Copyright 2000, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the 2000 SPE/DOE Improved Oil RecoverySymposium held in Tulsa, Oklahoma, 3–5 April 2000.

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AbstractFoam propagation in co-injection was studied in a 10 m longporous medium, equipped with pressure ports for every 1 m.The porous medium had been characterized by floodingexperiments on the core scale. In the absence of oil,propagation on the 10 m scale could be understood by core-scale, steady-state foam properties. In the presence of oil,however, the foam front propagated significantly slower thanthe injected fluid front. An extraction mechanism for oilcombined with foam oil sensitivity can explain the delayedpropagation. These effects were included in a foam simulatorthat reproduced the slow foam propagation.

IntroductionIn many cases, gas provides effective microscopicdisplacement of oil. The low density and low viscosity of gasoften results in a poor macroscopic sweep efficiency, however.Foam can be formed within the reservoir when gas andsurfactant solution flow together. Thereby, gas mobility isreduced, and the sweep of gas improved.

The success of a foam treatment, it be an injector orproducer treatment, is critically dependent on placement offoam to the desired depth in the reservoir. The injection time,and the amount of chemicals required to reach a given depthdepend on the propagation velocity of the foam. Literatureprovides some observations of foam propagation rates atvarious conditions. Some authors have observed very slowpropagation of the foam front, compared to the propagationrate of the fluids that constitute the foam.1-4

Other workershave found that foam propagates with the same rate as theinjected fluids.4-6

Literature examples points to surfactantretention and the presence of oil as sources of propagationdelay.

A quantitative understanding of foam propagation rate islacking, however, and especially the effect of oil. The studydescribed here aims at improving this understanding. Theapproach taken has been to study foam propagation over largedistances in well characterized systems. The porous mediumhas been characterized by laboratory experiments on the usualcore scale, with respect to relative permeability, capillarypressure, foam properties, and surfactant adsorption. Then,foam propagation was studied on the semi-reservoir scale, andcompared to modeling based on core scale data, in order tolearn how to use core data to predict foam propagation in thereservoir. This paper augments the results of previous work7

with experiments under a broader range of conditions.

ExperimentalThe semi-reservoir scale flow experiments were carried out atreservoir conditions in a 10 m long sand pack. The containerfor the sand pack was a specially constructed assembly of ten1 m long tubes made of the corrosion resistant alloy HastelloyC-276. The outer and inner diameter of the tubes was 25.4 and18.1 mm, respectively. The one meter long tube sections werecoupled together with coupling pieces made from the samematerial, with the same inner diameter. Each coupling piecewas equipped with one port for pressure measurement, onevalve for sampling of fluids during flooding, and a piston forcompression of the sand. Sand was filled through the pistonports and compressed by vibration and piston movement. Theprocess was repeated until sand filled the tubes and thecoupling pieces, and all voids in the sand were gone. Flowports and pressure ports were equipped with Hastelloy C-276wire mesh in order to confine the sand. Each coupling piecechanged the direction of flow by 180°, such that the entire tubeassembly only occupied a volume of 123x40x20 cm3, andcould be fitted into a thermostated cabinet. The layout of theapparatus is sketched in Fig. 1. The assembly was designed fora pressure limit of 620 bar at 90°C.

During flooding of the 10 m sand pack, the differentialpressure was measured over each 1 m section, with individual0-20 bar differential pressure gauges. The inlet and outletpressures were measured with two absolute pressure gauges.In Fig. 1, these are shown, together with two of the differentialpressure gauges. Saturations were deduced from mass balance.

The properties of the sand packs are summarized inTable 1. The 50-200 µm fraction of crushed Berea rock was

SPE 59284

Foam Propagation in the Absence and Presence of OilF. Vassenden, SPE, T.Holt, SPE, A. Moen, SPE, and A.Ghaderi, SPE, SINTEF Petroleum Research

2 F.VASSENDEN, T.HOLT, A. GHADERI SPE 59284

used as a porous medium. The sand was washed in brine inorder to remove the loose fines. Sand from Berea rock waschosen because of its clay content, which gave a practicalsurfactant adsorption level. Adsorption of the employedsurfactant at 90°C was measured in static adsorption tests withno oil present. The permeability of the individual sectionsvaried by ±10% from the average value of 6.1 Darcy.

