oilfield

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Non equidem insector delendave carminaLivi esse reor, memini quae plagosummihi parvo Orbilium dictare; sedemendata videri pulchraque et exactisminimum distantia miror. Inter quaeverbum emicuit si forte decorum, et siversus paulo concinnior unus et alter,iniuste totum ducit venditque poema.Nonequidem insector delendave carmina Liviesse reor, memini quae plagosum mihiparvo Orbilium dictare; sed emendatavideri pulchraque et exactis minimumdistantia miror. Inter quae verbumemicuit si forte decorum, et si versuspaulo concinnior unus et alter, iniustetotum ducit venditque poema.

Oilfield water:a vital

resource

Reservoir engineers can use water toperform useful tasks such as maintainingreservoir pressure, but when waterappears in the wrong place it createsmajor problems for the oil and gasindustry. Excessive water productionreduces profitability, increases corrosionrates and compels operators to expandtheir water treatment and disposalsystems serious environmentalproblems can arise if produced water isnot handled properly.

In this article, Fikri Kuchuk, MahmutSengul and Murat Zeybek outline thefactors controlling the distribution ofoilfield water and the methods used toassess porosity and permeability inreservoir rocks.

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M i d d l e E a s t We l l E v a l u a t i o n R e v i e w

Water is present in every oil field.Connate formation water,injected water and producedwater must all be dealt with if oil and gasproduction rates, and total recovery are tobe maximized. Modern productiontechnology aims to identify and assess theoverall distribution of reservoir water andto monitor and control the movement offormation and injection water.

Sedimentary rocks are usually depositedin water, with layers of sedimentaccumulating in rivers, lakes, shallow seasand on the ocean floor over many millionsof years. Consequently, most sedimentaryrocks are water-wet. The water present inthe rock from the time of deposition isknown as connate water. As sediments areburied and lithified, connate water willundergo major changes in composition. Insome cases it may be diluted or displacedby other waters, while in oi l and gasreservoirs some connate water has beendisplaced by hydrocarbons.

Hydrocarbon-bearing formations almostalways contain several immiscible fluids.Water that does not flow as reservoirpressure falls is known as irreduciblewater.

Figure 1.1 shows the fluid distributions ina typical reservoir before production orinjection begins. Above the free-oil levelthe water saturation will be at its irreduciblevalue. The transition zone between thefree-oi l and free-water levels ischaracterized by a gradual increase ofwater saturation to 100%. In this zoneboth oil and water are partially moveable.The thickness of the transit ion zonedepends on factors such as pore size,capillary pressure, wettability, etc. There isa transition zone between the hydrocarbonand water layers where water and oilsaturation vary. In general, low-permeabilityrocks will have thicker transition zones.

In shale sequences the bound water inthe pores is not normally considered partof the fluid flow. However, shale-boundwater makes it much harder to estimatewater saturation accurately from logs.

Water that can be displaced from thereservoir during production is referred toas free water. The total water content in ahydrocarbon-bearing reservoir rock (freeand irreducible) is formation water.

In simplest terms, the water saturation ina formation is the fraction of its porevolume occupied by water. A formationthat contains only water has a watersaturation of 100%. The water saturationof any formation can vary from 100% toquite low values, but it is rarely, if ever,zero. No matter how rich the oil or gaslayers in a reservoir, there is always a smallamount of capillary water that cannot bedisplaced by the hydrocarbons. A formationat irreducible water saturation will producewater-free oil.

In much the same way, it is impossible tof lush al l of the hydrocarbons from areservoir by ordinary f luid drives orrecovery techniques. Some hydrocarbonswill always remain trapped in the poresystem. This is referred to as the residualoil saturation.

Changing water into brine

The nature and quantity of formationwaters have a direct inf luence on oi lexploration and exploitation. Normal seawater contains around 3.5% dissolvedmaterial (often expressed as 35,000 ppm).About 90% of this dissolved material issodium chloride. The water in an oil andgas reservoir is very different. At depths inexcess of a few hundred meters thedissolved materials found in formationwaters are at a very high concentration.Formation waters with very high mineralconcentrations (typical ly those above100,000 ppm) are referred to as brines. Inextreme cases, formation waters maycontain more than 300,000 ppm.

The most concentrated brines are foundin undeformed basins, such as those whichoverlie geologically stable shield areas.

