Low-salinity waterflooding has been recognized as a method of enhancing oil recovery in low-permeability reservoirs. This method is relatively inexpensive and can be easily implemented in the field. Various mechanisms of low-salinity flooding have been proposed including interfacial tension reduction, wettability alteration (cation exchange), change in pH (increase), emulsion formation, and clay migration. Hydraulic fracturing has been known as a technique of stimulating hydrocarbon flow from low-permeability matrix into wellbores by creating high-conductivity fractures. The objective of this study is to evaluate the effectiveness of sequential low-salinity brine flooding process to enhance oil recovery in low-permeability fractured and non-fractured chalky limestone core samples. The low-salinity waterflooding tests were conducted with synthetic brines of five different salinity concentrations, namely, 157,662, 72,927, 62,522, 6252, and 1250 ppm. The properties of these brines have been thoroughly investigated in the laboratory. The crude oil and chalky limestone core samples, permeability range between 0.01 and 1.2 millidarcy, were gathered from a selected oil field in United Arab Emirates. When used as an opening − 2 move in a three-stage sequential brine flooding (SW/10→ SW/50→SW 6xSO4 ), sea water diluted ten times at 6252 ppm (SW/10) has been found to yield the highest oil recovery in fractured and non-fractured tests at the prevailing reservoir conditions, of 82.64 and 76% of OOIP, respectively. In all sequential brine flooding scenarios tested, sea water with sulfate − 2 concentration spiked six times (SW 6 × SO ) only slightly increased oil recovery. The highest observed incremental recov- ery with sulfate spiking was 2.083% of OOIP. The effectiveness of oil displacement by sequential brine flooding has been attributed to mineral dissolution and fines migration which resulted in a favorable wettability alteration. This postulation of flow mechanism is confirmed by introducing a “flow resistance index” concept and measurements of key properties of the injected and effluent brines of each stage of the attempted sequential brine flooding scenarios. Results of this study could be consulted when selecting most efficient EOR method to develop tight carbonate oil reservoirs in the UAE and worldwide. Keywords Enhanced oil recovery · Low-permeability · Carbonate reservoir · Low-salinity waterflooding · Hydraulic fracturing Background that oil will be a major player for the energy market for the next 30 years at least. Carbonate reservoirs contribute more The world energy demand is not static and it is forecasted than 60% of the world’s petroleum production. Carbonate to increase rapidly. Although the world is rapidly moving reservoirs (limestone or dolomite) are heterogeneous and in the direction of using a mix of energy, it is expected that require major skills to understand and develop a detailed 53% of the world’s energy needs will be met by oil and reservoir description. Low-permeability carbonate reservoirs gas in 2040 (Ban et.al. 2016). Therefore, we can safely say have been considered uneconomical to develop because of their low flow rates and longer pay out times. Oil in low- permeability oil reservoirs is classified as unconventional * Hazim H. Al-Attar reserves. Unconventional reserve is defined by the oil indus- email@example.com try as ‘hard to recover’ oil. The definition ‘hard to recover’ 1 reserve includes reservoirs having low-permeability and/or Chemical and Petroleum Engineering Department, UAE porosity. The oil recovery by waterflooding technology is not University, P.O. Box 15551, Al Ain, UAE Vol.:(0123456789) 1 3 272 Journal of Petroleum Exploration