Chapter 9 Scale Deposition, Removal,and Prevention

Causes of scale depositionPrediction of scaling tendencyldentification of scaleScale removalSca I e-p reve nti o n m eth od s

INTRODUCTION

Scale is deposited in formation matrix and frac-

tures. wellbore, downhole pumps, tubing, casing,flowlines, heater treaters, tanks, and salt water dis-posal and waterflood systems. Scale deposits usually

form as a result of crystallization and precipitation of

minerals from water.The direct cause of scaling is frequently pressure

cirop, temperature change, mixing of two incompati-

ble waters, or exceeding the solubility product. Scalesometrmes limits or blocks oii and gas production byplugging the formation matrix or fractures, perfora-

tions, wellbore, or producing equipment.The composition of scales is as variable as the na-

ture of the waters that produce them. The most com-mon oil field scale deposits are calcium carbonate(CaCOr), gypsum (CaSOo ' 2H2A), barium sulfate(BaSOo) and sodium chloride (NaCl) (See Table 9-l).Calcium sulfate (CaSO) or anhydrite does not usuallydeposit downhole but may be deposited in boilers andheater treaters. A less common deposit is strontiumsulfate (SrSO).

Scale deposited very rapidly may have gas chan-

nels, by very porous, and be easy to remove with

acid. Scale deposited slowly may be very hard anddense, and may be difficult to remove with acid or

other chemicals.

Loss of Profit

The greatest loss of profit each year in the U.S.

from scale deposits is probably caused by the loss of

oil and gas production. It is estimated that a rnajorit)-

of the 70O,000 oil, gas, and service wells in the U.S

have appreciably reduced productivity or injectivity

because of scale deposited in the wellbore, perfora-

tions. the formation matrix, or in formation fractures.

Scale causes a large number of costly pulling jobs'

fracturing of wells to bvpass scale, and other remedial

work each year in both production and iniection

wells, such as the two examples cited below. Many

oil and gas fields have probably been prematurely

abandoned because of scale.

l. Mobil reported gypsum (gyp) scale caused by

mixing incompatible waterflood waters plugged a 4-

in. flowline in four days.2. ln l95l , Earlougher reported that 187 remedial

fracturing jobs were performed to bypass scale plug-

ging of the formation flow channels and wellbores in

a single waterflood project in West Texas.

CAUSES OF SCALE DEPOSITION

Primary factors affecting scale precipitation, de-position, and crystal growth are: supersaturation; min-gling of two unlike waters having incompatible com-pounds in solution; change of temperature; change ofpressure on solution; evaporation (affects concentra-tion); agitation; contact time; and pH.

Tendency to Scale-CaCOt

In oil wells, calcium carbonate precipitation is

usually caused by pressure drop releasing COr from

bicarbonate ions (HCO,-t). When CO, is releasedfrom solution, the pH increases, the solubility of

dissolved carbonates decreases, and the more soluble

171

PRODUCTIONoPERATTONS/VOL. 2Well Complet ions, Workover, and St imulat ion 172

TABLE 9.i

Chemical Name Chemical Formula Mineral Name

Sod ium Ch lor ide

Calcium Carbonatelron Carbonatel ron Su l f idelron Oxidelron OxideMagnes ium Hydrox ide

Calcium SulfateCalcium SulfateBarium SulfateStrontium SulfateBarium Strontium Sulfate

Water Soluble Scale

NaCl

Acid Soluble Scales

CaCO.FeCO.FeSFerO.Fe.OoMg(oH) ,

Acid Insoluble Scales

CaSOoCaSOo.2HrOBaSOoSrSOoBaSr(SOo),

Ha l i te

CalciteSideriteTrol i teHematiteMagneti teBrucite

AnhydriteGypsumBariteCelestite

bicarbonates are converted to less soluble carbonates.As an illustration of the severity of the problem, lossof only 100 milligrams of bicarbonate per liter ofwater can result in deposition of 28.6 lb of calciumcarbonate per 1,000 bbl of water.

Scale precipitation also varies with calcium ionconcentration (common ion effect-such as fromCaCl2), alkalinity of water (concentration of bicar-bonate ion), temperature, total salt concentration,contact time, and degree of agitation:

-Scaling will increase with increased temperature.Figure 9-l shows the effect of temperature on sol-ubility in fresh water of calcium carbonate.

