sOCIETY OF PETROLEUMENGINEERSOF AIME PAPER

6200 North CentralExpressway NUMSER

Dallas,Texas 75206

SPE 3609

THIS IS A PREPRINT --- SUBJECTTO COmCTION

A Review of the Concepts and Methodology ofDetermining ~TNet Payi;

By

Richard H. Snyder, Member AIME, Core Laboratories,Inc.

@ Copyright 1971American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper was prepared for the 46th Annual Fall Meeting of the Society of Petroleum Engineersof AIME, to be held in New Orleans, La., Oct. 3-6, 1971. Permissionto copy is restrictedto anabstractof not more than 300 words. Illustrationsmay not be copied. The abstract should containconspicuousacknowledgmentof where and by whom the paper is presented. Publicationelsewhereafterpublicationin the JOURNALOF PETROLEUMTECHNOLOGYor the SOCIETYOF PETROLEUMENGINEERSJOURNAL isusually grantedupon requestto the Editor of the appropriatejournalprovi$d agreementto giveproper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to theSociety of Petroleum Engineers office. Such discussion may be presented at the above meeting and,with the paper, may be consideredfor publicationin one of the two SPE magazines.

ABSTRACT INTRODUCTION &

A review of the methods of deter- One of the most misunderstood andmining net pay in hydrocarbon-bearing poorly defined terms used in reservoirreservoirs is presented with emphasis geology and formation evacuation isplaced on the ultimate use of the net the concept of net pay. The followingpay map; i.e., for determining total discussion is an attempt to more pre-in-place hydrocarbons, for the deter- cisely define this term, to demonstratemination of the total energy balance methods of selecting net pay and showof the reservoir and evaluating secon- that the intended use of the net paydary recovery prospects. The use of often determines how net pay is “picked”.various logs, core data and test data Several different systems of determiningare discussed in conjunction with net pay thickness and mapping techniquescalibration of the net pay. The con- for net intervals are illustrated usingcept of petrophysical cut-off values an example reservoir. Methods for cai-and approaches to their determination culating volumes of net pay from theseare illustrated. An idealized reser- different types of maps are also dis-voir is mapped using net thickness, cussed and compared.pore volume and hydrocarbon pore volumedatums and the results compared. The DEFINITION AND USAGEresults indicate that the mapping usingthese different datums are essentially To anyone faced with the task ofcompatible , dependent only on the in- picking net pay in a reservoir thetended usage of the maps. Volumetric first problem is concerned with definingcalculations are also made and the the various intervals and thicknessesresults are compared and evaluated. so that some degree of consistency be-

tween wells can be maintained. Refer-ence to Figure 1 shows these intervals

References and illustrations at endof paper.

A REVIEW OF THE CONCEPTS AND METHODOLOGY OFt DETERMINING

and defines the different stratigraphicgross and net terms commonly used inthe petroleum industry and also usedwithin this discussion.

As seen on the illustration, thegross interval of the formation spansthe distance between log marker a and$2. The gross reservoir interval is thedistance between the top of the reser-voir a=d ~kL~ b~se ~f ~~.e ~e~~rv~ir,

This interval contains both reservoirand non-reservoir rock; i.e., shale,salt, anhydrite, gypsum, lignite, andpossibly dense limestones along withthe reservoir rock. The next smallerdivision defines the gross sand orlimestone” interval or gross reservoir,the interval in which the shales, salt,etc. have been removed. The net inter-val is the part of the reservoir thatcontatns both hydrocarbons and waterand is porous and permeable reservoirrock, Finally the net sand intervalcontaining only hydrocarbons 1S the netoil pay or net gas. pay. There are manyinstances noted in the iiteratiire, i~

unitization discussions, and in forma-tion evaluation work that define netpay in any or all of these categories.The only difference between net oil payand net sand in this example is thefact that an oilfw+,ker contact is

---- Ap~eaenL in the S~E6 whereas the diff~~-ences between net sand and gross sandis dependent on non-net reservoir rock.Normally, the problem of net pay iden-tification is not as simple as this“text-book” example, mainly due tothe variations in stratigraphy,especially lithology.

