Inhibition of Calcium Sulfate and Strontium Sulfate Scale in ... - OnePetro

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This study was conducted to investigate the permeability reduction caused by deposition of calcium sulfate. (CaSO4) and strontium sulfate (SrSO4) in Malaysian ...
Inhibition of Calcium Sulfate and Strontium Sulfate Scale in Waterflood Amer Badr BinMerdhah, Hadhramout University of Science and Technology

Summary One of the most common methods of preventing downhole and topside mineral-scale formation in oil fields is through the use of chemical-scale inhibitors. Several aspects of the brine composition may affect the performance of the various scale inhibitors used in oilfield applications. This study was conducted to investigate the permeability reduction caused by deposition of calcium sulfate (CaSO4) and strontium sulfate (SrSO4) in Malaysian sandstone and Berea cores from mixing injected Malaysian seawaters (SW) (Angsi and Barton) and formation water (FW) that contain a high concentration of calcium and strontium ions at various temperatures (50 to 95°C) and differential pressures (75 to 200 psig). Scale-inhibition efficiency was determined in both the bulk jar and the core tests by using scale inhibitors methylene phosphonic acid (DETPMP), polyphosphino carboxylic acid (PPCA), and phosphorus-based scale inhibitor (PBSI) at various temperatures (50 to 95°C) and concentrations. The results showed a large extent of permeability damage caused by calcium and strontium sulfates that deposited on the rock pore surface. At higher temperatures, the rate of CaSO4 and SrSO4 precipitation increases because the solubilities of CaSO4 and SrSO4 scales decrease with increasing temperature. At 90°C temperature, PBSI was the best inhibitor because it reduced more scale deposition compared to the DETPMP and PPCA inhibitors. Introduction Scale deposition can plug production lines and equipment and impair fluid flow. The consequence could be production-equipment failure, emergency shutdown, increased maintenance cost, and overall decrease in production efficiency. The failure of this equipment could result in safety hazards. In case of water-injection systems, scale could plug the pores of the formation and result in 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 relatively common problem in the oil industry. Most scale forms either by pressure and temperature changes that favor salt precipitation from FWs or when incompatible waters mix during pressure maintenance or waterflood strategies. Scale prevention is achieved by performing squeeze treatments in which chemical-scale inhibitors are injected into 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, and topside process equipment has presented a challenge to the oil and gas industry for more than 50 years. Chemical methods to control scale have been developed, including scale squeeze treatments and continuous chemical injection. A key factor in the success of such treatments is understanding the chemical placement and effectiveness of the treatment chemicals (Jordan et al. 2006). In most cases, the scaled-up wells are caused by the formation of sulfate and carbonate scales of calcium and strontium. Because of their proportionate hardness and low solubility, there are restricted processes available for their removal, and preventive measures such as the squeeze inhibitor treatment must be taken. It is therefore important to gain a proper understanding of the kinetics

Copyright © 2010 Society of Petroleum Engineers Original SPE manuscript received for review 20 February 2010. Revised manuscript received for review 14 June 10. Paper (SPE 141168) peer approved 26 July 10.