-Scaling increases with an increase in pH.-Scaling increases and becomes harder with in-

creased contact time.-Scaling decreases as total salt content (not counting

Ca ions) of water increases to a concentration ofl20g NaCl/1000g of water. Further increases inNaCl concentration decrease CaCO, solubility andscaling increases.3r

-Scaling increases with increase in turbulence.

Mixing of two incompatible waters will cause pre-cipitation of CaCO, scale. An example is the mixingof saline water and fresh water highly charged withbicarbonate.

Tendency to Scale-Gypsum (CaSOo' 2HrO) orAnhydrite (CaSOo)

The most common form of calcium sulfate scaledeposited downhole is hydrous calcium sulfate orgypsum (CaSOo ' 2H2O).

A reduction in pressure decreases solubility andcauses scaling. Pressure drop from 2,000 psi to at-rrrospheric pressure may precipitate as much as 900ppm (0.3 lb/bbl of water) calcium sulfate from a typ-ical Permian basin saline water. Fieure 9-226 i[us-

FlG. 9-1-Effect of temperature change on solubil ityof CaCO, (After Carlberg).

E

6

3E

!

T e m p e r a t u r e , ' F

Scale Deposition, Removal,and Prevention t7:l

FfG, 9-2-Gyp scale solubil ity at 95oF.26Permission to publish by Society of Petro-leum Engineers.

trates solubility ofgyp scale at zero and 1980 psig at95T. with various concentrations of NaCl. Thesecurves should be particularly useful in estirnatingdownhole scaling of gypsum.

Mixing of two waters, one containing calcium ionsand the other containing sulfate ions, often causes gyp

scaling, particularly in waterflooding.Casing leaks or poor cement jobs ate frequent

causes of scaling due to do'wnhole mixing of waterfrom the producing zone with water from other po-rous zones.

An increase of magnesium ions in the range of24,400-36,600 mg/liter may increase the solubilityof CaSOo up to several times the solubility of CaSOoin distilled water and thereby decrease scaling.

Agitation increases scaling tendency.Within ihe pH range of 6 to 8, pH has very little

effect on solubility and scaling.Evaporation of water due to evolution of free gas

Dear or in the wellbore may cause supersaturation andgyp scaling. Hydrates in gas wells frequently becomesupersaturated due to evaporation, with resultant scal-ing-

The effect of temperature on solubility of gyp scaleand anhydrite is illustrated in Figure 94. A changein temperature will change the solubility of calcium

sulfate or gyp and the tendency to precipitate.In wells having anhydrite (CaSOo) stringers in the

producing zone, water flowing in the reservoir is sat-urated with (and in equilibrium with) anhydrite. Thesame water, at disturbed flow conditions near thewellbore, is supersaturated with respect to gyp andu'ill precipitate gyp scale (CaSO 4

' 2H2O) near or inthe wellbore.2a

Figure 9-3 Gypsum Solubility Curves by Case2sshows the etfect of Ca and SO. ions in waters withvarying chloride ions. These curves-should be partic-ularly useful in predicting gyp scale when mixingwaters in water injection systems. Since this figurewas originally charted by Case only for relative val-ues of SOo as NarSOa, Ca as CaCO3, and Cl as NaCl,values for these ions, which are obtained from a watersample from the well or water system, must be mul-tiplied by a conversion factor (see Fig. 9-3) in orderto obtain values for NaSoo, CaCOr, and NaCl. Oncevalues for these compounds are obtained, plot themon Figure 9-3. If the relative values cf Ca and SOointersect above and to the right of the relative valuefor Cl, gypsum scale will form. If relative values forCa and SOo intersect below and to the left of the ClIine, CaSOo will not precipitate.

This system can be illustrated by assuming 2,000ppm of calcium, 4,000 ppm of sulphate, and 18,000ppm of chlorine. After conversion, the value ofCaCO, is 5,000, NaSOo is 5,920, and NaCl is29,700. These values, when plotted on the chart, indi-cate that the intersettions of the values for NaSO"and CaCO, are well above and to the right of theNaCl line and that gypsum scale will form.

