carbonate reservoir

A large proportion of the oil and gas in the Middle East is contained in carbonate reservoirs,including several supergiant fields. The traditional techniques for developing and assessing

clastic reservoirs are less effective or even counter-productive in carbonate rocks.Geoscientists need a clear understanding of their reservoirs because predictions aboutfuture behaviour can only be based on current performance and an understanding of the

mechanisms controlling that performance.

In this article, Roy Nurmi and Eric Standen investigate the new nuclear magneticresonance (NMR) technology, and the fresh insights it offers into the complexities of

carbonate reservoirs and pore systems. The logging of borehole NMR in Kuwait hasprovided a wealth of new data on the geological and production potential of

complex carbonate reservoirs.

With important contributions from: Ahmed A Latif and Dogan Sungur of KuwaitOil Company, along with Ian Stockden of British Petroleum and Chanh Cao

Minh of Schlumberger Middle East, whose SPE paper 37771 for therecent Middle East Oil Show (MEOS) in Bahrain is featured

in this article.

the inside story

Fig. 2.1: BIGNAMES:The list of giantcarbonatereservoirs inthe MiddleEast (e.g.Ghawar Field,Zakum Field,Kirkuk Field,Marun Fieldand NorthField) includessome of the

world’s largestand best known

oil and gasaccumulations.

28 Middle East Well Evaluation Review

Middle East carbonate reservoirscontain around 50% of theworld’s oil (figure 2.1). As

reserves in other regions are depleted,this proportion will increase and theMiddle East giants will come to dominatethe global oil and gas supply in the 21stcentury (see ‘2020 vision,’ Middle EastWell Evaluation Review , issue 14).Clearly, the industry must evaluate thesereservoirs accurately. However, charac-terizing carbonate reservoir sequencesusing borehole logs presents a specialchallenge. Existing systems for log inter-pretation are based on clastic shaly sandfacies and are of limited use in carbonates,where the pore structure is usually muchmore complex than in clastic rocks (figure2.2). These fundamental problems hamperattempts to develop successful productionstrategies in carbonate reservoirs.

Evaluating hydrocarbon saturationfrom measured electrical conductivity incarbonate rocks is one of the most funda-mental problems. In carbonate reser-voirs it is fairly common for dry oil to beproduced from zones where boreholelogs show high water saturations. Severalnew techniques are being introduced toovercome this type of problem. Of these,the Combinable Magnetic Resonance(CMR*) tool has provided the most dra-matic improvements by distinguishingeffective from non-effective pore spacein carbonates.

Better porosity measurements havelong been a focus for research in theindustry. In the 1950s some reservoirengineers proposed complex models ofsinuous, constant cross-section flowtubes to estimate fundamental reservoirproperties such as permeability (figure2.3). These early attempts to model poredimensions and permeability in reser-voirs were not very successful, either asrepresentations of fluid movement or astools to predict production rates.Concepts such as pore sizes, pore sizedistributions, tortuosity and constrictionfactors could be assumed and incorpo-rated into equations, but not measuredindependently (figure 2.4).

Modern carbonate studies attempt toassess large-scale effective porosity - theextensive network of fluid-conductingpores. Once a network has been recog-nized and its connectivity evaluated, thegeoscientist can choose the most suitablemethods to drain the reservoir anddevelop waterflooding procedures toenhance production. Drill cuttings andwell logs provide the geologist’s firstglimpse of the reservoir’s pore system.However, they cannot represent the fullcomplexity of carbonate reservoirs,which often leads to frustration ratherthan understanding.

In pore-fillingcalcite mud

Skeletal fragment andintraparticle mesopores

Microporousooid

Between pore-filling crystals

Ooid outer layer

Types of microporosity

Pelletal grainwith microporosity

Fig. 2.2: The range ofpore sizes and thedistribution ofporosity throughmatrix and grains incarbonate rocksmakes determinationof effective porosityvery difficult. In thisexample, microporesare distributedthroughout the rock;although the waterthey contain will notflow, it will berecorded in logs andmay lead to incorrectformation evaluationand completiondecisions.

Middle East carbonate reservoirs

Western Europe

EasternEurope

NorthAmerica

South Americaand Caribbean

Asia

Australasia

Africa

Former Soviet Union

Other MiddleEast reservoirs

Oil and gas reservoirs of the world

29Number 18, 1997

Fig. 2.4: FROMPORE TO PORE:Porosity andpermeability arethe fundamentalcontrols on thereservoir potentialand properties ofa rock. Grain size,compaction,sorting and crystalgrowths alldetermine poresizes and,therefore, porosityand permeability.

Initial particle

Mould

Solution-enlargedmould

Vug

Pr o g r e s s i v e s o l u t i o n

Until recently, thorough evaluation ofcarbonate reservoirs using standard welllogs was hampered by the complex andoften heterogeneous nature of lime-stones and other carbonate rocks.Standard logs run in carbonatesequences over the past 20 years haveprovided estimates of porosity and satu-ration, but have not been adequate topredict which fluids will flow from anygiven zone and at what rates. Geologistsworking with carbonate rocks quicklyrealised that a simple porosity measure-ment is not enough to characterize thereservoir. Secondary, diagenetic or tec-tonic porosity characteristics, includingmoulds, vugs, channels, fractures, openfaults and microporosity, can all giverise to unexpected behaviour.

In the Middle East, borehole electri-cal imagery has revealed that there aremore fractures and vugs (figure 2.5)within the region’s reservoirs than waspreviously suspected. These studieshave also revealed the presence ofmajor heterogeneities including largeopen faults. How can the informationfrom these electrical images be com-bined with other techniques and used toimprove overall reservoir performance?

