Fighting Scale—Removal and Prevention

Imagine an oilfield menace that can smother a productive well within 24 hours. The buildup

of scale inside wellbores does exactly that, causing millions of dollars in damage

every year. New understanding of scale accumulation is allowing production

engineers to predict when scale formation will occur, so that adverse

operating conditions can be prevented with new inhibitor

techniques. New tools are also available to blast

scale away from casing and tubulars.

Few production problems strike fear into thehearts of engineers the way scale can. Scale isan assemblage of deposits that cake perfora-tions, casing, production tubing, valves, pumpsand downhole completion equipment, therebyclogging the wellbore and preventing fluid flow.Scale, just like the scale found in home plumbingor tea kettles, can be deposited all along waterpaths from injectors through the reservoir tosurface equipment. Most scale found in oil fields forms either by direct precipitation fromthe water that occurs naturally in reservoir rocks,or as a result of produced water becoming

oversaturated with scale components when twoincompatible waters meet downhole. Wheneveran oil or gas well produces water, or water injec-tion is used to enhance recovery, there is the pos-sibility that scale will form. In some areas, suchas the North Sea and Canada, where entireregions are prone to scale, it is recognized as oneof the top production problems.

Scale can develop in the formation pores nearthe wellbore—reducing formation porosity andpermeability. It can block flow by clogging perfo-rations or forming a thick lining in production tub-ing (above). It can also coat and damagedownhole completion equipment, such as safety

30 Oilfield Review

Mike CrabtreeAberdeen, Scotland

David EslingerTulsa, Oklahoma, USA

Phil FletcherMatt MillerSugar Land, Texas, USA

Ashley JohnsonRosharon, Texas

George KingBP Amoco CorporationHouston, Texas

For help in preparation of this article, thanks to AndrewAcock, Houston, Texas, USA; Willem van Adrichem andWarren Zemlak, Sugar Land, Texas; Mike Barrett, SteveDavies, Igor Diakonov and Jon Elphick, Cambridge, England;Leo Burdylo, Sugar Land, Texas; Ingrid Huldal and RaymondJasinski, Aberdeen, Scotland; and Scott Jacobsen,Houston, Texas. Blaster Services, Bridge Blaster, CoilCADE, CoilLIMIT, JetAdvisor, Jet Blaster, NODAL, ScaleFRAC, Sterling Beadsand StimCADE are marks of Schlumberger. Hipp Tripper is amark of Baker Oil Tools; Hydroblast is a mark of Halliburton;and RotoJet is a mark of BJ-NOWSCO.1. Brown M: “Full Scale Attack,” REview, 30 The BP

Technology Magazine (October-December 1998): 30-32.

Scale in production tubing. Calcium carbonatescale growth in production tubing here obstructsmore than 40% of the flowing area of the tubingand prevents access to lower sections by well-remediation tools.

Autumn 1999 31

valves and gas-lift mandrels. The effects of scalecan be dramatic and immediate: in one North Seawell in the Miller field, engineers were shocked tosee production fall from 30,000 B/D [4770 m3/d]to zero in just 24 hours.1 The costs can be enor-mous also. Curing scale problems costs the indus-try hundred of millions of dollars per year in lostproduction. Until recently, ways to treat theproblem were limited and sometimes ineffective.When scale forms, a fast, effective removal tech-nique is needed. Scale-removal methods involveboth chemical and mechanical approaches, eachwith its own niche—depending on the location ofthe scale and its physical properties.

Some mineral scales, such as calcium carbon-ate [CaCO3], can be dissolved with acids, whilemost others cannot. Sometimes tar-like or waxycoatings of hydrocarbons protect scale fromchemical dissolvers. Accumulated solid layers ofimpermeable scale can line production tubing,sometimes completely blocking it, and are lesseasily removed. Here, mechanical techniques orchemical treatments are traditionally used to cutthrough the scale blockages. Nevertheless, com-mon hard scales, such as barium sulfate [BaSO4],are extremely resistant to both chemical andmechanical removal. Before recent developmentsin scale-removal technology, operators with hard-scale problems in their production tubing wereoften forced to shut down production, move inworkover rigs to pull the damaged tubing out ofthe well, and either treat for scale at the surfaceor replace the tubing.

In this article, we review the physical causesof scale buildup during oil production. Knowingthe conditions that lead to scaling and when andwhere it occurs helps in understanding how toremove scale and in designing intervention treat-ments to restore long-term well productivity.Then, we survey the chemical and mechanicaltechniques used in scale removal—including thelatest developments in jetting techniques—andexamine the strengths and limitations of eachapproach. Finally, we look at advances in watertreatments and new inhibitors that help controlthe delicate chemical balance to prevent scaleprecipitation from recurring.

Sources of ScaleIn oilfield scale, water is of primary importance,since scale will occur only if water is produced.Water is a good solvent for many materials and cancarry large quantities of scaling minerals. All natu-ral waters contain dissolved components acquiredthrough contact with mineral phases in the naturalenvironment. This gives rise to complex fluids, richin ions, some of which are at the saturation limitfor certain mineral phases. Seawater tends tobecome rich in ions that are by-products of marinelife and water evaporation. Ground water andwater in the near-surface environment are oftendilute and chemically different from deep subsur-face water associated with gas and oil.

Deep subsurface water becomes enriched inions through alteration of sedimentary minerals.The water in carbonate and calcite-cemented

sandstone reservoirs usually contains an abun-dance of divalent calcium [Ca+2] and magnesium[Mg+2] cations. Sandstone formation fluids oftencontain barium [Ba+2] and strontium [Sr+2] cations.In reservoir fluids total dissolved solids can reach400,000 mg/L [3.34 ppg]. The precise compositionhas a complex dependence on mineral diagenesisand other types of alteration encountered as for-mation fluids flow and mix over geological time.

Scale begins to form when the state of anynatural fluid is perturbed such that the solubilitylimit for one or more components is exceeded.Mineral solubilities themselves have a compli-cated dependence on temperature and pressure.Typically, an increase in temperature increasesthe water solubility of a mineral. More ions aredissolved at higher temperatures (below).Similarly, decreasing pressure tends to decrease

Mineral solubilities versus temperature

Minerals solubilities versus pressure

1000

100

10

1

0.1

Solu

bilit

y, lb

m/b

bl

0.01

0.001

0.000177 120

Temperature, °F

Strontiumsulfate

Calcite Barite

Siderite

Halite

Gypsum

Anhydrite

170 210 260 300

Minerals solubilities versus salinity

0.004

0.0035

0.003

0.0025

0.002

0.0015

0.001

0.0005

5 x 10-3

4 x 10-3

3 x 10-3

2 x 10-3

1 x 10-3

25°C

150°C

250°C

070

10 2 3 4 5 6

120 170 220 270

14,000 psi

1500 psi

7000 psi

14.5 psi

Temperature, °F

Diss

olve

d Ba

SO4, lb

m/b

blSt

ront

ium

Sul

fate

sol

ubili

ty, m

ol/L

NaCl mol/LSeawater

Mineral solubilities have a complex dependencyon many variables including temperature (top),pressure (center) and salinity (bottom).

>

>

solubilities and, as a rule-of-thumb, the solu-bility of most minerals decreases by a factor of two for every 7000-psi [48-MPa] decrease in pressure.

Not all minerals conform to the typical tem-perature trend; for example, calcium carbonateshows the inverse trend of increasing water sol-ubility with decreasing temperature. The solu-bility of barium sulfate increases by a factor oftwo in the temperature range 25°C to 100°C[77° to 212°F] and then decreases by the samemagnitude as temperatures approach 200°C[392°F]. This trend is itself influenced by thebackground brine salinity.

An additional complexity is the solubility ofcarbonate minerals in the presence of acid gasessuch as carbon dioxide [CO2] and hydrogen sulfide[H2S]. Carbonate solubility increases as fluid acid-ity increases, and CO2 or H2S at high pressuresupply significant acidity. Consequently, forma-tion waters, in contact with both carbonate rockand acid gases, can be rich in dissolved carbon-ate. This trend has a complex nonlinear depen-dence on brine composition, temperature and thepressure of the gas above the liquid phase; thisgas pressure effect is orders of magnitude greaterthan the normal effect of pressure on the solubil-ity of a mineral. Generally, as pressure falls, CO2

leaves the water phase causing the pH to rise—leading to calcite scale formation.

