Coupled Geochemical-Reservoir Model to Understand the Interaction Between Low Salinity Brines and Carbonate Rock

2015 ◽  
Author(s):  
Ramez A. Nasralla ◽  
Jeroen R. Snippe ◽  
Rouhi Farajzadeh
Keyword(s):  
Carbonate Rock ◽  
Reservoir Model ◽  
Low Salinity

Electrokinetics of Carbonate/Brine Interface in Low-Salinity Waterflooding: Effect of Brine Salinity, Composition, Rock Type, and pH on ?-Potential and a Surface-Complexation Model

SPE Journal ◽  
2016 ◽  
Vol 22 (01) ◽  
pp. 53-68 ◽  
Author(s):  
Hassan Mahani ◽  
Arsene Levy Keya ◽  
Steffen Berg ◽  
Ramez Nasralla
Keyword(s):  
Surface Charge ◽  
Carbonate Rock ◽  
Rock Type ◽  
Surface Complexation ◽  
Surface Complexation Model ◽  
Ζ Potential ◽  
Low Salinity ◽  
Ph Values ◽  
Different Types ◽  
Brine Salinity

Summary Laboratory studies have shown that wettability of carbonate rock can be altered to a less-oil-wetting state by manipulation of brine composition and reduction of salinity. Our recent study (Mahani et al. 2015b) suggests that surface-charge alteration is likely to be the driving mechanism of the low-salinity effect in carbonates. Various studies have already established the sensitivity of carbonate-surface charge to brine salinity, pH value, and potential-determining ions in brines. However, in the majority of the studies, single-salt brines or model-carbonate rocks have been used and it is fairly unclear how natural rock reacts to reservoir-relevant brine as well as successive brine dilution; whether different types of carbonate-reservoir rocks exhibit different electrokinetic properties; and how the surface-charge behavior obtained at different brine salinities and pH values can be explained. This paper presents a comparative study aimed at gaining more insight into the electrokinetics of different types of carbonate rock. This is achieved by ζ-potential measurements on Iceland spar calcite and three reservoir-related rocks—Middle Eastern limestone, Stevns Klint chalk, and Silurian dolomite outcrop—over a wide range of salinity, brine composition, and pH values. With a view to arriving at a more-tractable approach, a surface-complexation model (SCM) implemented in PHREEQC software (Parkhurst and Appelo 2013) is developed to relate our understanding of the surface reactions to measured ζ-potentials. It was found that regardless of the rock type, the trends of ζ-potentials with salinity and pH are quite similar. For all cases, the surface charge was found to be positive in high-salinity formation water (FW), which should favor oil-wetting. The ζ-potential successively decreased toward negative values when the brine salinity was lowered to seawater (SW) level and diluted SW. At all salinities, the ζ-potential showed a strong dependence on pH, with positive slope that remained so even with excessive dilution. The sensitivity of the ζ-potential to pH change was often higher at lower salinities. The existing SCMs cannot predict the observed increase of ζ-potential with pH; therefore, a new model is proposed to capture this feature. According to modeling results, formation of surface species, particularly >CaSO4− and to a lower extent >CO3Ca+ and >CO3Mg+, strongly influence the total surface charge. Increasing the pH turns the negatively charged moiety >CaSO4− into both negatively charged >CaCO3− and neutral > CaOH entities. (Note that throughout this paper, the symbol > indicates surface complexes.) This substitution reduces the negative charge of the surface. The surface concentration of >CO3Ca+ and >CO3Mg+ moieties changes little with change of pH. Nevertheless, besides similarities in ζ-potential trends, there exist notable differences in terms of magnitude and the isoelectric point (IEP), even between carbonates that are mainly composed of calcite. Among all the samples, chalk particles exhibited the most negative surface charges, followed by limestone. In contrast to this, dolomite particles showed the most positive ζ-potential, followed by calcite crystal. Overall, chalk particles exhibited the highest surface reactivity to pH and salinity change, whereas dolomite particles showed the lowest.

scholarly journals Reservoir Model and Production Strategy of Mishrif Reservoir-Nasryia Oil Field Southern Iraq

2020 ◽  
Vol 10 (3) ◽  
pp. 54-85
Author(s):  
Hamzah Amer Abdulameer ◽  
Dr. Sameera Hamd-Allah
Keyword(s):  
Oil Recovery ◽  
Carbonate Rock ◽  
History Matching ◽  
Water Saturation ◽  
Oil Field ◽  
Neutron Density ◽  
Reservoir Model ◽  
Water Contact ◽  
Medium Permeability ◽  
Production Strategy

