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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.

The reservoirs of the Middle East presentgeologists and engineers with some verydifficult challenges. Excessive waterproduction is all too familiar in many of theregions mature giant fields. The first steptowards successful treatment is anaccurate diagnosis of the water sourceand fluid pathways. There are many toolsand techniques available for diagnosis andtreatment. Effective treatment calls foran integrated approach to monitoring,problem diagnosis and treatments.

In this article Fikri Kuchuk and MahmutSengul examine the production issuessurrounding water problems and guide usthrough the range of potential treatments.

The challengeof water

control

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I n the past, reservoir engineers werehappy to assume that their wells hadhydraulic integrity and that all of thefluids entering the wellbore were going tothe right places. Only when they receivedclear indications that this was not the casewould the engineers begin their search forthe problem. Modern reservoir monitoringhelps to alert reservoir engineers andmanagers to water problems earlier, butdoes not usual ly provide a precisediagnosis. When monitoring indicates thatsomething is wrong, the reservoir engineermust examine al l avai lable data todetermine the cause before planning ordelivering the appropriate treatment.

Production logging is designed to providedata in several key areas: well diagnostics,production monitoring, injectionmonitoring and well testing. The aims andobjectives of these production loggingactivities have not changed, but the loggingenvironment has become much morechallenging. For complete control of anywell, the details of hydrocarbon and waterentry must be clearly understood.Engineers must also be able to measure theflow rates for each phase.

Developments in production logginghave not kept pace with the growingcomplexity of the logging environment.High-angle and horizontal wells complicatedownhole f luid behavior. In maturereservoirs under waterflood, for example,water breakthrough from high-permeability layers is becoming more andmore common. Techniques that can pin-point and shut off layers producingunwanted fluids are of vital importance. Asfields are depleted and reservoir pressuredeclines, gas will come out of solution,result ing in three-phase f low; newproduction sensors are needed to measurethese phases.

Over the past few years there have beendramatic improvements in themeasurement and understanding ofmultiphase flows in producing wells. Theincreased emphasis on production logginghas shown that evaluation can be difficultwhen conventional production loggingmethods are applied. Even in vertical wells,engineers often receive only qualitativeinformation, so plans for remedial work arebased on a partial understanding of wellconditions. Intervention after logging mayrequire a rig move and can, therefore, bevery expensive. This makes it veryimportant that the interventions aresuccessful; accurate logging data are thebest way to minimize the risks.

Conventional production loggingequipment such as spinners orGradiomanometer* specific gravity profiletools are global sensors. This means thatthey respond to more than one of the fluidphases present in the multiphase wellboreenvironment. A detailed fluid mechanicsmodel is required to make sense of thedata, but these models are still in theirinfancy. Fluid phases will be traveling at verydifferent velocities, and phase segregationsfrequently occur across the wellbore. Innear-horizontal wells phase separation canbe almost complete (Figure 3.1) and thismakes it impossible to interpret data fromspinners or even nuclear tools as theirresponses are affected by flow geometry.

A fresh start in productionloggingThe latest approach to the problem ofmeasuring flow in complex environmentscombines global sensors with those thatrespond locally. If these local sensors aresmall and have a rapid response, they canprovide data about the phase they are in atany given t ime. When these localmeasurements are combined with globaldata a clearer picture of complex fluidbehavior emerges. An added advantage of

Holdup

Velocity

Pure oil

Pure waterPure water

0

1

Figure 3.1: In near-horizontal wells phase separation can be almost complete

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local sensors is that f luid data can beobtained from a single plane within thewellbore, making water and hydrocarbonentry detection much more accurate. Thereservoir and production engineers idealsystem would provide: accurate holdup measurements to

identify first entry points for hydrocarbonor water, particularly in gas wells or wellswith high water cut

independent oil, water and gas flow ratesversus depth to provide overalldownhole flow rates and to identifyproduction from each zone orperforated interval

quantitative fluid identification that couldhelp determine the types of fluidproduced from each zone

images of the wellbore to determinecross flow, phase segregation andcirculating flow

system flexibility to minimize costs andaccess all types of wells.The new PSP* Production Services

Platform configuration represents a dramaticadvance in production logging. Traditionalmeasurements such as pressure,temperature, density and spinner have allbeen redesigned to deliver better accuracyand resolution. New sensors, such as localelectrical probes for holdup and an integratedXY caliper, help to provide accurate answersin the most complex flow regimes.

Water problems andsolutionsA large part of a reservoir and productionengineers job involves trying to reducewater production, enhance recoveryefficiency, improve reservoir management,and meet environmental standards. Toachieve these objectives, the engineer willrely on a range of conformance methods.While these methods might not alwaysincrease production, they can bring otherimportant benefits such as: extended productive life for a well reduced lifting costs reduced well maintenance costs reduced water treatment and disposal better environmental practices.

Once a water problem has beenidenti f ied, engineers must select anappropriate treatment method and designan effective treatment program.

Production from channels

behind casing

Poor cementing can leave gaps andchannels in the annulus between the casingand the borehole wall. Water producedfrom channels behind the casing can beidentified using the WFL* Water Flow Logtool, the FloView* holdup measurement

tool and the USI* Ultrasonic Imager tool.Left unchecked, water movement throughchannels in the cement can cause severeproblems for producing wells, but there aremany water shut-off techniques.

In Egypt, the Gulf Petroleum Company isrunning MPBT mechanical bridge plugs toisolate the water entry zones in its wells. Arecent survey measured the performanceof these water management operations andthe results were impressive. In the RasShukeir area in the Gulf of Suez, 129 jobswere performed between December1991 and November 1998. The oi lproduction gain for each job was 2,114BOPD and, on average, these gains paidfor the control job in less than three days.More than 85% of the wells were treatedsuccessfully and the cumulative productionincrease amounted to 272,746 BOPD.

Elsewhere in Egypt, through-tubingbridge plug (TTBP) water shut-offworkovers in October Field led to averageinitial production increases of around2500 BOPD per job, with average watercut reduced from 55% to 16%. Almost90% of the water shut-off workoversconducted since 1991 have been technicaland economic successes.

October Field has been in productionsince 1979 and water cut has increasedsteadily in recent years (Figure 3.2). Thishas led to steeper production declines thanhad been predicted and posed a number ofoperational problems with the fields gas lift.In each well, lower zone water wasisolated using TTBPs. A thick cement capwas then placed over the TTBP using adump bai ler to provide a permanentpressure seal. After a 24-hour shut-in forcement curing, almost all of the wellsreturned to production at significantlyhigher oil rates with dramatically-reducedwater cuts. The cost of a rigless TTBPwater shut-off workover is much less thanthat using a conventional rig.

240,000

200,000

160,000

120,000

80,000

40,000

0

80

60

40

20

0Water cut (%)

Oil rate(bbls/day)

79 80 81 82 83 84 85 86 87

Year

88 89 90 91 92 93 94 95 96

Total liquid rate (bbls/day)

Number of wells on production

Figure 3.2: Water cut increase in Egypts October Field

(1996) DC Borling, BS Powers and N Ramadan,

Water shut-off case history using through-tubing

bridge plugs; October Field, Nubia Formation,

Gulf of Suez, Egypt, SPE 36213

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Another technique for the shut off ofbehind-casing flows involves permanentsealing of watered-out zones with rigidpolymer gelling agents (Figure 3.3). Thiscan be very effective for near-wellboreproblems provided that the gelling agentonly enters the watered-out interval anddoes not damage adjacent productivelayers. Gelling agent placement can becontrolled using mechanical devices suchas packers and bridge plugs. However, inmany cases the gel l ing agent is notcorrectly placed and may enter productivezones through flow paths beyond thecasing (Figure 3.4).