Forming ScaleAlthough the driving force for scale formationmay be a temperature or pressure change, out-gassing, a pH shift, or contact with incompatiblewater, many produced waters that have becomeoversaturated and scale-prone do not alwaysproduce scale. In order for a scale to form it mustgrow from solution. The first development withina saturated fluid is a formation of unstable clus-ters of atoms, a process called homogeneousnucleation (left). The atom clusters form smallseed crystals triggered by local fluctuations inthe equilibrium ion concentration in supersatu-rated solutions. The seed crystals subsequently

grow by ions adsorbing onto imperfections on thecrystal surfaces—extending the crystal size. Theenergy for seed crystal growth is driven by areduction in the surface free energy of the crys-tal, which decreases rapidly with increasingradius after a critical radius is exceeded. Thisimplies that large crystals favor continuing crys-tal growth, and also implies that small seed crys-tals may redissolve.2 Thus, given a large enoughdegree of supersaturation, the formation of anyseed crystal will encourage an increase in thegrowth of scale deposits. The seed crystal, ineffect, is a catalyst for scale formation.

Crystal growth also tends to initiate on a pre-existing fluid-boundary surface, a process calledheterogeneous nucleation. Heterogeneous nucle-ation sites include surface defects such as pipesurface roughness or perforations in productionliners, or even joints and seams in tubing andpipelines. A high degree of turbulence can alsocatalyze scale deposition. Thus, the accumula-tion of scale can occur at the position of the bub-blepoint pressure in the flowing system. Thisexplains why scale deposits rapidly build ondownhole completion equipment. Through thisunderstanding of nucleation phenomena, scaleinhibitors—discussed later—have been devel-oped that use chemicals specifically designed topoison the nucleation and growth stages of scaleformation and reduce the rate of scale formationto almost zero.

32 Oilfield Review

Fluid flow

Pipe wall

Supersaturation

Supersaturation

Ion pairs

Clusters/nuclei

Imperfectcrystalites

Further growth at sitesof crystal imperfections

Transient stability

Ion pairs

Surface imperfections

SO4-2

Ba+2

Homogeneous nucleation

Heterogeneous nuleation

>Nucleation processes. Scale growth starts insupersaturated solutions with ion pairs formingsingle crystals in solution, called homogeneousnucleation (top). Scale can also grow on preex-isting surface defects—such as rough spots onthe liquid-tubing surface, called heterogeneousnucleation (bottom).

CaCO3

CaCO3cementedfish

FeS2 layer

Steeltubing

BaSO4 layer

CaCO3 layer

Wax layer

Production flow

Underdepositcorrosion

Asphaltenelayer

H2S pittingcorrosion

BaSO4 overperforations

Change inpressure atsafety valve

Gas lift

Scale Deposition in Tubing

Fish

CaCO3Tubingcrossover

>Scale in tubing. The location of scale deposits in tubing can vary from downhole perforations to thesurface where it constrains production through tubing restrictions, blocked nipples, fish, safety valvesand gas-lift mandrels. Scale is often layered and sometimes covered with a waxy or asphaltene coat-ing (insert). Pitting and corrosion on steel can develop under the scale due to bacteria and sour gas,diminishing steel integrity.

Autumn 1999 33

Identifying ScaleIdentifying the location and composition of thescale deposit is the first step in designing a cost-effective remediation program.

Production tubing and surface equipment—Scale in production tubing may occur as a thicklayer adhering to the inside of the tubing. It is often centimeters thick and has crystals up to1 cm or larger. The primary effect of scale growthon tubing is to lower the production rate byincreasing the surface roughness of the pipe andreducing the flowing area. The driving pressuretherefore goes up and the production goes down.If mineral growth increases, then access to lowersections of the well becomes impossible, andultimately the growth blocks production flowingthrough the tubing (previous page, bottom right).Tubing scale varies in chemical composition,being composed of layers of scale deposited dur-ing the well’s history. Often, scales includeasphaltene or wax layers, and the layers of scalethat are closest to the tubing may contain ironsulfides, carbonates or corrosion products.

Near-wellbore matrix—The carbonate or sul-fate scale that is typical of the near-wellboreregion has a finer particle size than tubing scale,on the order of microns rather than centimeters.It blocks gravel packs and screens as well asmatrix pores. Near-wellbore scale commonlyforms after long periods of well shut-in becausecrossflow mixes incompatible waters from differ-ent layers. Such scale is thought of as skin(above right). Removal by chemical dissolvers oracids can increase production rates dramatically.

Injector wells—Scale damage to injectionwells is usually caused by temperature-activatedautoscaling of the injection water. In addition,incompatible mixing can occur in the near well-bore when injection water contacts either naturalformation water or completion brine (right). Thisproblem is limited to the early stages of injection,when injection water is contacting incompatiblewater in the near-wellbore region. Scale formedhere can decrease the permeability of the forma-tion and reduce the effectiveness of the water-flood strategy.

Detecting scale—Physical evidence of scaleexists as samples of tubing scale or X-rayevidence from core analysis. Gamma ray loginterpretation often indicates barium sulfatescale since naturally radioactive radium Ra226

precipitates with this scale.3 As much as a 500-API increase in gamma ray activity over naturalbackground has been seen in many cases.

Evaluating production using NODAL analysiscan indicate tubing scale if a well suddenlydemonstrates tubing constraints that were notpresent during early production. In theory, NODALanalysis can indicate scale in matrix through theidentification of increasing reservoir constraintson production, although this is difficult to distin-guish from other forms of formation damage.

The onset of water production is often a signof potential scale problems, especially if it coin-cides with simultaneous reduction in oil pro-duction. Normally, operators track waterchemistry and in particular the dissolved ioncontent of the produced water. Dramatic changesin the concentrations of scaling ions, such asBa+2 or sulfate [SO4

-2], that coincide with reducedoil production and increased water cut, can sig-nal that injection water has broken through andscale is beginning to form. Inspection of theresponse to previous chemical interventions,such as acid treatments, can give weight to suchinterpretations.

Early warning of scaling conditions would bevaluable to operators, since wells can scale upwithin 24 hours or less. Wells with intelligentcompletions and permanent monitoring systemsare being designed to detect changes in waterchemistry. Downhole scale sensors and perma-nent monitoring applications are areas of activeresearch. For example, BP Amoco initiated anintegrated scale management system that uses adownhole electrochemical sensor sensitive to pHand chloride ion concentrations along with tem-perature, pressure and multiphase flow measure-ments to detect potential carbonate buildup andhelp regulate chemical dosages for scale control.4

Chemical modeling—Chemical models arenow available to predict the nature and extent ofscaling from detailed fluid conditions. Thesemodels predict phase equilibrium using thermo-dynamic principles and geochemical databases.All rely on basic input data such as elemental-concentration analysis, temperature, pressureand gas-phase compositions. These programsare designed to predict the effect of perturba-tions such as incompatible mixing or changes intemperature and pressure.

Water flow

Scale

Oil

>Matrix damage. Scale deposition restricts the flow of fluids through the formation,resulting in a loss of permeability.

Scale damaged zone

Injection water

Injection flow

Perforations

> Injection-well damage. Autoscaling of injectionwater can cause scale buildup and createrestrictions in the tubing. Calcium carbonate canprecipitate as a result of increased temperatureand pressure, leading to deposition and damagenear the wellbore, particularly in HPHT wells.Incompatible mixing of injection water with for-mation water also leads to damage early in theinjection program.

2. Richardson SM and McSween HY: Geochemistry:Pathways and Processes. Englewood Cliffs, New Jersey,USA: Prentice-Hall, Inc., 1989.

3. Bamforth S, Besson C, Stephenson K, Whittaker C,Brown G, Catala G, Rouault G, Théron B, Conort G, Lenn C and Roscoe B: “Revitalizing Production Logging,”Oilfield Review 8, no. 4 (Winter 1996): 44-60.

4. Snieckus D: “Tipping the Scales,” Offshore Engineer(September 1999): 117.

Many scale-prediction programs are nowavailable as public domain software and a lim-ited number of commercial computer programstailored specifically to the simulation of oilfieldbrine chemistry. These programs range fromspreadsheet models to highly developed geo-chemical models designed to simulate fluid andchemical transport in porous formations.5

Such simulators can be used to predict scal-ing problems far into the future, using scenariosof reservoir performance and expected waterbreakthrough. In fact, for new reservoirs thathave no history of scaling problems, chemicalmodels are the only available predictive tools.Still, simulators require highly accurate chemicalcomposition data for virgin reservoir fluids andinjection waters. These are rarely available, butcan be collected to provide more accurate pre-dictions of scale formation.

Common Scaling ScenariosFour common events typically encountered inhydrocarbon production give rise to scale.

Incompatible mixing—Mixing incompatibleinjection and formation waters can cause scaleformation. Seawater is often injected into reser-voirs during secondary and enhanced-recovery

waterflooding operations. Seawaters are typi-cally rich in SO4

-2 anions with concentrationsoften above 2000 mg/L [0.02 ppg], while forma-tion waters contain divalent cations Ca+2 andBa+2. Fluid mixing in the near-wellbore matrixgenerally produces new fluids with combined ion concentrations that are above the solubilitylimits for sulfate minerals. Calcium sulfate[CaSO4] scale forms in limestone formations, andbarium sulfate [BaSO4] and strontium sulfate[SrSO4] scales form in sandstone formations(below). If these scales form in the formation,they are difficult to remove chemically andimpossible to remove mechanically. Incompatiblewater mixing can also occur in tubing, producingscales that are accessible to both chemical andmechanical removal.