Free-oillevel

Free-water level

Gas and water

Oil, gas and water

Water

Oil and water

Density-neutron Pressure (psi) Resistivity

TVD

7200

7100

Water

Oil

Gas

GR

Figure 1.1: Reservoirs

which contain water, oil

and gas develop a series

of transition zones (left).

Modified from Amyx,

Bass and Whiting.

Formation pressures

(below) can be used to

define fluid type at any

given depth and to

locate fluid contacts

(1960) Amyx, Bass and Whiting, Petroleum Reservoir

Engineering, McGraw-Hill, New York

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Brines may also be part icularlyconcentrated in areas where thesedimentary sequence contains evaporiteunits. Waters in these stable basins becomenaturally concentrated with time and areprotected from meteoric water dilutionthrough the outcrop (Figure 1.2a). Basins inwhich reservoir rocks are close to outcrop,or where the rock sequence is stronglyfaulted, are generally characterized byoilfield waters with a lower salinity (Figure1.2b). Dilution by invading waters canreduce the mineral content of formationwater to 1% or less.

Analyses of formation waters are vital forexploration and effective oi l f ieldmanagement. The chemical differences

between various waters can be displayedgraphically for quick comparisons. One ofthe most common representations is theStiff diagram (Figure 1.3) where bars aredrawn with lengths proportional to theconcentrations of the various ions. Cationsare plotted on the left and anions to theright, providing a simple fingerprint forvarious water chemistries.

The salinity of oilfield waters usuallyincreases with depth. In some very thicksandstone sequences, however, formationwaters may become less saline with depth.As the concentrations of sodium andchloride decrease, the concentration ofdissolved silica rises. This is characteristic ofsome young, thick delta sequences with

High-salinity formation waterEvaporite seal

a)

b)

Low-salinity formation water

multiple sand reservoirs that weredeposited during cycles of marinetransgression and regression. The lowersands in the sequence were deposited in afresh-to-brackish deltaic environment,whereas the upper part is dominated bymarine rocks and waters.

Reserve determination is a crucial part ofoilfield development. Porosity, permeability,fluid saturations and distributions are someof the most important properties forreserves estimates and production planning.

Fresh water

Sea water

Tertiaryoilfield water

Cretaceousoilfield water

Eoceneoilfield water

Scale (M equiv.1-1)

NaCaMgFe

ClHCO3SO4CO3

100101010

Lower Paleozoic

oilfield water

Figure 1.2: Deep-buried waters in stable basins (a) become naturally concentrated

with time and are protected from meteoric water dilution. Formation water in

shallow, faulted or unstable basins (b) is often diluted by surface water

Figure 1.3: The Stiff diagram is a quick and clear way

to represent the chemical differences between various

waters and brines

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Aquifers

Most oil and gas reservoirs have developedas a result of hydrodynamic interactionsbetween oil and water. In addition to thewater present in oil- and gas-bearingformations, many major reservoirs arebounded by large water-bearing unitsknown as aquifers. Aquifers are generallymuch larger than hydrocarbon reservoirsand are integral parts of regional watersystems.

Aquifers influence hydrocarbon migrationand can provide the natural drive for oilproduction (Figure 1.4). This closerelationship, and the fact that waterfloodingis the most important method for secondaryrecovery, underline the importance ofeffective water management.

Understanding aquifers and the bottom-or edge-drive they provide is a crucial partof reservoir operations. Reservoirengineers must determine thepetrophysical and flow properties of theiraquifers in order to determine the pressuresupport they can offer the reservoir and topredict water encroachment.

Traditional logs are complemented bytesting systems such as the MDT* ModularFormation Dynamics Tester tool whichprovides crucial information about fluidproperties in the aquifer and in the oil, gasand transition zones. One of the mostfundamental applications for the MDT toolis direct evaluation of oilwater and gasoilcontacts (Figure 1.1b).

In one recent Middle East operation theMDT tool was used to evaluate horizontaland vertical permeabilities (mobility), from asingle well interference test, and to sampleformation water in a straight hole. The dualinflatable packer module, single probemodule, OFA* Optical Fluid Analyzersystem, sample chambers and pump-outmodules were used to conduct theevaluation.

After conducting pretests and establishingthe degree of communication within theformation, engineers performed theinterference test by withdrawing fluids atthe dual packer using the pump-outmodule. The pressures at the packer and atthe probe (6.4 ft) above the dual packerwere recorded with high-resolution quartzgauges. These modules were alsoequipped with strain gauges whichprovided backup pressure measurements.

During the drawdown period, pressuredropped 400 psi at the packer and 65 psi atthe probe. The flow rate at the dual packerwas around 10 B/D.

