An experimental and numerical study of low salinity effects on the oil recovery of carbonate rocks combining spontaneous imbibition, centrifuge method and coreflooding experiments (original) (raw)
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International Petroleum Technology Conference, 2014
This paper investigates the combined effect of injecting low salinity water (LSWI) and carbon dioxide (CO 2 ) on oil recovery from carbonate cores. The combined effect of LSWI and CO 2 injection on oil recovery was predicted by performing several synthetic 1D simulations using measured reservoir rock and fluid data. These simulations included the effect of salinity on both miscible and immiscible continuous gas injection (CGI), simultaneous water-alternating-gas (SWAG), constant wateralternating-gas (WAG), and tapered (WAG). For SWAG and constant and tapered WAG, both seawater and its dilutions were simulated, and the CO 2 was injected above the minimum miscibility pressure. Baker's three-phase relative permeability model was modified to account for the effect of salinity on the water/oil relative permeability.
Low salinity waterflood (LSF) is a promising improved oil recovery (IOR) technology. Although, it has been demonstrated that LSF is an efficient IOR method for many sandstone reservoirs, the potential of LSF in carbonate reservoirs is still not well-established as only a limited number of successful coreflood experiments are available in the literature. Therefore, the aim of this study was to examine the oil recovery improvement by LSF in carbonate reservoirs by performing coreflood experiments. This paper proposes an experimental approach to qualitatively evaluate the potential of LSF to improve oil recovery and alter the rock wettability during coreflood experiments. The corefloods were conducted on core plugs from two Middle Eastern carbonate reservoirs with a wide variation of rock properties and reservoir conditions. Seawater and several dilutions of formation brine and seawater were flooded in the tertiary mode to evaluate their impacts on oil recovery compared to formation brine injection. In addition, a geochemical study was performed using PHREEQC software to assess the potential of calcite dissolution by LSF. The experimental results confirmed that lowering the water salinity can alter the rock wettability towards more water-wet, causing improvement of oil recovery in tertiary waterflood in plugs from the two reservoirs. Furthermore, seawater is more favorable for improved oil recovery than formation brine as injection of seawater after formation brine resulted in extra oil production. This demonstrates that the brine composition plays an important role during waterflooding in carbonate reservoirs, and not only the brine salinity. It was also observed that oil recovery can be improved by injection of brines that cannot dissolve calcite based on the geochemical modeling study. This implies that calcite dissolution is not the dominant mechanism of IOR by LSF. To conclude, this paper demonstrates that low-salinity waterflood has a good potential as an IOR technology in carbonate reservoirs. In addition, the proposed experimental approach ensures the verification of LSF effect, either it is positive or negative. However, further research is required to explore the optimum salinity and composition and the most influential parameters affecting LSF response.
E3S web of conferences, 2019
Low salinity water flooding (LSF) is a relatively simple and cheap EOR technique in which the salinity of the injected water is optimized (by desalination and/or modification) to improve oil recovery over conventional waterflooding. Extensive laboratory experiments investigating the effect of LSF are available in the literature. Sulfate-rich as well as diluted brines have shown promising potential to increase oil production in limestone core samples. To quantify the low salinity effect, spontaneous imbibition and/or tertiary waterflooding experiments have been reported. For the first time in literature, this paper presents a comprehensive study of the centrifuge technique to investigate low salinity effect in carbonate samples. The study is divided into three parts. At first, a comprehensive screening was performed on the impact of different connate water and imbibition brine compositions/combinations on the spontaneous imbibition behavior. Second, the subsequent forced imbibition of the samples using the centrifuge method to investigate the impact of brine compositions on residual saturations and capillary pressure. Finally, three unsteady-state (USS) core floodings were conducted in order to examine the potential of the different brines to increase oil recovery in secondary mode (brine injection at connate water saturation) and tertiary mode (exchange of injection brine at mature recovery stage). The experiments were performed using Indiana limestone outcrops. The main conclusions of the study are spontaneous imbibition experiments only showed oil recovery in case the salinity of the imbibing water (IW) is lower than the salinity of the connate water (CW). No oil production was observed when the imbibing water had a higher salinity than the connate water or the salinity of the connate water and imbibing brine were identical. Moreover, the spontaneous imbibition experiments indicated that diluting the salinity of the imbibing water has a larger potential to spontaneously recover oil than the introduction of sulfate-rich sea water. The centrifuge experiments confirmed a connection between the overall salinity and oil recovery. As the salinity of the imbibing brines decreases, the capillary imbibition pressure curves showed an increasing water-wetting tendency and simultaneous reduction of the remaining oil saturation. The lowest remaining oil saturation was obtained for diluted sea water as CW and IW. The core flooding experiments reflected the results of the spontaneous imbibition and centrifuge experiments. Injecting brine at a rate of 0.05 cc/min, sea water and especially diluted sea water resulted in a significant higher oil recovery compared to formation brine. Moreover, when comparing secondary mode experiments, the remaining oil saturation after flooding by diluted sea water, sea water and formation water was 30.6 %, 35.5 % and 37.4 %, respectively. In tertiary injection mode, sea water did not lead to extra oil recovery while diluted sea water led to an additional oil recovery of 5.6 % in one out of two tertiary injection applications.