and Production Technology (2019) 9:271–280 known as an effective method in low-permeability carbonate keeping in mind that the process in carbonate reservoirs oil reservoirs. To maximize the wellbore–reservoir contact is quite different from that in sandstone reservoirs. Zekri area in these low-permeability reservoirs, a number of oil et al. (2011) reported that wettability alteration is the companies completed horizontal wells with multiple hydrau- dominant mechanism in both sandstone and carbonate lic fracturing stages. In spite of above-mentioned techno- rocks. Alameri et al. (2015) reported that the low-salinity logical advances, low-permeability oil reservoirs exhibit waterflood in low-permeability carbonate rocks yielded a huge variety of geological characteristics that makes the incremental oil recovery of up to 9%. Alameri is the only application of a single technique (completion/development) author to our knowledge investigated the possibility of unrealistic and might lead to unfavorable economical and/ using low-salinity in low-permeability rocks. Compre- or technical conditions. Therefore, an innovative explora- hensive review on the mechanism of low-salinity flooding tion/exploitation strategy is required for optimal hydrocar- was conducted by Sheng (2014). He reported based on the bon recovery from low-permeability oil reservoirs. Conse- literature review that several mechanism responsible for quently, research has been directed to develop new methods the success of low-salinity flooding. Although there are no to improve oil recovery from this type of reservoirs. clear consensus on the process mechanism, the majority In this work, we have investigated the possibility of using attributed the improvement of oil recovery to wettability low-salinity, sequential low-salinity waterflooding, fractur - alteration. Other mechanism includes interfacial tension ing, and combination of sequential low-salinity flooding reduction, rock dissolution, ionic exchange, and oil emul- with hydraulic fracturing to improve oil recovery from low- sion also reported as possible mechanism. In most of the permeability carbonate reservoirs. The objective is to deter- cases, it seems no single mechanism is responsible for the mine the optimum technique for a selected low-permeability improvement of oil recovery by low-salinity flooding, but carbonate oil reservoir. rather a combination of previously mentioned mechanism A substantial amount of research work has been con- acting at different degrees. ducted on the possibility of using low-salinity water- flooding in recovering oil from conventional sandstone and carbonate oil reservoirs Al-Quraishi et al. (2015). Al- Harrasi et al. (2012) investigated the performance of low- Experimental procedures and materials salinity using carbonate rocks and reported a significant oil recovery up to 16% of original oil in place. Al-Attar The experimental setup used in this work is designed to et. al. (2013) investigated the effect of divalent ion con- perform coreflooding tests by sequential brine injection centration of the performance of low-salinity waterflood- with and without simulated induced single fracture. A flow ing and they concluded that sulfate concentration plays a chart demonstrating the sequence of the laboratory tests major role on flood performance. Bagci et al. (2001) used performed in this study is shown in Fig. 1. All flooding dilutions of formation brine as injection system and they scenarios were conducted at simulated reservoir tempera- reported a success story in limestone rocks. Austad et al. ture and pressure. All materials including crude oil, core (2010) indicated that fine migration is a major player in samples, and