One of the major challenges in car-bonate formations is to analyse andquantify non-effective porosity. If this canbe achieved, permeability evaluationswill be more accurate. Large pores andheterogeneities can be defined by coreand/or borehole imagery. Geologically-guided pressure-transient testing canquantify the connectivity and productionpotential of heterogeneous pore systems.

Reservoir engineers can integrategeological information with cased-hole,production and water monitoring data inolder fields to improve their understand-ing of poorly-defined areas and identifybypassed oil zones.

Pore space within the rock is onlyuseful if it is part of a large-scale net-work. Isolated pores cannot contributefluids during production, even if theyhave been filled with hydrocarbons ear-lier in their development.

Unfortunately, the non-effective poresin carbonates can be smaller, equal insize or even larger than the effectiveintergranular or intercrystalline porespaces. These non-effective pores in car-bonate rocks include micropores, intra-particle pores, moulds and vugs. Welltesting will probably always be neededin addition to any logging or coring if thelarge-scale connectivity of a carbonatepore system is to be defined.

Fig. 2.3: Early attemptsto model permeabilityas sinuous tubes ofconstant cross-sectionwere not successful,either as representationsof fluid movementwithin a reservoir rockor to calculate oil andgas production rates.Pore size anddistribution are neededto define permeability incarbonate reservoirs.

Fig. 2.5: INNER SPACE:Pore shapes and sizesin carbonate rockssometimes reflect theoriginal particles, butmost vugs are mouldswhich have lost alltrace of originalparticle shape.Modified after A.J.Lomando.


Most carbonate rocks are formed fromaccumulations of skeletal fragments -the remains of carbonate-secreting ani-mals and plants. Although the animalsare better known to geologists, it is theplants, particularly blue-green and redalgae, which, as a major food source formarine micro-organisms, control thedistribution of carbonate sediments.

Numerous methods for carbonaterock classification have been proposedover the past 40 years. The mostwidely accepted method, devised byR.J. Dunham in 1962, concentrates onthe features which control porosity andpermeability, i.e. grain-matrix relation-ships and mud content (figure 2.6).

Boundstone

The components in any boundstonewere organically bound together dur-ing deposition. Blue-green algae andcorals play a major role in this type ofcarbonate sedimentation, producinglaminated carbonates and coral reefsrespectively.

Grainstone

Grainstones are grain-supported car-bonates containing less than 10% limemud. With very little mud blockingthe pore space, grainstones often

CARBONATES CLASSIFIEDMudstone

Less than10 % grains

More than10 % grains

Grain-supported

Lacks mudand is grain-supported

Originalcomponentswere boundtogether

Depositionaltexture notrecognizable

Mud-supported

Contains mud, clay and fine silt-size carbonate

Original components not bound together during deposition

Depositional texture recognizable

Wackestone Grainstone Boundstone CrystallinePackstone

Fig. 2.6: The classification of limestonesdevised by Dunham (1962) is based oninternal features such as mud contentwhich control the porosity andpermeability of the rock.

0.05

0.50

Effe

ctiv

e po

re th

roat

rad

ii de

fined

by

Hg

capi

lliar

y pr

essu

re

50.0

100 50% Hg saturation of pore volume

Good reservoir grainstone

00

500

Hg

pres

sure

(ps

ia)

2000

5

Reservoir grainstone with micropores or isolated macropores

4

1

2

3

Chalk small pores

Apparent progressive decrease in pore sizes

Non-reservoir rock

Good reservoirgrainstone

Reservoirgrainstone withmicropores or isolated macropores

Chalk small pores

25 2000

25 500

25 10

Heterogeneouspore sizedistribution

Non-effective pores

25 50

25 0.1

Rock type pu md

5

4

1

2

3

Fig. 2.7: The relationship between effective pore throat radii and pore volume for some typicalreservoir types (grainstones, wackestones and chalks) with a non-reservoir rock for comparison.All of these sediments could be encountered in the same carbonate sequence.

exhibit high porosity and permeabilityat time of deposition and after diagene-sis. They have the potential to becomeexcellent reservoir rocks. Many of theMiddle East’s biggest and best knowncarbonate reservoirs (e.g. Ghawar Fieldin Saudi Arabia and Zakum Field in AbuDhabi) are grainstones. The pore sys-tems are predominantly interparticle,but microporosity is present in thegrains and in the mud fraction of somegrainstones

31Number 18, 1997

Packstone

Packstones also have a grain-supportedtexture, but the rock contains largeamounts of mud, so the original porosityis lower than in grainstones. Packstonesare typically found in lower energy envi-ronments than grainstones.

Wackestone

In wackestones the carbonate grains‘float’ in an extensive mud matrix. Thisrock type is distinguished from mud-stones by the proportion of grains - morethan 10% of total volume. Wackestonesare typically found in low-energy environ-ments behind a reef or in deeper parts ofa carbonate shelf. The mud and grain frac-tions may contain microporosity.

Mudstone

The low-energy environments in a car-bonate sequence are characterized bylime-rich mudstones with less than 10%carbonate grains.

Reservoir rocks - ramps and reefs

The variations in reservoir performancefor carbonate rocks (figure 2.7) make itcritical that the producing zone is exam-ined in detail and characterized accu-rately before major production decisionsare made. These rocks do not becomereservoirs unless fractured or affectedby dolomitization.

However, carbonates, like sand-stones, occur in identifiable sequenceswhich reflect changing marine condi-

tions and environments (figure 2.8).The best interpretations place eachcarbonate unit in a sequence context.This allows the geoscientist to predictwhat type of changes in permeabilityand porosity may be anticipatedabove or below the zone of interest.

