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Carbonate reservoirs contain more than 50% of the worlds's hydrocarbons reserves. In Saudi Arabia, most of the current hydrocarbon production is from Arab-D carbonate reservoir (Upper Jurassic limestone). Oil production started 50 years ago. So, the various fields had been subjected to prolonged pressure support by waterfloods (since 1970) using high salinity brine (Arabian Gulf water). Oil recovery using waterflooding is about a third of the oil original in place (OOIP); while two-thirds still remain as a target for additional recovery. Low salinity waterflooding was introduced as an enhanced oil recovery technique from at least 65 years. Interfacial tension (IFT) between oil and brine during waterflooding has a significant effect on oil recovery and production strategy. So, this study was carried out to investigate the effect of brine dilution, temperature, and pressure on IFT of dead and recombined oil in Arab-D carbonate reservoir as the first phase in evaluating the potential of low salinity flooding technique to improve oil recovery. In this study, Arab-D reservoir brine with total dissolved solids (TDS) of 214,943 ppm was mixed with distilled water in two proportions resulting in a first solution with TDS = 107,906 ppm and a second with TDS = 52,346 ppm. For reservoir brine and each diluted brine, crude oil/water IFT was measured at reservoir conditions. Test results showed a decrease in IFT values for both dead and recombined oil as the volume percent of brine in the mixture decreased. IFT decreased with increasing temperature at constant pressure and increased with pressure at constant temperature. Such results show that low salinity flooding may be a good technique to improve oil recovery in Arab-D carbonate reservoir. This will require an intensive experimental coreflooding tests due to complexity of the Arab-D reservoir. Introduction Carbonate reservoirs make up about 20 % of the world's sedimentary rocks and contain 40 % of the world's oil. In Saudi Arabia, most of the current hydrocarbon production is from Arab-D carbonate reservoir (Upper Jurassic limestone). Various fields had been subjected to prolonged pressure support by waterfloods (since 1970) using high salinity brine (Arabian Gulf water). Oil recovery using waterflooding is about a third of the oil original in place (OOIP); while two-thirds still remain as a target for additional recovery. Hydrocarbon recovery depends mainly on the overall efficiency with which oil is displaced by some other fluid. When the fluids are brine and oil, this displacement is characterized by viscous and capillary forces, and by the original saturation and saturation history. It has been recognized that surface forces play an active part in the oil production and in determining the amount of unrecoverable oil. The magnitudes of these forces are governed by the value of interfacial tensions (Abrams, A., 1975). Low salinity waterflooding was introduced as an enhanced oil recovery technique 65 years ago. This technique received less attention than other enhanced recovery methods. The recovery mechanisms of low salinity waterflood are complex and not well defined especially for carbonate reservoirs. There are some investigators maintained that low salinity behaves in a fashion similar to alkaline flooding. Like alkaline flooding, low salinity reduces the interfacial tension between the reservoir oil and brine (Tang and Morrow, 1997, 1999). However, studies conducted to evaluate the effect brine salinity on interfacial and contact angle are very limited (Vijapurapu and Rao, 2003; Buckley and Fan, 2005).

Reservoir evaluation is one of the critical tasks of any reservoir exploration and field development plan. Water saturation calculated from open-hole resistivity measurements is a primary input to hydrocarbon reserves evaluation. Archie's equation is the water saturation model for the determination of water saturation. Application of Archie equation in carbonate reservoir is not easy due to high dependency of its parameters on carbonate characteristics. Determination techniques of Archie's parameters are relatively well known and validated for sandstone reservoirs, while carbonates are heterogeneous and a correct estimation of Archie' parameter is important in their evaluation. In the case of carbonate rocks, there are considerable variations in texture and pore type, so, Archie's parameters become more sensitive to pores pattern distribution, lithofacies properties and wettability. Uncertainty in Archie's parameters will lead to non-acceptable errors in the water saturation values. Uncertainty analysis has shown that in calculating water saturation and initial oil in place, the Archie's parameters (a, m, n) have the largest influence and R t and R w are the least important. The main objective of this study was to measure Archie's parameters on 29 natural carbonate core plugs at reservoir conditions, using live oil, these core samples were taken from three wells. For this purpose, three techniques were implemented to determine Archie's parameters; conventional technique, core Archie's parameters estimate technique and three-dimensional technique. Water saturation profiles were generated using the different Archie parameters determined by the three techniques. These profiles have shown a significant difference in water saturation values and such difference could be mainly attributed to the uncertainty level for the calculated Archie parameters. These results highlight the importance of having accurate core analysis's measurements performed on core samples that yield representative a, m and n values that highly influence the water saturation values.