The capillary pressure curve of the sand was measuredwith water and oil with the porous plate technique, and scaledwith the interfacial tensions of the surfactant solution at theprocess conditions. Relative permeability curves for gas andwater were measured in flooding experiments in a single onemeter section.7 The same preparative flooding was applied inthat case as in the experiments with oil in the 10 m sand-pack(see below). Gas relative permeabilities in the presence offoam, measured by the steady state method, are presented inFig. 2. The gas relative permeability curve without foam wasdeduced from history matching of steady state gas-waterexperiments in the same 1 m section, taking segregationeffects into account.

Synthetic sea water was used as the aqueous phase for allexperiments. For the foam experiments, a 1 wt% solution ofC14/16 AOS was used. The employed oil was recombined fromseparator oil and gas samples from the North Sea field Snorre.A hydrocarbon gas mixture with 70% methane was used,having the composition of the Snorre separator gas.

Preparative flooding and foam flooding experiments were

carried out at a temperature of 90°C and an outlet pressure of300 bar, which represented Snorre reservoir conditions. Forthe experiments involving oil, the sand pack was prepared forthe foam experiments by drainage to irreducible watersaturation by flooding with a viscous mineral oil. The oil wasexchanged by the reservoir oil, and the sand pack aged. Thenthe oil was displaced in a water flood, a gas flood, and anotherwater flood, in order to mimic the injection history at Snorre.At the process conditions, multicontact miscible displacementresulted in low residual oil saturations after gas flooding. Theobtained saturations are shown in Table 2. The experimentsnot involving oil were carried out in cleaned, 100% watersaturated sand. In some of the experiments, a pre-slug ofsurfactant solution was injected prior to foam flooding. Table2 shows how much of the sand pack that contained surfactantsolution when the foam flooding started (initial surf.coverage). Foam was generated by simultaneous injection ofgas and surfactant solution into the sand, at the rates given inTable 2.

The flow in the 10 m sand pack was simulated with thefoam option of the commercial numerical simulator STARS.8

A two-dimensional 105x10 Cartesian grid model wasemployed. The two-dimensional grid was used to captureeffects of gravity segregation. The grid cell width across theflow direction was varied with height in order to capture thecylindrical geometry of the tube.

The simulator describes foam by gas relative permeabilitycurves. Gas mobility is interpolated between the no-foamcurve and a curve that represents the measured properties of

foam at given reference conditions. The interpolationfunctions (the dependence of gas mobility on oil saturation andsurfactant concentration) can be specified to matchexperimental data. The gas relative permeability can also bemade specifically dependent on water saturation (instead ofliquid saturation) through an interpolation function thatrepresents foam breakdown at dry conditions. Fig. 2 showsboth the no-foam relative permeability curve, and the resultingreference foam curve when the foam breakdown interpolationfunction is included. The foam curve features the steep partdescribing foam breakdown at dry conditions, and the lowmobility at wet conditions.9 The relative permeability forwater was the same for both the foam and no-foam cases.

Two hydrocarbon components were used to model the oiland gas, one heavy and one light. Partitioning coefficients foreach component between the phases were specified.

Results and discussionExperiment 1: Surfactant present, no oilExperiment 1 was carried out in cleaned sand, saturated 100 %with surfactant solution. Surfactant adsorption was thussatisfied before foam injection. The response of the individualsections to foam flooding is shown in Fig. 3, presented as afunction of the injected fluid volume in units of the porevolume of a 1 m section (a section pore volume, SPV). Alinear pressure increase is observed in each section, withsuccessive response in successive sections. For each pressuregauge, data is lacking when the pressure drop exceeded therange limit of 20 bar. The over-all pressure drop was found toincrease linearly with injected volume, however, with amaximum pressure drop over each section of 40-60 bars. Theappearance of a high pressure gradient in a section can beinterpreted as the appearance of low-mobility foam. The figureshows that low-mobility foam arrives in a new section every1.05 SPV injected. This means that the foam front propagatesapproximately as fast as the injected fluids. The observedpressure gradient is very high, probably too high for most fieldapplications of foam. This is nevertheless not untypical forfoam flooding at high pressure.6,10

The fraction of the pore volume filled with foam, Nf , for anideal piston flow with the propagation limited by the gassupply can be expressed by

Nf=(Vw+Vg)/VP · fg/∆Sg................................................... (1)

where Vw+Vg is the total injected fluid volume, fg is theinjected gas fraction (foam quality), ∆Sg is the change in gassaturation over the foam front, and VP is the total pore volume.This formula yields a good match to the propagation data inFig. 3, for a water saturation of 4.4% behind the foam front.This is a reasonable value for the water saturation in a strongfoam. In this simple case, the foam thus propagates accordingto the injected volumes.

