Inhibition of barium sulfate scale at high-barium formation water

Inhibition of barium sulfate scale at high-barium formation water

Journal of Petroleum Science and Engineering 90–91 (2012) 124–130 Contents lists available at SciVerse ScienceDirect Journal of Petroleum Science an...

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Journal of Petroleum Science and Engineering 90–91 (2012) 124–130

Contents lists available at SciVerse ScienceDirect

Journal of Petroleum Science and Engineering journal homepage: www.elsevier.com/locate/petrol

Inhibition of barium sulfate scale at high-barium formation water Amer Badr BinMerdhah n Petroleum Engineering Department, Hadhramout University of Science & Technology, Mukalla, Hadhramout, Yemen

a r t i c l e i n f o

a b s t r a c t

Article history: Received 25 December 2011 Accepted 2 April 2012 Available online 21 April 2012

One of the most common methods for preventing scale formation is through the use of scale inhibitor. This study was conducted to investigate the permeability reduction caused by deposition of barium sulfate in Malaysian sandstone and Berea cores from mixing of injected Malaysian seawaters (Angsi and Barton) and formation water that contained high concentration of barium ion at various temperatures (50–95 1C) and differential pressures (75–200 psig). Scale inhibition efficiency was determined in both the bulk jar and core tests by using scale inhibitors Methylene Phosphonic Acid (DETPMP), PolyPhosphino Carboxylic Acid (PPCA), and Phosphonate-based scale inhibitor (PBSI) at various temperatures (50–95 1C) and concentrations. The results showed that a large extent of permeability damage was caused by barium sulfate that deposited on the rock pore surface. At higher temperatures, the rate of BaSO4 precipitation decreases since the solubility of BaSO4 increases with increasing temperature. At 60 1C temperature, PPCA showed very efficient BaSO4 inhibition effect where it reduced most amount of BaSO4 compared to the DETPMP and PBSI inhibitors. & 2012 Elsevier B.V. All rights reserved.

Keywords: scale deposition scale inhibition temperature pressure

1. Introduction Inorganic precipitations are one of the major flow assurance concerns in offshore oil and gas production, and lead to significant reductions in productivity and costly workovers if allowed to form uncontrolled. Numerous cases pertaining to oil well scaling by calcium carbonate, calcium sulfate, strontium sulfate, and barium sulfate have been reported (Lindlof and Stoffer, 1983; Mitchell et al., 1980; Shuler et al., 1991; Vetter et al., 1987). Problems in connection to oil well scaling have seriously plugged wells in Russia and similar cases in North Sea fields have been reported (Mitchell et al., 1980). Some oilfields around the world, such as Saudi, Algeria, South Sumatra in Indonesia, and El-Morgan in Egypt have scale problems because of water flooding where calcium and strontium sulfate scales have been found in surface and subsurface production equipment (El-Hattab, 1982). Scale prevention by the use of chemical inhibitors, applied either by continual injection or by squeeze treatment into the near wellbore formation, has generally been regarded as the most cost effective solution to the problem (Laing et al., 2003). In the post seawater-breakthrough period, however, there is a much more serious problem of precipitation of barium sulfate from an incompatibility between the formation water and seawater. BaSO4 scale removal is particularly difficult. Thus, BaSO4 scale treatment must focus mainly on its prevention through the use of

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scale-control chemicals. Thus, the severity of the scaling problem is determined both by the scaling rate and the efficiency of the chemical inhibitors (Mazzollnl et al., 1992). Scale inhibitors are chemicals which delay, reduce or prevent scale formation when added in small amounts to normally scaling water. Most common classes of inhibitor chemicals are inorganic phosphates, organophosphorous compounds and organic polymers. Poly-Phosphono Carboxylic acid (PPCA) and Diethylenetriaminepenta (methylene phosphonic acid) (DETPMP) are two common commercial scale inhibitors used to control mineral scaling in the oil and gas industry (Bezemer and Bauer, 1969). Moreover, PPCA is a polymer formed by two poly-acrylic-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 due to its incorporation in the crystal lattice. DETPMP, the phosphonate species, has a chemical structure as shown in Fig. 2. In contrast to PPCA, DETPMP is thought to retard the growth of the crystals and is less effective in preventing initial nucleation. Once nucleation has started, it is effective at stopping the further crystal growth by adsorbing at active growth sites on the scale crystal lattice (Chen et al., 2004). The action of scale inhibitors in preventing scale formation has been extensively investigated in the literature with different inhibitors. This 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 barium sulfate scale which is formed by mixing of water injection (Barton and Angsi seawaters) and formation water.