The main reason for determiningnet pay is to obtain a numeric valuefor the thickness term in the oil-in-place formula. Therefore it followsthat the reason Eor de~~l~pi~g thevolumetric oil-in-place value deter-mines the methods and parameters usedin defining net pay thickness. Forexample, the oil-in-place value isused in many different ways; the prin-cipal use being for determining thezm~-urLt~f -41“.* or gas av~ilahle fO~

primary production. Other uses in-clude determining the total amount ofoil and gas in place within a reservoirso than an inventory of the totalenergy of the reservoir can be estab-lished. Oil-in-place values also areof interest in ascertaining the amountof hydrocarbons that will be availablefor secondary recovery, Net pay valuescar. alse be qsed for guides in field

“NET PAY” SPE 3609

development and as a unitization para-meter . The following discussion is con-cerned with t-he effect these ‘uses h~%’e~= the method of picking net PaY.

Volumetric Oil-in-Place

The most common use of net pay is asthe thickness factor in the oil-in-placeequation and probably the majority ofnet pay work is oriented towards thisfactor. This thickness value is themost critical factor in oil-in-placecalculations. Certainly mistakes inporosity and water saturation can bemade and these erroneous values substi-tuted into the equation, but theseerrors are limited by maximum and mini-mum values inherent in these numbers;matrix porosity must be between 1 and 2percent and a maximum of 44 percent andwater saturation values cannot straymuch below 5 percent or much over 65percent. Therefore, it is the net paythickness that becomes the criticalvalue in the oii-in-piace equa~ioii as4-L..-.LIICL- are no ~Q=~~r~i~ingl%mits on thisnumber .

Usually net pay for this applica-tion is selected with the idea that arecovery factor will be applied to thisoil-in-place value.

The importance of this net payfactor should be emphasized. Estimatesof available oil and gas in placethroughout the world are most commonlybased on a volumetric oil-in-placenumber. Current concern over UnitedStates, Russian and Middle Ease reservesare based to a significant degree on theaccuracy of obtaining these net paynumbers . One wonders as to the consis-tency between picking net for the hugegas and oil fields in Russia, Siberiaa~d the Middle East in comparison to

the manner in which net sand is selectedfrom a deviated hole drilled off a GulfCoast platform to a salt dome for thepurpose of evaluating a lensing faultedMiocene sand for the basis of a MERhearing.

Determining Total Energy

A second reason for determiningnet pay is concerned with defining thetotal amount of hydrocarbons in a reser-voir so that the total energy of thereservoir can be calculated. In thiscase both movable and non-movable oil-in-place is desired. Net pay valuesfor this application can be much higher

S.FE 36G9 RTPHARD H, SNYDER..-4-..-.— 3

than for oil-in-place calculations. Asan example, net pay located in longtransition zones or below producingoillwater contacts is counted and in-cluded in this instance, but would~rQh=bIy he excIuded in the previouslydiscussed volumetric oil-in-place cal-culation. It is this movable plus non-

-..-..L-l *h4c-Irma== tusecj in che~uv=u-e riet pay ..LA-....-w-oil-in-place calculation that shouldcheck with material balance calcula-tions.

Secondary necovery

A third major reason for determin-ing net pay in a reservoir is to eval-uate the potential hydrocarbon avail-~~~e for =e~ep.d=ry re~Qvery: Thisapplication is especially important inevaluating economics of waterfloodprojects. The method of picking netpay in this case is slanted toward thedetermination of the amount of net paywith favorable relative permeabilityto the injection fluids, thus the majorcriteria for determining net pay arethese favorable relative permeabilitycharacteristics.

Miscellaneous Uses of Net Pay

Finally, net pay determination maybe used as a unitization parameter andalso net pay isopachous maps are usedas a guide for development drillingprograms and installation and designof secondary recovery projects.

