SPE-141168-PA-P

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1/8November 2010 SPE Production & Operations 545

Inhibition of Calcium Sulfate and StrontiumSulfate Scale in Waterflood

Amer Badr BinMerdhah,Hadhramout University of Science and Technology

Copyright 2010 Society of Petroleum Engineers

Original SPE manuscript received for review 20 February 2010. Revised manuscriptreceived for review 14 June 10. Paper (SPE 141168) peer approved 26 July 10.

Summary

One of the most common methods of preventing downhole andtopside mineral-scale formation in oil fields is through the use ofchemical-scale inhibitors. Several aspects of the brine compositionmay affect the performance of the various scale inhibitors used inoilfield applications. This study was conducted to investigate thepermeability reduction caused by deposition of calcium sulfate(CaSO4) and strontium sulfate (SrSO4) in Malaysian sandstone andBerea cores from mixing injected Malaysian seawaters (SW) (Angsiand Barton) and formation water (FW) that contain a high concen-tration of calcium and strontium ions at various temperatures (50 to95C) and differential pressures (75 to 200 psig). Scale-inhibitionefficiency was determined in both the bulk jar and the core tests byusing scale inhibitors methylene phosphonic acid (DETPMP), poly-phosphino carboxylic acid (PPCA), and phosphorus-based scale

inhibitor (PBSI) at various temperatures (50 to 95C) and concen-trations. The results showed a large extent of permeability damagecaused by calcium and strontium sulfates that deposited on the rockpore surface. At higher temperatures, the rate of CaSO4 and SrSO4precipitation increases because the solubilities of CaSO4 and SrSO4scales decrease with increasing temperature. At 90C temperature,PBSI was the best inhibitor because it reduced more scale depositioncompared to the DETPMP and PPCA inhibitors.

Introduction

Scale deposition can plug production lines and equipment andimpair fluid flow. The consequence could be production-equipmentfailure, emergency shutdown, increased maintenance cost, andoverall decrease in production efficiency. The failure of this equip-ment could result in safety hazards. In case of water-injectionsystems, scale could plug the pores of the formation and resultin injectivity decline with time (Yuan and Todd 1991; Yeboah et al.1993; Asghari et al. 1995; Andersen et al. 2000; Graham et al. 2001;Paulo et al. 2001; Voloshin et al. 2003).

The formation of mineral scale in production facilities is a rela-tively common problem in the oil industry. Most scale forms either bypressure and temperature changes that favor salt precipitation fromFWs or when incompatible waters mix during pressure maintenanceor waterflood strategies. Scale prevention is achieved by performingsqueeze treatments in which chemical-scale inhibitors are injectedinto the producers near-wellbore region (Romero et al. 2007).Furthermore, the formation of mineral scale (carbonate/sulfate/sulfide) within the near-wellbore region, production tubing, andtopside process equipment has presented a challenge to the oil and

gas industry for more than 50 years. Chemical methods to controlscale have been developed, including scale squeeze treatments andcontinuous chemical injection. A key factor in the success of suchtreatments is understanding the chemical placement and effective-ness of the treatment chemicals (Jordan et al. 2006).

In most cases, the scaled-up wells are caused by the forma-tion of sulfate and carbonate scales of calcium and strontium.Because of their proportionate hardness and low solubility, thereare restricted processes available for their removal, and preventivemeasures such as the squeeze inhibitor treatment must be taken. Itis therefore important to gain a proper understanding of the kinetics

of scale formation and its detrimental effects on formation damage

under both inhibited and uninhibited conditions (Wat et al. 1992;Moghadasi et al. 2003).

The most common classes of inhibitor chemicals are inorganicphosphates, organophosphorous compounds, and organic polymers.PPCA and DETPMP are two common commercial scale inhibitorsused to control mineral scaling in the oil and gas industry (Bezemerand Bauer 1969). PPCA is a polymer formed by two polyacrylicacids connected by a phosphorous group, as shown in Fig. 1.PPCAis often regarded as a nucleation inhibitor. After initial nucleation,PPCA continues to retard crystal growth, but it does not stop itentirely and becomes less effective with time. This is because ofits incorporation in the crystal lattice. DETPMP, the phosphonatespecies, has the chemical structure illustrated in Fig. 2. In contrastto PPCA, DETPMP is thought to retard the growth of crystals and

is less effective in preventing initial nucleation. Once nucleation hasstarted, it is effective at stopping further crystal growth by adsorbingactive growth sites on the scale crystal lattice (Chen et al. 2004).