SPE 59284 FOAM PROPAGATION IN THE ABSENCE AND PRESENCE OF OIL 3

Experiment 2: No surfactant, no oilIn experiment 2, gas and surfactant solution were co-injectedinto sea-water saturated sand. The experiment probed foampropagation when surfactant is not present ahead of the foamfront. Fig. 4 shows the response of the individual sections.Injection of approximately two SPV of fluids was required tofill one section with foam. Obviously, foam propagation isslower than the propagation of the injected gas and water.

This propagation delay can be explained by surfactantadsorption. The surfactant propagation velocity can becalculated from the adsorption level, by a simple surfactantmass balance. The fraction of pore space filled with foam iscalculated as

Nf=(Vw+Vg)/VP · fw/(Sw,foam+Γρ/ϕ c)...............................(2)

where fw is the injected water fraction, Sw,foam is the watersaturation in the foam zone, Γ is the surfactant adsorption level(mass of surfactant per mass of rock), ρ is the rock density, ϕis porosity, and c is the injected surfactant concentration. Theexperimental data were found to be well reproduced byEq. (2), for the measured adsorption level and a watersaturation of 9.3 % behind the foam front. Simulations of thisprocess with STARS were also found to match the observedfoam propagation, illustrating the ability of the simulator todescribe surfactant adsorption and concentration dependentfoam properties correctly.

The overall pressure drop was found to increase linearlywith injected volume, with an average pressure drop over eachsection of 40 bar. The STARS simulations were found toreproduce the rate of pressure build-up.

The arrow in Fig. 4 marks the observed gas breakthrough(GBT). Only the two first sections were then completely filledwith foam. The simulated gas saturation distribution justbefore gas breakthrough, shown in Fig. 5, explains the earlygas breakthrough. The figure shows a piston-like foam zone atthe inlet to the left, recognized by its high gas saturation. Thesurfactant and the region of high foam strength was found tobe limited to this zone. The gas that is not trapped in theadsorption limited foam zone travels in front of the foam, andforms an override tongue that gives breakthrough of gas longbefore foam fills the sand pack. In the foam zone, the low gasand water mobility makes the viscous forces dominate overgravity forces, preventing gas and water from segregating.Ahead of the foam zone, however, viscous forces arenegligible compared to gravity and capillary forces, and acapillary-controlled segregation results.

The combination of foam generation and surfactanttransport appears thus to be well described by the STARSsimulation model, as well as by simple theory.

Experiment 3: Vertical flow with residual oil and coreinitially saturated with surfactant solutionThe focus of Experiment 3 was on the effects of oil. Before theexperiment, the sand was prepared to residual oil saturation, as

described in the Experimental section. In order to controleffects of segregation, the 10 m sand pack was orientedvertically before the foam injection started, giving a gravitystable foam injection in odd-numbered sections, and a gravity-unstable flow in the even-numbered. The orientation of thesections is illustrated in Fig. 1. In order to eliminate effects ofsurfactant transport on foam propagation, the sand was pre-saturated with surfactant before foam injection.

The pressure drops over the individual sections are shownin Fig. 6. The figure shows that the foam broke through to thesecond section after 1.4 injected SPV. It appears that thegravity stable foam injection in the first section propagated ina piston-like manner, with little propagation delay. The firstgravity-unstable foam injection, in section 2, exhibited quitefast pressure build-up initially, but later, the rate of pressureincrease was reduced. The next section did not respond untilafter 22 SPV, revealing strongly delayed propagation. Thesame slow propagation persisted for the remaining sections,with 10-20 SPV injected volume required to fill each section.