Thickness(ft)

Horizontal mobility(md/cp)Packer Probe

Vertical mobility(md/cp)Packer Probe

Ct(1/psi)

11 2.88 2.3 2.2 2.28 1.76X10-6

Table 1.1: Horizontal and vertical mobilities, obtained from the packer and the probe analysis

Figure 1.5: Derivatives

and pressure differences

during build up at the

packer and at the probe

Water

Water

Water

Trap I Trap II Trap III Trap IV(a)

(b)

(c)

1e+03

1e+02

1e+01

1e-01 time (sec)

Packer pressure (PAQP)Packer rad derivative (PAQP)

Monitor pressure (BQP1)Monitor rad derivative (BQP1) p

ress

ure

and

deriv

ative

s (ps

i)

1e+00 1e+01 1e+02 1e+03

Analysis showed spherical/hemisphericaland radial flow regimes at the dual packer.The derivative at the probe also revealed aradial flow regime, indicating the totalsystem behavior seen by the twomeasurements (Figure 1.5).

Horizontal and vertical permeabilities wereobtained by reconstructing the pressure andthe derivative at the packer and at the probe.The computed parameters from the matchbetween modeled and measured pressurederivatives is shown in Table 1.1. The

Figure 1.4: Many oil and gas accumulations are bounded by large aquifers that

influence hydrocarbon migration and provide the natural drive for oil production

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reconstruction of the pressure and thederivative at the probe produced an almostperfect match. The results at the dual packerand the probe were consistent with thosegiven in Table 1.1. These results suggestedthat the rock was, broadly speaking,homogeneous and isotropic assessmentswhich were subsequently supported byborehole images and core samples.

Sampling success

Extensive field experience has proved thatrepresentative formation fluids can becollected using the MDT tool. However,when the objective is to sample formationwater in relatively low mobility formationsthe process can be extremely complicated.In this case the MDT tool collected a high-quality sample of formation water from alow-mobility limestone formation (seeTable 1.1).

The sampling operation was conductedafter the interference test. Prior tosampling, filtrate was removed with thedual packer. This was achieved bywithdrawing formation fluids through thedual packer using the pump out module.The dual packer provides 3.2 ft of testableformation interface between two inflatablepackers. The area open to f low is athousand times larger than would be

available with a conventional probe. Thisallows the reservoir engineer to achievehigher flow rates and less drawdown thancan be achieved with the probe.

The OFA system allowed real-timeidenti f icat ion of f lu ids as they werepumped out through the dual packer. Atthe same t ime pressure data wererecorded at the dual packer.

The OFA system pin-pointed thechanges from mud to water with filtrateand finally formation water. The pressuredrop during this pump-out procedure wasaround 440 psi. Resistivity readings are notreadily available through the dual packermodule, so the formation water wassampled by extensive pump-out throughthe dual packer. After 370 liters of fluids hadbeen pumped out, formation watersamples were collected in two 1-gallonsample chambers. Analysis of these samplesverified the original formation water.

Aquifers in action

Aquifers provide pressure-support toreservoirs by a process referred to as waterinflux (or encroachment) by expansionand/or replenishment by surface waters.The petrophysical and hydrodynamicproperties of aquifers are not generally well-known and the aquifer is usually treated as

an infinitely large body. Aquifers are veryrarely pressure tested, cored or logged, andestimates of aquifer support are often basedon empirical equations.

In contrast, the properties of water foundin the reservoir layers are examined in greatdetail. There are several ways to determinewater saturation in the oil and gas layers.Initial water saturation is usually estimatedusing core measurements, and open-holeand cased-hole logs.

Deep drilling difficultiesThe majority of water problemsencountered in the o i l f ie ld areassociated with the processes of injectionand production. However, naturaloverpressured zones in a reservoirsequence can present serious problemsand additional costs during drilling.

In Abu Dhabi, operators frequentlyencounter high-pressure formation saltwater flow (HPFSWF) problems whendri l l ing PermoTriassic and Paleozoicformations (Figure 1.6). The overpressurethey encounter is influenced by a range ofgeological factors: depth, facies changes,reservoir type and sealing properties. As aresult, overpressure conditions can varyfrom well-to-well within a very small area.

Note:This section is not penetrated by wells in Abu Dhabi.Recent penetration of Silurian shales on the Qatar arch by well bore suggests that sequence may extend toAbu Dhabi.