When behind-casing flow is a possibility,mechanical isolation within the well maynot be enough, especially if there is a highcross flow between zones. Dual injection,the simultaneous injection of a gelling agentand a protective f luid down separateconduits, can help to control unwantedwater production while protecting theproductive oil and gas zones.

The goal of dual injection is to improvethe precision of gelling agent placementwhen well conditions preclude completeisolat ion of watered-out zones fromproductive zones. To ensure no gelling-agent damage this isolation must extendbeyond the well and casing into the cementand the near-well portion of the reservoir.

In Figure 3.5 intra-well isolation isachieved with an inflatable packer run oncoiled tubing. However, as a result of poorcementing, there is direct communicationbetween the watered-out layer and the oillayer. A gelling agent injected into thewatered-out perforations will probablyenter and damage the oil layer.

If the vertical permeability in the reservoiris high, cross flow may occur directlythrough the reservoir layers. To rectify thistype of water production, gelling agentsmust penetrate far into the reservoir.Unfortunately in these cases permanentwater shut-off may not be possible.

Problem

Water Gel

Gel

Oil

Shale

Treatment Solution

Problem

Water

Water

Oil

Shale

Treatment Partial solution

Figure 3.3: Permanent sealing of watered-out zones

with rigid polymer gelling agents

Figure 3.4: In many cases gelling agent may still enter

productive zones through flow paths beyond the casing

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There are several potential solutions. Acement squeeze might work, but if thereare small fissures or voids in the cementthen new cement may be unable topenetrate effectively and seal the flowchannels. In any case, cement slurries willnot penetrate more than a few millimetersinto the reservoir rock and are, therefore,unlikely to stop the water at source.

I f gel l ing agent is to be used, anonselective inject ion method ( i .e.,bullheading) will distribute gelling agentacross both perforated intervals and maydamage the productive layer. Intrawellisolation with coiled tubing and a packerwould improve the placement but asignificant volume of gelling agent might stillenter the productive zone through thecement leak behind the casing.

Dual injection allows the engineer toinject the gelling agent into the watered-outzone while a protective fluid (water ordiesel) is delivered to the producing zonewithout either fluid crossflowing into theother. A common dual injection design isshown in Figure 3.6. A packer is run intothe well on workstring or coiled tubing andplaced between two perforated intervals. Inthis case gelling agent is injected down thetubing and protective fluid is sent down theannulus. Injection for each zone iscontrolled in two ways: individual injection rates are assigned on

the basis of transmissibility and pressurein each zone

the bottomhole injection pressures ofthe streams are balanced to achieve afluid potential gradient of zero and soprevent fluid cross-flow.There are, however, some problems

with these approaches. The transmissibilityand pressure in each zone are oftenunknown, so the injection rates for gellingagent and protective f luid may beinappropriate. The potential problems areshown in Table 3.1.

Improved cement jobs provide a morefundamental approach to the problems ofbehind-casing channeling. New cementsystems developed by Dowell, such asLiteCRETE and DensCRETE can helpto prevent al l of the water problemsassociated with channeling.

There are many places in the Middle Eastwhere lost circulation can ruin wellperformance. Standard cement systemshave a density of around 12.5 ppg, andwells where these are used often sufferenormous losses, particularly in fissured

Watered-out zone

Shale or lowpermeability rock

Oil productive pay

Good cement bond

Poor cement bond.Inter-layer flowbehind casing

Figure 3.5: Intra-well

isolation is achieved with

an inflatable packer run

on coiled tubing.

However, as a result of

poor cementing, there is

direct communication

between the watered-

out layer and the oil

layer. A gelling agent

injected into the

watered-out

perforations will

probably enter and

damage the oil layer

Watered-out zone

Shale or lowpermeability rock

Oil productive pay

Good cement bond

Poor cement bond,but no flow

behind casing

Protective fluidenters oil pay

Gelant enterswater zone

Figure 3.6: In many dual

injection jobs a packer is

run into the well on

workstring or coiled

tubing and placed

between two perforated

intervals. In this case

gelling agent is injected

down the tubing and

protective fluid is sent

down the annulus

Table 3.1: Potential

problems with gelling

agent injection for water

shut-off treatment

Gelling agentinjection rate

Protective fluidinjection rate

Potential problem

High

Low

High

Low

High

High

Gelling agent enters oil zone

Diluted gelling agent

Hydraulic fracturing

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limestone and dolomite sections. The newDowell LiteCRETE slurry system (10.5 ppg)helps to control fluid losses in some of theseproblem wells. Diagnosis is an essential partof any cementing service. Once the natureof the loss has been established and theLiteCRETE system is selected, it can helpengineers to achieve results that would beimpossible with conventional systems.

The LiteCRETE system offers a widerange of operat ion. In conventionalcementing, density variations of 0.2 ppg arecommon. Earlier cementing systems wererelatively sensitive to these small densityvariations and this led to irregularities in

compaction and viscosity and, ultimately, tofree-water problems. In contrast, jobsperformed with LiteCRETE show nofree-water pockets, just homogeneouscement free from compaction or viscosityvariations.

Some Middle East operators are nowconcerned about the l i fet ime of thecement behind the casing. Cements havea f in i te l i fet ime, part icu lar ly in hotconditions where they are subjected toionic exchange. The new slurry is muchless permeable and porous than the oldersystem (15.8 ppg, neat slurry). Alternativelight-weight solutions simply decrease the

proportion of cement and increase thewater content.

In the LiteCRETE system (as in the rest ofthe CRETE product family) this additionalwater is replaced by inert materials. TheLiteCRETE system relies on volume-packingoptimization to ensure cement stability, lowporosity and permeability. The LiteCRETEsystem is designed with grain sizes that fill thevoid space (Figure 3.7). This efficient packingmeans that a thin film of cement is enough tohold the blocks of inert material together.Careful placement of the cement minimizesfluid movement. The LiteCRETE system hasa low porosity and is, therefore, exposed toless water. This reduces ionic exchange andincreases the lifetime of the cement.

In Abu Dhabi, the LiteCRETE system isused close to surface because most of thecavern problems are encountered atshallow depths. In Saudi Arabia, however, itis being used in wells with temperatures of230 to 240C and silica flour is required tostabilize the cement. The silica flour isblended with the LiteCRETE system toproduce the correct slurry density (10.5 to11.0 ppg). The first 20-day test conductedwith silica flour in Saudi Arabia showedhow quickly and easily slurry performancecould be optimized.

Conventional cement system

Cement Inert material

LiteCRETE cement system

A conventional triple-combo log over the zones of interest CMR log display over the zones shown in theconventional triple-combo log

NMR signal (T2)distributions

T2 cutoff line

Pore size increases

Porosity (%) 30 0

Density

Neutron

PermeabilityWater saturation (%) Deep resistivity

B

A

B

A

Pore size information from the CMR toolin the potential pay zones helps

determine the fluid saturation

50

1:200 ft

00

50

50

00

50

1:200 ft

At least 40% waterin the pore space,

but no waterproduction

Porosity (%) 30 0

Figure 3.7: The

LiteCRETE system is

designed with grain sizes

which fill the void space.