The action of scale inhibitors in preventing scale formationhas been investigated extensively in the literature with differentinhibitors. The present work is conducted to test the efficiency ofcommon commercial scale inhibitors (DETPMP and PPCA) andlocally produced scale inhibitor (PBSI) in preventing or delayingCaSO4 and SrSO4 scales, which are formed by mixing injectionwater (Barton and Angsi SWs) and FW.

Materials and Methods

Core Material.In all flooding experiments, the porous media usedin this study were

1. Berea cores of 3-in. length, 1-in. diameter, average porosity of

21.60%, and initial permeability varying from 65.97 to 141.13 md.2. Sandstone cores from Sentumbung, Serawak, Malaysia, with

a 3-in. length, 1-in. diameter, average porosity of 14.37%, andinitial permeability varying from 11.64 to 14.36 md.

No oil was present in the cores. All the cores were cleaned usingmethanol in a Soxhlet extractor and dried in a Memmert UniversalOven at 100C overnight before use.

Preparation of Brines. Synthetic FW and injection water (Bartonand Angsi SWs) were made up according to the analyses in Table 1.Brines were prepared for each run by dissolving the salts in deion-ized water. Therefore, the FW and SW were filtered through a0.45-m filter paper before use in order to remove any particulatematerial. Inhibitor solutions were prepared by dissolving inhibitorsin SW. Five salts used for the preparation of synthetic FW andSW were computed on the basis of the ionic compositions givenin Table 2.

Types of Scale Inhibitors. Three different types of scale inhibitorswere tested for performance comparison. Two of them (DETPMP andPPCA) were imported from China. DETPMP and PPCA were selectedas scale inhibitors because both are commonly used for scale inhibi-tion in Malaysian oil fields. PBSI is a locally produced scale inhibitorselected as the third scale inhibitor to be tested in this study.

Scaling-Test Rig. Experiments were carried out using a test rig,which is schematically shown in Fig. 3.The core-test equipmentconsists of five parts: constant-pressure pumps, transfer cells, oven,pressure transducer, and core holder.

Constant Pressure Pumps. To inject the brines during flood-ing at different pressures, two double-piston plunger pumps

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2/8546 November 2010 SPE Production & Operations

Fig. 1Chemical structure of PPCA inhibitor.

Fig. 2Chemical structure of DETPMP inhibitor.

TABLE 2COMPOUNDS OF SYNTHETIC FW AND INJECTION WATER

Compound High-Salinity FW (ppm)Average Between Barton and Angsi

SW (ppm)

Sodium chloride 132, 461 26,113

Potassium sulfate 5,178

Magnesium chloride 35,625 9,843

Calcium chloride 110,045

Strontium chloride 3,347

TABLE 1THE IONIC COMPOSITIONS OF SYNTHETIC FW AND INJECTION WATER

Ionic High-Salinity FW (ppm) Barton SW (ppm) Angsi SW (ppm)

05.408,01947,9231,25muidoS

50.573043769,1muissatoP

52.592,1060,1062,4muisengaM

02.924483000,03muiclaC

775.64.5001,1muitnortS

2.0nahtssel01muiraB

Chloride 146,385 17,218 19,307.45

057,2069,2801etafluS

08.851631053etanobraciB

Plunger Pump

Core Holder

OvenTransfer Cell

Pressure Transducer

To Nitrogen Cylinder

S.W

Valve

F.W

Flow Meter

Brine Collection

Digital Readout

Water TankWaterWater

Fig. 3Schematic of the coreflooding apparatus.