After 4.2 injected SPV, gas broke through the 10 m tube.The pressure gradients showed that there was no foam in thesand, except in the first and part of the second section. Thisshows that gas and surfactant solution could be presenttogether without forming a low-mobility foam. This contrastsExperiments 1 and 2. Since surfactant transport andsegregation did not influence propagation in Experiment 3, itappears that the oil was the reason for the observedpropagation delay. It may be speculated if the lackingpropagation delay in the first section can be due to the largesurfactant pre-slug removing oil from that section.

Experiment 4, horizontal flow at residual oil and with asmall surfactant pre-slugIn the last experiment carried out in the 10 m sand pack, gasand surfactant solution were injected simultaneously into sandat the residual oil saturation after a multicontact miscible gasflood, as in Experiment 3. A small surfactant pre-slug,satisfying adsorption in the first 1 m of the sand, was injectedbefore foam injection started. The flood was horizontal. Thisexperiment represented a realistic case of foam injection in afield, which would simultaneously include all the aspectsaddressed by the other experiments.

Fig. 7 presents the pressure drop measured over theindividual sections. The pressure drop over the first sectionwas found to rise linearly with time. There was no pressureresponse in the other sections of the sand pack until 25 SPV,when the second gauge responded. After another 30 SPV, thethird pressure transducer responded. The overall pressure dropincreased almost linearly with injected volume, with pressuredrop over each section of between 30 and 60 bars. From thearrival times of strong foam to the ∆p gauges 2 and 3, thestrong foam front appear to propagate with a velocity ofapproximately 0.035 section per SPV injected. This iscomparable to Experiment 3 and literature results for similarfoam systems.3,4

4 F.VASSENDEN, T.HOLT, A. GHADERI SPE 59284

In Fig. 7 gas breakthrough and surfactant breakthrough(SBT) are marked with arrows. At surfactant breakthrough at24 SPV, foam filled only the first section of the pack. Thisshows that gas, water, and surfactant were present together inthe last nine sections without forming foam. A surfactant massbalance shows that not enough surfactant had been injected atthat time to satisfy adsorption in the entire sand, i.e., someparts of the sand lacked surfactant at surfactant breakthrough.This indicates that segregation effects could have contributedto the reduced propagation velocity in this experiment.

Shortly after 65 SPV, when the water injection rate wasincreased, there was response in several new pressuretransducers. Over sections 5, 7 and 8, large pressure dropswere measured, while virtually no pressure drop haddeveloped over sections 4 and 6. These observation suggeststhat several independent low-mobility foam zones wereformed spontaneously. Also the saturation development wasfound to exhibit large changes after irregularities in theexperiment. These observations indicate that the balancebetween capillary, viscous, and gravity forces was verydelicate in this experiment. Small perturbations could changethis balance, and make one of the forces dominate for shorttime intervals. This indicates that Experiment 4 must beinterpreted with caution, and that some aspects of theexperiment is probably not representative for a field process.This does not change the conclusion that Experiment 4 didshow delayed propagation of foam, however.

Simulations of experiments with oil presentWhile Experiments 1 and 2 could be simulated with core-scale, steady state foam properties, the slow build-up of thepressure drop observed in Experiments 3 and 4 could notcaptured with the same simulator model. Additional input of aphysical mechanism that delays foam propagation is requiredto obtain a match. Since the experiments shows that there is nopropagation delay oil free rock, but significant delay when oilis present it appears reasonable to investigate the effects of oilon foam stability. C14/16 AOS foam has been reported to besensitive to Snorre oil at high saturations.11

In order to explainthe observations in the 10 m sand pack, the foam has to besensitive to oil saturations of 4-5 %PV and less, however.Moreover, there must be a mechanism for changing the oilsaturation, in order to explain the appearance of a strong foamafter prolonged flooding. The 4-5%PV residual oil after themulticontact miscible gas flood in the 10 m sand pack is mostlikely immobile, and therefore a mechanism for removal ofimmobile oil not involving flow will be required for oilsensitivity to explain the propagation delay.

The foam-oil interaction model used described foam thatcollapsed for oil saturations above 6 %PV. For lowersaturations, the foam strength increased linearly to themaximum strength at zero oil saturation. The maximumstrength corresponds to the reference foam krg curve shown inFig. 2. Simulations were run for an initial oil saturation ofarbitrary 10 %PV.

