Prudhoe Bay Gas Oil Rel Perms

8/9/2019 Prudhoe Bay Gas Oil Rel Perms

1/866 SPE Reservoir Engineering, February 1997

Prudhoe Bay is a mixed-wet reservoir where about half the oil recov-

ery is attributable to gravity drainage. Gas/oil relative permeability

data show that gravity-drainage recovery efficiency is poorer for

more fine-grained sandstone and increases as the grain size increases.

Gravity-drainage efficiency also increases with connate-water satura-tion. Dependence of recovery efficiency on grain size is related to

changes in sorting. An effective grain size, defined by inverting the

Carman-Kozeny relation, provides a useful parameter for correlating

recovery efficiency. This estimate correlates well with visual esti-

mates and direct measurements on disaggregated core. Grain size is

also found to be a more effective parameter for correlating trapped gas

than porosity, a common alternative. Lithology impacts trapped-gas

level with finer-grained, more poorly sorted rock having higher

trapped gas. Trapped gas decreases with increasing microporosity.

Because little gas is trapped in microporosity, a zero-slope generaliza-

tion of the Land curve better represents trapped-gas data.

As a result of the size and economic importance of Prudhoe Bay andbecause of the variety of oil recovery methods operating in the reser-

voir, data for a variety of recovery mechanisms have been collected.

Much of the work to date on understanding relative permeability of

Prudhoe Bay has focused on water/oil1largely because it is an EOR

target, but gas/oil is at least as important. The oil recovery by gravity

drainage constitutes approximately half the production and poten-

tial reserves of the field. Understanding gravity drainage is impor-

tant for forecasting recovery efficiency in the future and in manag-

ing the relative contributions of gravity drainage, waterflooding,

and EOR recovery processes. Because macroscopic recovery effi-

ciency is generally high for the gravity-drainage process, variations

in microscopic efficiency have an even larger impact on overall re-

covery efficiency than in waterflooding. Gas relative permeability

and trapped-gas measurements are important to predicting miscible

gas usage and recovery efficiency.

Strictly speaking, a relative permeability endpoint, residual, or irre-

ducible saturation is that saturation at which a phase becomes dis-

continuous and therefore stops flowing. This definition is meaning-

ful in discussing nonwetting phases, such as gas, but is less

meaningful for wetting phases like oil in the gas/oil system. The

endpoint is controlled by the slow rate of film flow, which depends

on the number of pore volumes (PVs) of throughput or the time al-

lowed for drainage. To understand recovery efficiency, it is more

useful to compare microscopic displacement efficiency,

Ed1So/(1Swi), at a given small oil relative permeability in acentrifuge test or a large gas/oil relative permeability ratio in a dis-

placement test. Analysis of gravity drainage at low, stable rates indi-cates that oil relative permeability is often low enough to control re-

covery and that gas relative permeability is irrelevant.2To identify

the effects of relative permeability alone, it is useful to plot recovery

efficiency vs. dimensionless drainage time.2

dkrodSo1 tgkV

zo, (1). . . . . . . . . . . . . . . . . . . . . . .

Copyright 1997 Society of Petroleum Engineers

Original SPE manuscript received for review 11 March 1996. Revised manuscript received

2 December 1996. Paper peer approved 9 December 1996. Paper (SPE 35718) first pre-

sented at the 1996 SPE Western Regional Meeting, Anchorage, 2224 May.

where porosity, kVvertical permeability, ooil viscosity,zdistance from the gas/oil contact, anddensity differencebetween oil and gas. This measure is used in this paper. However,to understand the recovery of any particular zone or portion of thefield, it is important to be mindful of the other primary controls.