Tendency to Scal*BaSOo and SrSOo

For a given NaCl concentration, BaSO, scaling in-creases with decreases in temperature as a result ofdecreasing BaSOo solubility.

Both BaSO, and SrSOo scales are usually causedby mingling of two unlike waters, one containing sol-uble salts of barium or strontium and the other con-taining sulfate ions.

Pressure drop may decrease the solubility of BaSOoin a given NaCl solution and cause scaling.

Barium sulfate is often precipitated in gas wells ashydrates are evaporated.

Solubility of BaSOo is noted in Table 9-2 withchanges in percent NaCl and temperature." Solubilityof BaSO. in many of the high salinity oil-field brinesmay average 85 to 100 mg/liter.

Io6

3icE

NoCt { 9 / l l

PRODUCTIONoPERATIONS/VOL. 2Well Complet ions, Workover, and St imulat ion 174

\Iou,rrr9 l l l l l l ! | |

lhcorcticol moximw donccnlrolioSOr (NorSOr) vr. CdCoCOl) ot 85' F\

\ Keo'troo

30,

.l0ol, -N

\ Kl l5.O(o

t rO ppm Cl (N

t loCl) J a t, l rd

\

\

\\.

+ --l

Convcnion fo<lorr,SO1r l .48 :No1SO1Co x 2JO: CoCOrClr 1.65 : NoCl

l t | l i l l

o

zoEce

100, l @ r,000

ppm Co (CoCO1)

Ff G. 9-3-Gy psum solubil ity curves.25 Permission to publish by The Petroleum PublishingCompany.

An example of BaSOo precipitation occurred in thernixing of two incompatible waters in a 16-in. gath-

ering system in an Illinois waterflood. Bottomholewell temperature was 100"F. Soluble barium in waterwas 13 to 310 mg/liter and the soluble sulfate rangewas from 50 to 85 mg/liter. Scale deposition was sosevere that it was necessary to run a pig twice dailyto keep lines free of scale.

Tendency to Scal+-NaCl

Precipitation of sodium chloride is normally causedby supersaturation-usually due to evaporation or de-creases in temperature. For example, from Table 9-3" it may be noted that 4,000 mg/l of NaCl will be

Fecipitated from saturated salt water if temperature

drops from 140'F to 86'F.Salt precipitation may be quite severe near bottom

in gas wells or high GOR oil wells producing very

little or no water at the surface. Precipitation may re-

sult from both drop in temperature and drop in pres-

sure through perforations and into the tubing. Dry gas

will evaporate water, leaving the salt as a precipitate.

Table 9-4 shows the great difference in solubility

of NaCl, Gypsum, CaCO, and BaSrJo in distilled

water.

Tendency to Scal*lron Scales

Iron scales are frequently the result of corrosionproducts such as various iron oxides and iron sulfide.

Scale Deposition, Removal,and Prevention 175

E

TABTE 9.3Effect of Temperature on NaCl Solubility

Salt in solutionTemperature

oF Wt. percent Mg/liter

3286

1401 7 6212

2 5.926 .82 7 . 12 7 . 7zu . )

259,000 310,000268.000 323,00027 1,000 32 7,000277 ,000 335 ,500285,000 346,500

Ff G, 9-4.-Effect of temperature change on sotubilityof gypsum and anhydrite fn fresh water (After Carl-berg).

Sulfate-reducing bacteria can be a source of hydrogensulfide, which then reacts with iron in solution or withsteel surfaces to form iron sulfide. If oxygen is intro-duced to a system, it can react with iron to form aprecipitate and with steel surfaces to form an oxidecoating.

PREDICTION AND IDENNFrcANON OF SCATEPrediction of Scallng Tendencies

Techniques discussed under "Tendency to Scale"arc very helpful in predicting various types of scale.The Stiff and Davis2e method has been used for manyyears to show scaling tendencies. However, the ageand method of collecting samples may have a bearingon the water analysis values obtained. For example,an aged sample of water may show different valuesthan a fresh sample for pH, bicarbonate content, andCOr, The best procedure is to measur€ water prop-erties immediately after sampling.

Analysis of waterflood water will provide a reliablebasis for estimating scaling in injection lines and ininjection wells.