New Insights into the Low Salinity Water Injection Effect on Oil Recovery from Carbonate Reservoirs
International Petroleum Technology Conference, 2014
Low salinity water injection (LSWI) is gaining popularity as an improved oil recovery technique on account of being cost effective compared to other water based enhanced oil recovery methods such as chemical and steam flooding. In this paper, the wettability alteration option in our in-house simulator is used to history match and provide some insights in different seawater dilution cycles based on recently published corefloods. Two newly proposed methodologies to model dilution cycles are employed. We successfully modeled the experiments enhancing the wettability alteration model in the simulator using two different scaling factors. The study also revealed that the process is more sensitive to oil relative permeability compared to that of the water phase. A linear interpolation model for residual oil saturation (S or) was proposed.
SPE Improved Oil Recovery Conference, 2016
Several laboratory studies and some field trials have already demonstrated the potential of lowering the injected brine salinity and/or manipulating composition to improve oil recovery in carbonate reservoirs. Laboratory SCAL tests such as coreflooding and imbibition are key steps to screen low salinity waterflood (LSF) for a particular field to (i) ensure that there is LSF response in the studied rock/oil/brine system, (ii) find the optimal brine salinity, (iii) extract relative permeability curves to be used in the reservoir simulation model and quantify the benefit of LSF and (iv) examine the compatibility of injected brine with formation brine and rock to de-risk any potential scaling or formation damage caused by fines mobilization. This paper presents an extensive LSF SCAL study for a carbonate reservoir and the numerical interpretation of the tests. The SCAL experiments were performed at reservoir conditions using reservoir core plugs, dead crude oil and synthetic brines. The rock was characterized using porositypermeability measurement semi-quantitative X-ray diffraction (XRD), scanning electron microscopy (SEM), and mercury intrusion capillary pressure (MICP) techniques. The characterization work showed that the plugs can be classified into two groups (uni-modal and bi-modal) based on pore throat size distribution which correlated with porosity-permeability cross-plots. The SCAL experiments were divided in two categories. Firstly, spontaneous imbibition and qualitative unsteady-state (USS) experiments were performed to demonstrate the effect of low salinity brines. In addition, these experiments helped to screen different brines (seawater and different dilutions of seawater) in order to choose the one that showed the most promising effect. Secondly, quantitative unsteady-state (USS) experiments were conducted and interpreted using numerical simulation to extract relative permeability curves for high salinity and low salinity brines by history-matching production and pressure data. The main conclusions of the study are: 1-The spontaneous imbibition and qualitative USS experiments showed extra oil production when switching from formation brine to seawater or diluted seawater subsequently, 2-Oil recovery by LSF can be maximized by injection of brine at a certain salinity threshold, at which lowering the brines salinity further did not lead to additional recovery improvement,
Several laboratory tests have already demonstrated the potential of lowering/manipulating the injected brine salinity and composition to improve oil recovery in carbonate reservoirs. However, laboratory SCAL tests are still required to screen low salinity waterflood (LSF) for a particular field to (i) ensure that there is LSF response in the studied rock/oil/brine system, (ii) find the optimal brine salinity, (iii) extract relative permeability curves to be used in the reservoir simulation model and quantify the benefit of LSF and (iv) examine the compatibility of injected brine with formation brine and rock to de-risk any potential formation damage or scaling. This paper presents an extensive LSF SCAL study for one of the carbonate reservoirs and the numerical interpretation of the tests. The experiments were performed at reservoir conditions using representative reservoir core plugs, crude oil and synthetic brines. The rock was characterized using different measurements and techniques such as porosity, permeability, semi-quantitative X-ray diffraction (XRD), scanning electron microscopy (SEM), and mercury intrusion capillary pressure (MICP). The characterization work showed that the plugs can be classified into two groups (uni-modal and bi-modal) based on porosity/permeability correlation and pore throat size distribution. The SCAL experiments were divided in two categories. Firstly, spontaneous imbibition and qualitative unsteady-state (USS) experiments were performed to demonstrate the effect of low salinity brines. In addition, these experiments helped to screen different brines (seawater and different dilutions of seawater) in order to choose the optimal brine composition that showed the most promising effect. Secondly, quantitative unsteady-state (USS) experiments were conducted and modeled using numerical simulation to extract relative permeability curves for high salinity and low salinity brines by history-matching production and pressure data. Moreover, the pressure drop was monitored during all tests to evaluate any risk of formation damage. The main conclusions of the study: 1-The spontaneous imbibition and qualitative USS experiments showed extra oil production due to wettability alteration when switching from formation brine to seawater or diluted seawater subsequently, 2-Oil recovery by LSF can be maximized by injection of brine at a certain salinity threshold, at which lowering the brines salinity further may not lead to additional recovery improvement, 3-The LSF effect and optimal brine salinity varied in different layers of the reservoir, 4-The quantitative USS showed that LSF can improve the oil recovery factor by up to 7% at core scale compared to formation brine injection. This paper proves the potential of LSF to improve oil recovery in carbonate rock. However, the results demonstrate that the effect of LSF may vary in different layers within the same carbonate reservoir, which indicates that LSF effect is very dependent on the rock properties/mineralogy.