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manufactured by Lushyong Machiney Industry Limited with a 1.5hp motor, a maximum design pressure of 35 bar, and an approxi-mate flow rate of 20 L/min were used. Moreover, these pumpsoperate on pressure, and the required pressure for the experimentis in the range of 75 to 200 psig. The required pressure is set onthe pump with the help of a regulator. Upon opening the valve, thepump will deliver the set amount of pressure to the experimental rigand the extra fluid will be sent back to the tank by the pump.

Transfer Cells. The two stainless-steel transfer cells weremanufactured by Temco, Inc., and can withstand pressures up to10,000 psia. They were used to store and pump the injected brineto the core holder. Each cell with a capacity of 1,000 mL has

a free-floating piston, which separates the pump fluid (distilledwater) from the injection brine. The pump fluid was pumped intoa transfer cell to displace the brine into the core.

Oven.During all flooding runs, the core holder is placed insidea temperature-controlled oven.

Pressure Transducer.The differential pressure across the coreduring flooding runs was measured by a pressure transducer with adigital display (Model E-913 033-B29) manufactured by LushyongMachiney Industry Limited.

Core Holder. A Hassler-type, stainless-steel core holderdesigned for consolidated core samples with a 3-in. length and1-in. diameter was used. The holder was manufactured by Temco,Inc., and could withstand pressures up to 10,000 psia. This is arubber-sleeved core holder, subjected to an external confining pres-

sure, into which a sandstone core is placed.

Experimental Procedure. In general, the purpose of the laboratorystudy was to investigate permeability reduction by deposition of scalein a porous medium and to acquire knowledge about the efficiency ofscale inhibitor in preventing common oilfield scales from forming.

Jar Test. The aim of this study was to determine the efficiency ofscale inhibitor in preventing formation of common oilfield scalesbecause of synthetic brines (FW and SW) mixing at high salinity(high concentration of calcium and strontium) at various tempera-tures (50 to 95C). The experimental procedures used to determinethe efficiency of scale inhibitor are as follows:

1. For each experiment with common oilfield scales, the twobrine solutions (100 mL of SW containing inhibitor and 100 mL of

FW) were put in clean glass bottles. The bottles were then capped,placed inside the oven, and heated to the desired temperature for1 hour.

2. After 1 hour, the bottles were removed from the oven andSW was added to the FW. The bottles were shaken vigorouslyby hand for 60 seconds and then placed back in the oven. Themixture was left undisturbed for 4 hours. After this, the mixturewas removed from the oven and immediately filtered through0.45-m filter paper.

3. The crystals on the filter paper were dried in a humidityoven and the weight of dried-crystal sample was measured byelectronic top pan balance.

Core Test

Core Saturation. Before each run, the core sample was dried in aMemmert Universal Oven at 100C for overnight. The core samplewas prepared for installation in the core holder. A vacuum wasdrawn on the core sample for several hours to remove all air fromthe core. The core was saturated with FW at room temperature.After the appearance of FW at the outlet, flooding was continuedlong enough to ensure 100% saturation.

Coreflooding Test.As shown in Fig. 3, the system consisting of thecore-holder assembly with the saturated core sample and transfer

cells containing the two incompatible waters (SW and FW) wereplaced inside the oven and heated to the desired temperature of therun. The system was left for 3 hours for temperature equilibriumto be attained. The required confining pressure was then adjustedto be at approximately twice the inlet pressure. A flooding runwas started by setting both plunger pumps at the same pressure(ranging from 75 to 200 psig), then turning them on. Thus, the twowaters (SW and FW) were always injected into the core sample ata mixing ratio of 50:50. The inlet pressure was measured by pres-sure transducer, while the outlet pressure was atmospheric pres-sure. During each run, the flow rate across the core was recordedcontinuously and the permeability of the core was calculated usingDarcys linear-flow equation before and after scale deposition.Experiments on the core material were then repeated using aninhibitor to see how effective this was in preventing or delaying

scale formation resulting from mixing of Angsi and Barton SWswith FW. For selected runs, the core sample was removed at theend of flooding. The core samples were then cut into sections andinvestigated using scanning electron microscopy (SEM) to revealthe nature of the scale-formation crystals.