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Table 1 The ionic compositions of synthetic formation and injection waters. Ionic

Fig. 1. Chemical structure of PPCA inhibitor.

Sodium potassium Magnesium Calcium Strontium Barium Chloride Sulfate Bicarbonate

High barium formation water (ppm)

Barton seawater

Angsi seawater

(ppm)

(ppm)

42,707 1972 102 780 370 2200 67,713 5 2140

9749 340 1060 384 5.4 o 0.2 17,218 2960 136

10,804.50 375.05 1295.25 429.20 6.577 – 19,307.45 2750 158.80

Table 2 Compounds of synthetic formation and injection waters.

Fig. 2. Chemical structure of DETPMP inhibitor.

2. Materials and methods 2.1. Core material

Compound

High barium formation water (ppm)

Average between Barton and Angsi seawaters (ppm)

Sodium Chloride Potassium Sulfate Magnesium Chloride Barium Chloride

108,513 – 853 3914

26,113 5178 9843 –

scale inhibitor as the third scale inhibitor selected to be tested in this study. (1) PPCA: Poly-Phosphino Carboxylic Acid; (2) DETPMP: Diethylenetriamine Penta, (methylene phosphonic acid); (3) PBSI: Phosphonate-based Scale Inhibitor.

In all flooding experiments the porous media used in this study were: 2.4. Scaling test rig (1) Berea cores of 3 in. length and of diameter 1 in. with average porosity of 21.60% and of initial permeability varying from 65.97 to 141.13 md. (2) Sandstone cores from Sentumbung, Serawak, Malaysia with 3 in. length and of diameter 1 in. with average porosity of 14.37% and of initial permeability varied from 11.64 to 14.36 md. No oil was present in the cores. All the cores were cleaned using methanol in Soxhlet extractor and dried in a Memmert Universal Oven at 100 1C overnight before use. 2.2. Preparation of brines Synthetic formation water and water injection (Barton and Angsi seawaters) 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 formation water and seawater were filtered through a 0.45-mm filter paper before using in order to remove any particulate material. Inhibitor solutions were prepared by dissolving inhibitors in seawater. Four salts used for the preparation of synthetic formation water and seawater were computed based on the ionic compositions given in Table 2. 2.3. Types of scale inhibitors Three different types of scale inhibitors were being tested for performance comparison. Two of them (DETPMP and PPCA) were imported scale inhibitor, from China. DETPMP and PPCA were selected as scale inhibitors because both are commonly used for scale inhibition in Malaysia oilfield. PBSI is a locally produced

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. Here follows a brief description of each part. Constant pressure pumps: To inject the brines during flooding at different pressures, two Double-piston plunger pumps manufactured by Lushyong Machiney Industry Limited, with 1.5 hp motor, maximum design pressure of 35 bar and approximate flow rate of 20 L/min was used. Moreover, these pumps operate on pressure and hence the required pressure for the experiment is in the range of 75–200 psig. The required pressure is set on the pump with the help of a regulator. On 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 manufactured by TEMCO, Inc., USA, which can withstand pressures up to 10,000 psia were used to store and pump the injected brine to the core holder. Each cell with a capacity of 1000 ml has a freefloating 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 temperature controlled oven. Pressure transducer: The differential pressure across the core during flooding runs was measured by using pressure transducer (model E-913 033-B29) manufactured by Lushyong Machiney Industry Limited, with a digital display. Core holder: A Hassler type, stainless steel core holder designed for consolidated core samples, 3 in. length and 1 in.

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Digital Readout Pressure Transducer Flow Meter

S.W

Core Holder F.W

Transfer Cell

Oven Brine Collection To Nitrogen Cylinder

Plunger Pump Water

Water

Valve

Water Tank Fig. 3. Schematic of the core flooding apparatus.

diameter, was used. The holder was manufactured by TEMCO, Inc., USA, and could withstand pressures up to 10,000 psia. A rubber sleeved core holder, subjected to an external confining pressure, into which a sandstone core is placed, is used.

vacuum was drawn on the core sample for several hours to remove all air from the core. The core was saturated with formation water at room temperature. After the appearance of formation water at the outlet, flooding was continued long enough to ensure 100% saturation.