Age Formation/lithology Mainreservoirs Main sealsReservoirsubunits

G1 to G8

K1 to K4

UppersandLowersand

? ? ? ? ?

K5 to K7

Minjur

Jilh/Gulailah

Sudair

Upper Khuff

Lower KhuffMiddle Anhydrite

Pre-KhuffHaushi

Tawil

SharwaraTabuk

Saq

Hormuzsalt

Basement complexPre-Cambrian

Infra-Cambrian

Cambrian

OrdovicianSilurian

Devonian

Carboniferous

PermianLr

Lower

Middle

Upper

Tria

ssic

Mes

ozoi

cPa

leoz

oic

Uppe

r

Figure 1.6: Permo

Triassic and Paleozoic

stratigraphy of Abu Dhabi

02000

4000

6000

8000

10,000

12,000

14,000

16,000

18,000

20,000

22,0000 40

30" casingat 336

Casing diagramSize and depth (ft/brt)

80 120

160

200

240

280

320

Time (days)36

040

044

048

052

056

060

064

0

Mea

sure

d de

pth

(ft/brt

)

171/2" hole

121/4" hole(12 cores)

Kill the well121/4" hole

Stuck pipe

LoggingCore and logging

Kill the well

30" cond. at 336

26" hole

20" casing at 5403

133/8" casing at 10,999Sidetrack at 11,420 Back off at 11,886

Plug back at 8720

End of fishingat 14,553

(Recovered 2667 )95/8" liner at 15,800

Tied back95/8" casingfrom 10,480to the surface

Kick at 20,363

Kick at 16,053

20" casingat 5403

133/8" casingat 10,999

95/8" casingat 15,800

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Figure 1.8: A fish was left

in hole which was plugged

back and sidetracked at

11,420 ft. Drilling

resumed, reaching

15810 ft (above the

problem depth) where

9-5/8-in. liner was run

and cemented. From: A

Rahman, Al-Tawil and I

Azzam, SPE 36297

In the Gulailah/Jilh, Khuff and Pre-Khuffsections heavy drilling fluids have been usedin conjunction with intermediate casingsthat must be set in the problem formationsto control overpressure.

Most of the deep wells (below Triassic)drilled in Abu Dhabi have encountereddiff iculties with one or more of thefollowing: drillstrings, fishing operations,casing cement failure, formation and mudproblems. Complex and localized variationsin pressure (Figure 1.7) mean thatexploration drilling must be conducted withgreat caution and must be backed up bywell-control plans with broad safety margins.

A challenge in the Khuff

The problems encountered in one wellillustrate the range of challenges facingdrillers and well engineers. The primaryobjective of the well was to dri l l to20,436 ft in the Pre-Khuff and explore thehydrocarbon potential of various Khuff andJurassic reservoirs. Five casing sizes wereplanned for the well. Three of these wererun and cemented before HPFSWFproblems were encountered.

Upper sealGulailah

a

a) Upper normal pressureb) Middle overpressurec) Lower overpressure

Lower seal(middleanhydrite)

c

b

(G 1)(G 2)

Figure 1.7: Complex variations in pressure with depth.

Two pressure seals, Gulailah and the middle anhydrite,

separate two overpressure systems. From: A Rahman,

Al-Tawil and I Azzam, SPE 36297

The first indication of a problem came inthe Jilh Formation at a depth of 16,053 ftwhile drilling 12-1/4 in. hole (mud specificgravity 1.44). A fish was left in the holewhich was plugged back and sidetracked at11,420 ft. Drilling was resumed and thesidetrack reached 15,810 ft (above theproblem depth) where 9-5/8-in. liner wasrun and cemented (Figure 1.8). Drillingcontinued with 8-1/2 in. hole andpenetrated the lower Khuff at 20,632 ft(mud specif ic gravity 1.65) with noindication of the Jilh Formation salt waterflow that had posed a problem in theoriginal hole. At 20,363 ft, in the lowerKhuff, the well kicked. The kick was causedby salt water flow from the formation andengineers est imated that mud with aspecific gravity of 2.32 would be requiredto kill the well.