composition of injected water were provided performance of low-salinity in carbonate oil reservoirs. by Abu Dhabi Company for Onshore Petroleum Opera- Yi and Sarma (2012) reported that multi-ionic exchange tions Ltd. (ADCO). concept is the mechanism in both sandstone and carbonate Fig. 1 Flowchart illustrating the sequence of laboratory tests 1 3 Journal of Petroleum Exploration and Production Technology (2019) 9:271–280 273 Crude oil Sweet crude oil sample with API gravity of 39.48 degrees is collected from Asab Field. This field is one of the five major fields operated by ADCO. The viscosity of this crude oil is 2.927 cp under ambient conditions and 1.8953 cp under 255F and 3100 psia. Brines Five brines were used in this study including formation water of Asab Field (FW), seawater (SW), seawater diluted 10 times (SW/10), seawater diluted 50 times (SW/50), and seawater with sulfate concentration spiked 6 times (SW − 2 6 × SO ). The compositions of these five brines are listed in Table 1 and their densities and viscosities at ambient con- ditions are presented in Table 2. Core samples Nine chalky limestone (CaCO ) core samples from Zakum Oil Field were used in this work. The results of their routine core analysis are presented in Table 3. Simulating hydraulically induced fractures The induced fracture was synthetically created by cutting the core sample into equal halves along the entire length of the core and as illustrated in Fig. 2. Aluminum foil was then placed between the core two halves to keep the simulated fracture face open and the outer surface area of the core was wrapped up with aluminum foil to keep the core intact. Four core samples were prepared this way, namely ZK-454-6F, ZK-454-11F, ZK-454-20F, and ZK-454-27F. The results of liquid permeability measurements of these core samples before and after fracture simulation are presented in Table 4. Oilflooding and aging process All core plugs were fully saturated with formation water and then flooded with oil to S then aged for 5 weeks. The wi results of this part of the experimental work are listed in Table 5. Sequential waterflooding tests These tests represent the major part of this study. It was intended to assess selected brines as potential fluids to enhance oil recovery under simulated reservoir conditions. Flooding tests were conducted sequentially starting with high salinity brines followed by lower salinities and sulfate 1 3 Table 1 Compositions of the five brines Ion FW SW SW/10 SW/50 SW 6 × SO TDS (mg/I) Salinity (ppm) TDS (mg/I) Salinity (ppm) TDS (mg/I) Salinity (ppm) TDS (mg/I) Salinity (ppm) TDS (mg/I) Salinity (ppm) Sodium 44,261 44,312 19,054 19,076 1905 1908 381 382 24,137 24,165 Calcium 13,840 13,856 690 691 69 69 14 14 690 691 Magnesium 1604 1606 2132 2134 213 213 43 43 2132 2134 Potassium 0 0 672 673 67 67 13 13 672 673 Chloride 96,560 96,670 35,836 35,877 3584 3588 717 718 35,836 35,877 Bicarbonate 332 332 123 123 12 12 2 2 123 123 Sulfate 885 886 3944 3949 394 395 79 79 9254 9265 Total 157,482 157,662 62,451 62,523 6245 6252 1249 1250 72,844 72,928 274 Journal of Petroleum Exploration and Production Technology (2019) 9:271–280 Table 2 Density and viscosity of the five brines Table 4 Liquid permeability before and after fracturing No. Brine Density (g/m1) Viscosity (cP) Core no Permeability liquid(mD) Folds of perme- ability increase Initial Fractured 1 FW 1.103 1.35 2 SW 1.034 1.19 ZK-454-6F 0.32 2.23 7.0 3 SW/10 1 1.07 ZK-454-11F 0.02 6.97 348.3 4 SW/50 1 1.03 ZK-454-20F 0.02 3.02 150.8 5 2− SW 6 × SO 1.05 1.26 ZK-454-27F 1.7 3.88 2.3 spiked using the coreflooding system setup as shown in Results and discussion Fig. 3. The sequential brine flooding scenarios of the nine core samples used