The slow removal of oil was modeled through the pVTdescription. The heavy component partitioning coefficient for

the oil-water equilibrium was made proportional to thesurfactant concentration. This model represents oil extractionby solublisation into surfactant micelles. The value of thepartition coefficient was taken to represent that two moleculesof surfactant can dissolve one molecule of oil, which isphysically reasonable. Such an extraction model yield a zoneof zero oil saturation that propagates from the injection point,because surfactant solution that is equilibrated by the firstcontact with oil will pass oil further down-stream withoutdissolving more oil.

The plots in Figs. 8-10 show the simulated distribution ofsurfactant, gas and oil in a vertical cross-section along the 10m sand pack, just before the simulated surfactant breakthroughat 28 SPV (similar to the experimental value of 24 SPV). Thefigures show a under-ride tongue of surfactant, leaving asignificant part of the core without surfactant at breakthrough,and a zone of high gas saturation at the inlet, covering 6% ofthe model length. These simulations explains both theobservations that surfactant did not cover the entire model atsurfactant breakthrough, and the slow propagation of the low-mobility foam front. The pressure simulated with thesolublisation model was found to increase linearly withinjected volume, with approximately the same rate as observedexperimentally. Adjustment of the partitioning factor or theinitial oil saturation could give an arbitrarily good match to thepropagation rate. A comparison between the gas and surfactantdistributions shows clearly how the oil sensitivity is the effectthat limits propagation. Segregation is important for thesurfactant distribution, but surfactant is not the limiting factorfor foam propagation.

With the solublisation oil extraction mechanism, a massbalance relation for the removable oil component yields thatthe propagation rate of the oil saturation front (the front wherethe oil saturation or concentration of critical component(s)changes to zero), and hence the low-mobility foam front, canbe expressed as

Nf=(Vw+Vg)/VP · fw · Kiνoi/νw∆So .................................... (3)

where Vw+Vg is the total injected volume, Ki is the partitioncoefficient for the oil-water equilibrium (for the dissolvable oilcomponent i). The partition coefficient is defined Ki=xiw/xio,where xio/w is the mole fraction of component i in oil or water,respectively, and it is assumed to be proportional to surfactantconcentration. The partial molar volumes of oil component i(in oil) and water (in water) are vio and vw are, respectively.Across the foam front, the oil saturation changes by ∆So. It isinteresting to note that the details of the foam-oil interactiondo not affect the propagation velocity when extraction is theonly mechanism for oil transport.

Another pVT-model, with evaporation of oil beingresponsible for the slow oil removal was also tested. Theresults obtained with the evaporation model were similar to theresults of the dissolution model. It was anticipated that oilwould be preferentially removed at the top of the core for theevaporation model, and at the bottom in the dissolution model,

SPE 59284 FOAM PROPAGATION IN THE ABSENCE AND PRESENCE OF OIL 5

reflecting the dominant flow paths for the two fluids. Thesimulations proved this anticipation to be wrong. Thesimulation results, with similar piston-like flow in both cases,is a result of the favorable mobility ratio of the foamdisplacement.

One problem with the explanation above is that theexistence of oil in produced surfactant solution has not beenproven. Indeed, produced surfactant solution has been found tohave a much darker color than injected solution. It wasattempted to prove that this darkening was related to oil, bystudying the evaporation residue of a toluene extract of thedarkened surfactant solution. No oil was found, however, butif the foam oil sensitivity was caused by minority componentsin the oil, the detection method was possibly not adequate.

ConclusionsWith no oil present, foam propagation is limited by either gasor surfactant supply. The propagation process is wellunderstood, and is well described by steady state foamproperties. In the presence of oil, even at very low andimmobile saturation (5%PV), gas and surfactant solution hasbeen found to flow together without forming low-mobilityfoam, and a low-mobility foam zone was found to propagatefrom the inlet significantly slower than the gas and surfactantfronts. The delayed foam propagation in the presence of oilcan be explained if the foam can remove oil by an extractionmechanism. Slow foam propagation has been successfullysimulated by allowing oil to evaporate into the gas or tosolublise oil in the surfactant solution. It remains to identifythe physical extraction mechanism, however. The study showsthat core experiments for characterization of foam propertiesmust be carried out in the presence of a realistic oil (that givesa realistic foam-oil interaction), and that the transientdevelopment of the pressure drop must be analyzed forpropagation effects. Steady state data cannot generally be usedalone. The results suggest that oil sensitivity may stronglyreduce the usefulness of a foamer, even for injector treatments.