Open littoral

Open reef-shoals

Fore-reeftransition zone

Open basin

Back-reef shoalsReef wall

Reef talusslope Fore-reef

shoals Fore-reeftransition

zone

Fore-reef basin

Reef boundstones

Reef talus grainstones

Back-reef and top-reef grainstones and wackestones Upper shelf slope (fore-reef) packstones and wackestones

Lower shelf slope and basin wackestones and mudstones

Littoral zone and sabkha clastics and evaporities

(a) Ramp

(b) Reef shelf

Fig. 2.8: Carbonates can be deposited in a wide range of marine environments. They typically occur in sequences which can be characterized as

ramp (a) or reef shelf (b) settings. Low-energy environments, such as the back reef shoals, which are protected from wave and current action, are

characterized by higher concentrations of lime mud while clean rocks with high original permeabilities are found in high-energy zones at the

shoreline or around the main reef wall. If the basin area associated with either of these sections generates hydrocarbons the oil and gas should

migrate up the structure (green arrow) into the porous carbonate rocks.

R.J. Dunham (1962) Classification of carbonaterocks according to depositional texture. In:Classification of Carbonate Rocks (ed. W.E.Ham),pp 108-121. Mem. Am. Ass. Petrol. Geol. (1) Tulsa.


Dep

th

Microporous dolomite

Ooids with microporeswithin particles and alsointergranular pores

Ooids with oomoulds andsome intergranular pores

The upwards increase of poresize and pore volume may bedue to grain size decreasingdown the sequence

Position where a packstonefacies might be expected

Wackestone with microporesand moulds

Wackestone with micropores0.1 1.0 10.0 100

30 p

u

Pore size (microns)Pore size distribution (similar to CMR T2)

50 ft

.

Pore size distributions

Fig. 2.9: Poresize and typevary throughthis Jurassicgrainstonesequence.Porosity in thewackestones issimilar to thatin thegrainstonesabove, butpermeability islower becauseindividual poresare smaller.The CMR toolcan identifysmall pores andso improveformationevaluation.

Fig. 2.10: Microporosity in a typicalreservoir carbonate. If these porescontained water, standard well logs mightindicate a water saturation too high for oilproduction. Nuclear magnetic resonancetechniques can characterize these poresquickly and efficiently.

Grainstone shoaling-upward cycles

Shoaling-upward sediment sequenceswith grainstone deposits at the top arecommon within some Jurassic andCretaceous reservoirs of the Middle East.Rocks in the sequence are generallydominated by one type of grain - skeletalfragments, ooids, pellets or a large foramspecies. Whatever the grain type, theshoaling-upwards sequence usuallybegins with mudstones at the base whichgrade into wackestones. In manysequences the proportion of grainsincreases through the succession untilmud-free grainstones develop. Migratingtidal bars may have a thinner or less pre-dictable vertical transition from mud-stone to grainstone.

Microporosity within the grainstonesequence can be predictable, but is usu-ally distributed throughout a reservoir.The micropores may have a relativelysimple diagenetic origin, resulting fromthe leaching and incomplete reprecipita-tion of metastable calcite, or may be influ-enced by tectonic events such as upliftexposing the sequence to fresh waterleaching and diagenesis.

Borehole CMR measurements of poresize distributions in grainstone sequencescan be very helpful for the geologicalanalysis of depositional environments,and can be used to identify major diage-netic modifications in a sediment.

Dealing with microporosity

For more than 40 years microporosityhas been a recognized feature of carbon-ate reservoirs. However, it was not untilthe development of the chalk reservoirsin the North Sea that the importance ofthis type of porosity became apparent.Pore systems dominated by very smallpores can contain large oil and gas vol-umes, but their behaviour is very differ-ent to macro- and mesopore systems.

Experimental programmes to evalu-ate microporosity using reservoir rockare time-consuming and typically con-sist simply of scanning electron micro-scope (SEM) inspection of small spotsamples with little emphasis on howporosity distributions change throughthe sequence (figure 2.9). The CMR tooloffers a cost-effective way to acceleratethe process of defining microporosity(figure 2.10) and irreducible water satu-ration, while providing semiquantitativepore size distributions.

grainmicropore

micritecrystal

x385 x38.5x2560

10µm 100µm 1000µm

W. Kenyon (Schlumberger Doll Research),

H. Takezaki (ADOC - Japan) et al. (1995)

A laboratory study of nuclear magnetic resonance

relaxation and its relation to depositional texture and

petrophysical properties - carbonate Thamama

Group, Mubarraz Field, Abu Dhabi. SPE 29886 MEOS.

Fig. 2.12: Plots for young reservoirrocks which have been altered by gradual and uniform

cementation. The relationship between particle size and this pattern of diageneticeffects is very complex. The graph indicates a general trend in permeability and porosity reduction.Modified from R. Nurmi, GEO/96

33Number 18, 1997

Possible free water

Volume of water from RT

0.0 (PU) 25.0

0.0 0.25

CMR bound fluid

1:200ft

Irreducible water

Moved oil

Residual oilX900

-20 20(IN)

Diff. CaliperPerfs

Bound fluid

Water

Moved hydrocarbon

Oil

Water

Moved hydrocarbon

Oil

Residual oil

Porosity

Calcite

Dolomite

Anhydrite

Fig. 2.11: Some zones which appear to contain too much water for cost-effective oil production actually produce dry oil becauseall of the water in the zone is irreducible (i.e. bound in the rock’s micropores). Modified from M. Petricola and H. Takezaki(1996) Nuclear Magnetic Resonance: It Can Minimize Well Testing. SPE 36328 7th ADIPEC Conference.