in this work are presented in Table 6. During each stage of the attempted sequential waterflood- All the tests were conducted under similar reservoir con- ing scenarios, the volumes of the produced and injected ditions, an overburden pressure of 2500 psia (applied using fluids as well as the pressure drop across the core were the hydraulic pump) and temperature of 90 °C (core holder is carefully and continuously measured as a function of time. equipped with a heating jacket). The injection rate of brines Due to space limitation, the results of one sequential brine was kept constant at 1 cc/min throughout each sequential flooding scenario of the non-fractured core ZK-454-3 are flooding scenario. A back pressure regulator was installed to presented in Table 7 and Fig. 4. A complete set of all the control the outlet pressure at 100 psi to regulate the flow and results of this work can be found in Benny (2017). avoid extra pressure build-up after heating the system. Dur- In addition to the above and for the same core sam- ing each sequential flooding scenario, the salinity, resistivity, ple, the end-point effective permeability to brine of each pH, and conductivity of the effluent water were measured. flooding stage within the above sequential flood scenario Salinity in ppm and resistivity in ohm.meter were measured (k ) was calculated using Darcy’s equation at residual weff using a digital resistivity meter. Conductivity (mS/cm) and oil residual (S ). The viscosity of various brines at 90 °C or pH values were measured using a digital conductivity meter was estimated using an empirical correlation developed and digital pH meter, respectively. Table 3 Results of routine core analysis of the nine samples Sample id Dry wt Length Diameter Pore vol. Bulk vol. Grain vol. Grain den. Porosity Permeability (gm) (cm) (cm) air (cc) (cc) air (cc) (gm/cc) air (%) Air (md) Liquid (md) ZK-454-2 171.93 6.818 3.801 13.45 77.4 63.94 2.69 17.4 0.15 0.09 ZK-454-3 174.4 6.932 3.803 13.7 78.77 65.07 2.68 17.4 0.25 0.16 ZK-454-4 175.95 7.103 3.794 14.48 80.33 65.85 2.67 18 0.24 0.15 ZK-454-5 169.77 6.998 3.801 15.8 79.44 63.64 2.67 19.9 1.06 0.73 ZK-454-6 135.81 5.418 3.812 10.86 61.86 51 2.66 17.5 0.49 0.32 ZK-454-11 124.35 5.305 3.793 13.95 59.97 46.02 2.7 23.3 0.02 0.01 ZK-454-13 141.22 6.234 3.801 18.43 70.77 52.33 2.7 26 0.98 0.66 ZK-454-20 125.13 5.279 3.806 13.66 60.08 46.43 2.7 22.7 0.05 0.03 ZK-454-27 131.59 5.684 3.8 15.7 64.49 48.79 2.7 24.3 1.7 1.2 Fig. 2 Simulating a single induced fracture 1 3 Journal of Petroleum Exploration and Production Technology (2019) 9:271–280 275 Table 5 Results of flooding core samples to S wi No. Core ID Length (cm) Diameter (cm) Pore Vol by Porosity by Permeability by Produced Swi Soi water (cc) water (%) water (md) Water (cc) 1 ZK-454-2 6.818 3.801 11.818 15.276 0.09 9.5 0.196 0.804 2 ZK-454-3 6.932 3.803 11.628 14.767 0.16 9.1 0.217 0.783 3 ZK-454-4 7.103 3.794 12.244 15.247 0.15 10 0.183 0.817 4 ZK-454-5 6.998 3.801 13.622 17.154 0.73 11.3 0.170 0.830 5 ZK-454-13 6.234 3.801 15.688 22.178 0.66 11.5 0.267 0.733 6 ZK-454-6F 5.418 3.862 9.075 14.299 2.23 7 0.229 0.771 7 ZK-454-11F 4.619 3.843 9.888 18.455 6.97 7.2 0.272 0.728 8 ZK-454-20F 4.703 3.856 9.045 16.469 3.02 7.4 0.182 0.818 9 ZK-454-27F 5.684 3.850 12.416 18.764 3.88 10 0.195 0.805 Fig. 3 Schematic of coreflood- ing experimental set up; v1, v2, and v3 are isolation valves Table 6 Sequential No. Sample id Order of brines injected waterflooding scenarios 1st 2nd 3rd 4th 5th 2− 1 Z K-454-2 SW SW/10 SW/50 SW 6 × SO 2 Z K-454-3 FW SW SW/10 SW/50 SW 6 × SO 3 Z K-454-4 SW/10 SW/50 SW 6 × SO 4 Z K-454-5 SW/50 SW 6 × SO 5 Z K-454-13 SW 6 × SO SW/50 6 Z K-454-6F FW SW SW/10 SW/50 SW 6 × SO 2− 7 Z