Results and Discussion

High-Salinity FW Jar-Test Analysis. Scale inhibitor is the mainconcern of this study. There are three types of scale inhibitors(DETPMP, PPCA, and PBSI) that are being tested for their compara-tive effectiveness in preventing scale deposition. The test was car-ried out at the atmospheric pressure and at different temperaturesranging from 50 to 90C for 4 hours. Inhibitor concentrations of10 and 30 ppm were made up with synthetic SW. The solutions

were left undisturbed for 4 hours to allow scaling to occur. Thesolutions were filtered, and the scale that remained on the filterpapers were weighed to obtain a comparison of the weight of scalesdeposited according to different test conditions.

The jar tests started at 50C without inhibitor in the injectionwater. There was very little scale deposited compared with 70 and90C. A distinct increment occurred when the test was carriedout at temperature of 70C. It was noted as 0.286 g, while it was0.304 g of scale deposit on filter paper for the test at 90C. Thisshows the trend when high-salinity FW was mixed with SW, thescale deposited is directly proportional to the increase of the testtemperature, as shown in Fig. 4.

0

0.05

0.1

0.15

0.2

0.25

0.30.35

30 50 70 90

Temperature (C)

Weight(gm)

Blank

10 ppm- PPCA

10 ppm- DETPMP

10 ppm- PBSI

30 ppm- PPCA

30 ppm- DETPMP

30 ppm- PBSI

Fig. 4Effect of temperature on scale deposition without/with scale inhibitor added for high-salinity-FW tests.

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At 70C, PPCA inhibited the scale deposition most effectivelyat its 10-ppm concentration in SW, which gave 0.235 g of depos-ited scale weight in comparison to 0.286 g with no inhibitor added(Fig. 4). At the same temperature, DETPMPgave the best result atits 10-ppm concentration mixed in SW as injection brine. DETPMPmanaged to reduce 0.059 g of scale deposit. On the other hand, itwas observed that by using only 10 ppm of PBSI in SW, a greater

amount of calcium and strontium ions in the FW can remain inthe brine without being deposited with sulfate ions.

The temperature further increased to 90C, as other proceduresand conditions remained unchanged. At 90C, all three scaleinhibitors gave more or less the same trend, and the lines aresmoother when the concentration of scale inhibitors increased inSW brines. PPCA, at this high temperature, inhibited less scaleprecipitation for all concentrations of it in SWs. However, only 30ppm of PPCA was enough to prevent more scales from depositioncompared to other concentrations, which was a reduction of 0.101g of deposited scale. In this case, DETPMPperformed better thanPPCA. It reduced the scale deposition weight from 0.304 to 0.195 gat its 30-ppm concentration in SW. PBSI recorded the least weightof scale deposition at 30-ppm concentration, which was 0.186 g. Itreduced 0.118 g of scale precipitation on filter paper. Because PBSIgave the best result of scale inhibition with 30-ppm concentration,it outperformed the other two scale inhibitors and appeared to bethe best scale inhibitor at 90C (Fig. 4).

Fig. 4 shows the summary of the high-salinity-FW test, takinginto account of the effect of temperature on the weight of scaledeposition for various concentrations of different scale inhibitors.As mentioned earlier, when the temperature increased, the calciumand strontium ions were precipitated with sulfate ions. This obser-vation is in good agreement with observations reported in previousstudies (Jacques and Bourland 1983; Ying-Hsiao et al. 1995; Rochaet al. 2001; Rosario and Bezerra 2001).

Calcium Sulfate and Strontium Sulfate Experiments in the Pres-ence of Scale Inhibitors. Coreflooding is the most important partin the comparison of scale-inhibitor performance because the testphysical conditions are closer to the real field conditions. The mainconcern for this part is to investigate the permeability reduction ofcores caused by scale deposition. Less permeability reduction indi-cates better scale-inhibitor functioning in the injection brines.

SW with inhibitor concentration of 10, 500, and 1,000 ppmwere used as injection water to be mixed with high-salinity FWin core porous media at temperatures of 50, 60, 90, and 95C anddifferential pressures of 75, 125, 100, and 200 psig, respectively.There are three types of scale inhibitors (DETPMP, PPCA, and

PBSI) being tested for comparative effectiveness in preventingscale deposition.