Autoscaling—A reservoir fluid experienceschanges in temperature and pressure as it is pro-duced. If such changes take the fluid compositionbeyond the solubility limit for a mineral, it willprecipitate as scale—this phenomenon is calledautoscaling or self-scaling. Sulfate and carbon-ate scales can precipitate as a result of pressurechanges within the wellbore or at any restrictiondownhole. Sodium chloride scale (halite) forms in a similar way from highly saline brines

undergoing large temperature drops. Water cancarry 100 lbm/bbl [218 kg/m3] of halite at 200°C,but only 80 lbm/bbl [174 kg/m3] at surface tem-peratures. Halite can precipitate at the rate of 20lbm for each barrel of water produced, leading tomany tons of scale every day in a single well pro-ducing water at a rate of 1000 B/D [159 m3/d].

Another serious problem occurs when car-bonate scales precipitate from produced fluidscontaining acid gases. Reduction in pressure dur-ing production outgasses the fluid, which raisespH and causes scale deposition. The depositionof carbonate can extend from the near-wellborematrix, along tubing and into surface equipmentas the produced water continuously changes inpressure and temperature.

For carbonate scales, temperature effectsoften work against pressure effects. For example,the pressure drop at the point of entry into thewellbore can lead to matrix scale. As the fluidprogresses up the tubing to surface temperaturesand wellhead pressure, the resulting tempera-ture drop may override the pressure effect, reduc-ing scale formation in the tubing. On the otherhand, subsequent release of pressure from thewellhead to surface can lead to massive depositsof scale in surface equipment and tubing.

Evaporation-induced scale—Scale formationis also associated with the simultaneous pro-duction of hydrocarbon gas and formation brine(wet gas). As the hydrostatic pressure in produc-tion tubulars decreases, the volume of thehydrocarbon gas expands and the still hot brinephase evaporates. This results in dissolved ionsbeing concentrated in excess of mineral solubil-ities in the remaining water. This is a commoncause of halite scaling in high-pressure, high-temperature (HTHP) wells, but other scales mayalso form this way.

Gas flood—Flooding a formation with CO2

gas for secondary recovery can result in scaledeposition. Water containing CO2 becomes acidicand will dissolve calcite in the formation.Subsequent pressure drops in the formation sur-rounding a producing well can cause CO2 tobreak out of solution and cause carbonate scaleto precipitate in the perforations and in formation

34 Oilfield Review

600

Ion species

Sodium

Potassium

Magnesium

Barium

Strontium

Sulfate

Chloride

Calcium

Formation water, ppm

31,275

654

379

269

771

0

60,412

5038

Seawater, ppm

10,890

460

1368

0

0

2960

19,766

428

500

400

300

200

100

00 20 8040 60 100

Seawater, %

SrSO4

BaSO4

Brine Composition of Two Different Waters

Mas

s of

sca

le p

reci

pita

tion,

mg/

L

Scale from incompatible waters.The table (top) shows typical differ-ences in ion concentrations found in formation water and seawater.The graph (bottom) shows theamount of scale that precipitatesfrom different mixtures of seawaterand formation water.

5. Oddo JE and Tomson MB: “Why Scale Forms and How to Predict It,” SPE Production & Facilities 9, no. 1(February 1994): 47-54.

6. Martel AE and Calvin M: Chemistry of Metal ChelateCompounds. New York, New York, USA: Prentice-Hall,Inc., 1952.

7. Kotlar HK, Karlstad S, Jacobsen S, and Vollen E: “An Integrated Approach for Evaluating MatrixStimulation Effectiveness and Improving Future Design in the Gullfaks Field,” paper SPE 50616, presented at the1998 SPE European Petroleum Conference, The Hague,The Netherlands, October 20-22, 1998.

>

Autumn 1999 35

pores near the wellbore. The production of scalein the near-wellbore environment will cause afurther reduction in pressure and even more pre-cipitation (above). Like autoscaling, this self-gen-erating process can completely seal perforationsor create an impermeable wall between theborehole and reservoir within a few days, com-pletely shutting down production.

Scale RemovalScale-removal techniques must be quick, non-damaging to the wellbore, tubing or formationenvironment, and effective at preventing repre-cipitation. Formation matrix stimulation treat-ments frequently employ scale dissolvers toarrest production decline. The best scale-removaltechnique depends on knowing the type andquantity of scale, and its physical composition ortexture. A poor choice of removal method canactually promote the rapid recurrence of scale.

In tubulars, scale strength and texture play sig-nificant roles in the choice of removal technique.Strengths and textures vary from delicate, brittlewhiskers or crystals with high microporosity, torock-like, low-permeability, low-porosity layers.Scale purity affects its resistance to removalmethods. Scale may occur as single-mineralphases, but is more commonly a mixture of similar,compatible compounds. Pure barium sulfate isnormally of low porosity and is extremely impervi-ous to chemical removal, and only slowly remov-able by most established mechanical techniques.Mixtures of barium sulfate, often with strontiumsulfate, calcium sulfate or even calcium carbon-ate, will frequently yield to a variety of removalmethods, both chemical and mechanical.

Chemical techniques—Chemical scaleremoval is often the first, and lowest costapproach, especially when scale is not easilyaccessible or exists where conventional mechan-ical removal methods are ineffective or expen-sive to deploy. For example, carbonate mineralsare highly soluble in hydrochloric acid and there-fore can be easily dissolved. Hard sulfate scale ismore difficult because the scale has a low acidsolubility. In the formation matrix, it can betreated by the use of strong chelating agents,compounds that break up acid-resistant scale byisolating and locking up the scale metallic ionswithin their closed ring-like structure.6

Most chemical treatments are controlled byhow well the reagents gain access to the scale

surface. Consequently, the surface-area-to-vol-ume ratio, or equivalently the surface-area-to-mass ratio, is an important parameter in the speedand efficiency of the removal process. Large reac-tant surface areas, such as porous materials, clay-like particles of extremely thin plates, and hair-likeprojections react quickly, since the acid or reactantvolume surrounding the surface is large. Smallersurface-area-to-volume in thick, nonporous sheetsof scale are slow to react with any but thestrongest chemical reactants. Scale deposits intubing exhibit such a small surface area for a largetotal deposited mass that the reactivity of chemi-cal systems is usually too slow to make chemicaltreatment a practical removal method.

Frequently high-permeability zones in the for-mation—offering a path of least resistance—divert treatment fluids, and hinder the ability ofscale dissolvers to penetrate the intervals dam-aged by scale. Novel techniques using dissolversand preflushes containing viscoelastic surfactantscan enhance dissolver placement. Viscoelasticsurfactants form high-viscosity gels when mixedwith specific brine compositions, but completelybreak down and become water-like in the pres-ence of oil or hydrocarbon gas. Therefore, theseviscoelastic surfactants help channel the scaledissolvers into productive oil-saturated zones,avoiding nonproductive water-saturated zones.

Although hydrochloric acid is usually the firstchoice for treating calcium carbonate scale, therapid acid reaction may hide a problem: spent acidsolutions of scale by-products are excellent ini-tiators for reformation of scale deposits. For exam-ple, a field study evaluating matrix stimulationwith acid, helped an operator in the North Seainterpret declining production rates (below).7 Bycomparing well production histories in the

Injected seawater

Formation water

Precipitation of Calcium Carbonateproduces further pressure drop,leading to furtherprecipitation.

4 ft skin zone

Scale

Scale

Pressure drop zone

Fluid flow

>Production well damage. Autoscaling can lead to problems in producing wells (right), where scaleforms near the perforation throat (right insert). The pressure drop over the near-wellbore matrix canlead to runaway CaCO3 precipitation. Mixing incompatible injection water and formation water canlead to scale precipitation in the formation matrix (left).

7000

6000

5000

4000

3000

2000

1000

0

250.00

200.00

150.00

100.00

50.00

0Oct92

Flui

d flo

w, m

3 /d

Wel

lhea

d pr

essu

re, b

ar

Jan93

Mar93

Aug93

Nov93

Mar94

Sep94

Oct94

Jan95

Wellhead pressureDate of acid wash

Normalized flow

Oil flow Water flow

>Saw-tooth production profiles. A portion of the production history from one of the prolific wells in theGullfaks field shows cyclic production impairment. The normalized flow (red curve) is a good indicatorof productivity changes due to intervention efforts, because it removes the effects of choked-backproduction caused by surface equipment limitations. The normalized curve shows the large and imme-diate impact of multiple acid treatments (indicated by blue circles) and the subsequent loss in wellproductivity within one to three months afterwards—indicating recurring scale precipitation.