K-454-11F SW/10 SW/50 SW 6 × SO 8 Z K-454-20F SW SW/10 SW/50 SW 6 × SO 2− 9 Z K-454-27F SW 6 × SO SW/50 1 3 276 Journal of Petroleum Exploration and Production Technology (2019) 9:271–280 Table 7 Results of sequential No. Injected Brines Voil pro- Vwater Incremental RF (%) Incremental PV injected flooding scenario of a non- duced (cc) Injected RF (%) PV injected fractured core sample ZK-454-3 (cc) 1 FW 0 0 0.000 0.000 0.000 0.000 3.9 6.1 42.857 42.857 0.860 0.860 0.8 9.2 8.791 51.648 0.860 1.720 0.4 9.6 4.396 56.044 0.860 2.580 0.2 9.8 2.198 58.242 0.860 3.440 0.1 9.9 1.099 59.341 0.860 4.300 0 9.4 0.000 59.341 0.808 5.108 2 SW 0.6 17.3 6.593 65.934 1.542 6.651 0 34.7 0.000 65.934 2.981 9.632 3 SW/10 0.3 17.4 3.297 69.231 1.525 11.157 0 34.9 0.000 69.231 2.999 14.156 4 SW/50 0.2 17.4 2.198 71.429 1.511 15.667 0 34.7 0.000 71.429 2.987 18.654 2− 5 SW 6 × SO 0.1 17.5 1.099 72.527 1.509 20.163 0 34.9 0.000 72.527 3.001 23.164 by El-dessouky (2002). The results of end-point effective permeability calculations are shown in Fig. 5. Sequential low‑salinity waterflooding of non‑fractured cores A summary of the results of sequential coreflooding sce- narios of non-fractured core samples is shown in Table 8. By comparing the results of cores ZK-454-2 and ZK-454- 3, it can be sated that less volume of injected brines is required to recover approximately the same amount of oil without the injection of FW. All sequential flooding sce- Fig. 4 Oil recovery as per cent of OOIP and pressure drop across ver- narios were conducted at a constant injection rate of 1 cc/ sus PV injected for core sample ZK-454-3 min. The pressure drop at S was recorded for each stage or of every sequential scenario as presented in Table 8. A general trend of declining pressure drop can be observed with decreasing brine salinity. Such a trend is indicative Fig. 5 End-point effective permeability to brines of the sequential flood scenario of the non-fractured core sample ZK-454-3 1 3 Journal of Petroleum Exploration and Production Technology (2019) 9:271–280 277 Table 8 Summary of results of sequential flooding scenarios of non-fractured core samples No. Core ID Injected Brines Voil Vwater Incremen- RF Incremental PV injected AP at S (psi) Kw at Sor or eff Produced Injected tal RF PV injected estimated (mil- (cc) (cc) (%) lidarcy) 1 ZK-454-2 SW 6.1 59.1 64.211 64.211 5.001 5.001 1250 0.044 SW/10 0.3 52.6 3.158 67.368 4.451 9.452 1136 0.041 SW/50 0.25 52.35 2.632 70.000 4.430 13.881 1115 0.041 2− SW 6 × SO 0.15 52.55 1.579 71.579 4.447 18.328 1120 0.050 2 ZK-454-3 FW 5.4 59.4 59.341 59.341 5.108 5.108 1200 0.060 SW 0.6 52.6 6.593 65.934 4.524 9.632 930 0.060 5W/10 0.3 52.6 3.297 69.231 4.524 14.156 851 0.056 SW/50 0.2 52.3 2.198 71.429 4.498 18.654 818 0.057 2− SW 6 × SO 0.1 52.45 1.099 72.527 4.511 23.164 811 0.070 3 ZK-454-4 5W/10 7.2 64 72.000 72.000 5.227 5.227 1105 0.045 SW/50 0.3 52.5 3.000 75.000 4.288 9.515 811 0.059 2− SW 6 × SO 0.1 52.5 1.000 76.000 4.288 13.803 788 0.074 4 ZK-454-5 SW/50 8.1 63.1 71.681 71.681 4.632 4.632 381 0.123 2− SW 6 × SO 0.2 52.7 1.770 73.451 3.869 8.501 320 0.180 2− 5 ZK-454-13 SW 6 × SO 7.4 63 64.348 64.348 4.016 4.016 513 0.100 SW/50 0.45 52.6 3.913 68.261 3.353 7.369 415 0.101 Figure 6 presents a proposed flow resistance index as a function of pore volumes of injected brine. During any scenario of sequential brine flooding, the flow resistance index is defined as the ratio of pressure drop across the core sample to the maximum pressure drop across the core. These results show that sequential scenario number 3 is one of three sequential flooding scenarios which exhibited a sig- nificant reduction of the flow resistance index. This observa- tion confirms our previous postulation