2.5. Experimental procedure In general, the purpose of the laboratory study was to investigate permeability reduction by deposition of BaSO4 scale formation in a porous medium and knowledge of efficiency of scale inhibitor in preventing common oil field scales forming. 2.5.1. Jar test The aim of this study was to determine efficiency of scale inhibitor in preventing BaSO4 oil field scales forming due to mixing of synthetic brines (formation water and seawater) at high concentration of barium at various temperatures (50–95 1C). The experimental procedures used to determine the efficiency of scale inhibitor are as follows: (1) For each experiment of BaSO4 oil field scales, the two brine solutions, 100 ml of seawater containing inhibitor and 100 ml of formation water were put in clean glass bottles. The bottles were then capped and placed inside the oven and were heated to the desired temperature for 1 h. (2) After 1 h, the bottles were removed from the oven, and seawater was added to formation water and vigorously shaken by hand for 60 s and then placed back in the oven. The mixture was left undisturbed for 4 h. After this the mixture was removed from the oven and then was immediately filtered through a 0.45-mm 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.

2.5.2. Core test 2.5.2.1. Core saturation. Before each run, the core sample was dried in a Memmert Universal Oven at 100 1C for overnight. The core sample was prepared for installation in the core-holder. A

2.5.2.2. Core flooding 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 (S.W. and F.W.) were placed inside the oven and heated to the desired temperature of the run. The system was left 3 h for temperature equilibrium to be attained. The required confining pressure was then adjusted to be approximately at double 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 (S.W. and F.W.) 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 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 seawaters with formation water. For selected runs, the core sample was removed at the end of flooding. The core samples were then cut into sections and investigated using SEM to reveal the nature of the scale formation crystals.

3. Results and discussion 3.1. High barium ions concentration formation water 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 effectiveness in comparison of their ability in preventing scale deposition. The test was carried out at the atmospheric pressure and at different temperatures ranging from 50 1C, 70 1C to 90 1C and a time period of 4 h. Inhibitor

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0.4 Blank

effect are consistent with the previously published data (Rocha et al., 2001; Rosario and Bezerra, 2001; Ying-Hsiao et al., 1995).

10 ppm-PPCA

10 ppm-PBSI 30 ppm-PPCA

0.2

30 ppm-DETPMP

0.15

30 ppm-PBSI

0.1 30

50

70

90

Temperature (°C) Fig. 4. Effect of temperature on scale deposition without/with scale inhibitor added for high barium formation water tests.

concentrations of 10 ppm and 30 ppm were made up with synthetic seawater. The solutions were left undisturbed for 4 h to let scaling to occur, the solutions were filtered and the scale that remained on the filter papers were weighted to get the comparison of the weight of scales deposited according to different test conditions. The jar tests started at a temperature of 50 1C without inhibitor been added in the injection water. This can be seen from Fig. 4 which shows when the test temperature increases, less barium sulfate scales were deposited. The scale precipitation on filter paper marked 0.367 g at 50 1C. Moreover, a reduction of 0.013 g in weight was seen from the test that was carried out at a higher temperature, 70 1C. When the temperature further increased to 90 1C, it gave the least scale deposition weight where high temperature manages to keep the barium ions from depositing with sulfate ions in the brines mixture. Based on this trend, further analysis was done on the effect of concentration of scale inhibitors towards scale inhibition at each of the test temperature. The effect of scale inhibitor concentration increment on scale deposition using high barium ions concentration formation water at different temperatures was presented in graphic form in Fig. 4. At 50 1C, PPCA worked most efficiently at 30 ppm concentration where it reduced 0.094 g in weight of scale precipitation on filter paper. PPCA again showed its ability of barium sulfate scale inhibition at 70 1C. When the PPCA concentration increased, PPCA managed to lower down the scaling tendency of barium sulfate from 0.295 g of 10 ppm test to 0.267 g of 30 ppm test. It can be deduced that 30 ppm is better concentration than 10 ppm for PPCA in inhibiting barium sulfate scale precipitation. Furthermore, quite similar performance was demonstrated by DETPMP at this temperature. DETPMP worked best at its 30 ppm concentration but the efficiency was still lower than PPCA. DETPMP made a reduction of 0.069 g in weight. Comparably, PBSI did not appear to be the best barium sulfate scale inhibitor since at its 30 ppm concentration, it could only reduce 0.056 g in weight. At all temperature, DETPMP, PPCA, and PBSI showed a similar trend. The scaling occurred most severely at 10 ppm concentrations but there was still slight reduction of scale deposited at 30 ppm as shown in Fig. 4. Hence, at these temperatures, both DETPMP and PBSI inhibitors were not suitable as the barium sulfate scale inhibitor. As mentioned earlier, PPCA is the best barium sulfate scale inhibitor. PPCA with 30 ppm concentration was able to give 0.084 g of weight reduction at 90 1C while DETPMP and PBSI gave 0.062 and 0.042 g of weight reduction respectively. Fig. 4 elucidates the effect of temperature increment on scale deposition with the existence of inhibitors in high barium ions concentration formation water. As explained earlier, when the temperature increased, the barium ions were retarded to be precipitated with sulfate ions. These results on temperature