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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 inorganic phosphates, organophosphorous compounds, and organic polymers. PPCA and DETPMP are two common commercial scale inhibitors used to control mineral scaling in the oil and gas industry (Bezemer and Bauer 1969). PPCA is a polymer formed by two polyacrylic acids connected by a phosphorous group, as shown in Fig. 1. PPCA is often regarded as a nucleation inhibitor. After initial nucleation, PPCA continues to retard crystal growth, but it does not stop it entirely and becomes less effective with time. This is because of its incorporation in the crystal lattice. DETPMP, the phosphonate species, has the chemical structure illustrated in Fig. 2. In contrast to PPCA, DETPMP is thought to retard the growth of crystals and is less effective in preventing initial nucleation. Once nucleation has started, it is effective at stopping further crystal growth by adsorbing active growth sites on the scale crystal lattice (Chen et al. 2004). The action of scale inhibitors in preventing scale formation has been investigated extensively in the literature with different inhibitors. The present work is conducted to test the efficiency of common commercial scale inhibitors (DETPMP and PPCA) and locally produced scale inhibitor (PBSI) in preventing or delaying CaSO4 and SrSO4 scales, which are formed by mixing injection water (Barton and Angsi SWs) and FW. Materials and Methods Core Material. In all flooding experiments, the porous media used in 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%, and initial permeability varying from 11.64 to 14.36 md. No oil was present in the cores. All the cores were cleaned using methanol in a Soxhlet extractor and dried in a Memmert Universal Oven at 100°C overnight before use. Preparation of Brines. Synthetic FW and injection water (Barton and Angsi SWs) were made up according to the analyses in Table 1. Brines were prepared for each run by dissolving the salts in deionized water. Therefore, the FW and SW were filtered through a 0.45-µm filter paper before use in order to remove any particulate material. Inhibitor solutions were prepared by dissolving inhibitors in SW. Five salts used for the preparation of synthetic FW and SW were computed on the basis of the ionic compositions given in Table 2. Types of Scale Inhibitors. Three different types of scale inhibitors were tested for performance comparison. Two of them (DETPMP and PPCA) were imported from China. DETPMP and PPCA were selected as scale inhibitors because both are commonly used for scale inhibition in Malaysian oil fields. PBSI is a locally produced scale inhibitor selected 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 equipment consists of five parts: constant-pressure pumps, transfer cells, oven, pressure transducer, and core holder. Constant Pressure Pumps. To inject the brines during flooding at different pressures, two double-piston plunger pumps 545

Fig. 1—Chemical structure of PPCA inhibitor. Fig. 2—Chemical structure of DETPMP inhibitor.

TABLE 1—THE IONIC COMPOSITIONS OF SYNTHETIC FW AND INJECTION WATER Ionic

High-Salinity FW (ppm)

Barton SW (ppm)

Angsi SW (ppm) 10,804.50

Sodium

52,132

9,749

Potassium

1,967

340

375.05

Magnesium

4,260

1,060

1,295.25

Calcium

30,000

384

429.20

Strontium

1,100

5.4

6.577

Barium

10

less than 0.2



Chloride

146,385

17,218

19,307.45

Sulfate

108

2,960

2,750

Bicarbonate

350

136

158.80

TABLE 2—COMPOUNDS OF SYNTHETIC FW AND INJECTION WATER Compound

High-Salinity FW (ppm)

Average Between Barton and Angsi SW (ppm)

132, 461

26,113

Sodium chloride Potassium sulfate



5,178

Magnesium chloride

35,625

9,843

Calcium chloride

110,045



3,347



Strontium chloride

Digital Readout Pressure Transducer Flow Meter

S.W

Core Holder F.W

Transfer Cell

Oven Brine Collection

To Nitrogen Cylinder Plunger Pump Water

Valve

Water Water Tank Fig. 3—Schematic of the coreflooding apparatus.

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manufactured by Lushyong Machiney Industry Limited with a 1.5 hp motor, a maximum design pressure of 35 bar, and an approximate flow rate of 20 L/min were used. Moreover, these pumps operate on pressure, and the required pressure for the experiment is in the range of 75 to 200 psig. The required pressure is set on the pump with the help of a regulator. Upon opening the valve, the pump will deliver the set amount of pressure to the experimental rig and the extra fluid will be sent back to the tank by the pump. Transfer Cells. The two stainless-steel transfer cells were manufactured by Temco, Inc., and can withstand pressures up to 10,000 psia. They were used to store and pump the injected brine to the core holder. Each cell with a capacity of 1,000 mL has a free-floating piston, which separates the pump fluid (distilled water) from the injection brine. The pump fluid was pumped into a transfer cell to displace the brine into the core. Oven. During all flooding runs, the core holder is placed inside a temperature-controlled oven. Pressure Transducer. The differential pressure across the core during flooding runs was measured by a pressure transducer with a digital display (Model E-913 033-B29) manufactured by Lushyong Machiney Industry Limited. Core Holder. A Hassler-type, stainless-steel core holder designed for consolidated core samples with a 3-in. length and 1-in. diameter was used. The holder was manufactured by Temco, Inc., and could withstand pressures up to 10,000 psia. This is a rubber-sleeved core holder, subjected to an external confining pressure, into which a sandstone core is placed. Experimental Procedure. In general, the purpose of the laboratory study was to investigate permeability reduction by deposition of scale in a porous medium and to acquire knowledge about the efficiency of scale inhibitor in preventing common oilfield scales from forming. Jar Test. The aim of this study was to determine the efficiency of scale inhibitor in preventing formation of common oilfield scales because of synthetic brines (FW and SW) mixing at high salinity (high concentration of calcium and strontium) at various temperatures (50 to 95°C). The experimental procedures used to determine the efficiency of scale inhibitor are as follows: 1. For each experiment with common oilfield scales, the two brine 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 for 1 hour. 2. After 1 hour, the bottles were removed from the oven and SW was added to the FW. The bottles were shaken vigorously by hand for 60 seconds and then placed back in the oven. The mixture was left undisturbed for 4 hours. After this, the mixture was removed from the oven and immediately filtered through 0.45-µm filter paper. 3. The crystals on the filter paper were dried in a humidity oven and the weight of dried-crystal sample was measured by electronic top pan balance.