TABI.E 9.2Solubility of BaSO. In t{acl

NaCt-mg/liter

BaSO osolubilitymg/liter

Analysis of produced brine is an aid in predictingscaling in surface facilities, but may not provide areliable basis to estimate downhole scaling in pro-ducing wells. Downhole deposition of scale, fre-quently due to release of CO, from bicarbonate ionsin water-as pressure declines tends to cause an errorin predicting scaling tendencies from produced brine.

If bottomhole pressure is near original, bottomholesamples brought to the laboratory under subsurfacepressure and temperature conditions may provide re-liable information on both downhole and surface scal-ing tendencies under original reservoir conditions.

To determine calcium carbonate supersaturation,take a wellhead sample of water and run test on waterat the time of sampling. If the calcium carbonate su-persaturation is more than l0 percent of the bicar-bonate alkalinity content, then the water will usuallyhave a scalingtendency.

ldentification of Scale

X-ray diffraction is the most used method for scaleidentification. This involves directing a beam of X-rays onto a powdered sample of scale crystals.

Each crystalline chemical compound in the scalediffracts X-rays in a characteristic manner, which per-mits its identification. It is the fastest method and re-quires the least amount of sample.

TABLE 9.4Solubility of Various Scale in Distilled Water

TemperatureoF Temperature

OFSolubilitymg/liter

203a 1

203

00

100,000100,000

2 .33 .9

30.06 5 .0

Sodium chlorideGypsumCalcium carbonateBarium sulfate

7 77 77 77 7

3 1 8,300.02,080.0

53 .02 .3

PRODUCTIONoPERATIONS/VOL. 2W"fr bo-pr"tions, Workover, and Stimulation 176

TABLE 9-5Analyses of Field Brine and Scale

Analyses of scale'Analyses of brines

Milligrams / liter

Bartlesville Arbuckle Type scale PercentChemical

Sod ium, NaCalc ium, CaMagnes ium, MgBar ium, BaSulfates, SO oChlorides, ClA lka l in i ry , HCO3-1

CaCO.MgCO.'BaSOn

SrCO,SrSOos io,F e r O ,Water soluble

Saltso i i

Moisture

Total

52,00010,7001,807

250ni l

104,75044

58,4001 3,9002,182

n i l194

120 . i 5050

0.6 58 . 1 2

8 0 . 1 0

4.453 . 6 00 . 1 1v . l z

0 .87't.02

0.46

99.60%

f f i o { l U b i n g a n d o n r o d s , w i t h p e l | e t t y p e s o f S c a | e i n t h e b o t t o m o f p u m p i n g w e | | s .

Chemical analysis may also be used for scale iden-

tification. Sarnples of scale are decomposed and then

dissolved in chemical solution' Chemical elements

are then a alyzed by standard techniques of titration

or precipitation.d"ale^compounds will usually not be identified un-

less the analysis is made for each specific chemical

cation and anion. By comparison, all chemical com-

pounds can readily be identified from an X-ray anal-

vsis.After adding HCI to the scale sample' efferves-

cence usually indicates CaCO3, especially if the sam-

ple does noi contain iron sulfide or iron carbonate'

tt "

oOot of HrS will indicate the presence of sulfide

scale.Analysis of field brine can show scaling tenden-

cies. Table 9-5 shows an example of BaSOo scale

caused by mixing of Bartlesville and Arbuckle brines

from welis in the Boston Pool, Oklahoma'

Table 9-6 shows an example of predictable CaCO,

orecipitation due to pressure drop and release of COt

irom'HCO.-', in the Grayburg formation' Hobbs

field, New Mexico.

Table 9-7 shows water analyses from two flow sta-

dons and from an individual well in a specific field'

As a general rule, water should be taken from indi

vidual wells for analysis related to well scaling prob-

lems. Although water from the several locations var-

i"J "onria"ta6ly,

service company analysis suggested

r"ufin* of CaCb, at all temperatures above 0"F' Most

;;ll;-'ft"; Ftow station B also showed gyp scaling'

TABLE 9.6Analyses of Brine and Scale, Hobbs' New Mexico

Analyses of brine

Scale after extractionof water and oil

ChemicalMilligrams

per liter Type scale Percenl

Chlorides. ClSulfates, SO.A lka l in i ty , HCO3- 'Calcium, CaMagnesium, MgSodium, NaSulf ides, H rS