This efficient packing

means that a thin film of

cement is enough to

hold the blocks of inert

material together

Figure 3.8: The CMR tool can help to identify potentially productive zones with high

water saturation where most of the water is bound

Gamma ray

Caliper

100 0Gamma ray

Caliper CMR total

CMR free fluid

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Figure 3.9: A deviated or horizontal well will intersect

more high-angle fractures than a vertical well of the

same length

Figure 3.10: Early water breakthrough along a

well-developed fracture set

Perforation too close to the

water zone

Perforations placed too close to a waterzone can present a serious problem forproduction control. The correct placementof completions and perforations is crucial tothe long-term success of any producing well.Completion into unwanted fluids will causetheir immediate production, even if theperforations are above the original oilwatercontact or below the gasoil contact. Coningand cresting will occur much more readily ifthe perforations are close to these contacts.

Engineers can examine core data,dril ler s reports and openhole logs todetermine the cut-off point for moveablewater. However, these are inexact and amuch more accurate picture of bound andmoveable water can be achieved usingsystems such as the CMR* CombinableMagnetic Resonance tool. This toolidentifies bound fluids and allows engineersto place completions and perforations inthe optimum locations. The CMR toolhelps to identify productive zones thatwould have been ignored in the past, suchas those with high water saturation wherethe water is bound (Figure 3.8).

Fracturing out of zone

Natural or induced fractures that extendinto aquifer zones beyond the productivezones can severely reduce oil productionfrom a well. The orientation of natural orinduced fractures can be predicted bycareful analysis of local and regional stress,

and checked using borehole imagingtechniques. Having identi f ied andcharacterized fracture sets in a reservoir,geoscientists can plan stimulation programsand ensure that development wells aredrilled in orientations that avoid water-producing fractures.

Incorrectly designed or poorly executedstimulation treatments can cause hydraulicfractures to enter a water or gas zone. Ifthe stimulation is conducted on an oilproduction well, an out-of-zone fracturecan allow early breakthrough of water orgas. Any fractures that connect the floodedinterval to an aquifer or other permeablezone can divert injected fluid directly to theaquifer; taking it away from the oil zone andreducing sweep efficiency. Engineers canuse temperature logs, tracer surveys anddetailed reviews of fracture treatments toidentify this problem.

Natural fractures can be assessed usingborehole imaging systems such as the FMI*Formation MicroImager tool and the UBI*Ultrasonic Borehole Imager tool. Usingthese tools, geoscientists can evaluatefracture orientation, density and aperture;essential parameters for anyone planningfield developments such as new horizontalwells. In general, horizontal wells intersectmore high-angle fractures than verticalwells (Figure 3.9).

Channel from waterflood or

natural drive

Early water breakthrough may be due tofractures (Figure 3.10), high-permeabilitystreaks or channels within the reservoir.When this happens, sweep efficiency inlow-permeability zones will be extremelylow and large quantities of oil will be left inthe reservoir.

The f irst indication of early waterbreakthrough will usually be a sudden anddramatic increase in water production. Adetailed picture of the problem can begained from 4D seismic techniques thatal low geoscientists to monitor f luidmovement through the reservoir.

In Kuwait, 4D seismic methods havebeen used to examine a successful waterinjection program. (See: Time for Change,Middle East Well Evaluation Review, issue21.) This survey of a simple five-spotinjection scheme indicated a sl ightasymmetry in the injected water front,suggesting the presence of a sedimentarychannel with slightly higher permeabilitythan the surrounding reservoir units.

In many cases, producing the unsweptoil left behind after early breakthrough willrequire a major reconfiguration of thewater injection scheme and additionalproduction wells.

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Bottomwater coning

Fluid coning in vertical wells and cresting inhorizontal wells both result from lowpressure in the near-well formation.Pressure drops rapidly as the oi l iswithdrawn and water then moves into thislow pressure zone. Eventual ly, theunwanted water or gas will breakthroughto the perforated section, replacing all orpart of the hydrocarbon production. Oncebreakthrough has occurred the problemtends to worsen as the well suf fersincreasing water cut or gas production.Reducing the production rate at a well willhelp to alleviate the problem but cannotcure it.

Coning can be dealt with by shutting offthe flooded perforations and reperforatinghigher in the reservoir or, in extreme cases,by drilling a new well.

Production enhancement strategies for

strong bottomwater drive reservoirs

The maximum, water-free oil productionrate for a well is known as the critical rate.Industry experts have conductedexperimental, analytical and numericalstudies on coning behavior in vertical wellsto investigate the factors controlling thisrate. Most of these studies, however, haveneglected key factors such as variations inbottomwater influx rate and pressure, andviscous/gravity and capil lary pressureeffects. As a result studies generally predictlow and uneconomic critical coning ratesand drawdown pressures.

There are, however, numerousproduction improvement options toincrease critical coning rates and drawdownpressures. These include closer wellspacing to reduce drainage radius andfracture stimulation to increase the effectivewellbore radius. These methods alterreservoir fluid-flow geometry, but closerwell spacing may not be economical andfracturing reduces the distance betweenthe deepest production depth (in this casethe bottom of the fracture) and thewateroil contact. In the worst case, theinduced fractures could penetrate thebottomwater zone.

Horizontal wells can alter the shape ofthe rising water from a cone to a crest(Figure 3.11) but the cresting cannot beavoided. Recent advances in drilling andcompletion technologies allow engineers todesign and drill multibranch wells. This mayencourage innovative well patterns and

Gamma raySubseadepths Resistivity CNL / FDC

Deepohm-m

CNLp.u.

GRGAPI

PERFS

Mediumohm-m

Rhobg/cc

Ft5300

5400

5500

5550

OWC

0.1 1000 54 -6

0 100 0.1 1000 1.85 2.85

Figure 3.12: In this

Saudi Arabian example,

the gamma ray logs

show no major shales in

the main zone below

the perforations. Brief

examination of these

logs suggested that the

main zone was clean

and that water should

rise vertically from the

OWC to the

perforations

Figure 3.11: The most severe coning occurs in vertical

wells (left). Horizontal wells (right) drain more of the

hydrocarbon content of the reservoir before severe

water problems develop

configurations. In particular, tighter wellspacing may be achieved by joining severalvertical or horizontal well segments toproduce at a common wellhead.

Water coning in The Gulf

Water breakthrough is a major concern formany naturally flowing oil wells in The Gulf.Oil production from these wells continuesto decline as water production rises.

The mechanisms and pathways of waterproduction are often debated amongreservoir engineers, but bottomwaterconing and fingering are the most commonproblems. In water-drive reservoirs it isimportant to determine the t ime ofprobable water breakthrough. Thisinformation is critical for planning a fieldswater-handling facilities and assessing thetime to introduce or modify gas-l i f toperations. Understanding of water-breakthrough mechanisms and timing alsohelps to maximize production at minimumcost by avoiding severe rate restrictions,extensive workovers and the drilling ofreplacement wells.

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In Saudi Arabia engineers decided toconduct a f ield test to study waterproduction mechanisms, breakthrough andcone recession times.