Core Test Core Saturation. Before each run, the core sample was dried in a Memmert Universal Oven at 100°C for overnight. The core sample was prepared for installation in the core holder. A vacuum was drawn on the core sample for several hours to remove all air from the core. The core was saturated with FW at room temperature. After the appearance of FW at the outlet, flooding was continued long enough to ensure 100% saturation. Coreflooding Test. As shown in Fig. 3, the system consisting of the core-holder assembly with the saturated core sample and transfer cells containing the two incompatible waters (SW and FW) were placed inside the oven and heated to the desired temperature of the run. The system was left for 3 hours for temperature equilibrium to be attained. The required confining pressure was then adjusted to be at approximately twice the inlet pressure. A flooding run was started by setting both plunger pumps at the same pressure (ranging from 75 to 200 psig), then turning them on. Thus, the two waters (SW and FW) were always injected into the core sample at a mixing ratio of 50:50. The inlet pressure was measured by pressure transducer, while the outlet pressure was atmospheric pressure. During each run, the flow rate across the core was recorded continuously and the permeability of the core was calculated using Darcy’s linear-flow equation before and after scale deposition. Experiments on the core material were then repeated using an inhibitor to see how effective this was in preventing or delaying scale formation resulting from mixing of Angsi and Barton SWs with FW. For selected runs, the core sample was removed at the end of flooding. The core samples were then cut into sections and investigated using scanning electron microscopy (SEM) to reveal the nature of the scale-formation crystals. Results and Discussion High-Salinity FW Jar-Test Analysis. Scale inhibitor is the main concern of this study. There are three types of scale inhibitors (DETPMP, PPCA, and PBSI) that are being tested for their comparative effectiveness in preventing scale deposition. The test was carried out at the atmospheric pressure and at different temperatures ranging from 50 to 90°C for 4 hours. Inhibitor concentrations of 10 and 30 ppm were made up with synthetic SW. The solutions were left undisturbed for 4 hours to allow scaling to occur. The solutions were filtered, and the scale that remained on the filter papers were weighed to obtain a comparison of the weight of scales deposited according to different test conditions. The jar tests started at 50°C without inhibitor in the injection water. There was very little scale deposited compared with 70 and 90°C. A distinct increment occurred when the test was carried out at temperature of 70°C. It was noted as 0.286 g, while it was 0.304 g of scale deposit on filter paper for the test at 90°C. This shows the trend when high-salinity FW was mixed with SW, the scale deposited is directly proportional to the increase of the test temperature, as shown in Fig. 4.

0.35 Blank

Weight (gm)

0.3

10 ppm- PPCA

0.25

10 ppm- DETPMP

0.2

10 ppm- PBSI

0.15

30 ppm- PPCA

0.1

30 ppm- DETPMP

0.05

30 ppm- PBSI

0 30

50

70

90

Temperature (°C) Fig. 4—Effect of temperature on scale deposition without/with scale inhibitor added for high-salinity-FW tests. November 2010 SPE Production & Operations

547

Permeability ratio (Kd/ki)

1 Blank

0.9 10 ppm- PPCA 10 ppm- DETPMP

0.8

Ca=30000 ppm Sr=1100 ppm Berea Core

10 ppm- PBSI

0.7 0

20

40

60

80

100

120

Time (min) Fig. 5—Variation of permeability ratio as a function of time, showing the effect of scale inhibitors at 75 psig and 50°C.