From the foregoing discussion, itis important to realize that the netpay can vary within a well dependenton the ultimate usage of the net payvalue. The net pay value checked bymaterial balance calculations can varyfrom net pay for use in determiningoil-in-place available for primaryproduction, and both of these net payfigures may vary significantly fromnet sand available for secondaryrecovery operations.

METHODS FOR DETERMINING NET PAY

The basic or classic method forselecting net involves the use of.S. P.logs and/or Gamma Ray logs. Using nor-mal log criteria for determining theCQp and base Of the formations - or atleast changes in rock types - eachgross sand interval is marked on the~Qg . These icterval thicknesses areadded and a total gross sand interval

is obtained. Certain assumptions areimplied in this method; all the sandis porous, permeable, and is capableof contributing hydrocarbon, no tarmats, bitumen, disseminated shale par-ticles in pore spaces or any otherblocking or cementing materials arepresent in the sand; consequently, all“positive” deflections are reservoir,and all “negative” deflections are non-reservoir.

This is a valid technique if thestratigraphic section is a cleanalternating sandstone - shale sequencewith very porous and permeable cleansand. This is the classic manner ofpicking net pay and is as valid as theassumptions. Classic areas for use ofthis method are the Miocene Gulf Coastsediments, the Woodbine of East Texas,California Tertiary sandstones and theDevonian sandstones of Algeria. Thismethod is always the first step in anynet determination work as it is inessence separating non-reservoir fromreservoir rock. Often this is asdetaiied an aiitZl~SiS Df C=t pay 2s isnecessary.

A more sophisticated method re-quires the use of porosity determininglogs in conjunction with the S. P. orGamma Ray logs. After the reservoiror gross sandstone reservoir is definedfrom these lithology determining logsonly the porous - and probably permeableinterval of the porous rock is counted.

All types of porosity measuringlogs; Sonic, Microlog, Microlaterolog,Density and Caliper may be used depend-ing upon their availability. Oncethese porosity indicating tools areused it becomes necessary to define alower limit of porosity below whichthe reservoir will not produce oil orwill not contain hydrocarbons. Thisporosity is commonly called the porositycut-off.

One effect of cut-off porosity andlogging tool sensitivity should bementioned ; if porosity logs are usedfor making quantative estimates ofporous net sand, the lowest value ofporosity the log can measure automat-ically becomes a cut-off value. Forexample, certain wall resistivity logshave lower limits of sensitivity; belowwhich the log cannot measure porousintervals. If these logs are used toquantatively evaluate net, only reser-voir rock with porosity greater than the

A REVIEW OF THE CONCEPTS AND METHODOLOGY OFi DETERMINING

iower limits -will ~e -C-llmted as net-“....

pay. In other words - if the log showsporosity the interval is net reservoir.If no porosity is shown on the log,then the interval is non-net.

This system again is adequate inclean porous and permeable reservoirswith high porosity intervals. Bestresults for this technique are foundin strongly contrasting porosity typeswithin sandstone or limestone reser-voirs. This technique is especiallyuseful in alternating limestone-dolo-mite sequences where the porosity inthe dolomite interval is much greaterthan the porosity in the interbeddedlimestone.

The next step in defining net payis ~=corp~raring COre analysis anddescriptions with the porosity, S. P.,and Gamma Ray logs. With this datatwo new and very important parametersare available to help in defining whatis net pay, permeability and oilsaturation data.

Permeability cut-off values can beestablished and correlated with poro-sity cut-offs. Also the lower depthlimits of oil saturation can be estab-lished which is necessary in describingthe total oil trapped in a reservoir.Although resistivity logs can and areused to determine these oil satura-tions, it is core analysis and coredescriptions that are most useful inreservoirs with long transition zones,or with oil saturations many feetbelow producing oil/water contacts.