Gullfaks field before and after stimulation, engi-neers used NODAL analysis to determine thechange in formation damage, called skin. Then,the effect of each acid treatment on differenttypes of scale in each well was modeled using acoupled wellbore-reservoir simulator (see“Chemical Placement Simulator,” page 40). Theimpact of scale removal on the skin in each casewas compared with the production-derivedchanges in skin to evaluate the type of scale andits location. The field study confirmed that carbon-ate reprecipitation in the gravel packs was the pri-mary damage mechanism causing recurringproduction losses in the wells.

Chemicals that dissolve and chelate calciumcarbonate can break this reprecipitation cycle.Ethylenediamenetetraacetic acid (EDTA) was anearly candidate to answer the need for improvedchemical removal, and is still used today in manyforms (below). While EDTA treatments are more

expensive and slower than hydrochloric acid,they work well on deposits that require a chemi-cal approach. EDTA and variations on its chemi-cal structure are also effective in noncarbonatescale removal, and show promise for the removalof calcium sulfate and mixtures of calcium-bar-ium sulfate.

Recently, Schlumberger developed an im-proved EDTA-based scale dissolver, called U105,as a cost-effective alternative for carbonatematrix stimulation. This dissolver was designedspecifically for calcium carbonate, but is alsoeffective against iron carbonate and iron oxidescales. It dissolves carbonates more slowly thanhydrochloric acid and has a higher dissolvingcapacity than traditional organic acids, such asformic and acetic acid. Once the scale is dis-solved through chelation, there is no reprecipita-tion. Stable at temperatures up to 250°C [482°F],it is a low-toxicity scale dissolver that is effec-tively noncorrosive on most steels—making thetreatment extremely safe.

Other chelating agents have also been opti-mized especially for barium and strontium sulfatescale. For example, U104 is based on an EDTAdissolver containing chemical activators thatenhance the rate of scale dissolution, and hasproven effective on a wide variety of scalesincluding calcium sulfate, calcium carbonate andmixed scales. In a typical applications these solu-tions are diluted with fresh water with a 6- to 24-hour soak period.

36 Oilfield Review

SO4-2

Ba+2 EDTA

Surface complex

Ba-EDTA solutioncomplex

CH2

CO

O

O

CH2CO

CO

Ba CH2

O

O

CO CH2

CH2

N

N

>EDTA chelate compound. Chelating agents are used to lock up unwanted ionsin solution. An EDTA molecule shares electrons from oxygen and nitrogen atomswith barium ions, forming a barium-EDTA chelate compound (top). The chelatingprocess can help to dissolve solid barium sulfate scale (bottom).

1600

1400

1200

1000

800

600

400

200

0Time, days

147 days

Scale dissolvertreatment

Average 450 bblincremental oilover 147 days

700 bbl

1150 bbl

OilWater

Prod

uced

flui

d, b

bl

>North Sea well production history. High skin damage in a well due to BaSO4 andCaCO3 scaling in the perforations and matrix near the wellbore was successfullytreated, resulting in a 64% increase in oil production for more than 147 days.

Autumn 1999 37

The effectiveness of this new dissolver wasdemonstrated on a North Sea well that had high skin damage due to scaling in the near-wellbore matrix and perforations. The scale typewas identified as mixed barium sulfate and cal-cium carbonate. A U104 treatment was designedto bullhead, or pumped against pressure, into theformation to give an average radial displacementof 3 ft [1 m]. The treatment was overflushed witha tubing displacement of inhibited seawater, andthe well was shut in for a total soak time of 18 hours, after which it was returned to produc-tion (previous page, top). Production increased450 BOPD [72 m3/d] paying out all materials,pumping and lost production costs in 12 days.

Conventional mechanical methods—Mechan-ical solutions to remove scale deposits offer awide array of tools and techniques applicable inwellbore tubulars and at the sandface (below).Like chemical techniques, most mechanicalapproaches have a limited range of applicability,so selecting the correct method depends on the well and the scale deposit. Mechanicalapproaches, though varied, are among the mostsuccessful methods of scale removal in tubulars.

One of the earliest scale-removal methodswas an outgrowth of the use of explosives torattle pipe and break off brittle scale. Explosivesprovided high-energy impact loads that couldremove scale, but often damaged tubulars and

cement. Taming the explosive meant changing thetype of explosive or reducing the amount of explo-sive load. A strand or two of the detonation cord,called a string shot, was found to be adequate.

String shots are still used today, especially asa simple diagnostic tool, when quick wirelineentry and detonation during flow yield cluesabout the type and location of scale. Experienceshows that using a few strands of cord, deto-nated by an electronic cap, and long enough tocover the zone of interest, is effective in remov-ing scale blockages in perforations and thin scalefilms inside tubulars.

Thick scales, especially those in tubulars, areoften too strong for safe explosive removal andhave too little porosity for effective chemicaltreatments in a reasonable time frame. For thesedeposits, removal usually requires techniquesdeveloped for drilling rock and milling steel.Impact bits and milling technology have beendeveloped to run on coiled tubing inside tubularsusing a variety of chipping bits and milling con-figurations. The downhole power source is typi-cally a hydraulic motor or a hammer-type impacttool. Motors are fluid-powered, stator and rotorcombinations that turn the bit. Their powerdepends on fluid supply rate and motor size—smaller motors that remove scale inside tubing,typically 111⁄16-in. to 13⁄4-in. diameter, providetorque from 100 to 130 ft-lbf.

Because scale is rarely deposited evenly onthe tubing wall, milling power requirements varyenormously. When motors cannot supply thepower needed for the bit to cut the scale, themotor stalls and the milling process stops. As aresult, scale-removal rates vary with the type ofscale and application, but generally range fromabout 5 to over 30 linear feet [1.5 to over 9 m] ofscale removed from the tubular per hour ofmilling. The variation in milling speed dependson the match between the type of deposit andthe combination of motor and mill. Experienceshows that small, low-torque motors are gener-ally more effective when run with small-toothmills. Larger tooth mills, though more aggressive,do not spin well on irregular scale surfaces—stalling small motors. Thus, the small-tooth, lessaggressive mills cut faster because they are lessprone to frequent motor stalls.

Positivedisplacementmotor andmill

Fluid-powered ‘Moineau’motor and mill. Millremoves deposits bygrinding.

Yes. Cleanrate may bevery slow.

Positive surface indication of cleaningSmall cuttings make hole cleaning easier

Motor stator and mill are expensive expendables~300°F [150°C] limitNot compatible with scale dissolversMill can damage tubulars

Impacthammer

Fluid poweredpercussion hammer.High shock forcesshatter brittle deposits.

Large cuttings size makes hole cleaning more difficult Not compatible with scale dissolvers

Yes. Cleanrate may bevery slow.

Positive surface indication of cleaning Simple, robust tool

Fixed washtool

Fixed tool with manylarge-diameter nozzles.Normally used only withchemical dissolvers.

Most fluid power lost to circulating friction Low nozzle pressure—cannot remove inert deposits

Yes, ifdeposit issoluble.

Simple, robust tool

Spinning-jetting tool

Rotational torqueprovided by nozzlesoffset from tool axis. No speed control.

Inefficient jetting due to high rpm (>5000)

Simple tool Complete wellbore coverage by rotating jets

Yes, ifdeposit issoluble.

Indexed-jetting tool

Nozzle head rotates~90° when coiled tubing pressureis cycled. Head hasmany small-diameternozzles to improvewellbore coverage.

Requires multiple cleaning runs increasing job time and coiled tubing fatigueNo surface indication of cleaningSmall cleaning radius due to small nozzles

Turbine-poweredjetting tool

Fluid turbine rotatesnozzle with two nozzles.Eddy current brakecontrols rpm.

Abrasives cannot be pumped through turbine Complex tool

Complete wellbore coverage with large cleaning ratios

Sonic tools Used to create high-frequencypressure pulses thatremove deposits byshock waves orcavitation.

Hydrostatic pressure suppresses cavitation Tools not effective in removing hard scales in lab tests

SimpleYes, ifdeposit issoluble.

ScaleBlastingtechnique

Nozzle head rotated bytwo nozzles offset fromtool axis. Viscous brakecontrols rpm.

Complete wellbore coverage with large cleaning radius Positive surface indication of cleaning

BridgeBlastingtechnique

Fluid-powered ‘Moineau’motor and jet/mill head.Radial jets follow pilotmill.

Motor strator is an expensive expendable ~300°F limit

Positive surface indication of cleaning

Clean hardbridges

DescriptionTool Clean tubularjewelry

Otheradvantages

Otherdisadvantages

Mechanical cleaning

Chemical cleaning

Jet Blaster tools

>Mechanical scale-removal techniques.

Impact tools, such as the Baker Oil Tools HippTripper tool, are reciprocating tools that workmuch like a small jackhammer with a rotating bit.They impact the scale at 300 to 600 times perminute and rotate about 20 times per minute,typically with a chisel or star-shaped bit. Millscannot be used with such tools because theimpacts cause excessive damage to the millsurface. These tools work best on brittle scale deposits, removing scale as quickly as 10 to100 linear feet [3 to 30 m] per hour.