4,15554

2 .3354162 9 1

2 ,1 50345

C a S O o 1 . 8

C a C O , 9 5 . 5

FeS 1 .2sio, 0.9

Total 99.4

Scale Deposition, Removal,and Prevention 177

TABLE 9.7Water Analysis from Seven Rivers--Oueen Formation,

New Mexico

Milligrams / liter at various locations

Chemical Ban. A Batt. B Well #1

Chlorides, ClSulfates, SOoAlkal inity. HCO3-'Calcium, CaMagnesium, Mglron, FeSodium, NaSulf icies. H rS

36,600 3,900800 2,200

1,950 1.075r,000 7601,530 440ni i n i l

20,120 2,25560 120

12,100300

1 ,695320218

ni l7,820

60

SCALE REMOVAT

Scale is classified by methods of removal. Chem-ically inert scales are not soluble in chemicals. Chem-ically reactive scales may be classified as (a) watersoluble, (b) acid soluble, and (c) soluble in chemicalsother than water or acid.

Mechanical Methods

For perforated casing, reperforating is a most ef-fective method of bypassing perforations sealed withscale.

Mechanical methods such as string shot, sonictools, drilling, or rearning have been used to removeboth soluble and insoiuble scales from tubing, casing,or open hole.

Scale may be removed from surface lines with"pigs" or by reaming out.

Chemical Removal

Water-Soluble Scale-The most common water-soluble scale is sodium chloride which can be readilydissolved with relatively fresh water. Acid should notbe used to remove NaCl scale.

If gyp scale is newly formed and porous, it maybe dissolved by circulating water containing about55,000 mg/liter NaCl past the scale. At 100T,55,000 mg/liter NaCl will dissolve three times asmuch gypsum as fresh water.28

Acid-Soluble Scale--^fhe most prevalent of allscale compounds, calcium carbonate (CaCOr), isacid-soluble. Hydrochloric acid (HCl) or Acetic acidcan be used to remove calcium carbonate- Formic

acid and sulfamic acid have also been used.Acetic acid has special application downhole in

pumping wells when it is desired to leave chrome-plated or alloy pump in a well during acid treatment.Acetic acid will not damage chrome surfaces at tem-peratures below 200 F; however, HCI may severelydamage chrome.

Acid-soluble scales also include iron carbonate(FeCOr), iron sulfide (FeS), and iron oxides (FerOr).

HCI plus a sequestering agent is normally used toremove iron scale. The sequbstering agent holds ironin solution until it can be produced from the well. Asequestered Fe acid, such as l5%o HCI containingAcetic and Citric acid, may provide over 15 days ofsequestering time.

Normally l57o sequestered HCI is used, bat 20Vomay be necessary because of slow reaction with ironcompounds.

A lOVo solution of Acetic acid may be used to re-move iron scales without an additional sequesteringagent; however, Acetic acid is much slower actingthan HCl.

Calculation of required acid treatment is based ontype and amount of scale as indicated in Table 9-8.

Scales are frequently coated with hydrocarbons,thus making it difficult for acid to contact and dis-solve the scales. Surfactants can be added to all typesof acid solutions to develop a better acid-to-scale con-tact. Surfactant selection for this use should be testedto determine- that the surfactant will prevent acid-crude oil emulsions and will also leave rock surfaceswater-wet.

Acid-Insoluble Scales-The only acid-insolublescale which is chemically reactive is calcium sulfateor gypsum. Calcium sulfate, though not reactive inacid, can be treated with chemical solutions whichcan convert calcium sulfate to an acid soluble com-pound, such as CaCO, or Ca(OH)r. Table 9-9 showsthe relative solubility of gyp in some of the chemicalsnormally used for gyp conversion. Test conditions

TABLE 9-8Acid Required for CaCO" and lron Scales

Type ofacid-soluble scale

Gallons ot 15%HCI/cu ft of icale

CaCO.Fero,FeS

953 1 8180

PRODUCTIONoPERATIONS /VOL.2fr"rr bo-pt"t ions, Workover, and St imulat ion 178

N H . H C O 3NarCO.NarCOr-NAOHKOH

were 200 cc of solution and 20 grams of reagent grade

gvp.-'iuiott of the chemicals shown in Table 9-9 convert

gyp to acid-soluble CaCOr' KOI{ converts gyp to

6uionr, which is soluble in water or a weak acid;

howevei, only 68 to 72Vo is converted to Ca(OH)t'

leaving an unconverted scale matrix'

After converting gyp, the residual fluid is circu-

lated out. CaCO, can then be removed with either

HCl or Acetic acid'

Scale-removal procedure if waxes' iron carbonate

and gyp are Present is:

-Degrease with a solvent such as kerosene, or xy-

lene, Plus a surfactant.