Finally, in addition to all thepreviously discussed logging tools andcore information, the availability anduse of relative permeability data inii~fi~ki~t~ net pay ~Q~t he ‘Qe!ltiQn~de

This type of data is very important inevaluating the amount of reservoirsusceptible or compatible to water-flooding or other secondary recoveryschemes. Permeability to air of areservoir rock versus permeability towater or oil often makes significantdifferences in choosing cut-offpermeability.

One of the major factors thatinfluences the relative permeabilitycharacteristic of any formation is thepresence or absence of swelling clays,so again the lithology of the formationcan be a predorni.ii~tiiig f~CtGi in deter-mination of net pay. If the purpose of

“NET PAY” SPE 36C

defining net pay is to inventory theamount of reservoir available andsusceptible to waterflooding or gasinjection systems, a different methodand tools must be used to obtain re-liable net thickness and consequentoil-in-place volumes.

DETERMINATION OF “CUT-OFF VALUES”

From the previous discussion, itisapparent that the net pay problem maybe re-defined into determining porosityand/or permeability cut-off values. Asthe intended usage of oil-in-placedetermines the method of picking iistpay, these uses also determine themethod chosen for delineating the cut-off value.

Normally, a permeability and/orporosity value is chosen as a cut-offvalue based on intuitive judgment.Often this method is sufficient,especially when there is a largedifference between highest and lowestvalues. If the reservoir has a mixtureof 100’s of millidarcy permeability and0.1 millidarcy permeability, obviouslythe 0.1 millidarcy is considered as thecut-off value. Intuitively an occasion-al 2, 5 or even 10 millidarcy intervalwill be considered below the “cut-off”.A more difficult decision is requiredif there are some 50 millidarcy sam-ples or intervals. In this case, therehas to be something to make the decisioras to whether it is net or non-net payother than just the 50 millidarcypermeability value. There are two factsthat can be used to include or excludethese samples. obviOusiy, if the 50millidarcy sample does not have oil orgas saturation as reflected through coreanalysis, oil staining, fluorescence,odor or calculated oil saturation fromresistivity logs~ it can be excludedand considered below the cut-off. Asecond calibration can be made usingD. S. T. andlor production tests. Ifthe 50 millidarcy interval tests dry orat some minimal or non-commercial rate,this permeability or porosity can bejudged as at or below cut-off. Thiscut-off is applicable in the case ofdefining net pay available for primaryproduction. If an oil-in-place valuewas needed for determining total energyof the reservoir then the 50 millidarcyinterval would have to be included eventhough oil andlor gas was not produced,but oil saturation was present.

SPE 3609 RI CHARD

EXAMPLE RESERVOIR

To see aii the effects of ?ksusage of net pay and to show some mapp-ing techniques for net pay in a simplehypothetical reservoir has been devel-oped and is used as an illustration.The remainder of this discussion willbe concerned with this example reser-voir,

The hypothetical reservoir contain20 wells. Table I is a tabulation ofthe basic data for these wells, includ-ing well identification, top and baseof the reservoir in subsea depth, grossthickness, net thickness, averageporosity, average water saturation andcalculated pore volume and hydrocarbonpore volume.

Mapping Techniques

Using this net thickness data foreach well, an fsopachous map of the netthickness was drawn as shown by FigiiEe2. This map was contoured usingstraight interpretive contouring tech-niques as opposed to equi-distant ormechanical contouring procedures. Themap is interpretive in that the con-touring parallels and honors the knowngeologic information available on thereservoir. The reservoir could be achannel sand development with thickernet sand in the deeper portion of thechannel$ or the reservoir could bedouble-mounded sand bars with twothick or high sand build-ups at thetop of the gross reservoir interval.

