Estimation of the Scale Deposits Near Wellbore viaSoftware in the Presence of Inhibitors

R. Hosny,1 S. E. M. Desouky,1 M. Ramzi,1 Th. Abdel-Moghny,1

F. M. S. El-Dars,2 and A. B. Farag21Egyptian Petroleum Research Institute, Cairo, Egypt2Faculty of Science, Helwan University, Helwan, Egypt

In this study, computer software was used in order to estimate the scaling tendency of the com-mingling of two incompatible waters existed in Egyptian oil reservoirs of Gulf of Suez area. Thechemical analyses of the two incompatible waters (injection and formation waters) have been usedas input data to the computer simulator. The reservoirs characterized by a temperature of90127C, and salinity of 100,000230,000 ppm. The scaling results for the commingling of bothinjection and formation water at reservoir temperatures and pressures are recorded. The results oftheoretical software and laboratory jar-testing were compared. It was found that mixing of theinjection water and formation water may lead to calcium carbonate and barium sulphate scalingat 40% formation water in absence of scale inhibitor. Two types of commercial scale inhibitors(AII and SII) were evaluated using both jar test method and National Association of Corrosionengineers standard test methods. The results showed the mastery of AII over the commercialinhibitor SII in preventing of both scales.

Keywords Scale inhibitor, scale deposition, scale prediction, soft ware simulator

INTRODUCTION

Most of scales found in oileld are formed by eithermixing of two incompatible brines or sudden changes inproduced uid conditions, such as pressure, temperature,or pH.[1]

The formation of mineral scale as may result in greatlyreduced well performance as rock pores. Tubulars and top-side machinery become choked by a build up of insolubleinorganic precipitate.[2] Scale can develop in the formationpores near the wellbore, reducing formation porosity andpermeability. It also can coat and damage downhole com-pletion equipment, such as safety valves and gas-lift man-drels.[3] The primary effect of scale growth on tubing isto lower the production rate by increasing the surfaceroughness of the pipe and reducing the owing area. Thescale developed along the tube can be seeing in Figure 1,in this respect, the highest scaling rate is located at the inletof the tube.[4] Thereby, scale can be deposited all alongwater paths from injectors through the reservoir to surfaceequipment.

Scale Prediction

The scale prediction software program used to mea-sure the theoretical quantitative calculations of ST resultfrom mixing of two incompatible waters at one or morespecied temperature, pressure and at any specied ratioto simulate the reservoir conditions.[5] In order to obtainreasonable results from such program, however, it isessential that: 1) the results of the water analyses areaccurate; 2) a suitable computer program is used andthe capabilities and limitations of the program are under-stood; 3) the user understands the system they areattempting to model.

Scale prediction simulation technique[6] was used tocalculate queens speciation mineral saturation indices,mineral solubilitys and the effect of mixing between differ-ent uids are illustrated in part one by Hosny et al.[7] Thequantitative calculations of ST are performed using aspecic software designed to theoretically estimate the scaleformation conditions and scale quantities that may resultfrom mixing two incompatible waters at one or morespecied temperature and pressure and any specied ratioof mixing to simulate the reservoir conditions. The inputdata to the software are the results of two mixing waters.Reservoir pressure and temperature as well as mixing ratiosare also a must to complete the run.

Received 23 October 2007; accepted 5 November 2007.Address correspondence to Th. Abdel-Moghny, Egyptian

Pertoleum Research Institute, Cairo, Egypt. E-mail: Thanaa_h@yahoo.com

Journal of Dispersion Science and Technology, 30:203211, 2009

Copyright # Taylor & Francis Group, LLCISSN: 0193-2691 print=1532-2351 online

DOI: 10.1080/01932690802498658

203

Scale Inhibition

Scale preventative chemicals can be added to prevent theformation of scale, retard the growth of scale crystals orkeep scale mobile. Scale prevention can be take place byscale inhibition. The most commonly used approach toscale control in produced water is to inject chemical scaleinhibitors. Scale inhibitors can reduce the tendency forcrystallization or completely prevent scale formation andgrowth by disrupting the thermodynamic stability of grow-ing nuclei, causing dissolution of nucleated scale and=orinterfering with the crystal growth process, resulting inblockage of the growing.[8] Phosphate esters and phospho-nates are the most often chemicals used in this service. Tobe effective, though, the chemical must be applied to theproduced water stream at a location upstream of the pointat which the scale will likely begin to form. Furthermore,the chemical must be injected on a continuous basis so asto be in solution to prevent scale formation at all times thatthe produced water is being injected.[911]