The test was carried out on a giantsandstone reservoir interbedded withshales. The main producing zone has anaverage thickness in excess of 150 ft and anaverage permeability of 45 darcies. Thinand relatively t ight stringer sands aresituated above the main zone. For the past50 years the reservoir has produced understrong water drive that has maintainedreservoir pressure above the bubble point.The water cut has continued to rise as aresult of water encroachment. Wells arewatered-out at water cuts of 3050%depending on location within the field.

The test well was located on the flank ofthe reservoir and penetrated the mainproducing zone at almost 5300 ft.Openhole logs showed the oilwatercontact (OWC) at 5452 ft. The well wasperforated in the middle of the main zone,60 ft above the OWC. The gamma ray logs(Figure 3.12) showed no major shales inthe main zone below the perforations. Briefexamination of these logs suggested thatthe main zone was clean and that watershould rise vertically from the OWC to theperforations.

After completion, the well was hookedup to the existing flow manifolds. As anaturally producing well, the productionrate is dictated by the back pressureexerted at the well head by the flow lines.The aim of this study was to investigatewater arrival times, so the well had to beflowed at a higher rate to ensure that waterbreakthrough was achieved in a practicalt imescale. The t ime of breakthroughdepended on the production rate but wasalso influenced by vertical permeability,which was an unknown.

The test engineers faced threefundamental questions: how long will the test be? at what rate should the well be

producing? at what intervals should the pulsed

neutron log (PNL) be run to monitorwater cone levels?The test was started with an init ial

production rate of 3000 STB/D. Theflowing wellhead pressure was 480 psig.Eleven days later, wellhead samples showed

Aquifer

Top of reservoir

Perforations

-5276 SS

Top -5369 SS

Bottom -5392 SS

Barrier -5432 SS

OWC -5452 SS

PBTD -5593 SS

150

Hw = 15

Ho = 156

Figure 3.13: This PNL

log was run on day 16

of the test. Analysis of

the logs provided some

very surprising results:

a water finger had

developed at a depth

of 5432 ft, about 40 ft

below the perforations

Figure 3.14: The log

showed that below the

shale that caused the

water fingering the OWC

remained unchanged at

5452 ft (60 ft below the

perforations)

Subseadepths

ReversedGR / sigma

Sigma / sigma

Hydrocarbon WaterGamma ray PNL-1 TDT-P(6 MAR 89)

Tubing 41/2" Crude in wellbore

PERFS

PNL-1 TDT-P(6 MAR 89) PNL-2 PDK(1 JUL 89)

Ft5300

5400

5500

5550

50 0 50 0

0.50 0 50 0 50 0

traces of water. Water cut stabilized ataround 0.1% for the following few days.Concerned that early water breakthroughmight be due to some unknown reservoirheterogeneity, the engineers decided torun a PNL log to determine the location ofthe water entry.

This PNL log was run on day 16 of thetest and analysis of the logs provided somevery surprising results (Figure 3.13). A

water finger had developed at a depth of5432 ft, about 40 ft below the perforations.The log showed that, below the shale thatcaused the water fingering, the OWCremained unchanged at 5452 ft, 60 ft belowthe perforations (Figure 3.14).

Fol lowing the PNL log the wellcontinued to f low at a s imilar rate.Wellhead pressure gradually increased from450 to 470 psig, and water cut continued

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its gradual rise, reaching 0.4% by day 39 ofthe test. A new PNL was run on day 40(Figure 3.15). This showed that the waterhad moved to a point immediately belowthe lowest perforations, but the zonebetween the shale layer and initial OWCremained dry.

Production rates were increased over theremainder of the test period with productionreaching a maximum of 7500 STB/D. By theend of this phase of the test (day 336) watercut had reached 44%.

On day 336 the well was shut in and anew PNL was run to determine thelocation of the water. This showed that thewater had moved up to the middle of theperforated interval. After logging, the wellwas left shut in for almost four months untila new PNL was taken to determine howfar the water cone had dropped during theshut-in period. The log showed that thewater had fallen back to 5415 ft (still abovethe shale barrier), 23 ft below the lowestperforations.

This small shale, which could not beseen on the initial log, pulled a water fingerinto the well 20 ft above the original OWC.Shales in a high-permeability reservoir canplay a crucial role in water movement.Where they are found, engineers cannotguarantee that a well wil l havebottomwater coning. Where water cancone above a shale barrier, significantvolumes of oil will be left between theshale and the underlying OWC.

Corrosion and casing leaks

Corrosion is an inevitable problem in oiland gas production systems (Figure 3.16).The corrosion in injection systems, forexample, is general ly driven by thepresence of three dissolved gases: oxygen,carbon dioxide and hydrogen sulf ide.Oxygen is naturally present in all surfacewaters, in many shallow aquifers and mayenter process streams directly from theatmosphere. Corrosion resulting fromhydrogen sulfide produced by bacteria isalso very common.

Oxygen-related corrosion is proportionalto the rate at which oxygen is transferredto the steel surface. This is controlled byoxygen concentration in the brine, and fluidvelocity. Corrosion rates generally fall withtime as corrosion scale products form. Forexposure to surface waters at 25C(assuming an oxygen concentration of78.5 ppm) the long-term corrosion ratefor steel is between 0.5 and 3 mm/year.However, more-vigorous (up to ten times

Subseadepths Sigma / sigma Sigma / sigma Sigma / sigma

Hydrocarbon

PNL-1 TDT-P(6 MAR 89)

PNL-3 PDK(25 JUL 89)

Tubing 41/2"Crude inwellbore

Measured depth

PNL-4 TDT-P(5 JUN 95)

PNL-5 PDK(25 SEP 90)

PNL-1 TDT-P(6 MAR 89)

PNL-1 TDT-P(6 MAR 89)

PERFS Ft5300

5400

6200

6300

64005500

5550

50 0 50 0 50 0

50 0 50 0 50 0Water

50 0

Figure 3.15: A new PNL

was run on day 40. This

showed that the water

had moved to a point

immediately below the

lowest perforations, but

the zone between the

shale layer and initial

OWC remained dry

Figure 3.16: Corrosion

is an inevitable problem

in production systems

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faster) and more-localized pitting attackoften starts under scales or other depositssuch as sands, silts or biological coatings.

Oxygen attack is usually dealt with by theremoval or exclusion of oxygen. However,upstream of the oxygen removal systems,corrosion can be avoided either by usingcorrosion-resistant materials (such asselected stainless steels or glass-reinforcedepoxy resins) or by using a cathodicprotection system (Figure 3.17).

Carbon dioxide corrosion

Carbon dioxide attack on carbon steel isgenerally localized as a result of localturbulence effects, exposing clean metal atlower temperatures (below about 60C).Corrosion rates are inf luenced bytemperature, liquid velocity, and the partialpressure of carbon dioxide to which thewater is exposed.

Hydrogen sulfide corrosion

Hydrogen sulfide generally forms a thin,adherent corrosion-product scale thatgreatly reduces further corrosion.However, damage to this scale by chlorides(at concentrations above 100 ppm), stronglocal turbulence or sand abrasion can causerapid, localized galvanic pitting.