Application of Low-Salinity Waterflooding in Carbonate Cores: A Geochemical Modeling Study
Natural resources research, 2020
Waterflooding is the most widely applied improved oil recovery technique. Recently, there has been growing interest in the chemistry and ionic composition of the injected water. Lowsalinity waterflooding (LSWF) is a relatively recent enhanced oil recovery technique that has the ability to alter the crude oil/brine/rock interactions and improve oil recovery in both clastics and carbonates. In this paper, the increase in the recovery factor during LSWF was modeled based on the exchange of divalent cations (Ca 2+ and Mg 2+) between the aqueous phase and the carbonate rock surface. Numerical simulations were performed using laboratory coreflood data, and oil recovery and pressure drop from experimental works were successfully history matched. The ion exchange equivalent fractions, effluent ions concentrations, changes in mineral moles, and pH have also been examined. Besides, an investigation of multi-component ionic exchange as a mechanism responsible for wettability alteration during LSWF in heterogeneous low-permeability carbonate cores is presented. The results show that wettability alteration is responsible for the increase in oil recovery during LSWF, as reflected by the shift in the crossover points of the relative permeability curves. A sensitivity study done on many key parameters (e.g., timing of LSWF injection, injection rate and temperature) and the mechanistic modeling method revealed that they all have huge effects on the process.
Wettability Alteration during Low-Salinity Waterflooding in Carbonate Reservoir Cores
All Days, 2014
Production enhancement by low-salinity waterflood in carbonate formations is a subject of intense speculation. Several mechanisms are attributed to enhanced oil recovery by low-salinity waterflooding in carbonate formations. Review of experimental data in the literature indicates that the main mechanism involves interaction of Na+, Cl−, Ca2+, Mg2+, SO42− and crude oil carboxylate ions (R-COO−) with the rock in the electrical double layer (EDL) near the surface of carbonate pores, leading to wettability alteration.In this study, we performed four seawater floods in heterogeneous low-permeability carbonate cores followed by low-salinity floods. The core permeability is between 0.5 to 1.5 md, and porosity in the range of 18 to 25%. Cores were aged for eight weeks at reservoir pressure and temperature. We also conducted pendant drop oil-brine IFT measurement, and captive oil-droplet contact angle at different brine salinity, with and without the presence of surfactant.The carbonate core...
Effect of salinity degree of injected water on oil recovery from carbonate reservoir
Indian Journal of Geo-Marine Sciences, 2019
Water injection is considered the most successful and widespread secondary recovery method. Low salinity water injections is a well-established and proved technique for water flooding application in sandstone rocks to enhance the recovery efficiency; where the water salinity is adapted to a certain degree to extract the highest amount of oil from a reservoir. Reserve-estimation statistics show the significance of oil reserves in carbonate reservoirs, hence this work deals with the carbonate rocks where water flooding may fail due to many reasons, and the most common one is fractures existence in the carbonate rocks. This work applied the water injection for six carbonate (limestone) core samples from Belayim Formation of Middle Miocene age that extracted from an Egyptian offshore oil field in the Gulf of Suez. This carbonate facies is hard, vuggy, fragmented, dolomitic, and highly saturated with oil and considered a good reservoir. Relative permeability test was carried out to inves...