The operators pumped 4000 barrels ofmud with various speci f ic gravit ies(1.892.29) in an effort to control the well.Once annulus and drill-pipe pressures hadfallen to zero, efforts to circulate the well athigh pressure brought no returns and thestring was stuck. From this, i t wasconcluded that the annulus was packed-off

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OMAN

Dubai

Al AinABUDHABI

IRAN

QATA

RDoha

QATAR

Case study well

SAUDI ARABIAOther wells with overpressure problemsLow geothermal gradient 3.5C / 100m

Figure 1.9: The first

stage coincides with

hydrocarbon maturation

at the depocenters,

particularly in areas with

high geothermal

gradients, which creates

abnormal increases in

fluid volume and pore

pressure. From:

A Rahman, Al-Tawil and

I Azzam, SPE36297

and that the drill pipe was plugged-off.When efforts were made to work the drillstring free, it parted at 11,886 ft and thewell kicked again. This indicated that thebridge in the annulus was above the shoeof the parted drill pipe and the plugged drillpipe was left in-hole with the stuck section.The well continued to flow, despite beingtreated with 1400 barrels of mud (specificgravity 2.32).

A leak-off test showed that the formationwas fractured. Further efforts to control thewell failed and as the drill pipe was beingpulled out it parted. Fishing operationsrecovered 2667 ft out of a total stuck pipelength of 8477 ft.

None of the well objectives wereachieved. Efforts to solve the problem andcontrol the well took 170 days and costmore than $12 million.

From their examination of HPFSWFproblems encountered in Abu Dhabisdeep wells, ADNOC (Abu Dhabi NationalOil Company) engineers have reached the

following conclusions about deep drilling inthe region: at least one extra casing should be

allowed for in the well plan pipe sticking is almost inevitable when

formation salt water remains in contactwith the filter cake of water-base mud

oil-base mud is a useful way to controlHPFSWF

intraformational pressure seals, faults andfracture distributions should be found toevaluate pressure compartments.

The origins of overpressure

Experience and field evidence in AbuDhabi support one of the most widely-accepted models for the development ofoverpressured formations. The first stage,in this two-stage process, coincided withhydrocarbon maturat ion at the basindepocenters ( locat ions of maximumsedimentary deposition), particularly inareas with high geothermal gradients

(Figure 1.9). This stage created abnormalincreases in f lu id volume and porepressure. A later increase in temperature,caused by lower thermal conductivity andfluid migration in the overpressured zone,contr ibuted to the development ofoverpressure through thermal expansionof fluids.

The areas with the highest geothermalgradients in southern, onshore Abu Dhabiwere depocenters for the Gulailah andKhuff formations. This may indicate thatoverpressuring in the PermoTriassic/Paleozoic sequences first developed at oraround the depocenters, and that itssubsequent spread was controlled by thedistribution and efficiency of regional sealsin the area.

(1996) A Rahman, Al-Tawil and I Azzam,

Prediction of high-pressure formation salt water flow in

deep drilling in Abu Dhabi area, SPE 36297

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M i d d l e E a s t We l l E v a l u a t i o n R e v i e w12 M i d d l e E a s t We l l E v a l u a t i o n R e v i e w

injection begins. Above the free-oil levelthe water saturation will be at its irreduciblevalue. The transition zone between thefree-oi l and free-water levels ischaracterized by a gradual increase ofwater saturation to 100%. In this zoneboth oil and water are partially moveable.The thickness of the transit ion zonedepends on factors such as pore size,capillary pressure, wettability, etc. There isa transition zone between the hydrocarbonand water layers where water and oilsaturation vary. In general, low-permeabilityrocks will have thicker transition zones.

In shale sequences the bound water inthe pores is not normally considered partof the fluid flow. However, shale-boundwater makes it much harder to estimatewater saturation accurately from logs.

Water that can be displaced from thereservoir during production is referred toas free water. The total water content in ahydrocarbon-bearing reservoir rock (freeand irreducible) is formation water.

In simplest terms, the water saturation ina formation is the fraction of its porevolume occupied by water. A formationthat contains only water has a watersaturation of 100%. The water saturationof any formation can vary from 100% toquite low values, but it is rarely, if ever,zero. No matter how rich the oil or gas

layers in a reservoir, there is always a smallamount of capillary water that cannot bedisplaced by the hydrocarbons. A formationat irreducible water saturation will producewater-free oil.

In much the same way, it is impossible tof lush al l of the hydrocarbons from areservoir by ordinary f luid drives orrecovery techniques. Some hydrocarbonswill always remain trapped in the poresystem. This is referred to as the residualoil saturation.