Mixed gas exposure

Combinations of oxygen with dissolvedcarbon dioxide or hydrogen sulfide cancause more rapid corrosion. The acidityassociated with carbon dioxide will retardthe formation of oxide scales, resulting inthe continuation of higher oxygen-attackcorrosion rates. Oxygen and hydrogensulfide will react when mixed and producesulfur. This can cause very severe and rapidcorrosion. These gas mixtures do notoccur naturally; steps can be taken toprevent their development and to avoidthe accelerated corrosion thataccompanies them.

e-e-

e-

+ -

Figure 3.17: Cathodic protection methods include the sacrificial anode system (a) which makes the

pipeline the cathode of an electrochemical cell by attaching it to a more reactive metal which

corrodes. Impressed current cathodic protection (b) involves impressing a current on the pipeline to

protect it. Coating a pipeline (c) provides physical protection for external surfaces

(a)

(b)

(c)

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Problem Cause of corrosion Control methods Monitoring

Oxygen corrosion Oxygenated waterInternal attack

Resistant materialsOxygen scavengersOxygen strippingBetter seal design

CoatingsCathodic protectionResistant materialsBetter design

Water/oxygen samplingIron countsCorrosion probesOxygen sensorsCP surveysWall thickness surveysVisual internal inspectionVisual surveyCP surveys

External attack

Sulfate reducingbacteria (SRB)

Anaerobic fluidsStagnant fluidsConditions under scalesor other deposits

BiocidesChlorination

Anaerobic bacteria countChlorine residuals

Carbon dioxidecorrosion

Water from productionaquifer or other deep aquiferWater contaminated bystripping or lift gas

Degassing at low pressureControl contaminated gasResistant materials

ProbesIron countsWall thickness surveys

Hydrogen sulfidestress corrosioncracking

Produced fluids containinghydrogen sulfideAnaerobic systemscontaminated with SRB

Suitable materials Materials quality control

Materials quality controlHydrogen induced cracking(HIC)

Produced fluids containinghydrogen sulfideAnaerobic systemscontaminated with SRB

Suitable materials

Acid corrosion Stimulation and cleaningacids

Acid inhibitors Checks on acid inhibitors

Galvanic (bimetallic)corrosion

Two metals with differentionic potentials in acorrosive media

Electrical isolation ofmetals (coat cathode)Better design

Design review

Pitting corrosion (rapidcorrosion at defects in inertsurface film)

ImmersionInert surface films

Materials selection Equipment inspection

Sub-deposit corrosion Wet solids depositsBiofilmsPorous gaskets

PiggingBiocidesBetter sealing and designMinimum velocity design

Equipment inspectionBacteria counts

Crevice corrosion Poor designImperfections in metal

Better designMaterials selection

Equipment disassemblyand inspectionLeak detection

Chloride corrosion (rapidcracking on exposure to hotchloride media)

Salt solutionOxygen and heat

Materials selection Equipment inspectionOxygen analysis

Fatigue Rotating equipmentWave-, wind- orcurrent-induced loading

Vibration design Equipment inspection

Hydrogen sulfidecorrosion pittingattack

Water from productionaquifer or other deep aquiferWater contaminated bystripping or lift gas

Degassing at low pressureControl contaminated gasResistant materials

ProbesIron countsWall thickness surveys

Table 3.2 Corrosion summary

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Although common and pervasive,corrosion can be controlled by carefulselection of injection water, properly plannedand executed chemical treatments, and bythe selection of appropriate materials for eachpart of the injection/production/disposalsystem (Table 3.2).

Casing leaks

Casing leaks can be very costly, releasinghydrocarbon fluids into zones where theycannot be retrieved or allowing additionalformation water to enter producing wells(Figure 3.18). The cross flows which resultfrom casing leaks can be dif f icult tocharacterize and treat. Casing leaks areoften a direct result of excessive corrosionand, in the worst-affected wells, the entirecasing may have to be replaced.

Corrosion in oi l f ield pipes can beassessed using the TGS* Tubing GeometrySonde tool. This tool has 16 motorizedfeelers equal ly spaced around thecircumference of the pipe. The size of thefeelers depends on the size of thetubing/casing under investigation. Dataabout deformation in the tubing istransmitted from each feeler to ameasurement coil. The tool also features areference coil where the measurementremains constant throughout themonitoring operation and can be used fortemperature correction.

The standard display shows minimum,average and maximum radi i for eachsection of pipe, the percentages of metalloss and scaling, and a map of metal loss(Figure 3.19).

Oilsand

Watersand

Cracks

Tubing, casing and packer leaks

Figure 3.18: Casing leaks are often a direct result of

excessive corrosion in the production system

4535.0

4540.0

4545.0

4550.0

4555.0

4560.0

4565.0

4570.0

89

7 6 5 4 32

10 1112 13 14 5

16 168

15 14 13 12 1110

2 34 5 6

Top: 4532.3

Bot: 4571.9

END VIEW (TOP)

FEET

3.500

IN

3.092Pipe No 8IR

CLIENT=SUCOFIELD=ZEIT BAYWELL=ZB-A3

79

Channels not rotated (rb)

Figure 3.19: The

standard display

provided by the Tubing

Geometry Sonde shows

maximum, minimum

and average radii for

each section of pipe and

presents information on

metal loss and scaling

1

16

8

1514

131211

10

23

456

Top: 4532.3

Bot: 4571.9

EDGE VIEW

FEET

3.500

IN

3.092Pipe No 8IR

CLIENT=SUCOFIELD=ZEIT BAYWELL=ZB-A3

7

9

Channels not rotated (rb)

Figure 3.20: The Tubing

Geometry Sonde can

also produce detailed

images of changes in

internal radius

The sonde can also produce detailedimages of changes in the internal radius(Figure 3.20). Reductions in internal radius(scale deposits) are shown in blue, andenlargements (corrosion) in red or yellow.These pipe-end or edge-view plots aregenerated for sections of pipe that require amore detailed image. Assessing corrosion inother parts of the production system mayrequire special monitoring arrangements.

Depleted reservoirs

Excessive water production is a commonproblem in depleted reservoirs. Water cutusual ly increases at a steady ratethroughout the life of a field but may risesuddenly when a new field developmentproves to be inappropriate. Suddenincreases in water cut generally forceoperators to modify surface facilities.

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For f ields served by an onshoreproduction faci l i ty such changes areinconvenient, but the additional water canusually be dealt with relatively quickly byupgrading water handling and disposalfacilities at the wellsite. Offshore, however,a sudden increase in water cut may exceedthe capacity of any treatment system thatcould be installed in the restricted spaceavailable. Oil production, in such cases,may have to be reduced and the water cutwill effectively dictate production levelsfrom the field.

Flow channels and reservoir

heterogeneity

In heterogeneous reservoirs injected watercan be diverted from its intended target(the production well) by variations in rockpermeability or by unknown barriers withinthe sequence. This problem severelyrestricts the effectiveness of waterfloodingprograms and, unless rectif ied by thedrilling of additional injection wells, willresult in substantial parts of the reservoirremaining unswept. Tracking injected waterfronts has always been a difficult task.Tracers can be used to determine whetheror not injected water is reaching aproduction well, but cannot reveal thelocation of injection water that has beendiverted, nor indicate the cause. Recentadvances in 4D seismic methods arehelping to address this problem.

Stop thief

Thief zones are very porous formations orlayers where drilling mud is lost. Treatingthese zones to eliminate losses can be avery difficult process. One of the hardestparts of the job is placing the treatmentfluids in exactly the right zone. In mostwells, steps must be taken to protect oil- orgas-producing layers before sealing thewater-bearing unit.