This type of map is normallydrawn in making the various net payanalyses. The advantages of such amap is that contouring can be guidedby known geological principles andfacts. For example, if the reservoiris a channel sand and this formationwas known to be “V” shaped in crosssection rather than “U” shaped, theappropriate geometry of the sand bodycould be incorporated into the contour-ing. Sand bars, reefs, biostromes orany of the myriad geometric shapes ofsedimentary bodies, all of which arewell known, can be readily incorporatedinto the interpretive contouring of netpay isopachous maps. Structural fac-tors, such as roll-overs along faultplanes, suspected secondary mineraliza-tion or fracture planes and effects ofunconformity surfaces can also guidecontouring and lead to more reasonable

SNYDER 5

interpretations. The greatest disad-vantage in using net pay maps is noti~, ~~,e ‘--+- **+-O hut in finding aL“ub”L.*..~method for assigning of average pocosityand water saturation values to the rockvolume.

In our example reservoir, the rockvolume calculated from t&iS isopackI is

7190 acre feet. If we assign an arith-metic average porosity of 7.7 percentcalculated from the table, we have apore volume of 553.6 acre feet, andusing an arithmetic average water satu-ration of 54.3 percent we find we have300.6 acre feet of oil in the reservoir.

A second mapping technique can alsobe useful. Using average porosityvalues at the well locations and multi-plying the fractional porosity valuesby the wells’ net thickness results in

=--- ~oi~~me datum far each well.g nnl-a Thiscan be visualized as the feet of porespace available for fluid storage at--- Th4 meULh ti-~ii j)C)i~8t. ..aAU space Or p.0~~

volume is contoured as shown on Figure3. The advantage of this map is thatthe porosity VaiueS fili the ~eS~~VGiZS

are automatically volume weighted; how-ever, as there are two parameters toeach datum, it becomes necessary tocontour this map mechanically, and notinterpretively.

In the example reservoir, a volumeweighted pore volume of 623.5 acre feetis calculated and by assigning the samewater saturation as was done in theprevious example, 338.6 acre feet of oilis present in the example reservoir.This is 11 percent higher than was pre-viously found, the difference dependenton the different contouring method;mechanical versus the previously inter-pretive type and the volume weightingof pore space in contrast to the arith-metically averaged value assigned inthe first case.

The advantage of this technique isthat the porosity values are weightedand the contouring can be done mechan-ically. Again if consistency and repro-ducibility are needed, as Eor use iii

unitization work, this approach may bedesirable.

The next technique would be toreduce this pore volume by the amountof irreducible water saturation presentin the pore space and use this numberas a mapping datum. This calculation

A REVIEW OF THE CONCEPTS AND METHODOLOGY OF6 DETERMINING “NET PAY” SFE 3609

results in values of hydrocarbon porevolume at each well location. This mapis presented as Figure 4. This map canbe visualized as tank or containerfilled with oil. Advantages of thismap are that both porosity and thewater saturation value are volume~~~ghted,

From this map a total hydrocarbonin place value of 342.7 acre feet hasbeen calculated, or only 1.2 percenthigher than the value calculated fromthe pore volume map but 12 percenthigher than from the net isopachousmap .

The following technique will cir-cumvent all of these problems by show-ing that through the use of structuremaps of the top and base of the reser-voir and a net-to-gross ratio, reliableoil-in-place values can be calculated.

A structure map for the top andbase of the gross reservoir intervalare drawn and areas bet~’ee~ ezcb. gtrluc-tural contour line are determined.For our example reservoir, a structuremap on the top of the reservoir isshown as Figure 5. The structure mapon the base of the formation is simi-lar .

The addition of a few dry holesalong the perimeter of the field andthe problem of the sand body beingskewed off center from the structuralapex complicates the example reservoirbut demonstrates the advantages ofthis method.

The areas between the structurecontours for the top and base of thereservoir are plotted versus heightabove the oillwater contact, Figure6. Next th= aiea betwee~. +k- e~lrw~s-..---. .--is planimetered and converted to agross reservoir volume. An averagenet-to-gross ratio for the entirereservoir is calculated from the basicdata in Table I and applied to thegross column. Using the same porositieand fluid saturation data as in theisopach map example, a volumetric oil-in-place value of 349.9 acre feet iscalculated. This is only 10 percenthigher than the lowest value calculatedusing net pay isopach maps.