It is commonly observed in laboratory experiments ofboth spontaneous precipitation and seeded crystal growththat the presence of an inhibitor, even in the thresholdrange (typically between 0.1 and 10mg=l) in a supersatu-rated solution, will delay the nucleation and precipitation ofsparingly soluble minerals and thus prolong the inductionperiod.[1219] These precipitate include calcium carbonate,calcium sulfate, strontium sulfate, and barium sulfate.[20]

In this study, scale prediction software was used to eval-uate and quantify scaling precipitated from two Egyptianoil reservoirs existed in Gulf of Suez area at high tempera-ture of 90127C, high pressure of 3600 psi, and highsalinity of 100,000230,000 ppm and 35,000 ppm for for-mation and injected water, respectively. The cations andanions of such waters were determined experimentallyusing IC. The output data of software and laboratory

Jar-testing results were compared before and after addingdifferent concentration of commercial scale inhibitorsAII and SII.

EXPERIMENTAL

Water Analysis

Cations and anions of formation and injected brinewater were determined experimentally according to ASTMD4327[21] using Dionex IC model DX 600 equipped withhigh capacity columns. Alkaline species (CO3 , OH

, andHCO3 ) were determined experimentally according toASDTM D3875 instrument[22] calculations were doneusing Alkalinity calculator ver.2.10 (USGS). The tracesand ultra traces of metals were determined using induc-tively coupled plasma spectro instrument (ICP).[23] Thetotal dissolved solids, which are simply the total amountof matter dissolved in a given volume of water, was deter-mined experimentally according to ASTM D-1888.[24]

Conductivity and resistivity was determined experi-mentally using digital conductivity meter WTW 330Iaccording to ASTM D1125.[25] Density and specic gravitywere determined experimentally according to ASTMD1429,[26] pH was determined experimentally accordingto ASTM D1293.[27] Salinity value was calculated uponchloride content value. The water analysis was representedin Table 1.

TABLE 1Complete analysis of formation water and injection water

ITEM Formation water Injection water

Physical propertiesSalinity 44012 11619.3Conductivity 7.06 102

mohs=cm3.39 102mohs=cm

Resistevity 0.14164 ohm-m 0.28653 ohm-mpH 7.5 7.57T.D.S. mg=L 48283 12680

Cations and anionsLithium mg=L 0.06 0.07Sodium mg=L 14338 4387Potassium mg=L 95 60Magnesium mg=L 569.97 88.2Calcium mg=L 1347 254.5Barium mg=L 0.458 0.07Iron mg=L 19.74 6.212Fluoride mg=L 1.45 12.73Bromide mg=L 41 49.8Bicarbonate mg=L 169 219.7Chloride mg=L 26674 7042Sulfate mg=L 21.6 146.57

FIG. 1. The photographs of the scale formed at different positionsalong the tube.

204 R. HOSNY ET AL.

The Scale Prediction Software

The scale prediction software was used to perform thescaling precipitation and to calculates the queens specia-tion mineral saturation indices, mineral solubilitys, andthe effect of mixing between different uids (formationand injected waters).[16,17] This program calculates the scaletendency (ST) and scale index (SI).

Calculating a Scaling Tendency

The ST is dened as the ratio of the activity product ofan equilibrium equation to the solubility product for thesame equation, the activity products is dene as Q, there-fore the Scaling Tendency can be written as the followingequation:

ST Q=KSP;

where, KSP Solubility products.When the ratio Q=Ksp is greater than 1.0, then the solid

has tendency to form. When the ratio is less than 1.0, thenthere is little tendency to form.

Calculating a Scale Index

The scale prediction results are expressed as saturationindex and the amount of potential precipitation. The SIis the logarithmic volume of the ST, so that SI,

SI Log10STThe positive SI (SI> 0) can be indicating that the

solution (brine) is supersaturated, that is, from the viewof thermodynamic chemistry the scaling ions will have atendency to form. On the contrary, the negative SI(SI< 0) indicates that the solution (brine) is unsaturatedand there is no potential for the scale to form. The Scaleprediction software was run using the complete wateranalysis of such reservoir, and the output data weregiven in Table 1.

Jar-Test Procedure

The tested incompatible brines were rstly pre-ltered toremove any suspended materials. Then complete wateranalyses were carried out to determine the concentrationof the initial composing and scaling ions. After that thebrines were mixed at different Formation water: injectedwater of 20:80, 40:60, 60:40, and 80:20, respectively, andincubated at the 150F test temperature for 48 hours.Then the mixtures were left for 24 hours, and thenltered through 0.42-micron lter paper to catch any preci-pitate. The lter papers were dried at 150F for 2 hours andthen the precipitates were weighted. Then the maximumscaling ratio was determined based on the weight of theprecipitates.