regarding alteration of wettability as being the dominant mechanism that con- tributes to improved oil recovery. Sequential low‑salinity waterflooding in fractured cores Fig. 6 Flow resistance index versus pore volume injected of five sequential scenarios of brines flooding in non-fractured systems Many operators believe that development of tight oil reser- voirs can only be achieved by hydraulic fracturing. In this of improved oil displacement by low-salinity brines. The section, the performance of sequential brine flooding in core samples with synthetic fractures is evaluated and compared improved effectiveness of low-salinity brines in displac- ing oil may be attributed to mineral dissolution and thus with that of the non-fractured systems. A Summary of the results of sequential coreflooding by various brines in four improved alteration of wettability to the more favorable water-wet status. fractured cores under simulated reservoir conditions of pres- sure and temperature are presented in Table 9. By compar- Also shown in Table 8 is that the highest recovery factor was achieved in sequential number 3. Results of end-point ing the results presented in Tables 8 and 9 and the results shown in Fig. 6, and for similar sequential scenarios of brine effective permeability at S at the end of each stage of a or certain sequential flooding scenario indicate a shift of K flooding, it is clear that there is a significant increase of oil weff recovery in fractured cores. For example, a 5% additional to higher values. This shift supports the wettability altera- tion as being the dominant mechanism which is responsible oil recovery could be obtained when using the SW/10 brine − 2 in fractured system over the non-fractured system. The opti- for the improved oil recovery. Spiking of SW with SO improved the oil recovery by 3%. mum sequential scenario of brine flooding in fractured cores 1 3 278 Journal of Petroleum Exploration and Production Technology (2019) 9:271–280 Table 9 Summary of results of sequential brine flooding scenarios in synthetically fractured cores No. Core ID Injected Brines Voil Vwater Incre- RF (%) Incremental PV injected AP at Sor (psi) Kw at Sor eff produced injected mental PV injected estimated (mil- (cc) (cc) RF (%) lidarcy) 1 ZK-454-6F FW 4.6 60.9 65.714 65.714 6.711 6.711 413 0.135 SW 0.45 51.85 6.429 72.143 5.713 12.424 320 0.135 SW/10 0.25 52.25 3.571 75.714 5.757 18.181 280 0.133 SW/50 0.15 51.35 2.143 77.857 5.658 23.840 260 0.139 2− SW 6 × SO 0.1 52.1 1.429 79.286 5.741 29.580 285 0.155 2 ZK-454-11F SW/10 5.55 60.75 77.083 77.083 6.144 6.144 289 0.111 SW/50 0.25 51.75 3.472 80.556 5.234 11.378 197 0.158 2− SW 6 × SO 0.15 52.05 2.083 82.639 5.264 16.642 219 0.174 3 ZK-454-20F SW 5.3 58.6 71.622 71.622 6.479 6.479 313 0.120 SW/10 0.3 52.6 4.054 75.676 5.815 12.294 308 0.105 SW/50 0.1 52 1.351 77.027 5.749 18.043 296 0.106 2− SW 6 × SO 0.1 51.1 1.351 78.378 5.650 23.693 293 0.131 2− 4 ZK-454-27F SW 6 × SO 6.75 56.85 67.500 67.500 4.579 4.579 299 0.156 SW/50 0.4 52.7 4.000 71.500 4.244 8.823 228 0.167 brine in the secondary recovery mode in fractured cores is found to yield the highest oil recovery of 82.64% of the original OOIP. Monitoring brines’ properties Brine water properties including salinity, resistivity, con- ductivity, pH, and TDS before and after each stage of each sequential brine flooding scenario were measured. The results of such measurements of one scenario of sequential brine flooding are presented in Table 10. Total TDS of the effluent water was calculated using a reliable TDS converter software developed by Chemia-soft which Fig. 7 Flow resistance index versus pore volumes of injected brines in fractured systems converts brine conductivity