Two advantages of this method arereadily apparent; no isopach map isneeded , however, all the geological

data concerning geometry of the reser-voir are incorporated in the contouringof the structure maps. Secondly, theease in which average porosity data andespecially representative water satura-tions can be assigned to the reservoiron the basis of incremental net rockvolume above the oil/water contact. Ifcapillary pressure data converted toheight are available, the assigning andweighting of water saturation is proba-bly the best and most representativemethod. Figure 7 is a summary andcomparison of the results of these fourtechniques.

It appears from the foregoingdiscussion that there is little percent-age difference in the results of these

different gr=Phic=~ te~hnique~ fordetermining oil-in-place volumetrically.It also seems apparent that the techniquto use is one that best depicts thepoorest defined or most criticalvariable.

If r~~ervoir geometry is the mostuncertain variable for example, thenthe gross and net pay isopachs shouldbe used with interpretive contouringrather than pore volume mapping andmechanical mapping. Another examplewould be in the case of thin reservoirscompletely underlaid by a water level.Then possibly the area versus heightapproach using structure maps would bemost appropriate as water saturationdata could then be assigned in a morerepresentative manner so that thesaturation data would be weighted byreservoir volume in increments abovethe water level.

Determination of Reservoir Volumes

Finally, after all the maps andarea versus height curves have beendrawn it then becomes necessary todetermine a numeric rock volume oroil-in-place. There are many techniquesfor doing thisl, but normally eithergridding or planimetry is used to calcu-late volumes. Within each of thesemethods there are several ways of doingthis phase of the work.

The problems and techniques in-herent in this, a most important facetof the entire problem, of volumetricoil-in-place, could be the subject ofan entire paper, but will only be dis-cussed very briefly here.

‘mm aAf)Q RICHARD H. SNYDER 7

this amounts to a tolerance of ~ 5percent. Are core analysis porosityand permeability or water saturationreproducible to ~ 5 percent? Finally,the ratio of the scale to the map tothe thickness of, or more astronomi-cally, the percent of the reservoirsampled by a 9-518” hole versus thevolume of sediments in 640 acres,~=ke~ a + 5 percenttolerance accept-able. —

cIT?JMAQV“w.. . . . . . .

&u 4..4. .. —------

In gridding, area times thicknesscan be estimated and integrated by eyeor through analog gridding counters,-+.+i.t+~-l ~Q~nLins Of random dots..- ....”-----within a grid, all at an amazing degreeof accuracy. In using planimetry,automatic and computerized digitizersor hand planimeters can be used. Evenwithin the planimetry method there arediffering te~Flr~iq-UeS;CG?.ti~’dC’US ersummation of discrete areas planimetry,and finally several differing calculat-ing techniques can be uaed2. Se e%-e=in this phase of net sand determination,multiple techniques are available, noneof which are standard or accepted as“the” way to do the work. Experiencef~ors and time limitations, reproduc-ibility of values, grid sizes andefficiency all effect the choice ofmethods for determining volumes.

What is the best way? In thisexample we have calculated volumesusing standard planimetry techniquesand have used these figures in all thevolumetric calculations. Also the mapswere gridded by “eye-ball” usingrelatively small grid areas; i.e. ,approximately 150 grids over the totalmapped area. The results indicatethat there is little difference betweenplanimetry volumes using the summationof areas and gridding. The maximumdifference is 5 percent, but normallyis 1 to 2 percent, certainly withinthe tolerance levels of the originalinterpretation of the data. Can agross or net sand thickness be pickedon a Gamma Ray log less than one-halfa foot? In a reservoir 10 feet thick,

In summary, it is hoped that amore precise definition of net pay hasbeen presented, and that an awarenessof the importance of the intended useof net pay guides the manner of count-ing net pay, determining cut-off valuesand mapping techniques. Through theuse of an example reservoir it has beendemonstrated that despite what datums,averaging techniques or graphicalrepresentation of the reservoir aremade, results of oil-in-place calcula-tions are similar with maximum varia-tions of 10 percent.