Laboratory Evaluations

The ability of scale inhibitors to retard the unwanteddeposition of inorganic salts has been evaluated. The ef-ciency orders of these antiscalants upon chelating tenden-cies of calcium ion have been measured using NationalAssociation of Corrosion Engineers (NACE) standard testmethods.[28] In this respect two incompatible waters forma-tion and injection waters were mixed at ratio of 40% and60%, respectively. The commercial scale inhibitors (AIIand SII) were dosed 0100 ppm into brine waters. Aftermixing, the solution were placed in oven at 70C for 24hours, and allowed for cooling to 25C. The scaling ionconcentrations were then measured by inductively coupledplasma emission spectroscopy (ICP) to determine the con-centration of calcium ions remaining in solution.

Injection of Scale Inhibitor

A different concentration of the two individual commer-cial scale inhibitors AII and SII of 25, 50, 75, and 100 ppmwere added to the worst mixing ratio of injection: forma-tion water (40:60 with respect to formation water) at reser-voir conditions (pressure of 1000 psi and temperature of149F). All test cells and blank were placed in oven andincubated at 150F for 48 hours. Then the mixtures wereleft for 24 hours, and ltered through 0.42-micron lterpaper to catch any precipitate. The lter papers were thendried at 150F for 2 hours and the precipitates wereweighted. Then the efciency of scale inhibitor was deter-mined based on the following calculation:

Inhibition I Ca CbCc Cb 100;

where:

Ca: calcium ion concentration in the treated sampleafter precipitation.

Cb: calcium ion concentration in the blank afterprecipitation.

Cc: calcium ion concentration in the blank beforeprecipitation.

RESULTS AND DISCUSSION

Results of Water Analysis

The results in Table 1 indicated that the conductivityof formation water and injection water are 7.06102mohs=cm and 3.39 102mohs=cm, respectively, onthe contrary it have been found that the resistivity of elec-trical current ow as a function of an ion dissolved in waterdecreases from 0.28653 ohm-m to 0.14164 ohm-m for injec-tion, and formation water, respectively. Moreover, it hasbeen found that the salinity (ionic strength) of formationwater is higher by 3.787 ( 4) times than that of injection

ESTIMATION OF SCALE DEPOSITS 205

water. According to all this data and in addition to theknowledge about the inversely relation between thedissolved ions and the resistivity, one can predict thatthe formation water has an ability to form undissolved ionsthan injection water.

In Table 1 also, it has been observed that the rank ofincreasing of the concentration of the dissolved cationsand anions of formation water measuring using DionexIC, are Li

Scale Tendency

The results in Table 3 revealed that the ST of baritevalues at ambient conditions are 17.3929, 26.6169,35.7253, 44.6971, and 53.6329, that corresponding to 80,60, 40, 20, and 0 of formation water, respectively. Mean-while, the results of ST of calcite are 4.2006, 3.8835,3.5743, and 3.2238, that corresponding to 100, 80, 60,and 40 of formation water, respectively. It is clear that asevere barite and calcite-scaling are enlargement becausethere scale tendencies are greater than one (ST> 1.0),where as a little tendency toward gypsum formation dueto its ST is less than one (ST< 1.0). Our suggestion runin harmony with Yuan.[29]

The results of ST at reservoir conditions tabulated inTable 3 revealed that the barite values are 3.4251, 5.25,7.0771, 8.932, and 10.899, that corresponding to 80, 60,40, 20, and 0 of formation water, respectively. Where asthe ST of calcite are 8.2309, 7.9043, 7.5191, and 7.0048,which corresponding to 100, 80, 60, and 40 of formationwater, respectively. Figures 4 and 5 demonstrate the STof all possible scales resulting from mixing different ratioof formation water and injection water. They also indicatethat, calcium carbonate and barium sulfate are superiors togrowth at any mixing ratio between formation water andinjection water.