The origin of the low residual oil saturations seen in gravity drain-age is spreading. Spreading is the tendency of oil to form a film be-tween water and gas spontaneously. The measure this tendency isthe spreading coefficient, Sgwowgo, whereijis the inter-facial tension between Phases iandj. Data in the literature indicatethat, if the spreading coefficient is non-negative, oil will drain downto very low saturations and will not disconnect, while systems withnegative coefficients (nonspreading oils) can become discon-nected.3-5Measurements indicate that the initial spreading coeffi-cient for Prudhoe Bay crude at reservoir conditions is positive, witha value of S58.125.31.7310.5 dynes/cm. At typical labconditions, the initial spreading coefficient is also positive and of asimilar magnitude. Field data from the gas cap, which according tothe theory of oil accumulation at Prudhoe was once fully occupiedbyoil,6-8show very low oil saturations averaging 8%. This is moreconsistent with a spreading oil than a nonspreading oil. Although

mechanistically it might seem that wettability would affect oil rela-tive permeability, available data show little difference between pre-served and extracted samples. Two separate studies on two differentwells showed no systemic difference between experiments on pre-served or extracted samples at room conditions. This is consistentwith observations made in the literature.9,10

Review of the literature9,11-14indicates that the presence of connatewater is generally thought to increase oil recovery up to the point thatwater becomes mobile, when oil recovery begins to decrease. Many au-thors have found that gas/oil relative permeability is essentially a func-tion of gas or liquid saturation, independent of connate-water satura-tion. These results imply that the sum of residual oil saturation andconnate-water saturation should be a constant. Consequently, residual

oil saturation is strongly dependent on connate-water saturation, and re-covery efficiency should increase with increasing connate-water satu-ration. This picture characterizes Prudhoe Bay oil relative permeabilityat moderate and high but not low liquid saturations.

Fig. 1shows that the residual oil saturation determined from capil-lary pressure experiments for Prudhoe Bay decreases with connate-water saturation down to approximately 2%. Core residual oil satura-tions from the Prudhoe Bay gas cap support the idea that very lowresidual oil saturations can be reached, consistent with these data. Al-though widely accepted theory states that gas migrated into PrudhoeBay after it was filled with oil,6-8oil saturations in the cap reach lessthan 4% (with connate-water saturations less than 20%).

Although oil saturations approaching ultimate residual are in-sightful, they do not reflect much of what is important in the fieldbecause these values are not attained in realistic field lifetimes. For

example, a compensated neutron log (CNL) study in 1990 of 12wells in the gravity-drainage area showed an average oil saturationof 238%, with more than one-third of the intervals having oil satu-rations less than 20%. A second CNL study in 1988 showed an aver-age of Sorg0.31 for Zone 4 and Sorg0.25 for Zone 2. Fig. 2shows that the recovery efficiency at a fixed moderate dimension-less recovery time, t40, decreases with decreasing connate-watersaturation [the trends are the same at fixed low relative permeabil-ity15(e.g., kro0.004)]. The data are measurements made on plugsfor which two or three saturations are reported on the same plug.Thus, one can clearly ascribe differences to height above water/oilcontact rather than to changes in the level of microporosity. Becausethe experiments were done on extracted rocks with refined fluids,wettability changes are unlikely.


2/8



Fig. 4Dependence of porosity (top) and log permeability (bot-tom) on grain size, in phi units, estimated from visual inspection.

ume ratio is known and other factors may be estimated so thatpermeability and porosity can be related directly to particle radiussquared. This equation can be used to estimate particle size, d, frompermeability and porosity. To be consistent with geological nomen-clature this is done on the Wentworth scale yielding,

W ln2(d) ln1.784103 1 k , (2). . . . . . .where Wis in phi units and dis in millimeters.

