Modeling the Combined Effect of Injecting Low Salinity Water and Carbon Dioxide on Oil Recovery from Carbonate Cores (original) (raw)
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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.
Journal of Petroleum Science and Engineering, 2020
Low-salinity waterflooding (LSF) is a relatively simple and cheap Enhanced Oil Recovery technique in which the salinity of the injected water is optimized to improve oil recovery over conventional waterflooding. 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 waterflooding experiments have been reported. This paper combines spontaneous imbibition, centrifuge and unsteady state (USS) coreflooding experiments to investigate low-salinity effects in carbonate samples. The experimental study used three brine compositions to investigate low-salinity effects. A high-saline Formation-water (salinity of 183.4 g/l), Seawater (43.8 g/l) and 100-times Diluted-seawater (0.4 g/l). Initially, a sequence of spontaneous imbibition experiments was conducted to screen the impact of connate and imbibing water composition on spontaneous oil recovery. After completing the spontaneous imbibition tests, the samples were drained inside a centrifuge to determine the impact of brine composition on residual saturation and capillary pressure. Moreover, three USS corefloodings were conducted to test the different brine compositions in secondary and tertiary injection mode. The spontaneous imbibition, centrifuge method and coreflooding tests showed a consistent trend. Compared to Formation-water and Seawater , Diluted-sea water demonstrated the most promising potential to recover oil efficiently. The numerical part of the study includes the transparent development of a numerical centrifuge and coreflooding model on the top of the open-source simulator DuMu x. The mathematical model formulation demonstrates that a simple numerical approach is sufficient to history match the centrifuge and coreflooding experiments. In line with the experimental data, the numerically derived capillary pressure and relative permeability showed an increasing water-wetting behavior as the salinity of the imbibing/injection water decreased. All implemented numerical models were validated against the commercially established Cydar software.
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.
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.
Journal of Geophysics and Engineering
Connate water saturation and its composition, as well as the salinity of injected water, have significant impact on the performance of low salinity water injection (LSWI). Due to the lack of experimental data and difficulties in performing experiments on carbonate rocks, the mechanisms and impact of pertinent parameters involved in the low salinity water flooding in carbonate oil reservoirs is not well understood. In this study, several core flood experiments were conducted on tight carbonate rocks under highly controlled conditions, and using seawater at various dilution ratios as the injected and connate water. The cores were initially established with different connate waters, in terms of saturation and salinity, and the injection scenarios were carried out under secondary and tertiary stages at various salinities. Oil recovery as well as composition and pH of effluent brine were measured to investigate the impact of connate water and salinity on LSWI. The results depicted that oil recovery in the secondary injection stage is maximum for the highest connate water saturation and lowest connate water salinity. Hence, both the salinity of the injected brine and the salinity and saturation of connate brine play a significant role in the performance of LSWI in carbonate rocks. In the tertiary scenario, the highest oil recovery was obtained while both the saturation and salinity of the connate water were minimal. A new mechanism regarding ion exchange and wettability alteration processes was proposed based on ion tracking analysis.
2017
The effect of injection brine salinity on the displacement efficiency of low water salinity flooding was investigated using sea water at 35,000 ppm, and two field injection waters, namely, Um-Eradhuma (UER) at 171,585 ppm and simsima (SIM) at 243,155 ppm. The salinity of the employed waters was varied from original salinity to 1,000 ppm and used in the displacement of oil in selected core samples. The results of this set of experiments revealed that UER salinity of 5,000 ppm is the optimum system for the candidate reservoir. UER original water and its optimum water were then used in this project as the high and low salinity waters in the CO 2-WAG flooding experiments. Displacement efficiencies were evaluated under three injection modes: carbon dioxide WAG miscible flooding (CO 2-WAG, 1:1, 2:1, and 1:2), continuous CO 2 injection, and waterflood. The WAG performance parameters, such as secondary and tertiary displacement efficiencies, CO 2 flood utilization factor, and CO 2 performance during different WAG flood cycles were determined. To insure miscibility condition between the injected gas and the employed oil, all of the flooding experiments were conducted at 3,200 psia (which is 300 psia above the minimum miscibility pressure of CO 2 and used oil) and 250°F. Experimental results indicated that core length is a critical parameter in determining the optimum WAG process, and that a minimum core length of 29 cm is required to insure the generation of miscibility before breakthrough in CO2-WAG flooding experiments. On the other hand, core length had no effect on the performance of the low salinity flooding experiments. Using single core flooding low salinity CO 2-WAG of 1:2 flooding produced an improvement in the displacement efficiency of 29 % over the high salinity system. Also, composite core flooding experiments showed that the high salinity CO 2-2:1 WAG achieved a displacement efficiency of 98 %. These results indicate that achieving miscibility at the reservoir conditions is the dominant mechanism and that low salinity will have no major effect on the displacement efficiency of CO 2-Miscible WAG flooding. Results also indicate that oil recovery during different CO2-WAG cycles is a function of WAG ratios.