This work impacts foam screening studies by showing thatfoam systems showing aging (foam strength improvementwith time) must be interpreted as being oil sensitive, and thatextremely oil sensitive foamers may be of limited use in fieldprocesses due to the large propagation delay.

This work indicates that the most important issues needingclarification in future research are the identification of the oiltransport mechanism, and the components in the oilresponsible for the sensitivity of the foam. Furthermore,surfactants that are sufficiently oil tolerant for field use shouldbe identified.

NomenclatureV= volume, L3, m3

f= fractional flowK= partitioning coefficientν= partial molar volume, L3/1, m3/moleϕ= porosityΓ= surfactant adsorption, surfactant mass /rock mass

S= saturationx= mole fractionc= surfactant concentration, m/L3, kg/m3

AOS= α-olefin sulphonate

Subscriptsg= gasw= watero= oilf= foam

P= porei= component number

AcknowledgementsThe data presented in this work were obtained through theReserve-Foam project, sponsored by the Norwegian ResearchCounsil, and the oil companies Shell, Saga Petroleum, Statoil,Total, BP, Norsk Hydro, and Mobil. The authors also thankPeter Alveskog for measurements of surfactant adsorption,Kåre Solbakken for design of the flow model and core floodexperiments, and Jarle Glad for experimental work during coreflood experiments.

References 1. Patzek, T.W. and Koinis, M.T., 1990: ”Kern River Steam-Foam

Pilots”. J. Petroleum Tech, p 496, April. 2. Irani, C.A. and Solomon, C. Jr., 1986 “Slim-Tube Investigation

of CO2 Foams”, SPE/DOE paper 14962, presented at theSPE/DOE Fifth Symposium on Enhanced Oil Recovery, Tulsa,OK, April 20-23

3. Aarra, M.G., Ormehaug, P.A., and Skauge, A., 1997: “Foamsfor GOR control - improved stability by polymer additives”,paper 10 in Proceedings of the 9th European Symposium onImproved Oil Recovery, The Hague - The Netherlands, 20-22October.

4. Mannhardt, K. and Svorstøl, I., 1997: “Foam propagation inSnorre reservoir core - effects of oil saturation and ageing”,paper 52 in Proceedings of the 9th European Symposium onImproved Oil Recovery, The Hague - The Netherlands, 20-22October.

5. Kovscek A.R., Patzek, T.W., and Radke, C.J., 1993:“Simulation of Foam Transport in Porous Media”, paper SPE26402 presented at the 1993 SPE annual Technical Conferenceand Exhibition, Houston, TX, Oct. 3-6.

6. Osterloh, W.T., and Jante Jr., M.J., 1992: “Effects of Gas andLiquid Velocity on Steady-State Foam Flow at HighTemperatures”. paper SPE/DOE 24179, presented at theSPE/DOE Eighth Symposium on Enhanced Oil Recovery,Tulsa, OK, April 22-24.

7. Vassenden, F. Holt, T., Ghaderi, A., and Solheim, A. 1999:"Foam Propagation on Semi-Reservoir Scale ". Paper SPE58047, SPE Reservoir Eval. & Eng. 2, 436, October 1999;Vassenden, F. Holt, T., and Solheim, A. 1998: "FoamPropagation on Semi-Reservoir Scale ". Paper SPE 39682,presented at the SPE/DOE Improved Oil Recovery Symposium,Tulsa, OK, 19-22 April.

8. CMG 1994: The simulator STARS from Computer ModellingGroup, Calgary, Canada.

9. Vassenden, F. and Holt, T., 1998 :”Experimental Foundation forRelative Permeability Modeling of Foam”, SPE/DOE paper

6 F.VASSENDEN, T.HOLT, A. GHADERI SPE 59284

39660, presented at the 1998 SPE/DOE Symposium onEnhanced Oil Recovery, Tulsa, OK, April 19-22.

