Laboratory Investigation of Low Salinity Waterflooding for Carbonate Reservoirs (original) (raw)
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An Experimental Investigation of Low Salinity Oil Recovery in Carbonate and Sandstone Formation
2015
Water flooding has for a long time been employed to improve oil recovery in many oil fields. Formation damage due to water injection was the main issue of water flooding design process for many years and oil companies conducted different compatibility tests between injection water and formation water to eliminate any possibility of formation damage. In recent years, the results of extensive research work demonstrated that alteration of water salinity concentration and composition improves significantly the ultimate oil recovery of water flooding. Up to date there is no universal agreement among the researchers on the mechanism of low salinity flooding. Different mechanisms are proposed in the literature such as wettabiliy modification, fine migration, interfacial reduction, emulsion, and ionic exchange. In this paper an experimental investigation on the possible mechanism of low salinity flooding was conducted. Contact angle changes as function of time, and low salinity water flood ...
Low Salinity Flooding in a Selected Carbonate Reservoir: Experimental Approach
EAGE Annual Conference & Exhibition incorporating SPE Europec, 2013
Low-salinity waterflooding has been used to improve oil recovery for many decades. Several theories regarding the mechanism of low-salinity flooding have been discussed in the literature including interfacial tension reduction, wettability alteration, change in pH value, emulsion formation, and clay migration. This work presents the results of flooding tests on selected carbonate core samples taken from Bu Hasa field in Abu Dhabi using sea water and two field injection waters, Um-Eradhuma (UER) at 197,357 ppm and Simsima at 243,155 ppm. These results were used to evaluate the effects of brine salinity and ionic composition on the possible interactions of limestone rock/ brine/and oil system and to identify the oil recovery mechanism. The field injection waters were diluted to salinities of 5,000 and 1,000 ppm and the optimum salinity was determined and then modified by varying the sulfate and calcium ion concentrations. Wettability alteration was determined by contact angle measurements. Interfacial tension measurements of the studied systems were also performed in an attempt to evaluate the flow mechanism with low-salinity flooding. The experimental results revealed that a significant improvement in the oil recovery can be achieved through alteration of the injection water salinity. Reducing the salinity of UER water from 197,357 to 5,000 ppm resulted in an improvement of oil recovery from 63 to 84.5 % of OOIP and the latter salinity was used to evaluate the impact of changing the sulfate and calcium ion concentrations on oil recovery. Results also indicated that sulfate concentration has a significant effect on the flooding process and that increasing the sulfate concentration beyond some optimum concentration of 46.8 ppm resulted in a negative effect on the flooding process. Contact angle measurements indicated that lowering the solution salinity could shift the wettability of the system towards intermediate wettability levels and that the UER water exhibits higher shift toward intermediate wettability compared to other waters. Results also indicated that there is no clear correlation between the improvements in oil recovery and interfacial tension and the pH of the studied systems. The results of this work are useful for people working in this field.
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...
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.
The aim of this paper is to quantify the effect of low-salinity (LS) water on oil recovery from sandstone cores at different temperatures and at various permeabilities, oil viscosities, and Ca 2+ concentrations in the formation water. Six sandstone cores were waterflooded with high-salinity (HS) and LS water at various temperatures ranging from 25 to 90 °C. Four cores were allocated to oil recovery experiments, and the other two were dedicated to surface reactivity tests. The S wi and S or of the cores were established, and then the cores were pre-aged for 3 days at 70 °C with oil in a closed container. We examined the effect of different ionic solutions (HS water, LS water, and double Ca 2+ HS water) at different temperatures. The surface reactivity test cores were flooded with the same HS and LS brines that were used in oil recovery forced-imbibition experiments. During flooding, samples of the effluent were analyzed for pH and Ca 2+. The absence of an oil phase enabled us to isolate and quantify the important water–rock reactions. Ca 2+ desorption from the core that was aged in the double Ca 2+ concentration was larger than that desorbed from the other core, but pH and pressure was less than the other core during surface reactivity tests. Due to dehydration at high temperatures, the desorption of Ca 2+ decreased as the temperature increased. Also, as the temperature increased, the pH gradient between the HS and LS water effluents decreased. Oil recovery forced-imbibition experiments with a double Ca 2+ concentration showed a small LS water effect at all temperatures, meaning that the cores became more water-wet; however, the LS water effect was much greater when the amount of Ca 2+ in the HS water was decreased by half. Furthermore, as the core permeability and oil viscosity increased, our tests showed a greater positive effect from the LS water. This work attempts to isolate the separate effects and thus examines the oil recovery achieved with the most important LS waterflood factors, which are temperature, ion exchange, and pH. Keywords Low salinity water flooding · Surface reactivity test · Enhanced oil recovery · Geochemistry · Cation adsorption
Fuel, 2018
Wettability of the oil/brine/rock system is an essential petro-physical parameter which governs subsurface multiphase flow behaviour and the distribution of fluids, thus directly affecting oil recovery. Recent studies [1-3] show that manipulation of injected brine composition can enhance oil recovery by shifting wettability from oil-wet to water-wet. However, what factor(s) control system wettability has not been completely elucidated due to incomplete understanding of the geochemical system. To isolate and identify the key factors at play we used SO 4 2-free solutions to examine the effect of salinity (formation brine/FB, 10 times diluted formation brine/10 dFB, and 100 times diluted formation brine/100 dFB) on the contact angle of oil droplets at the surface of calcite. We then compared contact angle results with predictions of surface complexation by low salinity water using PHREEQC software. We demonstrate that the conventional dilution approach likely triggers an oil-wet system at low pH, which may explain why the low salinity water EOR-effect is not always observed by injecting low salinity water in carbonated reservoirs. pH plays a fundamental role in the surface chemistry of oil/brine interfaces, and wettability. Our contact angle results show that formation brine triggered a strong water-wet system (35°) at pH 2.55, yet 100 times diluted formation brine led to a strongly oil-wet system (contact angle = 175°) at pH 5.68. Surface complexation modelling correctly predicted the wettability trend with salinity; the bond product sum ([ > CaOH 2 + ][-COO − ] + [ > CO 3 − ][-NH + ] + [ > CO 3 − ][-COOCa + ]) increased with decreasing salinity. At pH < 6 dilution likely makes the calcite surface oil-wet, particularly for crude oils with high base number. Yet, dilution probably causes water wetness at pH > 7 for crude oils with high acid number.
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.
Low Salinity Waterflooding in Carbonate Reservoirs: Review of Interfacial Mechanisms
Colloids and Interfaces
Carbonate rock reservoirs comprise approximately 60% of the world's oil and gas reserves. Complex flow mechanisms and strong adsorption of crude oil on carbonate formation surfaces can reduce hydrocarbon recovery of an oil-wet carbonate reservoir to as low as 10%. Low salinity waterflooding (LSW) has been confirmed as a promising technique to improve the oil recovery factor. However, the principal mechanism underpinning this recovery method is not fully understood, which poses a challenge toward designing the optimal salinity and ionic composition of any injection solution. In general, it is believed that there is more than one mechanism involved in LSW of carbonates; even though wettability alteration toward a more desirable state for oil to be recovered could be the main cause during LSW, how this alteration happens is still the subject of debate. This paper reviews different working conditions of LSW, previous studies, and field observations, alongside the proposed interfacial mechanisms which affect the colloidal interactions at oil-rock-brine interfaces. This paper provides a comprehensive review of studies on LSW in carbonate formation and further analyzes the latest achievements of LSW application in carbonates, which helps to better understand the challenges involved in these complicated multicomponent systems and potentially benefits the oil production industry.