Calcium sulfate and strontium sulfate scaling tendency is mostsevere at 95C, while it is less severe at 50C. At higher tempera-tures, the rate of precipitation increases. The temperature incre-ment rises in supersaturation because the solubility of CaSO 4andSrSO4decreases with temperature. This will lead to an increase inprecipitation and eventually causes faster permeability reduction.Temperature also impacts the rate of reaction kinetics; because thetemperature increases along with saturation effects, there will beclear kinetic effects that are expected to speed up as the test fluidsbecome hotter so more scale can form in the same time period.

Figs. 5 through 8 reveal the permeability-reduction trendchanges with injection time when the cores were injected with SWthat contained various scale inhibitors. The coreflooding run withno inhibitor added in injection brine was taken as the referencetrend of permeability reduction with increasing injection time,where it can be seen clearly that in the first 30 minutes of the SWinjection, the permeability reduced sharply.

Moreover, the curves in the figures then reduce gradually incurve gradient as injection time continued. DETPMP, PPCA, and

0.7

0.8

0.9

1

0 20 40 60 80 100 120

Time (min)

Permeabilityratio(Kd/ki)

Blank

10 ppm- PPCA

10 ppm- DETPMP

10 ppm- PBSICa=30000 ppmSr=1100 ppmBerea Core

Fig. 5Variation of permeability ratio as a function of time, showing the effect of scale inhibitors at 75 psig and 50C.

0.5

0.6

0.7

0.8

0.9

1

0 20 40 60 80 100 120

Time (min)


Blank

10 ppm- PPCA

10 ppm- DETPMP

10 ppm- PBSICa=30000 ppmSr=1100 ppmBerea Core


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PBSI were observed to follow the expected permeability-reduc-tion trend (Figs. 5 through 8). A similar trend was reported in theliterature (Moghadasi et al. 2003; Todd and Yuan 1992; Moghadasiet al. 2002; Moghadasi et al. 2004; Jamialahmadi and Muller-Steinhagen 2008).

The flooding test was then continued with injection brines thatcontained scale inhibitors. At 50C (Fig. 5), 10 ppm of DETPMP

reduces the permeability-reduction percentage to only 16.26% incomparison to 19.86% with no inhibitor added. 10 ppm of PPCA

was slightly less effective at 17.93% permeability reduction.On the other hand, 10 ppm of PBSI successfully retained the

initial permeability for the first 30 minutes of the coreflooding run.After that, core-permeability decreased slowly and then graduallyleveled out at the end of the brine injection. At the end of run, thepercentage of permeability reduction is only 15.11% (Fig. 5).

Furthermore, it can be concluded for the high-salinity FWcoreflooding test that PBSI was the best calcium-sulfate andstrontium-sulfate scale inhibitor compared to the other two scaleinhibitors. The effectiveness of the scale inhibitor is followed byDETPMP(second) and PPCA (third).

At 95C, PPCA inhibited the scale deposition most effectivelyat its 500- and 1,000-ppm concentration in SW, which gave 32.46and 18.37% permeability reduction, respectively, in comparisonto 39.46% with no inhibitor added. At the same temperature,DETPMPgave the best result at its 500- and 1,000-ppm concen-tration mixed in SW as injection brine, which gave 26.31 and14.53% permeability reduction, as shown in Fig. 8. Moreover, itwas observed that by using 1,000 ppm of DETPMPin SW, a greaterquantity of calcium and strontium ions can remain in the solutionin the FW without being deposited with sulfate ions.

SEM Analysis. The scaled core samples were examined by SEMto observe the particle size and morphology of the precipitates.

The formation of CaSO4 andSrSO4during flow of injection andFW in porous media was recorded by SEM micrographs, whichshow CaSO4 andSrSO4crystal formation in porous space. Fig. 9presents an SEM image of unscaled core sample.