At 70°C, PPCA inhibited the scale deposition most effectively at its 10-ppm concentration in SW, which gave 0.235 g of deposited scale weight in comparison to 0.286 g with no inhibitor added (Fig. 4). At the same temperature, DETPMP gave the best result at its 10-ppm concentration mixed in SW as injection brine. DETPMP managed to reduce 0.059 g of scale deposit. On the other hand, it was observed that by using only 10 ppm of PBSI in SW, a greater amount of calcium and strontium ions in the FW can remain in the brine without being deposited with sulfate ions. The temperature further increased to 90°C, as other procedures and conditions remained unchanged. At 90°C, all three scale inhibitors gave more or less the same trend, and the lines are smoother when the concentration of scale inhibitors increased in SW brines. PPCA, at this high temperature, inhibited less scale precipitation for all concentrations of it in SWs. However, only 30 ppm of PPCA was enough to prevent more scales from deposition compared to other concentrations, which was a reduction of 0.101 g of deposited scale. In this case, DETPMP performed better than PPCA. It reduced the scale deposition weight from 0.304 to 0.195 g at its 30-ppm concentration in SW. PBSI recorded the least weight of scale deposition at 30-ppm concentration, which was 0.186 g. It reduced 0.118 g of scale precipitation on filter paper. Because PBSI gave the best result of scale inhibition with 30-ppm concentration, it outperformed the other two scale inhibitors and appeared to be the best scale inhibitor at 90°C (Fig. 4). Fig. 4 shows the summary of the high-salinity-FW test, taking into account of the effect of temperature on the weight of scale deposition for various concentrations of different scale inhibitors. As mentioned earlier, when the temperature increased, the calcium and strontium ions were precipitated with sulfate ions. This observation is in good agreement with observations reported in previous studies (Jacques and Bourland 1983; Ying-Hsiao et al. 1995; Rocha et al. 2001; Rosario and Bezerra 2001).

Calcium Sulfate and Strontium Sulfate Experiments in the Presence of Scale Inhibitors. Coreflooding is the most important part in the comparison of scale-inhibitor performance because the test physical conditions are closer to the real field conditions. The main concern for this part is to investigate the permeability reduction of cores caused by scale deposition. Less permeability reduction indicates better scale-inhibitor functioning in the injection brines. SW with inhibitor concentration of 10, 500, and 1,000 ppm were used as injection water to be mixed with high-salinity FW in core porous media at temperatures of 50, 60, 90, and 95°C and differential 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 preventing scale deposition. Calcium sulfate and strontium sulfate scaling tendency is most severe at 95°C, while it is less severe at 50°C. At higher temperatures, the rate of precipitation increases. The temperature increment rises in supersaturation because the solubility of CaSO4 and SrSO4 decreases with temperature. This will lead to an increase in precipitation and eventually causes faster permeability reduction. Temperature also impacts the rate of reaction kinetics; because the temperature increases along with saturation effects, there will be clear kinetic effects that are expected to speed up as the test fluids become hotter so more scale can form in the same time period. Figs. 5 through 8 reveal the permeability-reduction trend changes with injection time when the cores were injected with SW that contained various scale inhibitors. The coreflooding run with no inhibitor added in injection brine was taken as the reference trend of permeability reduction with increasing injection time, where it can be seen clearly that in the first 30 minutes of the SW injection, the permeability reduced sharply. Moreover, the curves in the figures then reduce gradually in curve gradient as injection time continued. DETPMP, PPCA, and

Permeability ratio (Kd/ki)

1 0.9

Blank

0.8

10 ppm- PPCA

0.7

10 ppm- DETPMP

Ca=30000 ppm Sr=1100 ppm Berea Core

0.6

10 ppm- PBSI

0.5 0

20

40

60

80

100

120

Time (min) Fig. 6—Variation of permeability ratio as a function of time, showing the effect of scale inhibitors at 100 psig and 90°C. 548

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Permeability ratio (Kd/ki)

1 Blank

0.9

500 ppm- PPCA

0.8 500 ppm- DETPMP

0.7

1000 ppm- PPCA

Ca=30000 ppm Sr=1100 ppm Sandstone Core

0.6

1000 ppm- DETPMP

0.5 0

20

40

60

80

100

120

Time (min) Fig. 7—Variation of permeability ratio as a function of time, showing the effect of scale inhibitors at 125 psig and 60°C.