In the Middle East, the potential prob-lems associated with microporosity firstbecame apparent as a result of difficul-ties with wells in the Lower CretaceousThamama Group. Predictions about oilor water production, based on log-derived saturation calculations, wereconsistently incorrect because irre-ducible fluids in non-effective microp-ores were being included in porositycalculations (figure 2.11).

Younger rocks have more microporosity (figure 2.12) than their oldercounterparts. The Tertiary carbonatereservoirs of Egypt and India are morelikely to be affected by microporositythan the deep Permian Khuff carbonatereservoirs of the Arabian peninsula. Thisprobably reflects the ease with whichmicropores can be closed by overbur-den pressure following deep burial.


Dolomite is a highly-ordered mineralconsisting of calcium and magnesiumions in separate layers alternating withcarbonate ions. The chemical transfor-mation of calcite (CaCO3) into dolomiteCaMg (CO3)2 can have a profound effecton reservoir properties such as poros-ity and permeability. The conversionprocess may occur at any time in thediagenetic history of a rock sequence -soon after sediments have beendeposited or long after deposition,when cementation has already affectedthe rock. Dolomite may replace thewhole rock or only grains or matrix. Tofurther complicate rock characteriza-tion, dolomite can be replaced by a late-stage calcite influx. This process mayretain the morphology and porosity ofthe dolomite rock, while changing itschemistry back to calcite.

Early, late or not at all?

Supratidal and hypersaline dolomite isproduced through evaporation and itprecipitates at high Mg/Ca ratios. Thisratio is increased by the precipitation ofcalcium-rich minerals which leaves a cal-cium deficit in the pore water.

Late stage dolomitization tends to cutacross depositional units rather thanbeing tied to particular limestone facies.In most cases the late stage dolomitedestroys the existing limestone fabric.

Late stage dolomitization may be per-vasive, where all of the limestone is con-verted to dolomite with only relics of theoriginal components, or selective, where,depending on pore water, sediment chem-istry etc., only the matrix or grains of a par-ticular limestone are replaced.

Dolomite also occurs as randomly dis-tributed rhombs in limestones (figure 2.13)and may occur as a cement in cavities.

The most important consequence oflate stage dolomitization is an accompa-nying increase in porosity. Dolomite hasa more compact crystal structure thancalcite, so in theory the total dolomitiza-tion of a limestone should result in aporosity increase of 13% so long as thereis no subsequent compaction or cemen-tation. Dolomitization generally createsgreater effective porosity, but most dia-genetic changes tend to reduce overallporosity.

Studies have shown that the planar grainsurfaces of dolomites create polyhedralpores. Consequently, as the rhombs developthey produce sheet pores and throats ratherthan the tubular pores and throats whichcharacterize limestones.

DOLOMITE DEFINED AND DESCRIBED

Fig. 2.13: Scanning electron micrograph showing rhombs of dolomite growing over crystalsof calcite which contain high concentrations of magnesium.

35Number 18, 1997

released from the limestone may formanhydrite which plugs the permeabil-ity, creating a dense rock from a porousone. Farther down the slope, very lowpermeability micrites (usually arago-nitic lime muds) are dolomitized, yield-ing intercrystalline or matrix porosity,so the best reservoir units are thosewith the poorest original permeability.

In the Arab-D zone in the Jurassic ofSaudi Arabia, principal productioncomes from detrital, bioclastic or ooliticlimestones. Where oil is produced fromdolomites, however, the rocks whichhave been dolomitized were predomi-nately micrites.

In addition to their capacity to pro-duce porosity in less promising settings,dolomites retain their porosity better thancarbonates during burial (figure 2.15).

Microdolomites that fill limestonemicropores can help to preserve porosityin deeply-buried carbonates (figure 2.16).

Reefs are particularly susceptible todolomitization, because the quiet shal-low waters of the backreef environmentare an ideal site for evaporite deposition.

The distribution of dolomites in thestratigraphic record is not equal. Theproportion of dolomites in oldersequences is higher than in their morerecent counterparts. In Mesozoic rocksthe limestone:dolomite ratio is around10:1, in the Palaeozoic it is 3:1 and in thePrecambrian 1:3. It may be that typicaldolomite-forming environments weremore common in the Precambrian orsimply that the older sequences havehad more time to be exposed to solu-tions capable of causing dolomitization.

All change, again

Dolomite may be replaced by calcite toproduce a limestone again. This pro-cess is referred to a dedolomitizationand usually occurs when the rock isexposed to fresh surface water duringperiods of tectonic uplift.

Identifying ‘dedolomites’ involvesnoting characteristic dolomite crystalshapes (usually rhombohedra) whichhave been ‘replaced’ by calcite or cal-cite crystals with small dolomite rem-nants. In some cases the originallimestone texture is partly regeneratedby dedolomitization; in other cases lay-ers and concretions of fibrous calcitecompletely replace the dolomite.

LimestoneDolomite

Sealevel

Supratidalhypersaline

pond

Beachridge

Evaporativedolomite

crusts

Hypersalinemarine water

Freshwaterlens

Meteoric-marine mixing zone and location of dolomite precipitation

Dep

th (

km)

Porosity (%)

0 10 20 30 40 500

1

2

3

4

5

> 75% limestone

> 75% dolomite

Fig. 2.15: Compaction in dolomites istypically less than in limestones, soalthough dolomites start with lowerporosity at the surface they retain reservoirlevels of porosity to greater depths.

Fig. 2.16: Micropores in limestoneare often closed by diageneticeffects or burial. The tiny grains ofdolomite which form in these porescan preserve microporosity.