to TDS. These results show that the maximum mineral dissolution is observed during SW/10 brine flooding stage as the TDS was increased by is number 2 for core ZK-454-11F (SW/10→SW/50→SW 295%. This observation also confirms our previously men- − 2 tioned postulation of mineral dissolution which could have 6 × SO ) which resulted in oil recovery of 82.639% of the OOIP. Fractured and non-fractured systems, however, share changed rock surface properties to the favorable wettabil- ity characteristics. These findings are in line with those similar optimum brine flooding of SW/10. As depicted in Fig. 7, a plot of the flow resistance index obtained by Zahid et.al. (2012). As indicated in Table 10, when the salinity of the efflu- versus pore volumes of injected brine exhibits similar trends as for the non-fractured systems. Similar trends of end-point ent water increases, the resistivity will decrease and so will the conductivity. Measurements of the pH values, in fact, effective permeabilities are also observed for both systems. Therefore, similar conclusions may be drawn regarding show that there is a correlation between the above proper- ties. No significant change in the pH value was observed the mechanism responsible for improved oil recovery, i.e., mineral dissolution that leads to a more favorable wetting during the SW/10 stage. Other stages of sequential flood- ing such as flooding with SW/50 displayed an increase in characteristics. The results of all scenarios of sequential brine flood - pH value. Consequently, no clear conclusion regarding the recovery mechanism can be drawn based on these results. ing tests in fractured and non-fractured core samples are illustrated in Fig. 8. It can be stated that using the SW/10 1 3 Journal of Petroleum Exploration and Production Technology (2019) 9:271–280 279 Fig. 8 Results of sequential brine flooding tests of all scenarios Table 10 Results of Injected Water Salinity (ppm) Resistivity Conductivity pH TDS (mg/L) measurements of supportive (ohm*meter) (mS/cm) brine water properties of one scenario of sequential brine Before After Before After Before After Before After Before After flooding FW 157,662 117,314 0.068 0.071 197.2 189.5 7.12 6.98 157,482 123,322 SW 62,522 69,259 0.136 0.104 89.9 125.3 7.22 6.89 62,451 83,779 SW/10 6252 20,584 1 0.291 11.63 40 7.17 7.18 6245 24,673 SW/50 1250 4496 3.53 1.21 3.13 9.47 7 7.33 1249 5446 2− SW 6 × SO 72,927 56,565 0.133 0.174 90 71 7.35 7.23 72,844 59,194 3. It is postulated that mineral dissolution and favorable Conclusions shift of end-point effective permeability could lead to a more favorable wettability condition. This mechanism of Based on the results of this work the following conclusions oil displacement by sequential brine flooding has been can be drawn: confirmed by monitoring “flow resistance index” pro- posed in this work and measuring key properties of brine 1. Sequential flooding scenarios which begin with the water before and after sequential flooding. injection of sea water diluted ten times (SW/10) have been found to yield highest oil recoveries. In non-frac- tured core samples, the highest oil recovery was 76% Acknowledgements Financial support and samples of this work are of OOIP and was achieved with the sequential flooding gratefully acknowledged from the Abu Dhabi Company for Onshore scenario which begins with SW/10 followed by SW/50 Petroleum Operations Ltd. (ADCO), Contract No. 21R011-The Petro- − 2 followed by SW 6 × SO (Table 8). In fractured core leum Institute. Also authors would like to thank UAE U research sector for their support. samples, the highest reported oil recovery was 82.64% of OOIP and was achieved with the sequential flooding Open Access This