When fullbore access to scale deposits is par-tially blocked by physical restrictions such asdecreasing tubing diameter and encroaching com-pletion equipment, tools that can change diame-ter are required to remove scale below therestriction. If such equipment is not available,then a small hole—less than full tubing size—can usually be drilled through the scale below therestriction to allow increased flow. Nevertheless,a residual scale surface in the tubing encouragesnew scale growth and makes inhibitor treatments

to block nucleation much more difficult. A clean,bare steel surface is more effective in preventingnew scale growth.

Impact tools like motors and mills usually needfullbore access and seldom clean scale completelyto the steel walls. For such partial access situa-tions, under-reaming mills can increase the effec-tive diameter by moving the milling bladesoutward in response to pump pressure and rate.Under-reaming mills are effective, but removescale only at about half the rate of a typical mill.

Fluid-mechanical jetting methods—Downholefluid-jetting systems, such as Halliburton’sHydroblast and BJ-NOWSCO’s RotoJet system,have been available for many years to removescales in production tubing and perforations. Suchtools use multiple jet orifices or an indexed jettinghead to achieve full wellbore coverage. Thesetools can be used with chemical washes to attacksoluble deposits wherever placement is critical toprevent bullheading reagent losses. Water jettingcan be effective on soft scale, such as halite, anddebris or fill, but experience shows that it is lesseffective on some forms of medium to hard scalesuch as calcite and barium sulfate (left).

38 Oilfield Review

>Removing calcium carbonate scale with waterjetting. The tubing was jetted with a single waterjet at a rate of 2.4 in./min [1 mm/sec]. Althoughcarbonate scale has been removed, a consider-able amount remains in place.

>Removing calcium carbonate scale with abrasivewater jetting. The tubing was jetted with abrasivesand in a single water jet at a rate of 2.4 in./min [1 mm/sec]. During the test the jet was held station-ary for 3 minutes, and the sand jet cut a hole nearly80% through the tubing wall, an unacceptable levelof damage.

Target

Speed timingelectronics

Barrel Gas cylinder

Individual particle impact Speed 200 m/sec Impact angle 30/90°

Sand particles Limestone particles Glass Beads Sterling Beads particles

Particle-impact tester. A particle-impact testerwas built to study and evaluate the abrasivematerial damage mechanism on steel tubing andscale substrate (top). This device can fire individ-ual particles in excess of 450 mph [200 m/sec]that hit the surface at angles between glancingblows of 30° and perpendicular impacts. Thedamage from various particles can be seen in thephotographs (bottom). Angular sand and calciteparticles tend to gouge through the steel, leadingto ductile failure. Round particles bounce off thesteel surface. Glass beads create large, deepimpact craters that eventually erode through thesteel tubing. Sterling Beads particles shatter onimpact with steel, creating only small pits thatleave the steel undamaged.

>

Autumn 1999 39

At surface pressure, water jetting removesscale by cavitation, whereby small bubbles formin the fluid jet stream. These bubbles are createdby the large pressure release as fluid passesthrough the jet nozzle. The bubbles collapse on impact with scale, causing a forceful—almost explosive—erosive effect. Research atSchlumberger Cambridge Research, England,shows that this cavitation process is highlysuppressed downhole under hydrostatic bore-hole pressure. Cutting rates are typically reducedby a factor of four or more. Surface pumping-pressure limitations using coiled tubing-conveyed jetting tools prevent increasing fluidpressure high enough to overcome the differen-tial loss at the bottom.

Abrasive slurries—Adding a small concentra-tion of solids, 1% to 5% by weight, to a water jetcan drastically improve its ability to cut throughscale. Water jets using abrasive sand are widelyused in the construction and demolition indus-tries for cutting reinforced concrete, and even indemilitarization for cutting live ammunitionswithout generating heat or an ignition source.This technique also shows superior cuttingperformance in calcium carbonate scale overwater jetting alone (previous page, top right).Unfortunately, using abrasives such as sand candamage steel tubulars. When scale is completelyremoved from tubing, the abrasive jet erodes thesteel as efficiently as it does the scale. Shouldthe jetting tool stall, there is a significant risk ofthe abrasive jet perforating the steel tubing.

An abrasive jet that cuts scale without dam-aging tubing must exploit the difference in hard-ness between wellbore scale and the underlyingsteel. One of the key differences between well-bore scale and tubular steel is that while scale isbrittle, steel is prone to ductile failure (previouspage, bottom). A sharp sand particle will erodethe surface of ductile material by a cutting andplowing action. On the other hand, a hard roundparticle will bounce off the surface, removingonly a small volume of steel and leaving animpact crater. Scale exhibits brittle failure, so theimpact of a hard particle fractures the scale andultimately causes substrate disintegration. Scalebreakdown is independent of particle shape.

Choosing round rather than sharp, angularparticles promotes scale erosion while reducingdamage to steel tubulars. For example, AdamsCoiled Tubing provides a glass-bead abrasive-jetting system. The jetting tool has eight station-ary nozzles allowing complete radial coverageand downward pointing jets. The system iscompatible with foaming fluids and effective onall types of scale. On the other hand, the cratersformed by repeated impacts with glass particlescan eventually lead to fatigue and failure of thesteel surface (above).

Sterling Beads abrasives—Glass beads aresignificantly harder than the steel tubing andcause excessive tubing erosion. Reducing thehardness of the abrasive particles too much,however, renders them ineffective. Thus, thedesired hardness is a compromise between min-imizing damage to the steel while maximizing thescale-cutting performance. Other parameters,such as abrasive material friability, are alsoimportant. Although many spherical particles ofcorrect hardness are available, they tend to havelow durability and shatter on impact—impartinginsufficient destructive energy to the substrate toremove the scale.

Based on experimental and theoretical studyof the physical interactions between abrasiveparticles and typical tubing materials atSchlumberger Cambridge Research, a new abra-sive material called Sterling Beads abrasive wasproposed.8 This material matches the erosive per-formance of sand on hard, brittle scale materials,while being 20 times less erosive of steel, andwill not damage the well if prolonged jettingoccurs in one spot (above). The abrasive particleshave a spherical shape, a high fracture tough-ness and low friability (below). The beads aresoluble in acid and have no known toxicity,making cleanup operations simple.

>Tubing cleaned with glass-bead abrasive. Thetubing was jetted with glass beads in a singlewater jet at a rate of 2.4 in./min [1 mm/sec].Carbonate scale has been removed. During thetest the jet was held stationary for 3 minutes, and the glass beads cut a hole nearly 30% intothe tubing wall.

>Tubing scale removed with the Sterling Beadsabrasive. The tubing was jetted with SterlingBeads abrasive in a single water jet at a rate of2.4 in./min [1 mm/sec], to remove carbonate.During the test, the jet was held stationary for 3 minutes, and less than 2% of the steel wasremoved from the tubing wall.

0.75 mm

>Microscopic view of Sterling Beads abrasive.

8. Johnson A, Eslinger D and Larsen H: “An Abrasive jettingRemoval System,” paper SPE 46026, presented at the1998 SPE/IcoTA Coiled Tubing Roundtable, Houston,Texas, USA, April 15-16, 1998.

Coiled tubinghead connector,

check valves and disconnect

Dual-actuatedcirculating

valve

Filter module

Swivel “Moineau” PDM

Motormodule

Drift ring

Headmodule

Radial jet head

Scale Blastingtechnique

Jet drillinghead

Radial jethead

and pilot mill

Bridge Blastingtechnique

Nozzle head Drift ring

< Jet Blaster tool. Photograph (top) shows thetoolbox containing the abrasive jetting system asdelivered to the wellsite. The Jet Blaster down-hole tool (middle left) includes coiled tubing con-nections, check valves and disconnect equip-ment; dual-acting circulation unit; and a filterthat prevents unexpected debris in the jettingfluid from clogging the jetting nozzles. The toolconverts fluid power to a continuous speedrotation with a viscous shearing-fluid speed-controlled swivel for removing scale along theinside of tubular walls (insert middle right).Reaction forces from the two offset jet nozzlesprovide about 5 ft-lbf torque to rotate the swivelhead at speeds less than 200 rpm. The jettinghead consists of a nozzle carrier and a drift ring.In the Jet Blasting and Scale Blasting tech-niques, the nozzle carrier is assembled with twoopposing tangential jets (bottom left). The offsetjetting nozzles maximize hydrodynamic energytransport to the wellbore. The drift ring allowsweight to be set down on the tool so that the tool will advance only after the entire minimumbore diameter is cleaned. In the Bridge Blastingtechnique, a positive displacement “Moineau”style motor (bottom center and right) can beused to drill scale bridges across tubing forBridge Blasting applications. This motor candeliver 150 ft-lbf torque to the head module at 300 rpm.