Fig. 2.14:Dolomitizationinvolves themovement ofmagnesium-rich fluidsthrough carbonaterocks. The details ofdolomite formationare unclear, but twopossible mechanismsare (a) precipitationaround hypersalineponds as a result ofmarine and meteoricwater mixing and (b)seepage reflux whereseawater seeping intosupratidal lakes issubjected to intenseevaporation andgypsum precipitationwhich raises theMg/Ca ratio insolution.

Several mechanisms have been pro-posed to account for dolomitization (fig-ure 2.14). One critical aspect of theprocess wherever it occurs is thatdolomite preferentially replaces mud-sized particles rather than the sand-sizedgrains in the original limestone.Consequently, the best oil and gas reser-voirs are seldom found in (mud-free)rocks with high primary permeability.

In intertidal and subtidal environ-ments permeable units such as skeletaland oolitic limestones display secondary(leached) porosity that has convertedmoulds into irregular vugs and fracturesinto solution channels. If dolomitizationoccurs at this stage the calcium ions

Sealevel

Intense evaporation

Tidal flat Lake

Area ofdolomitization

Reflux

Seepage

(a)

(b)

As one pore closes...

When sediment is deposited the inter-granular pores are almost always consid-erably smaller, on average, than the rockparticles. Burial makes the situationworse as compaction and cementationcombine to reduce pore size (figure2.17). If no major phase of cementationoccurs, intergranular carbonate poresgenerally remain well-connected untilpressure solution effects at great depthclose them completely.

Intraparticle pores are usually inde-pendent of the effective pore system andmay be preserved to greater depths. Theyare also very variable: their maximumsize is limited only by the dimensions ofthe rock grains. Intraparticle porosity mayoccur as several small pores within a rockparticle or as microporosity spreadthroughout a grain (see figure 2.2).

Making more of micropores

According to the long-established carbon-ate classification system devised byChoquette and Pray (1970), microporesare those with diameters below 1/16 mmwhile a pore with a diameter above 4mmis a megapore (figure 2.18). Pore diameterscan be difficult to visualize, so for a com-parison of relative size it is useful to enlargethe pores. If a 4 mm megapore wasenlarged to the size of a basketball hoop, atypical micropore - at the same scale -would be the size of the eye of a needle.

Micropores are frequently over-looked in core and cuttings, which canhave detrimental effects on productionplans and field development.

Microporosity can also cause barriersand/or baffles to fluid flow. In the Hanifareservoir in the Berri Field, for example,microporosity led to significant volumesof oil being bypassed.

In conventional logging techniquesmicroporosity is not distinguished fromother porosity types. Micropores are usu-ally water-filled, so well logs may indicatethat a reservoir zone is not suitable for

production because it contains too muchwater. However, the water in microporesis often irreducible water that will not beproduced - the micropores are ‘non-effec-tive’ - so the zone would be suitable forcompletion and produce dry oil after all.

To reduce the risk of missing produc-tive zones the CMR tool should be usedin conjunction with a Fullbore FormationMicroImager (FMI*) tool to characterizesedimentary sequences. Preliminary useof the CMR tool has shown that bestresults are achieved if rocks are exam-ined as part of a sequence, allowing thegeoscientist to predict probable poresize distribution and check resultsagainst it, rather than dealing witheach sample independently of itsdepositional framework.

Pore size terminology and examination

Classes

Megapore large Outcropcore

Boreholeimagery

Core,hand-lensthin section

SEM,Hgcapillary

CMR log

CMR log

mm microns

small

Mesopore

Micropore

large

small

1/2

1/16

4 4000

62.5

Mac

ropo

res

(vis

ible

)

Units Examination

(individually invisible to naked eye)

>4 >4000

500

Fig. 2.18: If a typical 4mm megaporewas enlarged to the size of a basketballhoop, a typical micropore, after thesame enlargement, would be the samesize as the eye of a needle.


0

1

10

100

1000

(a) deposition

(b) compaction

(d) fracturing

(e) leachingof cement

15Porosity (%)

30 45

(c) cementation(f) leachingof grains

Permeability (md)

Fig. 2.17: After deposition (a), sedimentsare compacted (b) which reduces inter-particle pore space. Cementation effects(c) also reduce interparticle porosity asmaterial from solution is depositedaround the grains. Fracturing (d) andleaching of cement (e) or grains (f)(usually by fresh water when sedimentsare returned to surface or shallow depthsby tectonic movements) will increaseporosity. From R. Nurmi, 1984, AAPGBulletin.

Moulds and vugs

Moulds are solution voids which retainthe shape of the dissolved fossil or rockparticles. Vugs are enlarged solutionvoids that no longer resemble the origi-nal particle or fossil. Both can be veryimportant for oil production.

However, in some cases, the pres-ence of vugs and moulds has no effecton production. The most important ques-tions to ask about them are:• do they form a continuous network?• is the rock around them porous?

If the network is continuous the vugswill contribute to production directly.However, if the moulds and vugs do notform a network, but the surroundingrock is permeable, then these large sec-ondary pores simply provide additionalstorage in the rock.

If the vugs are not part of a networkand the rock around them is imperme-able they will not produce oil.Megapores, large vugs and moulds arebest identified using electrical imageryand their attributes can be defined usinga computer workstation. Unfortunately,electrical imagery does not help to assessconnectivity away from the wellbore. Acomputer technique has been developedto assess vertical connectivity, but along-bedding connectivity (perpendicular,rather than parallel to the wellbore) ismore common.

Porosity around the wellbore

The porosity and permeability ranges oftypical carbonate rock types, and thegeological processes (e.g. fracturing,compaction, cementation and leaching)which lead from one to another, can berepresented graphically (figure 2.19).