PBSI were observed to follow the expected permeability-reduction trend (Figs. 5 through 8). A similar trend was reported in the literature (Moghadasi et al. 2003; Todd and Yuan 1992; Moghadasi et al. 2002; Moghadasi et al. 2004; Jamialahmadi and MullerSteinhagen 2008). The flooding test was then continued with injection brines that contained scale inhibitors. At 50°C (Fig. 5), 10 ppm of DETPMP reduces the permeability-reduction percentage to only 16.26% in comparison 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 gradually leveled out at the end of the brine injection. At the end of run, the percentage of permeability reduction is only 15.11% (Fig. 5). Furthermore, it can be concluded for the high-salinity FW coreflooding test that PBSI was the best calcium-sulfate and strontium-sulfate scale inhibitor compared to the other two scale inhibitors. The effectiveness of the scale inhibitor is followed by DETPMP (second) and PPCA (third). At 95°C, PPCA inhibited the scale deposition most effectively at its 500- and 1,000-ppm concentration in SW, which gave 32.46 and 18.37% permeability reduction, respectively, in comparison to 39.46% with no inhibitor added. At the same temperature, DETPMP gave the best result at its 500- and 1,000-ppm concentration mixed in SW as injection brine, which gave 26.31 and 14.53% permeability reduction, as shown in Fig. 8. Moreover, it was observed that by using 1,000 ppm of DETPMP in SW, a greater quantity of calcium and strontium ions can remain in the solution in the FW without being deposited with sulfate ions. SEM Analysis. The scaled core samples were examined by SEM to observe the particle size and morphology of the precipitates.

The formation of CaSO4 and SrSO4 during flow of injection and FW in porous media was recorded by SEM micrographs, which show CaSO4 and SrSO4 crystal formation in porous space. Fig. 9 presents an SEM image of unscaled core sample. Figs. 10 through 13 show SEM image of the CaSO4 and SrSO4 scaling crystals in rock pores precipitated from mixed SW and FW inside the cores. Comparison of CaSO4 and SrSO4 formed in porous media did not show significant differences in crystal external morphology. The differences lie in the irregularity of crystals formed in rock pores and the crystal-size variations from one location to another within a core. The maximum size of CaSO4 and SrSO4 crystals precipitated from mixed brines was approximately 2.55 µm. In all core tests, the abundance of scale reduced significantly from the front of the core to the rear, indicating that scale formation in porous media was rapid with the observation that the flow rate decreased soon after two incompatible waters were mixed within a core. The observations of scaling sites from previous tests (Todd and Yuan 1992; Jamialahmadi and Muller-Steinhagen 2008; Todd and 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 CaSO4 and SrSO4 crystals is higher compared with the outlet face (Fig. 11), which indicates more precipitation at the inlet face. The reason that the scaling decreased downstream of a core is clearly because most of the scaling ions had deposited within the front sections as soon as they were mixed and, leaving few ions in solution to precipitate from the flow stream in the rear sections. Fig. 13 presents the SEM images of CaSO4 and SrSO4 precipitated at 500 ppm of DETPMP (Fig. 13a) and 500 ppm of PPCA (Fig. 13b). For these images, the morphology of the crystals is very different from either of the uninhibited solutions. From the SEM images, it can be observed that in the absence of inhibitor (Fig. 12), the CaSO4 and SrSO4 crystals exhibited a large quantity of large

Permeability ratio (Kd/ki)

1 Blank

0.9

500 ppm- PPCA

0.8 500 ppm- DETPM P

0.7

1000 ppm- PPCA

Ca=30000 ppm Sr=1100 ppm Sandstone Core

0.6

1000 ppm- DETPM P

0.5 0

20

40

60

80

100

120

Time (min) Fig. 8—Variation of permeability ratio as a function of time, showing the effect of scale inhibitors at 200 psig and 95°C. November 2010 SPE Production & Operations

549

(a)

(b) Fig. 9—SEM image of unscaled Berea and sandstone cores.