The Ghawar field in Eastern Saudi Arabia contains the largest accumulation of carbonate reservoirs in the world. The majority of wells in the field produce from the Arab-D reservoir, an Upper Jurassic limestone sealed by anhydrite. Oil production from the field started approximately 55 years ago. Water injection started in the 1970's. Long before water injection was considered for the reservoir, the evaluation of wettability was considered essential. Our present day evaluation of Arab-D wettability takes into account a long historical record of wettability measurements and production history. The procedures, results and caveats of the original measurements have changed slightly but they also show a strong consistency fifty years later. Wettability indices obtained from initial tests, Amott, and USBM methods generally indicate neutral to slightly oil-wet character for cores processed and tested in a preserved state. Comparisons with restored state cores did not indicate major differences. Over the years fluids used in coring operations and core preservation have shown little impact on the observed results. Local variations in wettability indicating mixed wettability and oil-wet tendencies can be observed when tar is present in a significant amount and in areas high on structure. The combination of methods from advanced SEM observations, to qualitative contact angle measurements, to relative permeability results all point to a common wettability value. Introduction It has become an evident that about 50 % of the world proven oil reserves are contained in carbonate reservoirs.1 The wetting properties of carbonate reservoirs are fundamental to the understanding of fluid flow in all aspects of oil production, and can affect the production characteristics greatly during water flooding. So, knowledge of the preferential wettability of reservoir rock is of utmost importance to petroleum engineers and geologists. Due to this importance, many reviews of wettability and its effect on oil recovery have been conducted.2–4 Carbonate reservoirs are heterogeneous in nature due to the wide spectrum of environments in which carbonates are deposited and subsequent diagenetic alteration of the original rock fabric. These heterogeneities and effect of wettability on residual oil saturation, capillary pressure, electrical properties, relative permeability, and oil recovery encouraged many researchers to perform various studies to characterize and evaluate wettability of carbonate reservoirs. In the past, many engineers assumed that most reservoir rocks are water-wet. The reasons for this conviction are the work of Leverett5 and test methodology of determination of wettability after thoroughly cleaning cores that were likely to have been contaminated and exposed to air. The paper published by Treiber et.al.6 was the major breakthrough in showing that the large numbers of carbonate reservoirs are oil-wet. Consequently, various studies showed that the wettability of carbonate rocks is oil-wet, neutral or mixed.7–9 This paper provides detailed study and survey of wettability evaluation for Arab-D carbonate reservoir (Upper Jurassic), Saudi Arabia. The wettability results presented in this paper combine data obtained from various quantitative and qualitative methods over fifty years using preserved and restored core material. The studied areas are Uthmaniyah, Hawiyah, and Haradh. Arab-D Reservoir The Ghawar field in Eastern Saudi Arabia contains the largest accumulation of carbonate reservoirs in the world. The majority of wells in the field produce form the Arab-D reservoir, an Upper Jurassic limestone sealed by anhydrite. The Arab-D reservoir was discovered in 1948. Following further separate discoveries along the structure's main axis, five areas were quickly identified as parts of giant Ghawar oil field (Fig. 1): from north to south they are Ain Dar, Shedgum, Uthmaniyah, Hawiyah, and Haradh. At the Arab-D level, the field is NNE-trending composite anticline 230 km long and about 30 km wide.10 The largest oil accumulations occur in the lowest grainstone cycle of the Arab Formation, the Arab-D reservoir. The vertical oil column reaches a maximum of 1,300 ft. The oil-saturated interval extends about 250 ft below the anhydrite that separates the Arab-D reservoir from overlying Arab-C carbonate beds (Fig. 1).