There are often discrepanciesbetween porosity distributions derivedfrom core samples and those from logs.The most important source of this varia-tion is that core and well logs typicallyexamine and average different volumesand, because the two techniques aremeasuring slightly different pore popula-tions, they produce different results.

One of the most effective solutions tothis problem is to use the advancedborehole magnetic resonance technol-ogy of the CMR tool which samples avery small formation volume (figure2.20), and to cross-reference its resultswith electrical imagery.

This solution is of enormous benefitin wells where rock types vary overshort distances, e.g. from one side of theborehole to the other, or where two dis-tinct rock types are intimately mixed butbehave as separate units.

Borehole magnetic resonance is thelatest borehole technology to be intro-duced in the Middle East. The techniquehas been under development for morethan 15 years and even then some oil

Fig. 2.20: The CMR tool offers precise examinationof the borehole wall. Its small measurement volume

is in contrast to other tools which can only provideaveraged porosity values for a much larger volume.

37Number 18, 1997

the CMR tool, core petrophysicists, loganalysts and geologists must cooperate.

Combining the CMR tool with a FMIsurvey, the geoscientist can detect andquantify pore sizes ranging from micro-pores to megapores, which in the mostgeneral sense includes open faults whichmay extend up into a gas zone or downinto an aquifer.

Oriented CMR tool measurementsreveal whether vugs and fractures thatare not connected to each other will con-tribute to production through the rocksurrounding them.

Core

Wellbore cross-sectional view

8 1/4" diameter borehole

CMR measurement volume1" x 1" x 6"

Wellbore

CMRmeasurement

volume1" x 1" x 6"

companies knew it would be essential tocharacterize complex reservoirs.

From years of exploration and produc-tion, geologists have amassed a hugecompendium of information (thin sec-tions, SEM photos, cores, NMR results,pore casts and detailed sample descrip-tions) about the pore systems of carbon-ate reservoirs in the Middle East. Usingthis ‘library’ to guide CMR surveys willhelp to ensure a unique and accurateassessment of effective and non-effectivepores, and so improve saturation and per-meability calculations. The CMR tool alsooffers the possibility of routine evaluationof microporosity and irreducible watersaturation values. To get the most from

P. Choquette and L. Pray (1970) Geologicnomenclature and classification of porosity in sed-imentary carbonates. AAPG Bull., (54) pp 207-250.

Porosity (%)

Fractures

0 10 20 30

Per

mea

bilit

y (m

d)

1000

100

10

1

0.1

0.01

Compactionand cementing Leaching

Leac

hed

chan

nels

in m

etal

roc

k

Par

ticle

dia

met

er =

300

µP

artic

le d

iam

eter

= 1

00µ

Coccolith chalk pore diameter < 1µ

WackestonesMudstones

Moldic grainstone

Packs

tone

s,

Lim

e m

ud

Gra

inst

one,

por

e

diam

eter

dec

linin

g

Vuggy dolomiteWackestone

Par

ticle

dia

met

er =

500

µ

Fig: 2.19: Therelationshipbetween porosityand permeabilityfor variouscarbonate rocks.From: R.Nurmi(1986) Middle EastWell EvaluationReview, issue 1.Land of the giants.


The complex pore systems found insome carbonate oil reservoirs in WestKuwait (figure 2.21) have proved diffi-cult to evaluate. Borehole imagery hashelped to define fractures and faults inwells and, thus, to remove a majoruncertainty from formation evaluation.Standard open hole well logs provideporosity and saturation informationwhich is often insufficient for the evalu-ation of these complex, high-resistivitycarbonate sequences.

In some cases, apparent porosityand saturation can be misleading, giv-ing a false indication of which fluidswill flow and of flow rates from a par-ticular zone.

Low porosity layers can have thehighest permeability in a reservoir, andthe highest porosity interval may becomposed entirely of micropores and,therefore, be impermeable. In somewells, zones which are assessed as hav-ing high water saturation may flow dryoil, and tar mats may be incorrectlyinterpreted as oil zones.

Tests in West Kuwait

In a recent study, three Jurassic car-bonate reservoirs from Minagish andUmm-Gudair fields in West Kuwaitwere selected to test the new loggingtechnique (figure 2.22).

The Upper Jurassic Najmah andMiddle Jurassic Sargelu formations areoverlain by Kimmeridgian GotniaFormation and rest on the BathonianDharuma Formation. The Najmah iscomposed of limestones, usuallyargillaceous, carbonaceous andinterbedded with thin black shales. TheSargelu reservoir consists of an upperunit of clean, densely cementedpeloidal packstones and packstone-wackestones deposited in higherenergy, shallow water, plus a lowerunit of more argillaceous wackestonesfrom a deep water environment.

Primary permeability is generallytoo low for economic flow rates.However, some intervals in the Najmahand Sargelu formations are extensivelyfractured, with these large open frac-tures supporting high fluid flow rates.

Below the Dharuma Formation liesthe Marrat Formation, a limestonereservoir divided into three membersand composed of carbonate grain-stones and packstones interbeddedwith wackestones and mudstones froma shallow shelf setting.

Log interpretation of sequences suchas this has always been difficult. In theorganic-rich Najmah Formation, conven-tional resistivity-nuclear logs often indi-cate apparent high porosity andresistivity zones, but these are oftenfound to be non-reservoir zones.

At the other extreme, the shaliness,dolomitization and organic content of theNajmah and Sargelu formations canreduce porosity estimates dramaticallyin zones that will flow oil from well-developed fractures.

Porosity is generally better in theMarrat Formation than in the SargeluFormation, but there are fewer fractures.However, the widespread development ofmicropores makes permeability estimatesfrom porosity values very unreliable.