A simulator can help design an effective chemi-cal treatment. For example, StimCADE softwareis a coupled wellbore and reservoir stimulationprogram that includes a wellbore model, areservoir model and a chemical reaction modelfor scale prediction. Input parameters include a comprehensive list of wellbore, formation,fluids and chemical treatment descriptions. The wellbore model solves convection-diffusionequations for fluid flow down the treatment string

Universal scale-removal system—Engineersat the Schlumberger Reservoir CompletionsCenter in Rosharon, Texas, USA, developed a vis-cous fluid-controlled rotating head jetting toolcalled the Jet Blaster tool, that has jet-nozzlecharacteristics optimized for use with SterlingBeads abrasives (right). This new rotating jetting-head-based tool, combined with the SterlingBeads abrasives, forms the basis of a new sys-tem of coiled tubing-conveyed intervention ser-vices designed to remove scale in downholetubulars. The Blaster Services system featuresthree scale-removal techniques that can beapplied to a wide range of scale problems:• The Scale Blasting technique combines the use

of Sterling Beads abrasive with the new jettingtool for hard-scale removal.

• The Bridge Blasting technique uses a poweredmilling head and abrasive jetting, when scalecompletely plugs the tubular.

• The Jet Blasting technique uses the new jet-ting tool with nonabrasive fluids for soft-scale-removal applications.

The scale-removal system also includes ascale-removal design program, called Jet Advisorsoftware, that enables an operator to optimize thejetting-tool configuration and nozzle size based onwell conditions to maximize jetting power andhead penetration rate. It also helps with the selec-tion of either abrasive or nonabrasive—fluidonly—scale-removal techniques. The Jet Advisorprogram alerts the operator to the risk of tubulardamage due to headstalls—using steel damageand coiled tubing stick-slip analysis.

(production tubing, coiled tubing or the casing)to estimate friction pressure during pumping.

In estimating the invasion of treatment fluidsinto the formation surrounding the wellbore,the reservoir model tracks the location of differ-ent fluid fronts in the reservoir. The chemicalreaction model estimates the rate of mineraldissolution following kinetic rate laws for thesolvents used and mineral species present inthe formation lithology section. The net mineral

dissolution is translated into a skin reductionfor each acid treatment.

Additional features include the ability tomodel wellbore deviation, predict effects ofdiverting agents on fluid-invasion profiles in thereservoir, and simulate flow of two fluids simul-taneously into the well—one down tubing orcoiled tubing, and one down the annulus. Thesefeatures help predict the efficiency of varioustreatment placements.

Chemical Placement Simulator

40 Oilfield Review

Autumn 1999 41

Removing hard scale—For hard scales likeiron, strontium and barium sulfate, nonabrasivefluid jetting and chemical treatments are inade-quate. The controlled-erosive action of theSterling Beads abrasive has been successful inremoving every type of scale in tubing, includingthe most difficult barium sulfate scales, at ratesup to 100 ft/hr [30 m/hr] or more. The ScaleBlasting technique is a particularly good optionwhen the scale encountered in the well is insol-uble, unknown or of variable hardness. The sys-tem also provides a safe method to remove scalefrom downhole completion equipment. Rate ofpenetration (ROP) is controlled using a drift ringthat ensures full tubing-diameter cleaning withminimum damage to the steel surface.

The Scale Blasting technique was used in theNorth Sea to remove hard barium sulfate depositson two gas-lift valves, identified by multifingercaliper logs, in a multiple-mandrel gas-lift comple-tion well (right).9 Well flowing pressure decreasedas water was injected, and there was a possibilitythat the available gas pressure would be inade-quate to reach the only remaining active valve in aside-pocket mandrel. Failure to remove andchange a second damaged valve would haveresulted in the well dying as water cut increasedand led to a costly workover. Solvents were inef-fective in removing enough scale to allow kickovertools to engage and latch onto the valves.10

The new coiled tubing-conveyed abrasive-jetting technology was used in this well for thefirst time in the North Sea. Jet Advisor softwareprovided the optimal drift ring size, nozzle and noz-zle-head size to efficiently clean the hard scale.The software also provided the optimal abrasiveconcentration and predicted scale-removal rates.

First, the damaged side-pocket mandrel wascleaned at a rate of 100 ft/hr [0.5 m/min]. Then,the other operating side-pocket mandrel wascleaned with the same procedures. The entireoperation was evaluated by running the kickovertool and checking the possibility of changing thegas-lift valves in the cleaned side-pocket man-drels. A gamma ray log was also run to evaluatethe remaining scale deposit in the completion(right). The damaged valve was successfully

retrieved and replaced. Abrasive jetting efficientlycleaned the scale without damaging the mandrel.

In another example, up to 0.38-in. [1-cm] thickbarium sulfate deposits prevented an operator inGabon, West Africa, from accessing and chang-ing five gas-lift mandrels in a well with a taperedproduction-tubing completion. The well had notproduced since 1994. Gauge cutter runs showedscale buildup bridged the tubing, blocking accessto the lower section of the well. The workoverobjectives were to clean the tubing scale, changeout gas-lift mandrels, and gain access to the wellbelow the tubing.

Early attempts at conventional scale-removalmethods, including several positive displacementmotors (PDM) and milling runs, an impact hammerand another jetting system following dissolvertreatments, were unsuccessful. The ability toremove hard barium sulfate scale under a widerange of conditions made the Scale Blasting tech-nique an attractive alternative. Because of thetapered completion, several sizes of gauge ringsand nozzle heads were required. The jetting fluidwas formulated with standard concentrations ofpolymer and Sterling Beads abrasives to achieveoptimum well cleanup and rate of penetration.

Nominal tubing diameter

Diameter April 1996

Diameter April 1997

Diameter August 1997

Dept

h, ft

X526

X527

X528

X529

X530

4.0 in. 6.0 in.

>Scale buildup between April 1996 and August 1997. Multi-arm caliper logs show scaleaccumulation (shaded) in the upper side-pocket mandrel.

9. Tailby RJ, Amor CB and McDonough A: “Scale Removalfrom the Recesses of Side-Pocket Mandrels,” paper SPE54477, presented at the 1999 SPE/IcoTA Coiled TubingRoundtable, Houston, Texas, USA, May 25-26, 1999.

10. For a discussion of the use of kickover tools to removeretrievable gas-lift valves located in side-pocket mandrels: Fleshman R, Harryson and Lekic O: “ArtificialLift for High-Volume Production,” Oilfield Review 11, no. 1 (Spring 1999): 49-63.

900

X870 X880Depth, m

May 1998

Region of scale removal

April 1997

X890 X900X860

800

700

600

500

GR, A

PI

400

300

200

100

0

>Confirming scale cleaning. Gamma ray logs can be used to indicate the amount of scaleremoved over the 22-m [84-ft] cleaned interval centered at the side-pocket mandrel loca-tion. The 1997 gamma ray log shows the relative scale buildup on the lower side-pocketmandrel one year before treatment. The 1998 log was measured after scale was removedfrom the zone between X872 m to X894 m.

42 Oilfield Review

1.5

1

13

4

2.5

7

2

1.5

Scale Blasting technique

Scale Blasting technique

Bridge Blasting technique

Scale Blasting technique

Scale Blasting technique

Bridge Blasting technique

Scale Blasting technique

Scale Blasting technique

Blaster Services Length of scaleremoved, m

Treatmenttime, hr

Tool driftO.D., mm

Well 1

Well 2

Well 3

Well 4

Well 5

Well 6

Well 7

Well 8

1023

45

162

1108

28

270

511

20

54

46.7

46.7

46.7

54

54/45

54

46.7

>Beaverhill Lake scale-removal results.

Jet Advisor software optimized the rotatingjetting-head torque and abrasive cutting effi-ciency with rate, pressure and viscosity as vari-ables in the 56°-deviated wellbore. The mosteffective pump rates and surface pressures weredetermined by the CoilCADE software, while theCoilLIMIT program was used to determine thesafe working limits of the coiled tubing.

The treatment resulted in 6500 ft [1981 m] of tubing cleaned in a total jetting time of 25.5 hours. Average penetration rates were 600 to 900 ft/hr [3 to 5 m/min] in 31⁄2-in. tubing,and 40 to 100 ft/hr [0.2 to 0.5 m/min] across the gas-lift mandrels and in the 27⁄8-in. tubing.Successful treatments allowed the operator toreplace the gas-lift mandrels, and the well nowproduces 2000 B/D [320 m3/d]. The removed gas-lift mandrels had been cleaned in all areasexposed to the wellbore and the valves were not damaged.