Figure 3.21: Scale build up restricts the movement of

fluids in a well and, in extreme cases, tubing can

bridge-off if the scale is allowed to fill it

Figure 3.22: If a scale is particularly impermeable and

the downhole system contains oxygen, an oxygen

concentration cell can develop between the scale-

covered steel and the clean steel, causing pitting

corrosion beneath the scale

Scale effects a Increased surface roughness, lowering production rates b Reduced flow area for hydrocarbons

c Limited access to lower wellbore

d Ultimately tubing will bridge off

a

b

c

d

O2 O2Scale

Interwell communication

Severe water problems in a well canspread to affect nearby wells. In somefields, formation water passes through non-sealing faults or along permeability channelsfrom watered-out wells to af fectproduction wells elsewhere in thereservoir. Badly planned injection programscan also cause problems, for example,when injectors are placed too close to aproducing well which is not completelyisolated within the field.

Scaling

Scal ing causes a range of productionproblems. Increased surface roughnesswithin the production system, for example,tends to reduce oil and gas productionrates. The flow area for hydrocarbons isreduced, access to the lower part of thewellbore is restricted and, in extremecases, tubing will bridge-off if the scale isallowed to fill it (Figure 3.21).

The formation of scales is a familiarproblem for the oilfield engineer. Scalestypically form when: reservoir pressure drops water with high concentrations of

minerals breaks through fluid rising in the tubing saturates as

pressure and temperature fall minerals come out of solution in the

tubing.Scale deposits are formed in-situ on a

surface that is in contact with water. If ascale is particularly impermeable and thedownhole system contains oxygen, anoxygen concentration cell can developbetween the scale-covered steel and theclean steel, causing pitt ing corrosionbeneath the scale (Figure 3.22).

The most common oilfield scales are: calcium carbonate (CaCO3) calcite or

aragonite calcium sulfate (CaSO4) anhydrite,

gypsum, hemihydrate strontium sulfate (SrSO4) celestite barium sulfate (BaSO4) barite

Barium sulfate is insoluble and particularlydifficult to remove, but precipitation can beprevented by chemical inhibitors. Lesscommon scales include: iron carbonate,iron sulf ides, iron oxides, magnesiumcarbonate, barium carbonate, strontiumcarbonate, silica and sodium chloride.

Sulfate scales often occur when waterwith a high concentration of sulfate ions(such as sea water) is injected into aformation that is rich in calcium, barium or

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When this water is injected, even marginaltemperature changes and turbulence inpassing through the injection pumps caninit iate scal ing; control measures arerequired at all times (Table 3.4).

Injection of water from aquifers can bemore complex because the water willtypically be in equilibrium with surroundingminerals containing barium, strontium orcalcium ions and may contain dissolvedcarbon dioxide or hydrogen sulfide.

Scaling in the near-wellbore area

The main considerations in the near-wellbore area are the effect of reservoirtemperature and pressure on the injectionwater, and the mixing of injection andformation waters. Both can lead to poreblocking and reduce permeability.

Scaling of oil production wells and facilities

In most f ields produced waters aremixtures of true formation water andinjection water that has broken through.The relative proportion of these waters is acrucial factor in determining the likelihoodof scaling. It is worth remembering thatproduced injection water will have beenchanged by i ts passage through thereservoir, having come into contact withformation water, hydrocarbons andminerals. During production, the pureformation water or the formation/ injectionwater mixture will be subjected to largepressure and temperature changes,turbulence and gas breakout. Thesedramatic physical changes are the triggerfor scale deposition in production systems.

Downhole lift pumps

Flow up well

Wellhead valves

Degassing and filters

Injection pumps

Wellhead choke

Flow down injector

Turbulence, pressure rise

Reducing temperature and pressure

Temperature and pressure drop

Pressure drop (CO2 and H2S loss)

Turbulence, pressure and temperature rise

Vacuum at low flows

Pressure and temperature rise

BaSO4

CaCO3, BaSO4

CaCO3, FeS, FeCO3

CaCO3

CaCO3

SrSO4, CaCO4, CaCO3

Process Condition change Precipitation

14,500psia

7250psia

14.7psia

1450psia

Temperature (C)B

aSO

4 so

lubi

lity

(mg/

l)

0 50 100 150 200 250 300

7

10

5

3

4

2

1

strontium. In other cases, where theformation waters are already saturated inthese components, scales can be depositedthrough pressure or temperature changes.The relat ionship between scaleprecipitation and these physical conditionscan be described graphically (Figure 3.23).Increasing temperature may increase therisk of one scale forming while reducing therisks associated with others.

Scaling problems are often caused bymixing of two or more brines: changes inthe chemical balance lead to precipitation.In practice, the location of scale depositsdepends on surface properties, fluidproperties and velocities. For example, thesmooth walls of a plastic pipe may be lesssusceptible to scaling than the rougher surfacefound in a steel pipe. When scales developfrom single aquifer water (Table 3.3) theengineer should consider water compositionand every potential scaling compound withinthe injection/production system.

Other scales and problems

Although less common than carbonate andsulfate scales, there are a number of otherscale types that cause problems inproduction and water injection systems.These include: organic scales, scales causedby hydrogen sulfide (iron reactions in anaqueous environment) and those causedby paraffin build up.

Radioactive materials pose a seriousproblem in some scales. Radium isotopesmay precipitate with some of the otherions such as strontium and barium to formcomplex sulfates and carbonates. Theparent elements of these radium isotopesare uranium and thorium. They arepresent in oil and gas formations in widelyvarying amounts, so only some scales areradioact ive. However, unt i l theradioactivity of a scale has been measured,i t should be treated with caut ion,especially if it is to be removed by physicalmethods such as grit blasting or high-pressure water jetting. These methods putradioactive materials into suspension andrisk bringing them to the surface when thewell is circulated.

Scaling at injection facilities

For seawater injection facilities the mostcommon scale is calcium carbonate formedas the water passes through heatexchangers or down the injection well.Some enclosed, warm seas, including theGulf, are saturated with calcium carbonate.

Figure 3.23: Where the formation waters are saturated scales can be deposited

through pressure or temperature changes. The relationship between scale

precipitation and these physical conditions can be described graphically

Table 3.3: Examples of scale occurrence with single aquifer water

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Figure 3.24: MDT tool

sampling capabilities.

The ability to pump

fluids out of the

formation before

sampling ensures that

the MDT tool collects

representative fluid

samples

Table 3.4: Scale removal

methods

Oil indicator

Pressure

(psia)0 5000

Pumped volume

(cm3)0 20000

Oilindicator

Pressure

Time(sec)

SC1valve

position

Pum

pout

mot

or s

peed

Gas 1 0 1 0

Waterfraction

Hydrocarbonfraction

Highly absorbingfluid

150

300

450

600

750

900

1050

1200

1350

1500

1650

1800

1950

2100

2250

2400

2550

2700

2850

3000

3150

3300

3450

3600

3750

3900

Pumped volume

Treatment

Replacingcompletion

Suitable for

Solves all scaleproblems

Limitations/disadvantages

Chemical Soluble scale.Simple and effectivefor calciumcarbonate scale

Ineffective on inertscale

Fluid jetting Soft scale or debris Not effective formedium-hard orhard scales

Milling Medium-hard scale orbridges in tubing

Slow

Costly. Requires rigworkover and cleaningof tubulars using ultrahigh pressure jetting

Scale prediction and water sampling

There are many predictive models for scaledevelopment and a large number arecomputerized. Accurate water samples arerequired for predictive work and this oftenmeans collecting individual downhole samplesduring field exploration, but, in some

circumstances, samples will also be takenfrom flowlines and from the wellhead.