Decisions on where to perforate theseunits are, clearly, not simple, and thereare often marked variations in produc-tion rates from intervals where the rockshave the same porosity range.

In an effort to resolve these problemsnuclear magnetic resonance (NMR) sur-vey techniques were introduced intoKuwait early in 1996.

Porosity and production

The problem described below is fre-quently encountered in the Najmahreservoirs. Traditional logs indicate anapparent porosity of 20% and deep resis-tivity values of 100 ohm-m or more,resulting in a water saturation (Sw) valuebelow 10%. Despite these clear indica-tions of a suitable reservoir zone, pro-duction tests yielded no hydrocarbon.

A CMR log was run and showed thatthere was no effective porosity and per-meability in the Najmah Formation.Close core examination showed thatorganic content reached 50% in someinstances. The high organic content isthe source of the readings which nor-mally indicate an oil-saturated andporous reservoir zone.

The low matrix porosity valuesrecorded by the CMR were too low toexplain the flow rates seen in this reser-voir. Using an Ultrasonic BoreholeImager (UBI*) tool, Kuwait Oil Companyassessed the importance of fractureporosity and permeability.

West Kuwait

Minagish

Umm-Gudair

Kuwait City The Gulf

Hith

KimmeridgianUpper

OxfordianCallovianCallovian

BathonianMiddle

ToarcianLower

RhaetianUpper

LadinianUpper middle

ScythianLower Triassic

Bajocian

Bajocian

Carnian

Anisian

TatarianUpper Permian

Tria

ssic

Jura

ssic

Tithonian

Gotnia

Dharuma

Minjur

Jilh

Sudair

Khuff

Najmah

Sargelu

Marrat

KazanianPermian

CARBONATE LOGGING - THE WAY AHEAD

Fig. 2.21: KUWAIT AND SEE: Some of thecarbonate oil reservoirs of West Kuwaitcontain very complex pore systems.Borehole imagery and nuclear magneticresonance have helped to answer thequestions posed by anomalous productionrates and contradictory results fromstandard well logs.

Fig. 2.22: The Jurassic reservoirs of West Kuwait, in the Najmah, Sargelu and Marrat formations,are complex carbonate sequences. Production-related decisions about these units are neversimple, so they provide a perfect test for any new logging technique.

39Number 18, 1997

The CMR tool can be used to checkother permeability measurements Forexample (figure 2.23), where a pack-stone-wackestone series grades intomudstone (as indicated by the decreas-ing pore size trend in the CMR), theDipole Shear Sonic Imager (DSI*) tool-derived permeability values areaffected by mudstone laminations andgive an incorrect value below the faultat X450. The CMR-derived porosityvalue is correct.

Predicting permeability

The porosity of the Marrat Formation isin the range 0-15 % and permeability isvariable. The estimation of permeabil-ity is of vital importance in this majorreservoir. This is a clean carbonatewith a complex pore structure as indi-cated by the T2 distribution log of theCMR.

The Marrat carbonate sequence hasa complex pore size distribution (figure2.24). The CMR tool indicates wherethere is a high proportion of micro-porosity (and a reduction in effectiveporosity and permeability). The lowersection shows porosity decreasingupwards, but permeability increases inthis direction, contrary to the usual rela-tionship between these parameters.However, when CMR permeability isused to calibrate results from the DSItool the results agree with drawdown-derived permeability.

A new approach in West Kuwait

Integration of borehole NMR responsesand other open hole logs can be usedto better quantify the reservoir proper-ties and lead to optimal completion ofwells in the West Kuwait carbonatereservoirs. Borehole NMR has allowedan improved interpretation of: •Effective porosity in complex litholo-gies: it is essential to determine effectiveporosity in the organic-rich NajmahFormation and the Sargelu Formation toquantify the matrix support to the frac-ture systems in these reservoirs.•Permeability: NMR-derived perme-ability allows the correct interpretationof permeability in complex pore geo-metries. Further, the integration of NMRand DSI tool-derived permeabilitieswith ultrasonic borehole images hashighlighted the importance of fracturesin well productivity.• Pore size distribution: an indicationof the pore geometry allows a betterunderstanding of permeability variationin these complex carbonates.

Ahmed A Latif, D. Sungur, I. Stockden and C. Cao

Minh (1997) Borehole nuclear magnetic resonance:

experience and reservoir applications in West Kuwait

Carbonate Reservoirs. SPE 37771

Fig. 2.24: Thisexample from theMarrat Formation.shows that in thelower part of thesequence porositydecreases upwards,but this change isaccompanied by apermeabilityincrease. The CMRtool (track 2)identifies pore sizedistributions, helpingto explain thisapparent anomaly.

Fig. 2.23: This example is taken from the Najmah Formation. Beneath the fault at X450, there isa packstone-wackestone series that grades into mudstone (as indicated by the decreasing pore-size trend in the CMR). DSI permeability values are affected by the mudstone laminations andare incorrect. The CMR-derived porosity value is correct.

x430

x450

x470

x490


In the right environment

Modern carbonate sediments are foundin all major world oceans, but modernreef deposits are restricted to tropicaland subtropical latitudes (figure 2.25).Changing climatic zones tied to tectonicmovements mean that reefs have devel-oped in every continent at some stage ingeological history (e.g. Canada’sDevonian reef reservoirs). Chalks andlimestones are lithified carbonate formedby the dissolution, reprecipitation,recrystallization and compaction of bio-genic carbonate particles. Initial porosi-ties of 70% have been recorded inunconsolidated sediments, althoughthese are rapidly reduced during burial,typically falling to around 10% in lime-stones. Chalks, which form under rela-tively shallow burial (a few hundredmetres), can be considered an inter-mediate step to limestones. The addi-tional cementation that produceslimestones from chalks typically occursat depths in excess of 1000 m.