TABLE 3Scale tendency for all possible scales

Type of scale

% Formationwater

BaSO4(Barite)

CaCO3(Calcite)

CaSO4 2H2O(Gypsum)

FeCO3(Siderite)

SrSO4(Celesite)

At ambient conditions100 8.0874 4.2006 0.0067 0.1588 080 17.3929 3.8835 0.0136 0.1457 060 26.6169 3.5743 0.0194 0.1324 040 35.7253 3.2238 0.0237 0.1169 020 44.6971 2.765 0.0257 0.0961 00 53.6329 2.0465 0.0232 0.0628 0At reservoir conditions100 1.5929 8.2309 0.0047 0.1324 080 3.4251 7.9043 0.0097 0.1292 060 5.25 7.5191 0.0141 0.1244 040 7.0771 7.0048 0.0176 0.1165 020 8.932 6.236 0.0197 0.1023 00 10.899 4.8724 0.0186 0.0728 0

FIG. 4. Scale tendency for all possible scales for ratios of mixture atambient conditions.

FIG. 5. Scale tendency for all possible scales for ratios of mixture atreservoir conditions.

ESTIMATION OF SCALE DEPOSITS 207

The Scale Index

The SI at ambient conditions are shown in Table 4(Figure 6), such results illustrated that the higher SI valuesof barite are 1.2404, 1.4252, 1.553, 1.6503, and 1.7294 thatcorresponding to 80, 60, 40, 20, and 0 of formation water,respectively. Also, it is indicated that the SI of calcite are0.6233, 0.5892, 0.5532, and 0.5084, that corresponding to100, 80, 60, and 40, of formation water, respectively. Suchvalues illustrated that the SI are greater than zero (SI> 0),then such solid are supersaturated and have a tendency toform hard scales.

The values of SI at reservoir conditions shown inTable 4, point to that the SI of barite are 0.7202, 0.8499,0.9509, and 1.0374, that corresponding to 60, 40, 20, and0 of formation water, respectively. Where as, the SI ofcalcite are 0.9154, 0.8979, 0.8762, and 0.8454 that corre-sponding to 100, 80, 60, and 40, of formation water, respec-tively. On the contrary as indicated in Figure 7, SI of thecalcium sulfate (gypsum), and ferric carbonate recordednegative values (SI< 0), this mean that gypsum and ferriccarbonate are undersaturated, and did not cause scaleprecipitation.

TABLE 4Scale index for all possible scales

Type of scale

% Formation Water BaSO4 (Barite) CaCO3 (Calcite) CaSO4 2H2O (Gypsum) FeCO3 (Siderite) SrSO4 (Celesite)At ambient conditions100 0.9078 0.6233 2.1739 2.2291 080 1.2404 0.5892 1.8665 0.8365 060 1.4252 0.5532 1.7122 0.8781 040 1.553 0.5084 1.6253 0.9322 020 1.6503 0.4417 1.5901 1.0173 00 1.7294 0.311 1.6345 1.202 0At reservoir conditions100 0.2022 0.9154 2.3279 0.8781 080 0.5347 0.8979 2.0132 0.8887 060 0.7202 0.8762 1.8508 0.9052 040 0.8499 0.8454 1.7545 0.9337 020 0.9509 0.7949 1.7055 0.9901 00 1.0374 0.6877 1.7305 1.1379 0

FIG. 6. Scale index for all possible scales for ratios of mixture atambient conditions.

FIG. 7. Scale index for all possible scales for ratios of mixture atreservoir conditions.

208 R. HOSNY ET AL.

It is clear that from all these results the superior scalesformed are calcite and barite.

Results of Jar Test

Jar test was conducted to conrm the results of thesimulator, and the results are given in Table 5 and plottedin Figure 8. It was found that the commingling of injectedwater with the formation water lead to scaling problems of384.6mg=l (total scale) at 60:40 of formation water toinjection water, respectively. So the results indicated thatwhen the amount of commingled injection water isincreased than 50%, the minor amount of CaCO3 scale willformed. Whereas, the predictions of BaSO4 scale dependon the assumption composition of the injection water.Moreover, no scaling of CaCO3 and BaSO4 minerals ispredicted below approximately 50% injection water.

The results of maximum scale amount of jar test and thesoftware at reservoir conditions that represent in Table 5evident a good conformity between both tools used to cal-culate and understanding the meticulous thermokineticprocess that causes the scale. Accordingly, the ratios of

80 and 60 of formation water are the most favorable ratiosthat can be applied safely in oileld.

Evaluation of Commercial Scale Inhibitors UsingNACE Test

The study was carried out to investigate in more detailsthe role of the commercial scale inhibitors on the amountof calcium ion remained in the scalable solution. Theefciency values were measured for scale inhibitors at dif-ferent inhibitor concentrations using NACE standard testmethods. Therefore, two commercial scale inhibitors (AIIand SII) were evaluated by laboratory testing to determinetheir relative effectiveness. The efciencies of these inhibi-tors are evaluated against precipitation of mineral scalesusing natural brine and sea water provided from Gulf ofSuez. The effect of scale inhibitors AII and SII on preven-tion of scale deposition at reservoir conditions and at

TABLE 5Maximum scale mass mg=l) in jar test at reservoir

conditions

% FormationWater

Amount of ScaleFormed (mg=l)

20 201.440 384.660 105.880 114.2

FIG. 8. Maximum scale mass in mg=L for ratios of mixture in jar testat reservoir conditions.