The composition of subsurface waterchanges with depth and changes laterallywithin a single aquifer layer. This makes itextremely difficult to obtain a representativesample of the water in any sequence.Unfortunately, water compositions also

vary over time as, for example, gases comeout of solution.

In some cases the well may have to beflushed with nitrogen in order to obtainformation samples that have not beencontaminated with drilling or completionfluids. When samples are retrieved, great caremust be taken to ensure that none of thegases dissolved in them are lost. Variousparameters such as pH, carbon dioxide andbicarbonate content, bubble point and gascomposition are crucial for accurateprediction of scale. Other parameters can bedetermined from depressurized samples.

Fluid sampling technology

The MDT* Modular Formation DynamicsTester tool can collect representative fluidsamples from several depths and return themto surface in a single trip. This helps toaccelerate the testing operation. The samplingis so sensitive that it can be used to correlatefluids between wells (Figure 3.24).

Scale control

Once the water has been sampled and thescaling predictions made, the reservoirengineer must choose the most effectivetreatment. The options are: process change and ion removal (e.g.,

the removal of sulfate ions from seawater or pH adjustment)

chemical inhibitor dosing a combination of both.

The choice will be project specific. Forexample, the removal of sulfate ions fromsea water is very costly. To date, thistechnique has been economically justifiedonly in cases where the connate waterhad a very high barium content (about1000 mg/l). In some fields scale controlcan be achieved at little extra cost bymaintaining an aquifer water supply aboveits bubble point to prevent loss of carbondioxide and consequent calcium carbonateprecipi tat ion. Del iberate degass ingrequires a separator vessel, boosterpumps, f i l ters and cont inuous scale-inhibitor dosing. To minimize scale-relatedcosts engineers require deta i ledknowledge of in-situ water composition,reservoir rock behavior, tolerance ofprecipitates in suspension, behavior oftreatment chemicals, and opt ions tochange the injection/production process.

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A scaling case study

The scaling problem in Abu Dhabis BuHasa Field was first identified in 1989. Theseverity of the problem ranged fromcomplete plugging of the tubing string orsurface facilities, to build up in the tubing orsubsurface safety equipment. In most wells,analysis showed that the scale was mainlycalcium carbonate, which could bedissolved by acid treatment. The responseto the problem included: trials to clear the obstruction using

wireline tools acid wash using 15% hydrochloric acid

plus additives.The wireline trials had little success in

clearing the problem. The acid wash, thoughmore successful in the short term, could notprevent a recurrence of scaling in sometreated strings over a relatively short period.More than 40 wells in the field were found tohave some form of scaling problem.

The aim of the project was to predictwater compatibility problems in the Bu HasaField. The study predicted calcium carbonatescaling potential and recommendedmethods to inhibit future scaling.

The current methods for dealing withscale problems include mechanical cleaning(bit runs or milling), hydraulic jetting withcoiled tubing, chemical dissolving agentsand inhibitors. Of these, the inhibitormethod is the most convenient option forlong-term success and ease of application.On the basis of predicted inhibition period,scale inhibitor can either be injectedcontinuously or squeezed from thewellhead periodical ly. Treatmentperformance is usually monitored by wateranalysis and a change in the frequency ofdownhole equipment failures.

Water compatibility analysis in the BuHasa Field was conducted at eight locations(or nodes) in the fluid cycle (Table 3.5).Water quality/compatibility issues havebeen studied by monitoring the changes inchemical composition of water betweentwo nodes. Variations in ionic composition,pH, hydrogen sulfide or carbon dioxidecontents indicate scaling and corrosion.

Scaling problems in Bu Hasa Field werecaused by the deteriorating quality ofinjected water and permeability reductions.Deteriorating water quality led to scaling,sludge deposition, corrosion, erosion andloss of water-injection potential.

The f ield study at Bu Hasa used acomputer model to predict calciumcarbonate and minor calcium sulfate scalingtendencies throughout the f luid f lowsystem. These predictions were verified byfield scale analysis reports. The severity ofthe scaling problem would have to beassessed using reliable scale predictionsoftware, a rock/water chemical simulatorand an up-to-date field database.

Technology for dealing with scale problems

The SCALE BLASTER* service is designedto provide scale removal under difficultconditions. This coiled-tubing-conveyedscale-removal system uses fluid-jetting andabrasive-jetting technology. It offers severaladvantages over mechanical removalmethods, including cleaning of tubingequipment (gas lift mandrels, subsea safetyvalves, etc.), through-tubing cleaning ofliners and casing, and cleaning of high-temperature deposits. The jetting systemremoves soft organic wellbore deposits byjetting with water or chemicals, solublescales by jetting with acid, and hard inertscales by jetting with abrasives.

Flow media

Flow type

Brine

No. of mix. brines

Temperature, CPressure, psig

pH

Specific gravity

GWR, scf/bbl

Bubble point, psig

Ionic species, mg/l

Carbon dioxide, CO2Hydrogen sulfide, H2S

Sodium, Na

Calcium, Ca

Magnesium, Mg

Barium, Ba

Strontium, Sr

Iron, Fe

Chloride, Cl

Bicarbonate, HCO3Sulphate, SO4

TDS

Porous

Single

Single

1

64

1900

5.7

1.13

1.35

99

649

229

57,613

14,033

3024

1

546

1

122,028

244

420

159,825

Pipe

Single

UER + SIMS

2

65

5.55

1.142

1.182

636

160

60,793

16,066

3031

1

599

4

130,605

207

399

211,103

Pipe

Single

Mixed

2

Pipe

Single

Mixed

2

1820

6.4

1.1318

535

238

58,701

13,707

3306

0.7

124,110

232

372

200,428

Porous

Multiphase

Mixed

3

6.3

1.13

45

52,294

15,529

1256

738

1160

112,597

265

659

184,543

Porous

Multiphase

Mixed

3

6.4

1.1304

268

142

55,498

14,618

2281

0

369

118,354

249

516

192,486

Pipe

Multiphase

Mixed

>4

6.5

1.0631

273

19

22,429

6493

3161

13.2

54,963

161

385

87,592

Multiphase

Mixed

>4

3

6.4

1.0732

348

31

34,442

7375

1750

15.5

70,920

134

441

115,062

Analysis zone A B C D E F G H

Disposal well

WH

Surface facility

Tank

Production well

SS

Reservoir

1

Injection well

WH LS

Surface facility

F/L

Wells

BH

Aquifers

2

Table 3.5: Water analysis from Bu Hasa Field

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The key to the success of this newservice is Sterling beads, a revolutionaryproduct that, when mixed with jetting fluid,shatters scale deposits without damagingthe tubing. The SCALE BLASTER serviceremoves even the hardest scale, such asbarium, strontium and iron sulfates, makingit unnecessary to kill the well and pull thetubing. A rotating nozzle provides completecoverage, cleaning nipple profiles andcompletion hardware, as well as the tubingwall. This eliminates the risk of damage tothe tubing and other downhole equipment.