Fig. 5shows a test of this Carman-Kozeny estimate of grain sizeand compares the estimate of grain size based on visual estimates tothat estimated from the permeability and porosity of the observedplug. The results indicate that, while the estimate works well for me-dium- to very-fine-grained rocks, for very coarse grain and above,

the Carman-Kozeny estimate does not match visual estimates. Thismay be because sorting is not well modeled or because visual esti-mates inaccurately portray mean grain size (because larger grainsinfluence the visual estimates more than flow). Note, however, thatthe majority of the rock is finer grained and, therefore, a method thatworks on these rocks is quite useful. For example, in the data col-lected by Begg et al.,2294% of the rock had grain sizes less thancoarse grain. Rock with a grain size in phi units of 3.5 or greater isalso not of interest because it is so fine grained and low in permeabil-ity that it is usually nonpay. Grain-size measurements made with la-ser-light scattering on disaggregated plugs more directly addressesthe accuracy of this estimate. Fig. 6shows that there is reasonablygood agreement between the median grain size measured on the dis-aggregated samples and the estimates made with the permeability

Fig. 5Grain size in phi units based on visual analysis vs. grainsize estimated by Carman-Kozeny relation from permeability andporosity of the core sample (W). There is good agreement in therange of coarse to very fine grain but poor agreement otherwise.

Fig. 6Effective grain size (in microns) vs. measured value.

and porosity of the plug and the Carman-Kozeny equation. Thus, di-rect measurements, visual estimates, and estimates based on the

Carman-Kozeny equation all agree.Fig. 7shows the dependence of sorting on grain size for disaggre-

gated core. Finer-grained rocks have poorer sorting. The sorting co-

efficient, defined as the standard deviation in grain size measured

in phi units, increases nearly linearly with the grain size in phi units.This trend is also apparent in visual inspection. Extrapolating with

respect to grain size in phi units indicates that perfect sorting occurs

around W0. In this limit, the relative permeability behavior mayapproach that of uniform sands. Because poorly sorted rock tends

to have lower recovery efficiency, one can expect that fine-grainedrocks will have poorer recoveries.

Fig. 8shows recovery efficiency vs. sorting coefficient. As ex-

pected, the data show that poorly sorted sandstones have lower re-

covery efficiency. Recovery efficiency at an oil relative permeabil-ity of 0.004 and at a dimensionless time of 40 show the same trend.15

Other studies of Prudhoe Bay relative permeability support and ex-pand on the simple trend with lithology given previously. There are

consistent trends found in studies on other wells. In particular,


4/8SPE Reservoir Engineering, February 1997 69

Fig. 7Sorting vs. grain size. Data are from laser particle-sizemeasurements on disaggregated core.

coarse-grained and better-sorted material has consistently more fa-vorable behavior when viewed on a liquid-saturation basis.

Fig. 9shows displacement gas/oil relative permeability data on com-posites of different lithologies along with centrifuge oil relative perme-ability data taken on the plugs from the composites. The conglomeraticsample has the most unfavorable behavior, the medium-grained sand-stone the most favorable behavior. The fine-grained sandstone has lessfavorable behavior than the medium-grained sandstone, and the veryfine-grained sandstone slightly less favorable behavior.

Differences in lithology reflect more than differences in micro-porosity level. Medium to pebbly sandstones have more favorablerelative permeability behavior than fine-grained sandstones both ona liquid-saturation basis and a displacement-efficiency basis. Con-

Fig. 9Data that demonstrate systematic difference betweenlithologies and between centrifuge (closed symbols) and displace-ment (open symbols) data. Diamondsconglomerate, circlesmedium grained, trianglesfine grained, and squaresvery finegrained; centrifuge data taken on plugs from the composite.

Fig. 8Displacement efficiency at krog0.004 (top) and at a di-mensionless drainage time of 40 vs. sorting coefficient. Solidline is RMA and dashed line is a least-squares fit .

glomeratic samples look more unfavorable on a liquid-saturation ba-sis than on a displacement-efficiency basis largely because they con-tain more microporous chert, which in these experiments is saturatedwith water and does not participate in the flow. While these generaldescriptions are useful in exploring differences in behavior, the effec-tive-grain-size concept helps to quantify the impacts and correlate thedata in a more meaningful way. Fig. 10shows recovery efficiency asa function of effective grain size for sandstones and conglomerates ata dimensionless time of 40. The data are derived from centrifuge rela-tive permeability experiments for all available data that containedconnate water. This figure shows that recovery efficiency is lower forfiner-grained samples. The data also show that, for large effectivegrain sizes, the conglomerates and sandstones have essentially thesame recovery efficiency, but that conglomerates have a lower recov-ery efficiency for small effective grain sizes. The difference in recov-

Fig. 10Displacement efficiency at a dimensionless time of 40vs. effective grain size for conglomerates and sandstones.