CaSO4 and SrSO4 scales

(a)

(b)

Fig. 10—SEM image of CaSO4 and SrSO4 scales in inlet face of Berea sandstone core at 100 psig and 90°C.

crystals, while in the presence of inhibitors, the CaSO4 and SrSO4 crystals are fewer and smaller, as shown in Fig. 13. In general, a difference in morphology of the CaSO4 and SrSO4 precipitates is observed in the presence of inhibitor. At 500 ppm of DETPMP, less CaSO4 and SrSO4 precipitate could be seen than with 500 ppm of PPCA, as shown in Fig. 13. Conclusions This work was carried out to investigate permeability reduction by deposition of scale in a porous medium and to acquire knowledge

of the efficiency of scale inhibitor in preventing formation of common oilfield scales. On the basis of the results obtained from this study, the following conclusions can be drawn: • At elevated temperatures, the mass of precipitation of both CaSO4 and SrSO4 scales increases because the solubilities of CaSO4 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 temperatures because the rate of both CaSO4 and SrSO4 precipitation increases with temperature.

CaSO4 and SrSO4 scales

(a)

(b)

Fig. 11—SEM image of CaSO4 and SrSO4 scales in outlet face of Berea sandstone core at 100 psig and 90°C. 550

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CaSO4 and SrSO4 scales

(a)

(b) Fig. 12—SEM image of CaSO4 and SrSO4 scales in inlet face of sandstone core at 200 psig and 95°C.

CaSO4 and SrSO4 scales

(a)

(b)

Fig. 13—SEM image of CaSO4 and SrSO4 scales in inlet face of sandstone core at 200 psig and 95°C and at (a) 500 ppm of DETPMP and (b) 500 ppm of PPCA.

• When synthetic SW containing sulfate is mixed in situ with FW that contains a significant amount of dissolved calcium and strontium ions during laboratory coreflooding, in-situ precipitation of CaSO4 and SrSO4 occurs. • The pattern of permeability decline in a porous medium because of scaling injection was characterized by a concave curve with a steep initial decline that gradually levels. The initial steepness of these curves generally decreased with increasing distance from the point of mixing of the incompatible brines. The concave shape of the permeability/time curves was common to the majority of the porous-medium flow tests. • Observations of micrographs using SEM showed the formation of CaSO4 and SrSO4 crystals in porous space during flow of injection water and FW. • At the inlet face, the amount of CaSO4 and SrSO4 crystals is higher compared with the outlet face, which indicates more precipitation at the inlet face. The reason that the scaling decreased downstream of a core is because most of the scaling ions had deposited within the front sections as soon as they were mixed, with fewer ions left to precipitate from the flow stream in the rear sections. • For high-salinity FW, PBSI was the best CaSO4 and SrSO4 scale inhibitor compared with the other two scale inhibitors, PPCA and DETPMP. The effectiveness of the scale inhibitor is followed by DETPMP (second) and PPCA (third). References Andersen, K.I., Halvorsen, E., Saelensminde, T., and Ostbye, O.N. 2000. Water Management in a Closed Loop-Problems and Solutions at November 2010 SPE Production & Operations

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SPE 68332 presented at the International Symposium on Oilfield Scale, Aberdeen, 30–31 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): 279–285. 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): 85–92. 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, 29–30 January. 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 Control Symposium, Lafayette, Louisiana, USA, 26–27 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 presented at the SPE International Symposium on Oilfield Chemistry, New Orleans, 2–5 March. doi: 10.2118/25166-MS. Ying-Hsiao, L., Crane, S.D., and Coleman, J.R. 1995. A Novel Approach to Predict the Co-Precipitation of BaSO4 and SrSO4. Paper SPE 29489 presented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, USA, 2–4 March. doi: 10.2118/29489-MS. Yuan, M.D. and Todd, A.C. 1991. Prediction of Sulfate Scaling Tendency in Oilfield Operations. SPE Prod Eng 6 (1): 63–72. SPE-18484-PA. doi: 10.2118/18484-PA. Engineering, SPE 18484, pp. 63–72. Amer Badr Bin Merdhah is a lecturer in the petroleum engineering department at Hadhramout University of Science and Technology, Yemen. His experience includes formation damage, production, reservoir, and drilling. He is author of one book, 15 international journals, three international conferences, and one seminar in “Prediction and Treatment of Scale Formation in Oil Reservoir during Water Injection” (Petroleum Engineering). He holds a BE degree in petroleum at Hadhramout University of Science and Technology, Yemen, and ME and PhD degrees in petroleum at Universiti Teknologi Malaysia. He is a member of SPE.

November 2010 SPE Production & Operations