The SCALE BLASTER service was usedin West Africa, where it proved to be aviable and reliable method for removing4000 ft of barium sulfate scale, allowing theremoval and replacement of five gas liftvalves. After SCALE BLASTER treatmentthe client placed the well on production forthe first time since 1994. Previous mill runsusing different mills and motors, impacthammers, chemical scale-dissolvingtreatments and alternate jetting systems hadall been unsuccessful.

Carbonate, chloride, iron, silica andhydroxide scales can be treated by a rangeof chemical methods. Sulfate scales,however, such as barium sulfate, cannot betreated in this way. A mechanical solution isrequired. In Algeria, where barium sulfate

scales are very common, the SCALEBLASTER abrasive jetting technique wasused to boost oil production. In some wellsthis meant increases from 200 BOPD to1400 BOPD (Figure 3.25).

The SCALE BLASTER technique can bedelivered using coiled tubing and offers arate of penetration up to 30 m/h. It cleansall elements within the tubing. There is noneed to alter the completion. The tubinghas longer life as its integrity is not affectedby the abrasive Sterling beads. AbrasiJetAdvisor* software is available to optimizetreatment design.

Bacterial growth

Bacteria can survive under extremeconditions and are found in environmentsranging from hot springs to ice sheets.Scientific opinion is divided on the questionof bacterial survival in a dormant stateunder reservoir conditions for millions ofyears. Physical and toxic limits to bacterialsurvival are not well defined, but undercertain condit ions, bacteria can beexpected to flourish.

Bacteria require: organic nutrients in the environment to

supply carbon nitrogen from ammonium, nitrate or

nitrite ions trace elements (calcium, magnesium,

barium, sil icon, sodium, potassium,chlorine, etc.)

suitable temperature and pressureconditions. Many species survive over abroad range of conditions while othersare specially adapted to extremes oftemperature or pressure. Sulfate-reducing bacteria (SRB) requireanaerobic conditions, nutrients andsulfates (above 10 ppm) from naturalsources or from treatment chemicals.

Bacterial corrosion and reservoir souring

SRB-induced corrosion typically occursbelow bacterial colonies and is a rapid,pitting attack. Control of SRB bacteriarequires chlorination or periodic treatmentwith other biocides.

For many years the causes of reservoirsouring have been a subject for debate.While SRB can generate hydrogen sulfidefrom sulfate (as seen at many waterinjection surface facilities) some reservoirsremain sweet even when injection waterhas broken through to the producing wells.Other possible explanations for the souringof reservoirs include the thermaldegradation of sulfite oxygen scavengerresidues to sulfide, or the release of naturalhydrogen sulfide following depressurization.

Empirical evidence seems to suggest thatSRB can cause reservoir souring undercertain conditions, i.e., where: injection or formation waters contain

sulfates formation water contain nutrients and

VFA above 50 mg/l formation rocks do not contain hydrogen

sulfide absorbents there are insufficient bacterial control

measures bacteria are present deep within the

reservoir.

Injection out of zone

Waterflood problems are difficult to detect.If water is being injected in a mature field, itis important that the injected water isreaching the target zones. Where water isbeing injected into watered-out zones orzones containing gas, the injection programwill boost production of these unwantedfluids (Figure 3.26).

Careful examination of production logsmay indicate a problem, but the reservoirengineer will probably have to run newlogs in the injection well to determinewhether or not water is being injected intothe wrong layer. Once identified, out-of-zone injection can be dealt with byrecompletion of the injector well. This

1600

1400

1200

1000

800

600

400

200

00.5 1.0 1.5 2.0

Tubing ID

Oil

rate

(B

/D)

2.5 3.0

ScaledID=1"

31/2" tubing OD

Not scaledID = 2.993"

~

Figure 3.25: Scaling treatment and its effect on

production in Algeria

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Injection water Mixed fluids includingextra gas and water

would involve shutting off the water layerand reperforating in a way that ensures theinjected water is restricted to the oil-bearing layers within the reservoir.

The curse of crossflows

Crossflows occur when leaky casing orpoor cementation allow reservoir fluidsfrom different rock layers to mix behind thecasing. If ignored, crossflows can causesevere damage to reservoir potential.Some Middle Eastern fields have crossflowsof up to 5000 B/D.

Crossf low at water inject ion wellsremoves water from the waterflood and soreduces sweep efficiency. Water drainsaway from the well, along fractures,channels or high-permeability layers, intoformations where the water pressure islower. At production wells, cross flowsreduce the amount of oil reaching theproduction string.

The volume of a crossflow is controlledby several factors, including: relat ivepermeability and pressure differencesbetween the reservoir layers, cementquality, casing corrosion, and the ambientflowing or shut-in conditions. In most casesnone of the controlling parameters areknown and traditional flowmeter surveysare of little value as they cannot detect thelocation or volume of crossflow when itoccurs behind casing.

Crossflows can, however, be detectedby examining temperature profile and WFLdata along the well.

Reduced injectivity

Pressure distribution around a well is a vitalfactor in its performance. The ease withwhich a fluid can be pumped into an injectionwell is measured as the ratio of the volumeentering the formation during a period of timeto the pressure differential between wellboreand reservoir. The value of this ratio is knownas the injectivity index.

Reduced injectivity is caused by formationdamage, excessive skin development andassociated formation problems.

What came out wont go back

In the Middle East, one company faces anunusual and costly water problem: theirwells are producing at water cuts of6090%, but the produced water cannotbe reinjected into the reservoir. Theinjection wells in the reservoir were drilledto dispose of produced water in

accordance with current environmentalregulations.

The production index for the formationshows that water is produced at300 BWPD/psi, but can only be injected at20 BWPD/psi. This means that the client isfacing a surplus of 6000 BWPD that cannotbe pumped back into the reservoir. Thepoor performance of these disposal wellsencouraged the operators to approachDowell for a major fracturing program toincrease their injectivity. If successful, thisprogram should allow the operators to drillfewer of these wells, thereby saving around$40 million.

Studies have shown that this injectionproblem is not related to waterincompatibility or to skin effects. Expertsare now suggesting that a betterunderstanding of rock mechanics(particularly the plastic behavior of theformation around the wellbore) may helpto solve the problem.

Engineers working on the problembelieve that the low injectivity is related toincreases in pore pressure during injection.It may be that small grains in the formationare being mobilized by the higher porepressures during injection. These coat thelarger grains, closing pore throats and soforming a barrier to fluid flow.

Fracturing operations carried out threeyears ago were hindered by excessive fluidloss. A planned mini-fracture, which will be

conducted with a fluid-loss additive, shouldprovide better results and help to establishthe feasibility of a major fracturing project.

Conclusions

Control l ing water in the oi l f ield is acomplex chal lenge. There are manypotential sources of water and many water-related problems. The complexity ofmodern completions and productionsystems make them vulnerable to effectssuch as scaling and corrosion.

Vigi lance is the key to maintainingconsistently high production rates andrelatively trouble-free operations. Regularchecks or a comprehensive monitoringprogram, though expensive, will allow theearly diagnosis and treatment that willprove more cost-effective in the long-run.

Figure 3.26:

Where water is

being injected into

watered-out zones

or zones containing

gas, the injection

program will boost

production of these

unwanted fluids