One of the most unusual properties ofporous chalks is their tendency to retainmicroporosity well after burial. Chalkreservoirs often have high porosity, rela-tively uniform pore size and very well-connected pore space. They arecomposed of micron-sized particles andfragments of disarticulated planktonicnanofossils. Pore size typically rangesfrom 10 microns to a fraction of a micronand the pore throats are usually an orderof magnitude smaller.

Superficially, chalk units may appearvery similar but two chalks with identicalporosity values may behave in very dif-ferent ways. For example, a chalk com-posed primarily of foraminiferal bioclastswill generally display a higher permeabil-ity than one composed of coccolithmicrofossils (figure 2.26).

As depth of burial increases, cement-ation, compaction and recrystallization ofthe low magnesium calcite decrease poresize and volume. Ultimately, this processwill damage the pore system to the pointwhere the loss of permeability means that

Fig. 2.25: ALL OVERTHE WORLD.Modern carbonatedeposits are found inall of the world’smajor oceans andseas but modern reefcarbonates arerestricted to tropicaland subtropicallatitudes.

Pores and diagenesis

The most important stage of diagenesisfor a possible carbonate reservoir iscementation. Early cementation can helpto preserve pore space in a sedimentduring burial. In carbonate rocks, poresmay be of any shape from irregular toperfectly spherical. Carbonates, in con-trast to sandstones, do not usually havethe complete range of grain sizes fromlarge particles down to clays: sandstonescontain sand, silt and clay particles, but‘silt’ size particles are usually missingfrom carbonate deposits. Carbonatescan, therefore, be considered bettersorted at time of deposition. However,this benefit must be weighed against thefact that carbonate particles undergomore post-depositional changes thanquartz grains.

Two common carbonate reservoirsequences, chalks and shoaling grain-stone sequences, are end members ofcarbonate deposition and have very dif-ferent pore systems.

Fig. 2.26: Chalk pore size dataand porosity/permeabilitycrossplot of various samples ina sequence. Grain compositionis very important indetermining the porosityretention of various chalks.Coccolith chalks, for example,will generally have lowerpermeability values thanequivalent chalks composed ofmore coarse-grainedforaminiferal bioclasts.Modified from R. Nurmi,GEO/96.

60°

40°

20°

0°

20°

40°

60°Key: Reef Shelf carbonate Deep carbonate Carbonate oil province

41Number 18, 1997

the rock is no longer of reservoir quality.Early entry of hydrocarbons can halt orslow down this process. The CMR toolidentifies the total pore space in a reser-voir rock and its results can be cross-referenced with mercury-injection analy-sis and whole-pore data derived fromscanning electron microscope (SEM)studies (figure 2.27). If the original poresystem of the carbonate has not beenmodified by diagenesis, then the CMRpore size distributions can be used toinfer particle size at time of deposition.However, where diagenesis has modifiedthe pore system significantly, the CMRshould not be used to infer depositionalcharacteristics. In all cases, even withcomplex diagenesis, the CMR-derived‘free fluid volume’ is the key to assessingthe effective porosity volume.

The industry now accepts that carbon-ate reservoirs are much more compli-cated than early models suggested. Rocktype is not a firm indicator of reservoirquality and the essential factors - porosity,permeability and pore size distribution -can change dramatically through the post-depositional history of the unit. Even highporosity chalks may be poor reservoirrocks at time of deposition if their poresare small (figure 2.28). Any fall in perme-ability may have disastrous conse-quences for production potential. Thecurrent focus of research in chalk reser-voirs is on wettability. This research isbeing pursued through laboratory andborehole NMR methods.

Unexpectedly high permeability inchalks is usually caused by either anotherrock/pore type mixed in the sequence orthe presence of fractures or faults. Openfractures and faults are identified by bore-hole imagery, especially in horizontalwells where many more discontinuitiesare intersected by the borehole.

In some reservoirs thin, coarse-grained beds with relatively large porescan be interbedded with the chalks.These beds may produce surprising andunwelcome effects, including earlywater production from edge waterencroachment.

Rather than relying on samples takenin isolation, geoscientists are now turn-ing to methods that suggest the lateralextent of depositional facies and diage-netic overprints for each reservoir unit.The CMR tool allows the interpreter toaccount for the microporosity which candisguise effective pore systems. Whenrelated to well-designed well tests, thisapproach will ensure that productionand field development strategies reflectthe full extent of reservoir complexity.

Dep

th Shale with no effective pores

Pore size (microns)Pore size distribution (similar to CMR T2)

0.1 1.0 10.0 100.0

Micropores

Ave

rage

por

osity

30%

Ave

rage

por

osity

30%

-?- Mesopores

50 p.u.

Fig. 2.28: Thischalk sequencecontains a shaleunit with noeffective pores.The carbonaterocks above andbelow haveaverage porositiesof 30% but most ofthis is concentratedin small pores (lessthan 10 microns).Larger pores areconcentrated at (a)and it is from thislayer that fluids arelikely to flow.

0.10

20

40

Cum

ulat

ive

% p

ore

spac

e

Diameter (microns)

60

80

100

1.0 10.0 100.0

Pore apertures(Hg-injection data)

Whole pores(image data)

Fig. 2.27: Comparison of Hg injection andimage-derived whole-pore data (from SEM)shows that pore throats are about one tenththe size of whole pores. The CMR toolmeasures similar features but presentsresults for all pore space in the rock.

(a)

carbonate reservoir

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