-Remove iron scales with a sequestered acid'

-{onvert gyp scales to CaCO, or Ca(OH)t'

-ftsrneve converted CaCO, scale with HCI or Acetic

acid. Dissolve Ca(OH), with water or weak acid'

Compounds such as EDTA (Ethylenediamine-te-

traacetic acid) and DTPA (diethylenetriamine-penta-

acetic acid) can dissolve gyp without the necessity of

conversion to CaCO, or Ca(OH)r' But EDTA and

DTPA are not used ixtensively because of the high

cost. EDTA is manufactured and sold by Dow Chem-

ical under the trade name of Versene'

Halliburton's LSD (Liquid Scale Disintegrator) is

a converter and disintegrator of anhydrite (CaSOo)

and gypsum (CaSOn'HrO) scale' LSD produces a

watei &spersible sludge which is acid soluble' al-

though u"1d *uy not be required' Normal well treat-

rnent is:

1. Degrease prior to LSD treatment' In a pumping

well, place lower end of tubing near the bottom of

producing zone, and circulate degreasing solvent for

1Z to Zq hours and then pump from well'

2. Dump LSD into annulus and let it soak for sev-

eral hours, then circulate with pump for a minimum

of 24 hours. A surfactant may be added to LSD to

water wet scale and to prevent emulsions'

3. For flowing or gas lift wells, degrease and then

soak with LSD for a minimum of 24 hours'

Chemically Inert Scales-The most common

chemically inert scales are barium sulfate (BaSOo)

and stroniium sulfate (SrSOo)' Barium sulfate scale

on the formation face or in perforations may be re-

moved by mechanical methcds such as string shots'

drilling out, or unde-r-reaming, or bypassing by re-

perforiting. The best approach is to prevent deposi-

tion.

SCALE PBEVENTION

Inhibition of Scale Precipitation by Inorganic

PolyphosPhates

Inhibiting scale with a few parts per million of

molecularlf dehydrated polyphosphates- is called a

"threshold treatment"' When a crystal nucleus is

formed, polyphosphate is adsorbed on the surface anC

slows further crystal growth'

For about 25 years, sand-grain size polyphosphate

particles have been injected as a-part of regular frac-

iuring treatments' Also, wells have been fractured

specifically to inject the phosphate particles' The po-

iiprtotpituL slowly dissolves in produced water anci

pievents scale PreciPitation'Reversion to Orthophosphate-When placed in so-

Iutiqn all polyphosphates tend to hydrolyze into or-

thophosphatei. tn ttt" presence of calcium ions' in-

sotuUte calcium precipitates may be formed'

Polyphosphates will also revert to orthophosphates in

the presence of acid.

Rate of reversion to orthophosphates depends on

temperature, acidity, mineral content, phosphate con-

tent. and nature of polyphosphates' Reversion does

not start until polyphosphate goes into solution'

Sodium-calcium phosphates are normally used in

well treatment because of their slow dissolving rate'

This property assures a near constant phosphate con-

centration in the water over a long period of time'

The objective is for the phosphate-containing water

to be iroduced from the well before reversion can

occur.

lnhihition of Scale with Polyorganic Acid

During the mid 1960's, a very stable polyorganic

u"id, LP"-55, was field-proven by Halliburton'17 This

tiloiA mut"rial inhibits scale formation through

TABLE 9.9Gyp Solubility Tests

TYpeof solution 24 Hours

Percent gyP dissolved72 Hours

87 .8I3 .871 .26 7 .6

9 1 . 0

/ t . c

Sceh &posltion, Removal,atd h*ention 179

"tMld treatment" approach. It has no tempera-ture limit and does not precipitate solids.