3.2. Barium sulfate experiments core test analysis For high barium ions concentration formation water core flooding tests, seawaters with inhibitor concentration of 10, 500 and 1000 ppm respectively were used as injection water to mix with high barium formation water in core porous media at temperatures 50, 60, and 95 1C and the differential pressures were 75, 100, and 200 psig. On top of this, PPCA was solely the best barium sulfate scale inhibitor, thus DETPMP and PBSI were designed to challenge PPCA effectiveness in core flooding test. Seeing as BaSO4 scaling tendency is most drastic at temperature 50 1C than 60 and 95 1C. In addition, the rate of BaSO4 nucleation and crystal growth decreases with temperature. Consequently, performance of each scale inhibitor is evaluated at this vital condition. Figs. 5–8 disclose the relationship between permeability decline and the seawater injection time for high barium ions concentration formation water flooding tests. At 50 1C, the reference trend of the permeability decline was taken at which the test Permeability ratio (Kd/ki)

10 ppm-DETPMP

0.25

1 0.9

Blank

0.8

10 ppm- PBSI

0.7

10 ppm- DETPMP

ΔP = 75 psig Ba = 2200 ppm Berea Core

0.6

10 ppm- PPCA

0.5 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 50 1C.

1 Permeability ratio (Kd/ki)

0.3

0.9

Blank

0.8

10 ppm- PBSI 10 ppm- DETPMP

0.7

ΔP = 100 psig Ba = 2200 ppm Berea Core

0.6

10 ppm- PPCA

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 90 1C.

Permeability ratio (Kd/ki)

Weight (gm)

0.35

127

1 Blank

0.9

500 ppm- DETPMP

0.8 500 ppm- PPCA

0.7

1000 ppm- DETPMP

ΔP = 125 psig Ba = 2200 ppm Sandstone Core

0.6

1000 ppm- PPCA

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 60 1C.

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was run without scale inhibitor in sea water. Similar to the previous tests, the permeability reduced sharply in the first 30 min of seawater injection. Then, permeability reduction was slightly decelerated at the end of the run as shown in Fig. 5. This trend was reported by Graham et al. (2002), Todd and Yuan (1990, 1992), Yuan et al. (1997), Yuan (2001). At 50 1C, 10 ppm of DETPMP and 10 ppm of PBSI were detected having permeability decline more than the test with 10 ppm of PPCA inhibitor as shown in Fig. 5. Hence, at this temperature, both of DETPMP and PBSI inhibitors were not suitable as barium sulfate scale inhibitor. The permeability reductions for these two scale inhibitors were higher than PPCA inhibitor, which were 35.64% and 38.76% correspondingly in comparison to 40.63% with no inhibitor added. Moreover, 10 ppm PPCA demonstrated a trend outcome very similar to 10 ppm DETPMP and 10 ppm PBSI. At the end of the run, as it is seen from Fig. 5, the percentage of permeability reduction is only 34.07%. It can be brought to a close that PPCA is the more disassociated inhibitor since it was an

Permeability ratio (Kd/ki)

1 Blank

0.9

500 ppm- DETPMP

0.8 500 ppm- PPCA

0.7

ΔP = 200 psig Ba = 2200 ppm Sandstone Core

0.6

1000 ppm- DETPMP 1000 ppm- PPCA

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 95 1C.

excellent barium scale inhibitor compared to the others in this study. The efficiency of the scale inhibitor is followed by DETPMP and thirdly PBSI. At 95 1C, DETPMP gave good result of inhibition barium sulfate at its 500 ppm and 1000 ppm concentration in seawater, which gave 20.90% and 9.13% permeability reduction respectively in comparison to 27.07% with no inhibitor added. At the same temperature, PPCA gave best result at its 500 ppm and 1000 ppm concentration mixed in seawater as injection brine, which gave 14.94% and 5.96% permeability reduction respectively as shown in Fig. 8. Moreover, it was observed that by using 1000 ppm of PPCA in seawater, more amounts of barium ions in the formation water remained without being deposited with sulfate ions.