Removing scale bridges from tubulars—Scale deposits that completely bridge tubularscan be removed with a special adaptation of theJet Blaster abrasive jetting tool using the BridgeBlasting technique. The Bridge Blasting tech-nique incorporates a 1.69-in. diameter PDM spe-cially modified to prevent Sterling Beads abrasivefrom clogging the motor’s high-pressure labyrinthshaft seal. The PDM drives a combination jettingand milling head that uses a Reed-Hycalog dia-mond mill to make a small pilot hole in thedeposit (above right). Radial jets complete thecleaning. Since the mill removes only a fractionof the total bridged deposit volume, the cleaningrate and overall mill and motor reliability aremuch higher than with conventional PDM-milling-cleaning methods.

A drift ring centers the tool and prevents milldamage to the tubulars—frequently a problemwith conventional milling techniques. In hard,bridged deposits, a different jet-drilling head isused if the pilot mill does not achieve acceptablecleaning rates. The jet-drilling head uses four crit-ically oriented jetting nozzles to drill through thescale bridge using a Sterling Beads slurry. A sub-sequent run with the Jet Blaster swivel withSterling Beads abrasive is usually required to com-plete cleaning to the full diameter of the tubulars.

Iron sulfide [FeS2] scale is a special problemfor BP Amoco throughout the Kaybob south fieldin the Beaverhill Lake formation in Canada. Theiron sulfate crystallites form directly on steeltubing, attaching firmly, and promote eitherbimetallic or crevice corrosion beneath the crys-tallites. These sour gas [H2S] condensate wellsdeposit high molecular-weight compounds, suchas asphaltene, on the iron sulfide crystallitesinside tubing.11

This unusual scale cannot be removed byhydrochloric acid, surfactants or chelating agentsbecause asphaltene protects the scale from scaledissolvers. The scale can be removed only bymechanical techniques or by first chemicallyremoving the asphaltene layers. Past experiencewith conventional methods for scale removal—including foamed acid, acid jetting combined withorganic solvents such as xylene, and drilling,milling and tubing shakers—were inconsistent.

New abrasive jetting techniques using theSterling Beads abrasive were evaluated in eightwells. Gelled water containing a xantham bipoly-mer additive was used for friction reduction andimproved cuttings transport. The Sterling Beads

weight concentration used in these wells was2.5%. Treatment times varied from 1 to 4 hoursfor six wells treated with the Scale Blastingtechnique, and up to 13 hours in one of the twowells containing scale bridges treated with theBridge Blasting technique (below). Rates of pen-etration vary depending on tool drift, nature ofthe deposits, occurrence of bridges when usingthe Scale Blasting technique, and wellborerestrictions. Overall, 10,400 ft [3170 m] of scalewere successfully removed from the eight wellsin 32.5 hours cumulative jetting time.

Removing sand plugs—When wellboredeposits are soft, acid soluble or chemically reac-tive, the nonabrasive Jet Blasting technique is themost cost-effective and efficient. The increasedfluid-jet efficiency from the optimized jetting headmaximizes cleaning ability on soft scale, freshcement and filter cake. Other drilling damage andinsoluble deposits benefit greatly from a com-bined chemical and jet-cleaning treatment.

An operator in south Texas was having diffi-culty removing sand plugs in a well with threefracture-stimulated zones that were isolated bysand plugs. Each sand plug was topped with a cap

>Bridge Blaster milling head. The Bridge Blaster system can be configured with aradial jetting head, drift ring and a Reed-Hycalog mill (left), or with downward-facingabrasive jetting nozzles (right) that drill a hole through scale bridges that cannot becut with tungsten carbide mills.

11. Crombie A, Halford F, Hashem M, McNeil R, Thomas EC, Melbourne G and Mullins O: “Innovations in Wireline Fluid Sampling,” Oilfield Review 10, no. 3(Autumn 1998): 26-41.

12. Wigg H and Fletcher M: “Establishing the True Cost of Downhole Scale Control,” paper presented at theInternational Conference on Solving Oilfield Scaling,Aberdeen, Scotland, November 20-21, 1995.

13. Rosenstein L: “Process of Treating Water,” U.S. PatentNo. 2,038,316 (April 21, 1936). This 1936 US patent is one of the earliest references to threshold inhibitors.

14. Nancollas GH, Kazmierczak TF and Schuttringer E: “A Controlled Composition Study of Calcium CarbonateGrowth: The Influence of Scale Inhibitors,” Corrosion-NACE 37, no. 2 (1981): 76-81.

Autumn 1999 43

of silica flour to provide a better pressure seal. Adrill motor with a mill was used to try to clean outthe sand plugs. The first plug was cleaned out suc-cessfully, but the mill was completely worn downafter cleaning 2 ft [0.6 m] of the second plug. Asecond mill managed to drill out only an additional5 ft [1.5 m] in the plug before it was completelyworn (above). The plug with silica flour on top hadbeen crushed and packed tightly due to fracturingpressure from above, forming a hard fill.

Jet Advisor software was used to select theproper nozzle size for the Jet Blasting techniquebased on well conditions. Head components andsizes were based on well completion and fill mate-rial. The jetting fluid was a 2% potassium chloride[KCl] water with friction reducer, foaming agentand nitrogen [N2]. Treatment resulted in a cleanoutrate of 420 to 600 ft/hr [2 to 3 m/min]. The plugsand silica flour were removed from the well in lessthan one day, saving the operator the cost of theworkover rig and five days in lost production.

Preventing ScaleThe direct cost of removing scale from one wellcan be as high as $2.5M, and the cost of deferredproduction even higher.12 Just as prevention isbetter than cure in medical practice, keepingproducing wells healthy is ultimately the mostefficient way to produce hydrocarbons. In mostcases, scale prevention through chemical inhi-bition is the preferred method of maintainingwell productivity. Inhibition techniques can rangefrom basic dilution methods, to the mostadvanced and cost-effective methods of thresh-old scale inhibitors.

Dilution is commonly employed for control-ling halite precipitation in high-salinity wells.Dilution reduces saturation in the wellbore by continuously delivering fresh water to thesandface, and is the simplest technique toprevent scale formation in production tubing. It requires installation of what is called amacaroni string through the production tubing

(above). The macaroni string is typically small-diameter tubing—less than 11⁄2-in.

In addition to dilution, there are literally thou-sands of scale inhibitors for diverse applicationsranging from heating boilers to oil wells. Most ofthese chemicals block the growth of the scaleparticles by “poisoning” the growth of scalenuclei. A few chemicals chelate or tie up the reac-tants in a soluble form. Both approaches can beeffective, but each requires careful application astreatments show little tolerance for change in theproducing system. Chelating inhibitors block pre-cipitation or scale growth only for a certain lim-ited level of oversaturation. Equilibrium upsetsoccur, even in protected systems, allowing scaleto precipitate. Because chelating agents con-sume scale ions in stoichiometric ratios, the effi-ciency and cost-effectiveness of chelants asscale inhibitors are poor.

In contrast, threshold scale inhibitors interactchemically with crystal nucleation sites and sub-stantially reduce crystal growth rates. Thresholdscale inhibitors effectively inhibit formation ofmineral scales at concentrations on the order of1000 times less than a balanced stoichiometricratio.13 This considerably reduces the treatmentcost. Most scale inhibitors are phosphate com-pounds: inorganic polyphosphates, organic phos-phate esters, organic phosphonates, organicaminophosphates and organic polymers. Thesechemicals minimize scale deposition through acombination of crystal dispersion and scale sta-bilization (left).14

>Mill worn by silica flour.

Macaroni string

B

A

Chemical squeeze

Salineproduction

Freshwater

>Macaroni string. The small-diameter macaronistring, also called a spaghetti string, or capillarystring, delivers fluids and chemicals into produc-tion wells. It delivers chemicals close to the interval, as shown at A, that is producing the fluid needing treatment. A periodic inhibitorsqueeze into the formation is shown at B.

Dispersion Stabilization

Inhibitor absorbed onto the active sites of the growing crystals—preventing further growth

Crystal nuclei are stericallystabilized—preventing further growth

>Dispersion and stabilization. Dispersion (left) prevents small seed crystals of scale from adhering totubing walls and other crystal particles. Stabilization chemicals modify the deposited scale structure,preventing additional crystal attachment.

44 Oilfield Review

Fluid inflow through adsorbed zone

Phase-inverted inhibitor in proppant orimpregnated proppants in proppant

> Fracture stimulation with inhibitor placement. High-efficiency scale-inhibitor placement isachieved by pumping the inhibitor into the fracturing fluid during fracture stimulation. The inhibitoris retained by adsorption on the formation in the leakoff zone, or by precipitation on the proppant.As formation water passes through the inhibitor-absorbed zone, it dissolves enough inhibitor toprevent the water from precipitating in the fractures and wellbore.

Inhibitor lifetime—Scale inhibitors areretained in the formation by either adsorbing tothe pore walls or precipitating in the pore space.Adsorption is most effective in sandstone forma-tions (above). Treatment lifetimes depend primar-ily on the surface chemistry, the temperature, andthe pH of the liquid contacting the formation, andare occasionally unusually short (3 to 6 months)because the adsorption capacity of reservoir rocksunder reservoir conditions is limited.15 Under spe-cial conditions, such as high adsorption-capacityformations and low water-production rates, up totwo-year lifetimes can occur.