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Results and discussions in this paper relate to a Lower Cretaceous carbonate reservoir located in southeastern Saudi Arabia. It is a heterogeneous carbonate formation with various facies due to diagenetic alteration of the original rock fabric. The reservoir is large and prolific with mixed-wet characteristics. Because of the economic importance and variety of oil-recovery mechanisms operative or possible in the reservoir, the multiphase recovery behavior has been extensively studied. Also, various wettability tests were carried out using Amott and USBM methods. This paper describes the variation in wettability and relative permeability of Lower Cretaceous carbonate reservoir and the multi-phase simulations of the experimental results. It shows that measurements are consistent with recent theories of the relationship between water saturation, relative permeability, and wettability as described by Jadhunadan and Morrow, 1991. However, the results indicate that the wettability of the reservoir changes from water-wet low on structure near the oil/water contact to mixed or neutral wet behavior higher on structure. Oil-wetting character increases towards the top of oil column and is correlated to decreasing water saturation. The results revealed that changes in wettability are accompanied by changes in waterflood efficiency and facies of deposition.

The existence of tar accumulations (tarmat) beneath the oil zone in some reservoirs creates productivity problems through restricted aquifer support during the primary recovery stage. It also affects the performance of peripheral water injection when the tar/oil boundary is irregular. The objective of this study was to investigate and evaluate combined solvent and hot water injection beneath the tarmat to improve aquifer support by displacing and dispersing the tar. Displacement runs were conducted in one-foot long Berea sandstone composite cores, simulating a tar zone and an oil zone in series, at injection rates of 1 ml/min. and higher. The results show that although the oil recovery from hot water displacement is lower than cold water displacement in the absence of tar, the gain in recovery for hot water over cold water is substantial in the presence of tarmat. Driving a slug of solvent with hot water to displace tar increases the hydrocarbon recovery even further. However, for each of the two solvents studied, there is an optimum slug size with which the hydrocarbon recovery is maximum. Moreover, the recovery was found to increase further when the optimal slug is divided into portions separated by small slugs of hot water. The injection rate had a profound effect on the recovery for all hot-water flooding schemes. The results showed consistently that the recovery increased at lower injection rates. Introduction Many oil reservoirs are characterized by the presence of a highly viscous hydrocarbon layer (tarmat) at the oil/water contact. Such tarmats are found in many major oil reservoirs in the world and, particularly, in the Middle East. They are reported in the literature to vary widely, ranging from highly viscous hydrocarbon fluids to near solid materials(1). The thickness of the tarmat varies from place to place in the same reservoir and sometimes reaches few hundred feet; while their extent can reach several kilometres. In Ghawar field, for example, the tar zone extends more than 25 km and reaches up to 150 m in thickness(2). Several geochemical studies presented by various authors attribute tarmat formation to gravity segregation which leads to a compositional grading with depth(3–5). Depending on reservoir conditions and tar viscosity, field experience shows that some of these tarmats can become mobile under conditions of moderate differential pressure(2). The presence of tar deposits at the oil/water contact in a tarmat reservoir can have serious adverse effects on the effectiveness of natural water drive as well as secondary recovery projects. When the tarmat completely surrounds the oil zone, the oil reservoir behaves like a finite lens where the pressure decreases rapidly as soon as the first well starts producing. This leads to an alarming increase in gas/oil ratio during the primary stage of depletion which has been the case with Minagish reservoir in Kuwait(2). Another such example is El Bundug reservoir in Qatar(6).