Fig. 11Gas relative permeability data from steady-state (solidcircles), pseudosteady-state (x,+,*) and low-rate displacementscorrected for capillary end effects (open diamonds). Primary-drainage oil/water relative permeability (solid diamonds) is thesame as gas/liquid data. Bold lines are correlation with grainsize; solid triangles are Leveretts23unconsolidated sand data.

ery between coarse- and fine-grain material is rather dramatic, withcoarse-grained sandstones having a recovery efficiency in excess of65% and fine-grained rocks less than 50% (at krog0.004 or40).Recovery-efficiency data for samples from a single well and Zone 4show similar trends to those in the entire database. Thus, lithologyrather than structural location is controlling.

The dominant factor in these trends is permeability variation. How-ever, statistical tests on the centrifuge data and evidence in the litera-ture19indicate that porosity as well as permeability influences recov-ery efficiency. In particular, a more statistically significant correlationexists between recovery efficiency and effective grain size than be-tween recovery efficiency and permeability or log permeability. Inaddition, simultaneous regression on both initial water saturation andeffective grain size shows that both are statistically significant.

Fig. 11shows primary drainage gas relative permeability data forPrudhoe Bay. Not shown are displacement data, which are thoughtto be impacted by viscous fingering and are systematically differentfrom other data types (e.g., steady-state, pseudosteady-state, andlow-rate gasfloods corrected for end effects).15This figure alsoplots results of a two-parameter gas relative permeability equation,

krgSg1 cg2Sg SgtSmaxg 1 Smaxgr

cgl

1 cg2Sg SgtSmaxg 1 Smaxgr cgl11c

g2,

(3). . . . . . . . . . . . . . . . . . . . . . .

used to fit the data. This equation approaches the Corey equation18

at low gas saturations and has a continuously decreasing slope athigh gas saturations, consistent with the idea that gas enters largerpores first and then successively smaller pores. The Corey exponentportion models the way a nonwetting phase becomes connected(i.e., the dependence of relative permeability on the shape and num-ber of pores in the connected set of pores filled by gas). The latterportion models the successively smaller contribution of smallerpores to the relative permeability. The hysteresis behavior implicitin the choice of reduced saturation is the same as Carlsons24; im-bibition relative permeability is the same as secondary-drainage rel-

Fig. 12Decrease of gas saturation at krg0.5 with decreasinggrain size. Open triangles are for conglomeratic samples andsolid circles for sandstones. Lines are RMA fits of the data; solidfor sandstone and dashed for conglomerates.

ative permeability and is related to primary-drainage relativepermeability through the gas-trapping function. Evidence in the lit-erature25and Prudhoe Bay data15indicate that there is no hysteresisbetween imbibition and secondary drainage, consistent with thismodel. Other experiments show that there is no difference betweenmiscible injectant (reservoir conditions) and nitrogen (ambientconditions) relative permeability in both imbibition and secondarydrainage. These results are consistent with the bulk of the evidencein the literature, which indicates that gas relative permeability de-pends only on the current and maximum gas saturation, and is inde-pendent of the other two-phase saturations in the immiscible lim-it.9,11,26,27