FIG. 9. Effect of scale inhibitors (AII&SII) on prevention scaledeposition of the 40:60% of formation water.

TABLE 6Effect of scale inhibitor on prevention scale deposition at

reservoir conditions

Amount of scale, Wt (mg)(40:60%)

Inhibitor concentrations(ppm)

Inhibitor(AII)

Inhibitor(SII)

0 384.6 384.625 103.842 115.3850 88.458 107.68875 80.766 119.226100 99.996 130.764

ESTIMATION OF SCALE DEPOSITS 209

different concentrations are presented in Table 6 (Figure 9).The results indicated signicant decreases on the amount ofscale precipitated after adding scale inhibitor AII by about1.1, 1.2, 1.5, and 1.3 times over scale inhibitor SII at the con-centration of 25 ppm, 50ppm, 75 ppm, and 100ppm, respec-tively, that is, the mastery of AII over SII as antiscalants.

The prevention of calcium carbonate and barium sulfatescales with scale inhibitors AII and SII and at 40% of for-mation water are summarized in Table 7. The data showthat, the inhibitor AII manage, prevent and retard thegrowth of crystals of calcium carbonate and barium sulfateas its concentration increased. It also clears that, above25 ppm up to 75 ppm inhibitor concentration, the solublecalcium ions are increased from 72.9% up to 78.99% andfrom 74.55% to 80.2% for CaCO3 and BaSO4, respectively.However, the efciency of scale inhibitor SII at 50 ppm has

been enhanced to 71.99% and 73.6% for CaCO3 andBaSO4, respectively.

CONCLUSIONS

Computer scaling predictions have been performed on anumber of aqueous systems. The software program wasused in order to estimates the ST of the commingling oftwo incompatible waters existed in Egyptian oil reservoirsof Gulf of Suez area, indicated high scaling tendencies ofBaSO4, and CaCO3 at various water compositions,temperatures and pressures covering oileld conditions. Aseries of laboratory scaling experiments are the way toconrm the ST of two incompatible waters.

TABLE 7Efciencies of scale inhibitors AII and SII on the deposition of calcium carbonate and barium sulfate at

different inhibitors concentrations

CaCO3 BaSO4

Inhibitor concentration, ppm Ca Cb Cc Efciency Ca Cb Cc Efciency

Scale inhibitor AI25 670.61 614.12 691.5 72.9 17.93 4.487 22.52 74.5550 673.702 614.12 691.5 77 18.61 4.487 22.52 78.3275 675.25 614.12 691.5 78.99 18.95 4.487 22.52 80.2100 671.38 614.12 691.5 73.99 18.1 4.487 22.52 75.5Scale inhibitor SI25 668.284 614.12 691.5 69.99 17.416 4.487 22.52 71.750 669.832 614.12 691.5 71.99 17.76 4.487 22.52 73.675 667.512 614.12 691.5 68.99 17.25 4.487 22.52 70.78100 665.592 614.12 691.5 66.52 16.74 4.487 22.52 67.96

FIG. 10. Efciencies of the inhibitors AII as calcium carbonate andbarium sulfate at different inhibitor concentration.

FIG. 11. Efciencies of the inhibitors SII as calcium carbonate andbarium sulfate at different inhibitor concentration.

210 R. HOSNY ET AL.

The maximum scale amounts of jar test and the softwareprogram at reservoir conditions are obtained at 40:60 offormation water; consequently, one can say that both ofthe simulation results and jar test results are in good agree-ment with each other.

A different concentration of the two commercial scaleinhibitors AII and SII of 25, 50, 75, and 100 ppm wereadded to the worst mixing ratio of injection: formationwater (40:60 with respect to formation water) at reservoirconditions. The results (Figures 10 and 11) indicate the pre-vention of both barium sulfate and calcium carbonateincreases as the concentration of the inhibitor increasesup to the optimum concentration 75 ppm, as well as theinhibition efciency were enhanced up to 78.99% and80.2% for CaCO3 and BaSO4, respectively. The resultsshowed the mastery of AII over the commercial inhibitorSII in preventing of both scales.

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ESTIMATION OF SCALE DEPOSITS 211