Figs. 10 through 13show SEM image of the CaSO4andSrSO4scaling crystals in rock pores precipitated from mixed SW and FWinside the cores. Comparison of CaSO4 and SrSO4formed in porous

media did not show significant differences in crystal external mor-phology. The differences lie in the irregularity of crystals formedin rock pores and the crystal-size variations from one location toanother within a core. The maximum size of CaSO4 and SrSO4crys-tals precipitated from mixed brines was approximately 2.55 m.

In all core tests, the abundance of scale reduced significantlyfrom the front of the core to the rear, indicating that scale formationin porous media was rapid with the observation that the flow ratedecreased soon after two incompatible waters were mixed withina core. The observations of scaling sites from previous tests (Toddand Yuan 1992; Jamialahmadi and Muller-Steinhagen 2008; Toddand Yuan 1990; Bedrikovetsky et al. 2003; Bedrikovetsky et al.2005) were confirmed by these test results.

At the inlet face of Berea cores (Fig. 10), the amount of CaSO 4and

SrSO4

crystals is higher compared with the outlet face (Fig.11), which indicates more precipitation at the inlet face. The reasonthat the scaling decreased downstream of a core is clearly becausemost of the scaling ions had deposited within the front sectionsas soon as they were mixed and, leaving few ions in solution toprecipitate from the flow stream in the rear sections.

Fig. 13 presents the SEM images of CaSO4andSrSO4precipi-tated at 500 ppm of DETPMP (Fig. 13a) and 500 ppm of PPCA(Fig. 13b). For these images, the morphology of the crystals is verydifferent from either of the uninhibited solutions. From the SEMimages, it can be observed that in the absence of inhibitor (Fig. 12),the CaSO4 andSrSO4 crystals exhibited a large quantity of large

0.5

0.6

0.7

0.8

0.9

1

0 20 40 60 80 100 120

Time (min)

Permeabilityratio(Kd/ki) Blank

500 ppm- PPCA

500 ppm- DETPMP

1000 ppm- PPCA

1000 ppm- DETPMP

Ca=30000 ppmSr=1100 ppmSandstone Core


0.5

0.6

0.7

0.8

0.9

1

0 20 40 60 80 100 120

Time (min)


Blank

500 ppm- PPCA

500 ppm- DETPMP

1000 ppm- PPCA

1000 ppm- DETPMP

Ca=30000 ppmSr=1100 ppmSandstone Core


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crystals, while in the presence of inhibitors, the CaSO4and SrSO4crystals are fewer and smaller, as shown in Fig. 13. In general, adifference in morphology of the CaSO4 andSrSO4precipitates isobserved in the presence of inhibitor. At 500 ppm of DETPMP, lessCaSO4 and SrSO4precipitate could be seen than with 500 ppm ofPPCA, as shown in Fig. 13.

Conclusions

This work was carried out to investigate permeability reduction bydeposition of scale in a porous medium and to acquire knowledge

of the efficiency of scale inhibitor in preventing formation of com-mon oilfield scales. On the basis of the results obtained from thisstudy, the following conclusions can be drawn: At elevated temperatures, the mass of precipitation of both

CaSO4 and SrSO4 scales increases because the solubilities ofCaSO4 and SrSO4 scales decrease with increasing temperature.Temperature also has an effect on the rate of reaction kinetics:the rate of reaction kinetics increases at elevated temperaturesbecause the rate of both CaSO4 and SrSO4 precipitation increaseswith temperature.

Fig. 9SEM image of unscaled Berea and sandstone cores.

(a) (b)

(a) (b)

CaSO4

andSrSO4scales

Fig. 10SEM image of CaSO4and SrSO4scales in inlet face of Berea sandstone core at 100 psig and 90C.

(a) (b)

CaSO4andSrSO4scales

Fig. 11SEM image of CaSO4and SrSO4scales in outlet face of Berea sandstone core at 100 psig and 90C.

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When synthetic SW containing sulfate is mixed in situ withFW that contains a significant amount of dissolved calcium andstrontium ions during laboratory coreflooding, in-situ precipita-tion of CaSO4 and SrSO4occurs.

The pattern of permeability decline in a porous medium becauseof scaling injection was characterized by a concave curve with asteep initial decline that gradually levels. The initial steepness ofthese curves generally decreased with increasing distance fromthe point of mixing of the incompatible brines. The concaveshape of the permeability/time curves was common to the major-ity of the porous-medium flow tests.

