chemicals can react directly with clay minerals and the silica substrate to cause consumption of OH ~ ions. The reactions with clays are manifest by the elution of soluble aluminum and silica species from core displacements. The resulting soluble species subsequently can cause precipitates through hydroxyl reactions as in Eq. 24. lo2 The rate of hydroxyl consumption from this slow reaction (cation exchange is generally fast enough so that local equilibrium applies) 47-21

w

Fig. 47.29-Effluent histories pH from laboratory corefloods. Ex- perimental curves are solid lines with points, theo- retical results are dashed lines.

is determined by a dimensionless DamkGhler number,

ND,,

N,, =+k L/u,,., . . .(25)

where k is the reaction rate constant, time - , and L is the medium length for a first-order reaction. ND, is the ratio of the reaction rate to the bulk fluid rate. If all conditions are equivalent between a laboratory experiment and a prototype field flood, ND, clearly will be much larger in the field than in the laboratory owing to the much larger length scale. A larger ND, implies more reaction relative to the residence time within the system. Thus, it follows that the penetration distance-the distance traveled by full-strength OH - ions-will be considera- bly smaller in the field than in the laboratory. Bunge and Radke, who illustrate this with several numerical calculations, caution against extrapolating laboratory-measured values of OH - consumption to field cases unless the dis- crepancies in ND, have been taken into account.

Field Results

High-pH field tests of articular interest include a wettability reversal test, 99 an emulsion flood,Y6 and a polymer-driven flood. lo3 Fig. 47.30 shows the production data from a high-pH flood conducted in the Whittier field. 04 The crude oil was 20API with a 40-cp viscosity, and the 0.2 wt% NaOH chemical was injected as a

0.23.PV slug. There are many features in these data that are common

to the responses of the other chemical flooding processes in Figs. 47.6 and 47.22. The oil production rate declines as the total fluid production increases, indicating a declining oil cut. The oil rate response to the caustic injection is again superimposed on the waterflood decline, which is ext

47 - chemical flooding

Documents

average mobility ratio

endpoint mobility ratio

shock mobility ratio

mobility ratio concept

mobility of displacing

mobility of displaced

lowift processes

mobility buffer drives