Nasryia oil field is located about 38 Km to the north-west of Nasryia city. The field was discovered in 1975 after doing seismic by Iraqi national oil company. Mishrif formation is a carbonate rock (Limestone and Dolomite) and its thickness reach to 170m. The main reservoir is the lower Mishrif (MB) layer which has medium permeability (3.5-100) md and good porosity (10-25) %. Form well logging interpretation, it has been confirmed the rock type of Mishrif formation as carbonate rock. A ten meter shale layer is separating the MA from MB layer. Environmental corrections had been applied on well logs to use the corrected one in the analysis. The combination of Neutron-Density porosity has been chosen for interpretation as it is close to core porosity. Archie equation had been used to calculate water saturation using corrected porosity from shale effect and Archie parameters which are determined using Picket plot. Using core analysis with log data lead to establish equations to estimate permeability and porosity for non-cored wells. Water saturation form Archie was used to determine the oil-water contact which is very important in oil in place calculation. PVT software was used to choose the best fit PVT correlation that describes reservoir PVT properties which will be used in reservoir and well modeling. Numerical software was used to generate reservoir model using all geological and petrophysical properties. Using production data to do history matching and determine the aquifer affect as weak water drive. Reservoir model calculate 6.9 MMMSTB of oil as initial oil in place, this value is very close to that measured by Chevron study on same reservoir which was 7.1 MMMSTB. [1] Field production strategy had been applied to predict the reservoir behavior and production rate for 34 years. The development strategy used water injection to support reservoir pressure and to improve oil recovery. The result shows that the reservoir has the ability to produce oil at apparently stable rate equal to 85 Kbbl/d, also the recovery factor is about 14%.

Favorable attributes of low salinity water aided alkaline on crude oil-brine-carbonate rock system

2020 ◽  
Vol 585 ◽  
pp. 124144 ◽  
Author(s):  
Bizhan Honarvar ◽  
Ali Rahimi ◽  
Mehdi Safari ◽  
Shahrokh Rezaee ◽  
Mohammad Karimi
Keyword(s):  
Crude Oil ◽  
Carbonate Rock ◽  
Rock System ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water

Effect of Total Acid Number and Recovery Mode on Low-Salinity Enhanced Oil Recovery in Carbonates

2021 ◽  
pp. 1-18
Author(s):  
Takaaki Uetani ◽  
Hiromi Kaido ◽  
Hideharu Yonebayashi
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbonate Rock ◽  
Acid Number ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Oil Composition ◽  
Total Acid ◽  
Low Salinity ◽  
Total Acid Number

Summary Low-salinity water (LSW) flooding is an attractive enhanced oil recovery (EOR) option, but its mechanism leading to EOR is poorly understood, especially in carbonate rock. In this paper, we investigate the main reason behind two tertiary LSW coreflood tests that failed to demonstrate promising EOR response in reservoir carbonate rock; additional oil recovery factors by the LSW injection were only +2% and +4% oil initially in place. We suspected either the oil composition (lack of acid content) or the recovery mode (tertiary mode) was inappropriate. Therefore, we repeated the experiments using an acid-enriched oil sample and injected LSW in the secondary mode. The result showed that the low-salinity effect was substantially enhanced; the additional oil recovery factor by the tertiary LSW injection jumped to +23%. Moreover, it was also found that the secondary LSW injection was more efficient than the tertiary LSW injection, especially in the acid-enriched oil reservoir. In summary, it was concluded that the total acid number (TAN) and the recovery mode appear to be the key successful factors for LSW in our carbonate system. To support the conclusion, we also performed contact angle measurement and spontaneous imbibition tests to investigate the influence of acid enrichment on wettability, and moreover, LSW injection on wettability alteration.

scholarly journals Low salinity waterflooding EOR laboratory test using a carbonate rock

2016 ◽  
Vol 81 (6) ◽  
pp. 489-494
Author(s):  
Takaaki Uetani ◽  
Katsumo Takabayashi ◽  
Hiromi Kaido ◽  
Hideharu Yonebayashi
Keyword(s):  
Laboratory Test ◽  
Carbonate Rock ◽  
Low Salinity ◽  
Low Salinity Waterflooding

scholarly journals Pore-scale imaging and analysis of low salinity waterflooding in a heterogeneous carbonate rock at reservoir conditions

2021 ◽  
Vol 11 (1) ◽  
Author(s):  
Ahmed M. Selem ◽  
Nicolas Agenet ◽  
Ying Gao ◽  
Ali Q. Raeini ◽  
Martin J. Blunt ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Carbonate Rock ◽  
Pore Space ◽  
Contact Angles ◽  
Fluid Distribution ◽  
Pore Scale ◽  
Low Salinity ◽  
Low Salinity Waterflooding ◽  
Capillary Pressures ◽  
Micro Tomography

AbstractX-ray micro-tomography combined with a high-pressure high-temperature flow apparatus and advanced image analysis techniques were used to image and study fluid distribution, wetting states and oil recovery during low salinity waterflooding (LSW) in a complex carbonate rock at subsurface conditions. The sample, aged with crude oil, was flooded with low salinity brine with a series of increasing flow rates, eventually recovering 85% of the oil initially in place in the resolved porosity. The pore and throat occupancy analysis revealed a change in fluid distribution in the pore space for different injection rates. Low salinity brine initially invaded large pores, consistent with displacement in an oil-wet rock. However, as more brine was injected, a redistribution of fluids was observed; smaller pores and throats were invaded by brine and the displaced oil moved into larger pore elements. Furthermore, in situ contact angles and curvatures of oil–brine interfaces were measured to characterize wettability changes within the pore space and calculate capillary pressure. Contact angles, mean curvatures and capillary pressures all showed a shift from weakly oil-wet towards a mixed-wet state as more pore volumes of low salinity brine were injected into the sample. Overall, this study establishes a methodology to characterize and quantify wettability changes at the pore scale which appears to be the dominant mechanism for oil recovery by LSW.

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