Observations of micrographs using SEM showed the formationof CaSO

4

and SrSO4

crystals in porous space during flow ofinjection water and FW.

At the inlet face, the amount of CaSO4 and SrSO4 crystals ishigher compared with the outlet face, which indicates more pre-cipitation at the inlet face. The reason that the scaling decreaseddownstream of a core is because most of the scaling ions haddeposited within the front sections as soon as they were mixed,with fewer ions left to precipitate from the flow stream in therear sections.

For high-salinity FW, PBSI was the best CaSO4and SrSO4scaleinhibitor compared with the other two scale inhibitors, PPCA andDETPMP. The effectiveness of the scale inhibitor is followed byDETPMP(second) and PPCA (third).

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(a) (b)

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Fig. 12SEM image of CaSO4and SrSO4scales in inlet face of sandstone core at 200 psig and 95C.

(a) (b)

CaSO4

andSrSO4scales

Fig. 13SEM image of CaSO4and SrSO4scales in inlet face of sandstone core at 200 psig and 95C and at (a) 500 ppm of DE-TPMP and (b) 500 ppm of PPCA.

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Rosario, F.F. and Bezerra, M.C.M. 2001. Scale Potential of a Deep

Water Field-Water Characterization and Scaling Assessment. Paper

SPE 68332 presented at the International Symposium on Oilfield Scale,

Aberdeen, 3031 January. doi: 10.2118/68332-MS.

Todd, A.C. and Yuan, M.D. 1990. Barium and Strontium Sulfate Solid-Solution

Formation in Relation to North Sea Scaling Problems. SPE Prod Eng 5

(3): 279285. SPE-18200-PA. doi: 10.2118/18200-PA.

Todd, A.C. and Yuan, M.D. 1992. Barium and Strontium Sulfate Solid-Solution

Scale Formation at Elevated Temperatures. SPE Prod Eng 7 (1): 8592.

SPE-19762-PA. doi: 10.2118/19762-PA.

Voloshin, A.I., Ragulin, V.V., Tyabayeva, N.E., Diakonov, I.I., and Mackay,

E.J. 2003. Scaling Problems in Western Siberia. Paper SPE 80407

presented at the International Symposium on Oilfield Scale, Aberdeen,

2930January. doi: 10.2118/80407-MS.

Wat, R.M.S., Sorbie, K.S., Todd, A.C., Chen, P., and Jiang, P. 1992.

Kinetics of BaSO4 Crystal Growth and Effect in Formation Damage.

Paper SPE 23814 presented at the SPE Formation Damage Con-

trol Symposium, Lafayette, Louisiana, USA, 2627 February. doi:

10.2118/23814-MS.

Yeboah, Y.D., Somuah, S.K., and Saeed, M.R. 1993. A New and Reliable

Model for Predicting Oilfield Scale Formation. Paper SPE 25166 pre-

sented at the SPE International Symposium on Oilfield Chemistry, New

Orleans, 25 March. doi: 10.2118/25166-MS.

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to Predict the Co-Precipitation of BaSO4 and SrSO4. Paper SPE 29489

presented at the SPE Production Operations Symposium, Oklahoma

City, Oklahoma, USA, 24 March. doi: 10.2118/29489-MS.

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in Oilfield Operations. SPE Prod Eng 6 (1): 6372. SPE-18484-PA. doi:10.2118/18484-PA. Engineering,SPE 18484, pp. 6372.

Amer Badr Bin Merdhahis a lecturer in the petroleum engineeringdepartment at Hadhramout University of Science and Technology,Yemen. His experience includes formation damage, production,reservoir, and drilling. He is author of one book, 15 internationaljournals, three international conferences, and one seminar inPrediction and Treatment of Scale Formation in Oil Reservoirduring Water Injection (Petroleum Engineering). He holds a BEdegree in petroleum at Hadhramout University of Science andTechnology, Yemen, and ME and PhD degrees in petroleum atUniversiti Teknologi Malaysia. He is a member of SPE.

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