3.3. Scanning electron microscopy analysis The scaled core samples were examined by SEM to observe the particle size and morphology of the precipitates. The formation of BaSO4 during flow of injection and formation waters in porous media has been observed by Scanning Electron Microscopy (SEM) micrographs which show BaSO4 crystals formation in porous space. Fig. 9 shows an SEM image of an unscaled core samples. Figs. 10–13 show SEM image of the BaSO4 scaling crystals in rock pores precipitated from mixed seawater with formation water inside the cores. Comparison of BaSO4 formed in porous media did not show significant differences in crystal external morphology. The differences line in the irregularity of crystals formed in rock pores and the crystal size variations from one location to another in a core. The maximum size of BaSO4 crystals precipitated from mixed brines was about 2.05 mm.

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

BaSO4 scales

Fig. 10. SEM image of BaSO4 scale in inlet face of Berea sandstone core at 100 psig and 60 1C.

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BaSO4 scales

Fig. 11. SEM image of BaSO4 scale in outlet face of Berea sandstone core at 100 psig and 60 1C.

BaSO4 scales

Fig. 12. SEM image of BaSO4 scale in inlet face of sandstone core at 125 psig and 60 1C.

BaSO4 scales

Fig. 13. SEM image of BaSO4 scale in inlet face of sandstone core at 125 psig and 60 1C and at (a) 500 ppm of DETPMP and (b) 500 ppm of PPCA.

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 into a core. The observations of scaling sites from previous tests (Bedrikovistsky et al., 2003; Bedrikovistsky et al., 2005; Jamialahmadi and Steinhagen, 2008; Todd and Yuan, 1990, 1992) were confirmed by these test results. At the inlet face of Berea cores (Fig. 10), the crystals amount of BaSO4 is higher compared to outlet face (Fig. 11) which indicates more precipitation at the inlet face. The reason why the scaling decreased downstream of a core is clear due to most of the scaling ions that had deposited within the front sections as soon as they

were mixed and left few ions to precipitate from the flow stream in the rear sections. Fig. 13 presents the SEM images of BaSO4 precipitate at 500 ppm of DETPMP and 500 ppm of PPCA. For these images, the morphology of the crystals is very different from either of the non-inhibited solutions. From the SEM images, it can be observed that in the absence of inhibitor (Fig. 12), the BaSO4 crystals exhibited a lot of large crystals while in the presence of inhibitors, the BaSO4 crystals are less and small as shown in Fig. 13. In general, a difference in morphology between the BaSO4 precipitates was observed in the presence of inhibitor. At 500 ppm of PPCA, less precipitation of BaSO4 is observed than at 500 ppm of DETPMP as shown in Fig. 13.

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4. Conclusions The work carried out to investigate permeability reduction by deposition of scale formation in a porous medium and knowledge of efficiency of scale inhibitor in preventing BaSO4 oil field scales forming. Based on the results obtained from this study, the following conclusions can be drawn: (1) At elevated temperatures the mass of precipitation of BaSO4 scale decreases because the solubility of BaSO4 increases with increasing temperature. (2) When synthetic seawater containing sulfate ion is mixed insitu with formation water that contains a significant amount of dissolved barium ion during laboratory coreflooding, insitu precipitation of barium sulfate occurs. (3) The pattern of permeability decline in a porous medium due to scaling injection was characterized by a concave curve with a steep initial decline which gradually slowed down to a lower. 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. (4) Observations of micrographs using SEM showed the formation of BaSO4 crystals in porous space during flow of injection and formation waters. (5) At the inlet face, the crystals amount of BaSO4 is higher compared to outlet face which indicates more precipitation at the inlet face. The reason why the scaling decreased downstream of a core is clear due to most of the scaling ions that had deposited within the front sections as soon as they were mixed and left few ions to precipitate from the flow stream in the rear sections. (6) For high barium ions concentration formation water, apparently PPCA appeared to be the best BaSO4 inhibitor compare to the others in this study. The efficiency of the scale inhibitor is followed by DETPMP and thirdly PBSI.

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