On the basis of the results of the last section, it is clear that oneshould expect differences in gas relative permeability curves owingto differences in lithology. In addition, studies of gas relative perme-ability found in the literature indicate that there is a correlation be-

tween permeability level and gas relative permeability,19,16withlower gas relative permeability at a given saturation for more per-meable rock. Fig. 12 shows a similar correlation between the gassaturation at a displacement gas relative permeability of 0.5 and theeffective grain size. The figure shows that gas relative permeabilityat a given gas saturation decreases with increasing grain size. Tomatch this behavior (Fig. 11), displacement data were regressed todetermine gas saturation at given relative permeability levels as afunction of effective grain size and the parameters in the gas relativepermeability equation were made simple functions of effectivegrain size to reproduce the trends.15

Fig. 13 shows laboratory measurements of trapped gas as a functionof initial gas for Prudhoe Bay. Consistent with the literature,28thedata indicate little dependence on whether oil or water is trapping,whether the experiment is done at reservoir or laboratory condi-tions, and whether the experiments are done on composites or plugs(or even with centimeter-scale in-situ saturation measurements) oron native-state or extracted cores. Moreover, there is little apparentdifference between sandstone and conglomeratic data plotted onthis basis.15The data are well correlated with a zero-slope adapta-tion of the Land29curve,

SgtSmaxg

1 1Smaxgr 1Smaxg 11Smaxgr

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

with Smaxgr 0.255.


6/8



Fig. 16Dependence of maximum trapped gas on effectivegrain size for Prudhoe Bay sandstone. Solid line is RMA fit,dashed line is least-squares fit.

for the better agreement with the database at higher porosities (e.g.,see Fontainebleau samples,20 which are virtually microporosityfree) and for the weak trend with porosity, the impact of microporos-ity on trapped gas partially canceling the impact of porosity level.Conglomeratic samples often have a larger fraction of pore space inmicroporosity,8accounting for their lower level of gas trapping ata given porosity level.

Fig. 16shows trapped gas vs. effective grain size calculated fromthe Carman-Kozeny equation. For sandstone samples, there is atrend of increasing trapped gas with smaller effective grain size,consistent with the idea that poorer sorting leads to higher trapped-gas levels. Moreover, the correlation is more statistically significantwith grain size than porosity.

1. Gravity-drainage oil recovery efficiency decreases with de-creasing initial water saturation and poorer sorting. Fine-grained,low-permeability sandstones tend to have low recovery efficiencybecause they have poor sorting.

2. Effective grain size defined by inverting the Carman-Kozenyrelation provides a useful parameter for correlating recovery effi-ciency. This estimate of grain size correlates well with visual esti-mates and direct measurements on sandstones.

3. Gas relative permeability depends on rock texture with coars-er-grained sandstones and conglomerates having a higher relativepermeability level at a given gas saturation. Much of this differencebetween sandstones and conglomerates is because of the impact ofmicroporosity.

4. Trapped gas depends primarily on porosity or sorting and micro-porosity level. For sandstones, low porosity and poor sorting lead tolarger trapped-gas levels. Little gas is trapped in microporosity. Be-cause conglomerates contain a larger fraction of microporosity thansandstones, conglomerates trap less gas at a given porosity level.

d grain diameter, LEd displacement efficiency, fraction

h thickness, Lk absolute permeability, L2

krg gas relative permeabilitykrj Phasejrelative permeability

krog oil relative permeabilitykV vertical direction permeability, L2Sg gas saturation

Sgt trapped-gas saturationSmaxgr maximum trapped gas

Sj saturation of Phasej, fractionSl liquid saturationSo oil saturation

Sorg residual oil to gasSw water saturation

Swc connate-water saturationSwi initial water saturation

t dimensionless recovery timet drainage time, tW

effective grain size

z distance from gas/oil contact, L porosity, fraction of bulk volume density difference between gas and oilj viscosity of Phasej(Ft/L2) dimensionless drainage time

ij interfacial tension between Phases iandj

I thank Arco Alaska Inc. and the working-interest owners of PrudhoeBay for permission to publish this paper. A wide variety of data in thispaper were measured by the various companies participating in thePrudhoe Bay Unit. The results of this work would not be possiblewithout the dedicated and careful experimental work of many peoplein these companies. The interpretations and conclusions presented in

this paper are those of the author and do not necessarily reflect theopinions of all the Prudhoe Bay working-interest owners.