10. Holt, T., Vassenden, F., and Svorstøl, I, 1996: Effects ofPressure on Foam Stability; Implications for Foam Screening,SPE 35396, Presented at SPE/DOE Tenth Symposium onImproved Oil Recovery, Tulsa, 21-24 April.

11. Svorstøl, I., Vassenden, F., and Mannhardt, K., 1996:“Laboratory Studies for Design of a Foam Pilot in the SnorreField”, SPE/DOE paper 35400, presented at the 1996 SPE/DOETenth Symposium on Enhanced Oil Recovery, Tulsa, OK, April21-24.

SI Metric Conversion Factorsbar ×1.0* E+05 =PacP ×1.0* E+03 =Pa s

TABLE 1-CHARACTERISTICS OF THE 10 M SAND PACKTube inner diameter mm 18.1Sand grain sizes µm 50-200Adsorption of C14/16 AOS mg/g rock 0.2Permeability, k Darcy 6.1Porosity, ϕ 0.394PV at 300 bar/90°C ml 1097PV of each section (SPV) ml 109.7Sand mass g 4480Effective length (volume/area) m 10.8

TABLE 2-CONDITIONS DURING PREPARATION AND FOAM FLOODINGExperiment 1 2 3 4Preparative floodingIrreducible water saturation (%PV) - - 16 15Residual oil after water flooding (%PV) - - 21 28Residual oil after gas flooding (%PV) - - 5 6Res. oil before foam injection (%PV) 0 0 4 5Sw before foam injection (%PV) 100 100 77 73Initial surf. coverage. (sections) 10 0 10 1Foam injectionWater rates ml/h 0.5 0.5 0.5 0.5Gas rates ml/h 7.7 4.1 4.8 5.0Total frontal rate sections per day 1.8 1.0 1.2 1.2Model orientation horiz. horiz. vert. horiz.

10

9

8

7

6

5

4

3

2

1

0

∆p1

pin pout

∆p10

Fig. 1-Schematic of the experimental set-up for the 10 m sandpack.

0.000001

0.00001

0.0001

0.001

0.01

0.1

1

0 0.1 0.2 0.3 0.4 0.5 0.6Liquid saturation, PV

Rel

ativ

e pe

rmea

bilit

y

krg no foam

krw

krg foam

krg foam exp

Fig. 2-Relative permeabilities used in simulation, compared toexperimental data measured on one single section of the sand-pack

SPE 59284 FOAM PROPAGATION IN THE ABSENCE AND PRESENCE OF OIL 7

0

5

10

15

20

25

0 1 2 3 4 5 6

Injected total volume, section PV

Sect

ion

diff

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tial p

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ure,

bar

dp1 dp2 dp3 dp4 dp5

dp6

Fig. 3-Pressure drop over individual sections, for experiment 1.

0

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0 2 4 6 8 10 12Injected volume, section PV

Diff

eren

tial p

ress

ure,

bar

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dp1 dp2 dp3 dp4 dp5 dp7dp6

Fig. 4-Pressure response in Experiment 2 (no surfactant pre-slug)

Fig. 5-Gas saturation just before gas breakthrough in the simulations of foam injection into 10 m tube saturated with sea water (Experiment 2)

8 F.VASSENDEN, T.HOLT, A. GHADERI SPE 59284

0

5

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0 10 20 30 40 50 60Injected volume, section PV

Diff

eren

tial p

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dp1

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Fig. 6-Pressure drop over the individual sections during foam injection in vertical orientation (Experiment 3).

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0 20 40 60 80 100Injected volume, section PV

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e dr

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dp4,6

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Fig. 7-Pressure drop over individual sections, Experiment 4.

SPE 59284 FOAM PROPAGATION IN THE ABSENCE AND PRESENCE OF OIL 9

Fig. 8-Surfactant distribution at surfactant breakthrough, simulated with the solublisation model for oil removal.

Fig. 9-Gas saturation at surfactant breakthrough, simulated with the solublisation model for oil removal.

Fig. 10-Oil saturation at surfactant breakthrough, simulated with the solublisation model for oil removal.