Changing water into brine

The nature and quantity of formationwaters have a direct inf luence on oi lexploration and exploitation. Normal seawater contains around 3.5% dissolvedmaterial (often expressed as 35,000 ppm).About 90% of this dissolved material issodium chloride. The water in an oil andgas reservoir is very different. At depths inexcess of a few hundred meters thedissolved materials found in formationwaters are at a very high concentration.Formation waters with very high mineralconcentrations (typical ly those above100,000 ppm) are referred to as brines. Inextreme cases, formation waters maycontain more than 300,000 ppm.

The most concentrated brines are foundin undeformed basins, such as those whichoverlie geologically stable shield areas.Brines may also be part icularlyconcentrated in areas where thesedimentary sequence contains evaporiteunits. Waters in these stable basins become

Advantages Disadvantages

Core Direct measurement of rock properties

Capillary and wettability characteristics can be evaluated

Dynamic rock properties which control fluid movement (permeability, etc.) can be measured

Nature and distribution of porosity can be assessed

Costly in rig time

Increased risk of drillstring sticking

Drilling mud filtrate contamination

Laboratory test conditions do not match reservoir conditions

Logs Measurements at reservoir conditions

Can be performed after drilling

Less expensive than coring

Indirect measurements of rock propertiesTable 1.2: Advantages

and disadvantages of

coring and logging

techniques

Water is present in every oil field.Connate formation water,injected water and producedwater must all be dealt with if oil and gasproduction rates, and total recovery are tobe maximized. Modern productiontechnology aims to identify and assess theoverall distribution of reservoir water andto monitor and control the movement offormation and injection water.

Sedimentary rocks are usually depositedin water, with layers of sedimentaccumulating in rivers, lakes, shallow seasand on the ocean floor over many millionsof years. Consequently, most sedimentaryrocks are water-wet. The water present inthe rock from the time of deposition isknown as connate water. As sediments areburied and lithified, connate water willundergo major changes in composition. Insome cases it may be diluted or displacedby other waters, while in oi l and gasreservoirs some connate water has beendisplaced by hydrocarbons.

Hydrocarbon-bearing formations almostalways contain several immiscible fluids.Water that does not flow as reservoirpressure falls is known as irreduciblewater.

Figure 1.1 shows the fluid distributions ina typical reservoir before production or

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At present there is no reliable technique todetermine the lateral distr ibution ofpermeability. It is usually estimated fromcore and/or log porosity measurements.However, at the flow unit (i.e., simulationblock grid) scale heterogeneity affects bothlateral and vertical permeabilities.

The MDT tool provides a part ia lsolution to this problem. Where tests areconducted in association with a goodgeological description the MDT tool canprovide permeability estimates with aradius of invest igat ion in the range1050 ft depending on format ioncharacter ist ics and durat ion of theproduction and buildup periods.

Without 4D dynamic pressuremeasurements that are spatially distributedit is virtually impossible to estimate thespatial distribution of permeability at thereservoir scale. The next millennium willsee the development and application of 4Dpressure transient testing.

Water supply well(WSW)

Surface facility Surface facility

Water injection well(WIW)

Disposal well

c g

h

b d

Reservoir

e

f

Aquifer 2Aquifer 3

a

Aquifer 1

Fluid flow path

Pres

sure

Water from three aquifersWSW Scaling and corrosionSurface facility Corrosion,scaling, oxygen ingress and pluggingWIW Corrosion and scalingReservoir Mineral formation,dissolution, scaling, finesmigration and formation damageOil well Scaling, corrosion, PI decline and equipment failuresSurface Scaling, corrosion, pluggingand down timeScaling and corrosion

abc

de

f

g

h

a b c d e f g h

Figure 1.10: A stylized injection/production/disposal cycle from an onshore oil field

Conclusions

In the early days of Middle East oil and gasdevelopment there was little reason toworry about water production. Many ofthe major fields in the region producedvery little water and, given their size, thereseemed to be no reason to believe theywould for years to come. The giant MiddleEast fields discovered in the 1960s and1970s have now been in production for 20or 30 years, and water cuts are rising.

Since the late 1980s there has been anincreasing awareness of water controlissues in the major oil and gas reservoirs inthe Middle East and elsewhere. Effectivewater control can help to reduce the costsassociated with production facilities, and toprotect the environment by reducing thevolumes of produced water for disposal.

Water problems can be encountered atevery stage of oilfield development and atevery point in the injection/productioncycle (Figure 1.10). Oilfield managers mustbe aware of potential problems and makestrenuous efforts to protect faci l i t iesthrough regular inspection and monitoringprograms. Efforts to monitor and controloilfield water are now a central part of fielddevelopment and management.

oilfield

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