1. Jerauld, G.R. and Rathmell, J.J.: Wettability and Relative Permeability

of Prudhoe Bay: A Case Study In Mixed-Wet Reservoirs, SPERE(Feb-

ruary 1997).

2. Richardson, J.G. and Blackwell, R.J.: Use of Simple Mathematical

Models for Predicting Reservoir Behavior,JPT (1971) 1145.

3. Chatzis, I., Kantzas, A., and Dullien, F.A.L.: On the Investigation of

Gravity Assisted Inert Gas Injection Using Micromodels, Long Berea

Sandstone Cores, and Computer Assisted Tomography, paper SPE

18289 presented at the 1988 SPE Annual Technical Conference and Ex-

hibition, Houston, 25 October.

4. Oren, P.E., Billiote, J, and Pinczewski, W.V.: Mobilization of Water-

flood Residual Oil by Gas Injection for Water-Wet Conditions, SPEFE

(March 1992) 70.5. Dullien, F.A.L. et al.: The Effect of Wettability and Heterogeneities on

the Recovery of Waterflood Residual Oil with Low Pressure Inert Gas

Injection, Assisted by Gravity Drainage, paper presented at the 1991

European Symposium on IOR, Stavanger, 2123 May.

6. Erickson, J.W. and Sneider, R.M.: Structural and Hydrocarbon Histo-

ries of the Ivishak (Sadlerochit) Reservoir, Prudhoe Bay Field, SPERE

(February 1997).

7. Holstein, E.D. and Warner, H.R. Jr.: Overview of Water Saturation De-

termination for the Ivishak (Sadlerochit) Reservoir, Prudhoe Bay Field,

paper SPE 28573 presented at the 1994 SPE Annual Technical Confer-

ence and Exhibition, New Orleans, 2528 September.

8. Sneider, R.M. and Erickson, J.W.: Rock Types, Depositional History,

and Diagenetic Effects: Sadlerochit Reservoir, Prudhoe Bay Field,

SPERE(February 1997).

9. Narahara, G.M., Pozzi, A.L., and Blackshear, T.H. Jr.: Effect of Connate

Water on Gas/Oil Relative Permeabilities for Water-Wet and Mixed-WetBerea Rock, SPE Advanced Technology Series(July 1993) 114.

10. Vizika, O. and Lombard, J.M.: Wettability and Spreading: Two Key

Parameters in Oil Recovery With Three-Phase Gravity Drainage,

SPERE(February 1996) 54.

11. Delclaud, J., Rochon, J., and Nectoux, A.: Investigation of Gas/Oil

Relative Permeabilities: High-Permeability Oil Reservoir Application,

SPE 16966 presented at the 1987 Annual Technical Conference and Ex-

hibition, Dallas, 2730 September.

12. Hagoort, J.: Oil Recovery by Gravity Drainage, SPEJ(June 1980) 139.

13. Dumore, J.M. and Schols, R.S.: Drainage Capillary Pressure Function

and the Influence of Connate Water, SPEJ(October 1974) 437.

14. Owens, W.W., Parrish, D.R., and Lamoreaux, W.E.: An Evaluation of

a Gas Drive Method for Determining Relative Permeability Relation-

ships, Trans., AIME (1956) 207,275.


8/8SPE Reservoir Engineering February 1997 73

15. Jerauld, G.R.: Gas/Oil Relative Permeability of Prudhoe Bay, paper

SPE 35718 presented at the 1996 SPE Western Regional Meeting, An-

chorage, 2224 May.

16. McCord, D.R.: Performance Predictions Incorporating Gravity Drain-

age and Gas Cap Pressure Maintenance, LL-370, Area, Bolivar Coastal

Field, Trans., AIME (1953) 198, 231.

17. Molina, N.N.: How to use relative permeability correlations, Oil &

Gas J.(1983) 96.