Normally, treatment lifetimes exceed one yearfor properly designed treatments in which precipi-tation is the inhibitor retention mechanism—evenwhen high water-production rates are encoun-tered.16 For example, phosphates and phosphino-carboxylic acid inhibitors are among those knownto prevent calcium carbonate scale. Calcium ionsare often liberated when the inhibitors are placedin carbonate formations, and precipitation is thedominant long-term retention mechanism in car-bonate formations. A calcium chloride brine over-flush is often pumped to induce scale inhibitorprecipitation and extend the treatment lifetime inreservoirs that do not naturally contain enoughsoluble calcium to precipitate the inhibitor.17

Long inhibitor lifetime can be also beachieved by pumping large volumes of inhibitordeep into the formation, such that the inhibitor isexposed to and absorbed to a large surface area.This is not always successful because squeezingwater-based inhibitors into oil zones can lead toa temporary change in formation wettability. Thisresults in unacceptably long production-recoverytimes. Alternative oil-soluble inhibitors that donot cause the formation rock to become waterwet are needed. New fluids based on criticalpoint wetting of rock are being tested for inhibitor

enhancement. These make the reservoir rock“super wet,” allowing a higher degree of inhibitorretention and a longer protection lifetime.

Commercial software, such as the Squeeze-Vprogram that was developed at Heriot-WattUniversity, Edinburgh, Scotland, models theretention and release of scale inhibitors byadsorption or precipitation. This program is usedto optimize inhibitor concentrations, treatmentand overflush volumes to maximize inhibitor life-time. It can also be used to match histories ofprevious treatments as part of an overall strategyof continual improvement in scale management.

Improving inhibitor placement—Ultimately,treatment performance is based on scale preven-tion, not on the duration of the inhibitor. Properinhibitor placement is a key factor in the perfor-mance of an inhibitor squeeze treatment.Bullheading the inhibitor into a formation canlead to overtreatment of low-pressure and high-permeability zones, and undertreatment of

high-pressure and low-permeability zones. Thus,it is considered good practice to place scaleinhibitors in heterogeneous formations using thesame placement techniques employed to controlacid placement. In fact, there are significantadvantages to combining the acid and scale-inhibitor treatments to ensure that the scaleinhibitor is controlled along with the acid. Caremust be taken to insure that the acid pH does notexceed that required for inhibitor precipitation.18

Integrating scale inhibitor with fracturestimulation—Protection of propped fracturesagainst mineral scale fouling is critically depen-dent upon proper inhibitor placement. Portions ofthe fracture that are left untreated by theinhibitor might be irreversibly damaged becauseof the ineffectiveness of contacting mineralscales in proppant packs with scale solvents. Asa result, there have been efforts to pump scaleinhibitors in fracturing fluid, thereby guarantee-ing proppant-pack coverage.19

Phase-trappedinhibitor

Adsorbed inhibitorClay or othercharged surface

Inhibitor Adsorption Inhibitor Precipitation with Phase Separation

Phase-separated inhibitor

Clay or othercharged surface

Dissolved inhibitor

>Adsorption and precipitation. Scale inhibitors yield the best treatment lifetimes when they are retained in the formation eitherby adsorption to the pore walls (left), or by precipitating in the pore space (right).

Autumn 1999 45

An alternative inhibitor delivery system,implemented by Schlumberger, called theScaleFRAC system combines a scale-inhibitortreatment and fracture treatment into a single-step process by using a new liquid inhibitor com-patible with fracturing fluids. The scale inhibitoris effectively placed everywhere in the proppedfracture by pumping the scale inhibitor during thepad and sand-laden stages of the fracturingtreatment (previous page, bottom). The newprocess eliminates a scale squeeze treatmentimmediately following a fracture stimulationtreatment, and also circumvents the problem ofslow oil-production recovery caused by wettabil-ity changes produced by conventional scale-squeeze treatments.

The new inhibitor delivery system has beenused extensively on the North Slope in Alaska,and has found applications in the North Sea andthe Permian Basin. For example, results in thePermian Basin show that inhibitor concentrationsin produced water remain above threshold valuesnecessary to prevent scale deposition signifi-cantly longer than conventional treatments(above right). The new integrated inhibitor-frac-ture treatment provides sustained fracture pro-ductivity due to better inhibitor placement. It alsosimplifies wellsite logistics, due to combining thesqueeze and inhibitor treatments; and the wellreturns to production faster because there is noshut-in to allow the inhibitor to adsorb or precip-itate in the formation.

Recently, AEA Technology in England devel-oped a new porous ceramic proppant that isimpregnated by the scale inhibitor for use duringhydraulic fracturing.20 The novel feature of the AEA scale inhibitor is that the salt of a

commonly used oilfield scale inhibitor is pre-cipitated such that it fills the porosity of alightweight ceramic proppant. The filled ceramicproppant can then be substituted for a fraction ofthe original proppant in the fracture-treatmentdesign. Upon production, any water flowing overthe surface of the impregnated proppant willcause dissolution of the scale inhibitor—protect-ing the well against scale depositing from thewater. The inhibitor-release mechanism is disso-lution of the inhibitor from the interstitial poresof individual proppant grains. This avoids wastedinhibitor by phase trapping. After all the inhibitoris dissolved, the ceramic substrate remains andcontinues to serve as a propping agent.

ConclusionThere have been many significant advances inscale control and remediation in recent years.Today, operators have access to a portfolio ofchemical and mechanical products designed toremove scale and prevent its buildup. Theimprovements in placement technology, reservoirchemistry and intelligent fluids furnish more cost-effective options for chemical scale inhibition andremoval in the formation. Developments in scale-removal services incorporating new abrasivematerials are providing fast, reliable ways toremove scale inside tubulars without risk to thesteel tubing.

Each new technology improves one aspect ofscale control in a wellbore. Combined, these newtechnologies become part of a scale-managementprocess in which one can apply surveillancemethods to identify the onset of scaling condi-tions and develop the optimum strategy for reduc-ing scaling-related production losses andremedial expenses. The strategy may include ele-ments of scale prevention and periodic removal.Engineers working in scale-prone reservoirs aregrateful for every improvement in the technologyused to combat their scale problems. —RCH

50,000 100,000 150,000 200,0000.1

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Scal

e-In

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tor c

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ppm

Cumulative water tested, bbl

ScaleFRAC Well AScaleFRAC Well BConventional treatment

Minimum inhibitor range

> Inhibitor retention. Inhibitor elution data measured in two wells treated with theScaleFRAC system show that inhibitor concentrations in the produced waterremained above the threshold value—typically 1 to 5 ppm—to prevent scaledeposition and growth. Wells A and B treated with the new inhibitor-placementtechnique produced scale-free water significantly longer than those with conven-tional treatments.

15. Browning FH and Fogler HS: “Precipitation andDissolution of Calcium Phosphonates for theEnhancement of Squeeze Lifetimes,” SPE Production & Facilities 10, no. 3 (August 1995): 144-150. Meyers KO, Skillman HL and Herring GD: “Control ofFormation Damage at Prudhoe Bay, Alaska, by InhibitorSqueeze Treatment,” paper SPE 12472, presented at theFormation Design Control Symposium, Bakersfield,California, USA, February 13-14, 1984.

16. Martins JP, Kelly R, Lane RH, Olson JB and Brannon HD:“Scale Inhibition of Hydraulic Fractures in Prudhoe Bay,”paper SPE 23809, presented at the SPE InternationalSymposium on Formation Damage Control, Lafayette,Louisiana, USA, February 26-27, 1992.

17. See Meyers et al, reference 15.18. Crowe C, McConnell SB, Hinkel JJ and Chapman K:

“Scale Inhibition in Wellbores,” paper SPE 27996, presented at the University of Tulsa CentennialPetroleum Engineering Symposium, Tulsa, Oklahoma,USA, August 29-31, 1994.

19. Powell RJ, Fischer AR, Gdanski RD, McCabe MA andPelley SD: “Encapsulated Scale Inhibitor for Use inFracturing Treatments,” paper SPE 30700, presented atthe SPE Annual Technical Conference and Exhibition,Dallas, Texas, USA, October 22-25, 1995. See alsoMartins et al, reference 16.

20. Webb P, Nistad TA, Knapstad B, Ravenscroft PD andCollins IR: “Economic and Technical Features of aRevolutionary Chemical Scale Inhibitor Delivery Methodfor Fractured and Gravel Packed Wells: ComparativeAnalysis of Onshore and Offshore Subsea Applications,”paper SPE 39451, presented at the SPE InternationalSymposium on Formation Damage Control, Lafayette,Louisiana, USA, February 18-19, 1998.