Comparison of Oil Recovery by Low Salinity Waterflooding in Secondary and Tertiary Recovery Modes
Oil recovery by low salinity waterflooding in secondary and tertiary modes was investigated in the present study. Cores from Berea outcrop sandstone and Minnelusa reservoir sandstone were used in the single phase and two phase experiments. Two types of Minnelusa crude oils were used in the two phase experiments. The single phase experiments provided the baseline for pH and pressure changes in the two phase experiments. Set of experiments were performed by using low salinity brine for the tertiary waterflood recovery method where oil saturated cores were first flooded with high salinity brine to simulate the secondary recovery method. In the second set of experiments, oil saturated cores were directly flooded with the low salinity brine. Conductivity and pH analysis of effluent brines were performed in all the single phase and two phase experiments. Increase in oil recovery with low salinity brine as the invading brine was observed in both secondary and tertiary modes (2-8% OOIP) with Berea sandstone. However, higher oil recoveries (5-8% OOIP) were observed when low salinity waterflooding was implemented as a secondary recovery method. Minnelusa reservoir cores had little to no response to low salinity brine when it was used as a tertiary recovery method. However, Minnelusa cores showed an increase in oil recovery (10-22 % OOIP) with both types of crude oils when it was used as a secondary recovery method. An increase in pH of the effluent brine was observed during the low salinity brine injection in both Minnelusa and Berea cores. However, magnitude of the pH increase was smaller with the Minnelusa cores compared to Berea cores. The level of investigation into the mechanism of low salinity incremental production has sharply increased in the past two years. Most of the studies focus on core floods using the tertiary mode. Our work contributes systematic coupled secondary and tertiary mode experiments that offer an expanded dataset for all researchers to use in investigation of the mechanisms.
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.
Transport in Porous Media, 2012
Carbonated water injection (CWI) is a CO 2-augmented water injection strategy that leads to increased oil recovery with added advantage of safe storage of CO 2 in oil reservoirs. In CWI, CO 2 is used efficiently (compared to conventional CO 2 injection) and hence it is particularly attractive for reservoirs with limited access to large quantities of CO 2 , e.g. offshore reservoirs or reservoirs far from large sources of CO 2. We present the results of a series of CWI coreflood experiments using water-wet and mixed-wet Clashach sandstone cores and a reservoir core with light oil (n-decane), refined viscous oil and a stock-tank crude oil. The experiments were carried out to assess the performance of CWI and to quantify the level of additional oil recovery and CO 2 storage under various experimental conditions. We show that the ultimate oil recovery by CWI is higher than the conventional water flooding in both secondary and tertiary recovery methods. Oil swelling as a result of CO 2 diffusion into the oil and the subsequent oil viscosity reduction and coalescence of the isolated oil ganglia are amongst the main mechanisms of oil recovery by CWI that were observed through the visualisation experiments in high-pressure glass micromodels. There was also evidence of a change in the rock wettability that could also influence the oil recovery. The coreflood test results also reveal that the CWI performance is influenced by oil viscosity, core wettability and the brine salinity. Higher oil recovery was obtained with the mixed-wet core than the water-wet core, with light oil than with the viscous oil and low salinity carbonated brine than high-salinity carbonated brine. At the end of the flooding period, an encouraging amount of the injected CO 2 was stored in the brine and the remaining oil in the form of stable dissolved CO 2. The experimental results clearly demonstrate the potential of CWI for improving oil recovery as compared with the conventional water flooding (secondary recovery) or as a water-based EOR (enhanced oil recovery) method for watered out reservoirs.