18. Corey, A.T.: The Interrelation Between Gas and Oil Relative Permea-

bilities, Producers Monthly(November 1954) 38.

19. Felsenthal, M.: Correlation of kg/koData with Sandstone Core Charac-

teristics, Trans., AIME (1959) 216, 258.

20. Bourbie, T. and Zinszner, B.: Hydraulic and Acoustic Properties as a

Function of Porosity in Fontainebleau Sandstone,J Geophysical Re-search(1985) 90, 11524.

21. Dodds, J. and Leitzelement, M.: The Relation Between the Structure

of Packs of Particles and Their Properties, Physicals and Chemistry of

Porous Media,Proc., AIP Conference (1984).

22. Begg, S.H., Gustason, E.R., and Deacon, M.W.: Characterization of a

Fluvial-Dominated Delta: Zone 1 of the Prudhoe Bay Field, paper SPE

24698 presented at the 1992 SPE Annual Technical Conference and Ex-

hibition, Washington, DC, 47 October.

23. Leverett, M.C.: Flow of Oil/Water Mixtures Through Unconsolidated

Sands, Trans., AIME (1938) 132, 149.

24. Carlson, F.M.: Simulation of Relative Permeability Hysteresis to the

Nonwetting Phase, paper SPE 10157 presented at the 1981 SPE Annual

Technical Conference and Exhibition, San Antonio, Texas 57 October.

25. Jerauld, G.R. and Salter, S.J.: The Effect of Pore-Structure on Hystere-

sis in Relative Permeability and Capillary Pressure: Pore-Level Model-

ing, TIMP(1990) 5,103.

26. Fayers, F.J. and Matthews, J.D.: Evaluation of Normalized Stones

Methods for Estimating Three-Phase Relative Permeabilities, SPEJ

(April 1984) 224.

27. Oak, M.J., Baker, L.E. and Thomas, D.C. Three-Phase Relative Perme-

ability of Berea Sandstone,JPT(August 1990) 1054.

28. Morrow, N.R.: A review of the effects of initial saturation, pore struc-

ture and wettability on oil recovery by waterflooding,North Sea Oil

and Gas Reservoirs, Graham and Troutman (eds.), Norwegian Inst. of

Technology (1987) 179191.

29. Land, C.S.: Comparison of Calculated with Experimental Imbibition

Relative Permeability, SPE 3360 presented at the 1971 SPE Rocky

Mountain Regional Meeting, Billings, Montana, 24 June.

30. Katz, D.L. et al.: 1966 How Water Displaces Gas From Porous Media,

Oil & Gas J.(Jan. 10), 5560.

31. Yuan, H.H.: The Influence of Pore Coordination on Petrophysical Pa-

rameters, paper SPE 10074 presented at the 1981 SPE Annual Techni-

cal Conference and Exhibition, Dallas, 57 October.

32. Wardlaw, N.C. and Cassan, J.P.: Estimation of Recovery Efficiency by

Visual Observation of Pore Systems in Reservoir Rocks, Bulletin of

Canadian Petroleum Geology(1978) 26,572.

33. Blunt, M.J.: What Determines Residual Oil Saturation in Three-Phase

Flow?, paper SPE 27816 presented at the 1994 SPE/DOE Symposium

of Improved Oil Recovery, Tulsa, Oklahoma, 1720 April.

34. Schneider, F.N. and Owens, W.W.: Sandstone and Carbonate Two- and

Three-Phase Relative Permeability Characteristics, SPEJ(1970) 3, 75.35. Swanson, B.F. and Hickman, W.B.: Application of Air-Mercury and

Oil-Water Capillary Pressure Data in the Study of Pore Structure and

Fluid Distribution, SPEJ(March 1966) 55.

dyne/cm1.0* E00mN/mpsi6.894 757 E00kPa

*Conversion factor is exact. SPERE

Documents

Prudhoe Bay Gas Oil Rel Perms