Ptscement during fracturing-If placed during acmventional frac treatment, the LP-55 liquid shouldprece& the introduction of sand. If injected duringa minifrac, carried out only to place the chemical, thewell is fraced and then LP-55 is pumped in the wellat rates of 0.25 to 1.0 bbl/minute to permit rapidleakoff.

The feedback rate is controlled by pressure dropwhen the well is produced from formation capillariesor from minute fractures.

It may be combined with a corrosion inhibitor ifdesired; however, lab tests of compatibility should bemade before injecting both a corrosion inhibitor andscale inhibitor into a well.

The.polyorganic acid is placed on the basis of 10gals of chemical per 1,000 gals of water or alcohol.

The polyorganic acid can also be irrjected in a watersolution down the annulus to reduce scaie depositionin the casing, tubing, pump, and surface equipment.It can also be used in the power oil of hydraulic lifttype of downhole pumps.

Inhibition of Scale with Organic Phosphates andPhosphonates

Various organic phosphates are now offered to in-hibit against calcium sulfate, barium sulfate, and toa lesser degree, against calcium carbonate scale.Many of these water soluble liquid organic phos-phates are suitable for squeeze treatments into the for-mation.

Calgonz3 has reported on lab and field results of itsorganic inhibitors S-31 and S-51. S-31, an aminoe-thylenephosphonate (AMP), is designed to inhibitagainst CaSOa, BaSOo and CaCO..

Some of the most successful treatments with S-3 Iappear to be effective for six to twelve months; how-ever, Calgon reported treatments in Lake Maracaibo,Venezuela to have inhibited scale for 15 months inwells producing 2,000 barrels of water per day.

Calgon's most recent development is S-51, an or-ganic phosphate, designed to inhibit against calciumsulfate scaling.

Exxon Inhibitors-Exxon Chemical Company of-fers several organic phosphate inhibitors, two ofwhich, COREXIT 764O and COREXIT 7641, havebeen used for several years. COREXIT 7640 is pri-marily designed to inhibit calcium sulfate and bariumsulfate scaline bv formation squeeze treatments. It

may also be used in surface water distribution sys-tems.

Exxon Production Research Company2a reportedaverage effective inhibiting of nine months againstvery severe gyp scaling in one West Texas field, withretreatment being considered when the inltibitor in theproduced water decreases to about 7 ppm. With thisapproach, some wells have been relatively scale freewith retreatments every 15 months depending onwater production.

COREXIT 7640 treatine procedure for downholesqueeze is:

l. Preflush with 30 barrels fresh water.2. Squeeze 165 gallons COREXIT 7640 dissolved

in 30 banels of fresh water.3. Overflush with 100 barrels fresh water.4. Shut-in well for 24 hours.5. Return to production.

COREXIT 7641 is a water soluble organic phos-phate, especially designed to prevent deposition ofCaCO' CaSOo and BaSOo. It may be applied eitherby continuous injections or by the formation squeezetechnique.

Visco Inhibirors-Visco Division of Nalco Chem-ical Co. offers three organic phosphate scale inhibi-tors-VISCO 950,953, and 959.

VISCO 950 inhibits against deposition of BaSOo,CaSOa, and CaCOr. VISCO 950 may be added tosurface watgf systems or may be used for continuousfeed into down the casing-tubing annulus. As an ef-fective tbrmation squeeze treatment. scale inhibitor,Visco 950 is best used with a l:9 ratio of producedwater, with 200-500 barrels of overflush into the for-mation.

Visco 953 controls CaCO3, CaSOo, and BaSOoscales at very low dosages in oil and gas wells, waterinjection systerns, and salt water disposal systems.For water injection systems, continuous treatment isbest; for downhole usage, batch treatment or semi-continuous treatment is most effective. Visco 953 alsois used as a formation squeeze treatment scale inhib-itor, mixed at a l:9 ratio with overflush into the for-mation. However, the most effective treatment is tomix a l-37o solution of Visco 953 '*'ith producedwater, displacing the solution into the formation.