article is distributed under the terms of the Crea- scenario which begins with SW/10 followed by SW/50 tive Commons Attribution 4.0 International License (http://creat iveco − 2 followed by SW 6 × SO (Table 9). mmons.or g/licenses/b y/4.0/), which permits unrestricted use, distribu- 2. Adding divalent sulfate ion to low-salinity water would tion, and reproduction in any medium, provided you give appropriate credit to the original author(s) and the source, provide a link to the increase the overall cost of the oil recovery process and Creative Commons license, and indicate if changes were made. may not necessarily improve the ee ff ctiveness of oil dis - placement by the low-salinity water. 1 3 280 Journal of Petroleum Exploration and Production Technology (2019) 9:271–280 Benny A, Harahap (2017) Laboratory investigation of oil recovery effi- References ciency achieved by low-salinity waterflooding in low-permeability fractured and non-fractured chalky limestone cores, M.Sc. Thesis Alameri W, Teklu TW, Graves RM, Kazemi H, AlSumaiti AM (2015) submitted to the College Of Engineering, Chemical & Petroleum Experimental and numerical modeling of low-salinity waterflood Engineering Department, UAE University, Dec 2017 in a low-permeability carbonate reservoir. Paper SPE-174001-MS. El-Dessouky HT, Ettouney HM (2002) Fundamentals of sea water SPE Western regional Meeting, California desalination. Elsevier, Amsterdam Al-Attar HH, Mahmoud MY, Zekri AY, AImehaideb R, Ghannam M Sheng JJ (2014) Critical review of low-salinity water flooding. J Pet Sci (2013) Low-salinity flooding in a selected carbonate reservoir: Eng 120:216–224. https ://doi.org/10.1016/j.petro l.2014.05.026 experimental approach. J Pet Explor Prod Technol 3(2):139–149. Yi Z, Sarma HK (2012) Improving waterflood recovery efficiency https ://doi.org/10.1007/s1320 2-013-0052-3 in carbonate reservoirs through salinity variations and ionic Al-Harrasi A, Al-maamari RS, Masalmeh SK (2012) Laboratory inves- exchanges: a promising low-cost ‘Smart-Waterflood’ approach. tigation of low-salinity waterflooding for carbonate reservoirs. Soc In: Proceedings of the Abu Dhabi International Petroleum Confer- Pet Eng. https ://doi.org/10.2118/16146 8-MS ence and Exhibition, SPE-161631-MS, Abu Dhabi, UAE Al-Quraishi AA, Al Hussinan SN, Al Yami HQ (2015). Efficiency and Zahid A, Shapiro AA, Skauge A (2012) Experimental studies of low- recovery mechanisms of low-salinity waterflooding in sandstone salinity waterflooding carbonate: a new promising approach. In: and carbonate reservoir. In: Proceedings of the Offshore Mediter - Proceedings of the SPE EOR Conference at Oil and Gas West ranean Conference and Exhibition, OMC-2015- 223, Ravenna, Asia, SPE-155625-MS, Muscat, Oman Italy Zekri AY, Nasr MS, Al-Arabai ZI (2011) Effect of losal on wettability Austad T, RezaeiDoust A, Puntervold T (2010) Chemical mechanism and oil recovery of carbonate and sandstone format ion. Int Pet of low-salinity water flooding in sandstone reservoirs. Paper Technol Conf. https ://doi.org/10.2523/IPTC-14131 -MS SPE129767 presented at the SPE Improved Oil Recovery Sym- posium.Tulsa, OK, 24–28 Apr 2010 Publisher’s Note Springer Nature remains neutral with regard to Bagci S, Kok MV, Turksoy U (2001) Effect of brine composition on jurisdictional claims in published maps and institutional affiliations oil recovery by waterflooding. Pet Sci Technol. 19(3–4):359–372. https ://doi.org/10.1081/LFT-10000 0769 Ban J, Arellano JL, Alawami A, Aguilera RF, Tallett M (2016) World Oil Outlook. Organization of the Petroleum Exporting Countries 1 3
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Published: May 31, 2018
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