REFERENCES

1. Campbell, J. M.: “Oil PropertyEvaluation”, Prentice-Hall,Englewood Cliffs, New Jersey(1959) 135-137.

2. Craft, B. C. and Hawkins, M. F.:“Applied Petroleum ReservoirEngineeriitg”, P~eiltiC~- Hall,Englewood Cliffs, New Jersey(1959) 27, 106.

TABLE 1 - BASIC WELL DATA

WELLID

TOP(SUBSEA)

BASE(SUBSEA)

GROSSTHICKNESS

NETnAvrnl

0PERCENT

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

A

B

c

D

E

1672

1665

1679

1652

1652

1672

1636

1638

1642

1650

i665

1679

1678

1691

1701

1700

1710

1704

1700

1698

1673

1665

1715

1690

1710

NET/GROSS =AVERAGE g =AVERAGE Sw =

1712

1703

1716

1694

1697

1721

1688

1698

1689

1688

17D0

1726

1721

1731

1751

1752

1767

1760

1757

1750

1733

1735

1763

1743

1772

18.5%8.09%

54.5.%

40

38

37

42

45

49

52

60

47

38

35

47

43

40

50

52

57

56

57

52

60

70

58

53

62

4

15

7

10

22

9

10

10

15

19

5

18

9

20

4

11

3

13

4

22

0

0

0

0

0

5.0

5.5

6.0

5.0

6.5

7.9

6.0

7.4

8.0

7.9

~~.z

11.0

11.5

9.5

9.1

9.0

8.3

8.8

iO.i

9.0

0.20

0.83

0.42

0.50

1.40

0.71

0.60

0.74

1.20

1.50

n K7“.<*

1.98

1.03

1.90

0.36

0.99

0.25

0.11

0.40

1.98

SwPF!RCF.NT. --------

70

40

70

60

25

60

70

65

40

35

gg

45

55

40

80

45

70

45

70

25

Hcpv

0.06

0.50

0.13

6.23

1.11

0.28

0.18

0.26

0.72

0.98

0.10

1.09

0.46

1.14

0.07

0.54

0.08

0.06

n“.~’2

1.49

D

+

E

+-0

SPor GR RL-m

+NET PAY NET SAND

mII I

I

m

~:,!1

1’,:~,

m‘,,,rlLdJ

Fig. 1 - Definition of reservoir intervals.

II

Fig. 2 - Net pay isopachous map (Cl. = loft).

E

+D

Fig. 3 - Iso-pore volume map (C.i. = O.s $~j.

E

+D

+

V.L u

Fig. 4 - Iso-hydrocarbon pore volume map (C.I.=0.5 HCPV).

E

Fig. 5 . st~u~ture Map top of reservoir (Cl. ‘ 10 ‘t).

1630

1640

Ii,650V A

+ I660IAw

L:-1670 v//,///~sC9Gz 1680 TOP OF STRUCTURE

1690-

—-.-F Ar e-rntlm-rllDr

A ‘w’> “>”F”>’FL/////// /h\Ilvv

I I

()/w-1710 I i

400 600 800 I000 I200 I400 1600 18000 200

AREA-ACRES

Fig. 6 - Height vs area for determination of 9roSSreservoir volume (from structure maps) .

ROCK VOLUME

(A~c./Ft.)

o(1)o

0

.—

so

(1-SJ

H.C.P.V.

(!\C./Ft.)

NET OILSAND

7190

7.7

54.3

300.6

PORE

VOLUME

623.5-

54.3

338.6

——

HYDROCARBON

PORE VOLUME

\

342,7-

STRUCTURE

MAPS

7955

(N/G = 18.5%)

7.7

54.3

332.6

Fig. 7 - Comparison of r,~sults of mapping.