VISCO 959 is designed for formation squeeze jobs

to inhibit CaCO, and sulphate deposits in oil and gaswells and producing equipment. Typical treatment isto preflush with 5 to l0 bbl of produced water, pumpin VISCO 959 mixed with formation water at a ratio

PRODUCTIONoPERATTONS/VOL. 2Well Complet ions, Workover, and St imulat ion 180

of one to ten, overflush with 50 to 250 bbl of for-

mation water, depending on daily water production.

Usual treatment is about 165 gal of VISCO 959.Tretolite Inhibitors---Tretolite SP-223, an organic

phosphorate, has been reported as very successful inpreventing calcium carbonate and calcium sulfatescaling. It may be used on a continuous basis to cir-culate into a well or squeezed into the formation.Welis or lines are protected from scaling as long as5 ppm of chemical can be detected in the fluid streamin contact with the pipe or equipment.

Tretolite SP-219, a liquid scale inhibitor, which is

a combination of a phosphate and a polymer, preventsdeposition of bprium sulfate and calcium carbonate.It may also be used to protect against CaSOo depo-sition. Concentrations of SP-219 for protection againstBaSOo and CaCO, are from 5 to 50 ppm, dependingon the severity of the problem.

Baroid Inhibitors-Surflo H-35 is an anionic or-ganic phosphonate designed to prevent the depositionof Calcium Carbonate, Calcium Sulfate, and BariumSulfate. It may be injected as a continuous treatmentin wells or used as a periodic squeeze treatment intothe formation. When squeezed, 4 to l2Vo of SurfloH-35 is mixed with fresh water or prcduced water andthen overflushed with 25 to 100 bbl of water.

lnhibiting Scale with Polymers

ARCOHIB 3-223,27 a salt of polyacrylic acid, de-veloped by Atlantic-Richfield, is marketed by majorservice companies under various trade names. Pro-cedure for use in prevention of BaSOo, CaSOo andCaCO, is as follows:

1. Pump in 100-500 gal HCI spearhead to insure

CaCO, scale cleanup.2. Pump in a slug consisting of 45 bbl produced

water, 100 gal l5%o HCl, and 100 gal ARCOHIBpolymer.

3. Follow up with enough CaCL, to raise the

CaCL, content in the 45 bbl slug of water to 10,000ppm. This raises the pH from about 1.2 to about 4.5and causes the polymer to crosslink and precipitate

as a gel in the formation.4. The crosslinked polymer is then pushed into the

formation and dispersed with 100 to 200 bbl of pro-

duced water. The polymer is slowly dissolved by pro-

duced water to provide inhibition against BaSOa,

CaSOo, and CaCO, scale.

Exxon Chemical's COREXIT 7647, a low molec-

ular weight polymer, has been effectively used for

continuous injection and circulation of wells and sur-

face systems and also for squeeze treatments into the

formation. It is a stable inhibitor up to 500'F and con-

trols deposition of both carbonate salts of calcium and

magnesium, strontium and barium.

CaCO, Scale Prevention by Pressure Maintenance

If calcium carbonate scale can be predicted as a

result of drop in reservoir pressure, pressure mainte-

nance should be considered as a nleans of reducing

scaline.

Summary

Steps to be taken in solving scale problems are:

1. Identify the scale and the reason for its depo-sition,

2. Remove deposit by chemical or mechanicalmeans.

3. In perforated completions, it may be more sat-isfactory to bypass scaled perforations by reperforat-ing.

4. Inhibit against further scale deposition.

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Scale Deposition, Removal,and Prevention 1 8 1

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15. Bel l . W. E.: "Chelat ion bhemistry-i ts importance towater treatment and chemical cleaning," Materials Protec-fion, February. 1965.

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17. Tinsley. J. M., Lasater, R. M., and Knox, J. A.: "De-s ign Techn ique fo r Chemica l Frac ture Squeeze Treat -ments," J. Pet. Tech., Nov. 1967, p. 1,493.

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29, Sti f f , H. A., Jr. and Davis, L. E.: "A Method for Pre-dict ing the Tendency of Oil Field Waters to Deposit CalciumCarbonate," SPE of AIME Transactions. Vol. 195 (1952), pp.21T-216.

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34. Wheeler, D. W., and Weinbrandt, R. M., "Secondaryand Tert iary Recovery with Sea Water and Produced WaterIn The Huntington Beach Field," SPE 7464. Oct. 1978.

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