Hasan Y. Al-Yousef

Alkaline surfactant polymer formulation for Saudi Arabian carbonate reservoirs

This paper presents a systematic study to test the applicability of alkaline-surfactant-polymer (ASP) processes as an enhanced oil recovery method to Saudi Arabian carbonate reservoirs, with the objective of designing a cost-effective ASP slug. To achieve this objective, several alkalis were first screened to test their compatibility with the injected sea water that has large quantities of divalent ions. Then surfactant-polymer, alkalis-surfactant, and alkalis-surfactant-polymer interactions at the reservoir temperature (90°C) were investigated. Static and dynamic adsorption of surfactant on reservoir carbonate rocks were also investigated at the same temperature. IFT measurements were also made between the slugs formulated and crude oil from the same reservoir. And finally core flooding tests were carried out using Arab-D carbonate core samples to test the effectiveness of the formulated slugs. Two surfactants were used, Triton X-102 and Ethoxylated sulfonate (Dodi-flood B1083), and the polymer used was FLOCON 4800C. The results of the compatibility tests showed that the ASP slug has to be prepared using a softened brine and be protected by pre- and after-flush softening brine slugs. B1083 surfactant was found to be a promising candidate surfactant for the conditions of the Saudi Arabian carbonate reservoir. A combination of NaHCO 3 and Na 2 CO 3 was found to significantly reduce the adsorption level of B1083 surfactant on carbonate rock at low surfactant concentrations (<1% by wt.). This is very desirable for formulation of a cost-effective ASP slug. Finally, the results of core flooding tests under reservoir conditions using the formulated ASP slugs on Arab-D carbonate core samples showed a promising additional oil recovery.

Effect of electroosmosis on relative permeabilities of sandstones

Abstract Dynamic displacement experiments were performed to investigate the effect of electroosmosis on relative permeability. Berea sandstone cores, Arabian light crude oil and a 20 g/l NaCl aqueous solution were used. Direct electrical potential gradients of up to 3 V/cm were applied across the core with the cathode placed at the injection end. The application of the electrical potential gradient increased the oil relative permeability and decreased the water relative permeability. The changes in relative permeabilities increased with increasing the applied electrical potential gradient. The breakthrough water saturation at the outlet end generally shifted towards successively higher values with increasing electrical potential gradients, and the two-phase flow period increased resulting in higher breakthrough and ultimate recoveries.

Alkaline Surfactant Polymer Formulation for Carbonate Reservoirs

Abstract This paper presents a systematic study to investigate the applicability of alkaline-surfactant-polymer (ASP) process as an enhanced oil recovery method to Saudi Arabian carbonate reservoirs. Several alkalis were first screened to test their compatibility with the injected sea water that has large quantities of divalent ions. Then surfactant-polymer, alkali-surfactant, and alkali-surfactant-polymer interactions at the reservoir temperature (90○C) were investigated. Static adsorption of surfactant on reservoir carbonate rocks were also investigated at the same temperature. Interfacial tension (IFT) measurements were made between the slugs formulated and crude oil from the same reservoir. Two surfactants were tested, Triton X-102 and Ethoxylated sulfonate (Dodiflood B1083), and the polymer tested was FLOCON 4800C. The results of the compatibility tests showed that the ASP slug has to be prepared using softened seawater and be protected by a pre- and after-flush softening seawater slugs. B1083 surfactant was found to be a promising candidate surfactant for the adverse conditions of the Saudi Arabian carbonate reservoir. A combination of NaHCO3 and Na2CO3 was found to significantly reduce the adsorption level of B1083 surfactant on carbonate rock at low surfactant concentrations ( < 1% by wt.). This is very desirable for formulation of a cost-effective ASP slug.

Vertical Multiphase Flow Correlations for High Production Rates and Large Tubulars

Numerous correlations exist for predicting pressure drop in vertical multiphase flow. These correlations, however, were all developed and tested under limited operating conditions that do not match the high production rates and large tubulars normally found in the Middle East fields. This paper presents a comprehensive evaluation of existing correlations and modifications of some correlations to determine and recommend the best correlation or correlations for various field conditions. More than 400 field data sets covering tubing sizes from 2 3/8 to 7 inches, oil rates up to 23,200 B/D, water cuts up to 95%, and gas/oil ratio (GOR) up to 927 scf/STB were used in this study. Considering all data combined, the Beggs and Brill correlation provided the best pressure predictions. However, the Hagedorn and Brown correlation was better for water cuts above 80%, while the Hasan and Kabir model was better for total liquid rates above 20,000 B/D. The Aziz correlation was significantly improved when the Orkiszewski flow-pattern transition criteria were used.

Adsorption and precipitation behaviour of petroleum sulfonates from Saudi Arabian limestone

Abstract The adsorption behaviour of a petroleum sulfonate (TRS10-410) on Saudi Arabian limestone has been studied as a function of salinity, surfactant concentration and pH. The adsorption data on limestone exhibit the significant effect of mineral solubility in controlling the surfactant depletion. Release of Ca2+ ions from the semi-soluble limestone matrix produces precipitation of the surfactant followed by its redissolution at concentrations exceeding the critical micelle concentration (CMC). This characteristic behaviour generates an apparent adsorption maximum which is of considerable interest in surfactant flooding. The precipitation tolerance of TRS10-410 has also been investigated in the presence of Na+ and Ca2+ ions to quantitatively describe the precipitation behaviour of this surfactant. The adsorption and precipitation data are analyzed to elucidate the mechanism of surfactant adsorption on limestone and that of surfactant precipitation by inorganic ions.

Effect of Hysteresis on the Archie Saturation Exponent

It is common practice in the oil industry to use a single value of the Archie saturation exponent (n) in reserves evaluation based upon well log data. This practice ignores, in essence, the development (or depletion) stage of the reservoir. This study investigates the effect of saturation hysteresis on the saturation exponent using a double membrane (oil-wet membrane and water-wet porous plate) arrangement. An electrocapillarometer was used for this purpose. With the electrocapillarometer, it is possible to perform measurements while the displacing phase is injected continuously at predetermined rate, as opposed to waiting for equilibrium. This facilitates rapid data acquisition. The influence of the experimental procedure on the saturation exponent, vis-a-vis, static (constant pressure) and dynamic (constant rate) desaturation methods was also investigated. Using this same membrane arrangement, it was possible to determine the wettability of the reservoir rock at reservoir conditions of pressure and temperature. In this study, the Archie saturation exponent was determined to reveal a saturation history dependent (hysteresis) behavior. The hysteresis aspect of the study identified a region of a) oil-displacing water (primary drainage) where the saturation exponent was found to be 1.8; b) spontaneous water imbibition followed by forced imbibition. The saturation exponent in this region was 2.72. Another region is the spontaneous secondary drainage, followed by forced secondary drainage. The saturation exponent in this region was 2.14. Results from the electrocapillarometer (in the case of oil-displacing water) were compared with those from a conventional constant pressure, single membrane system. There was very good agreement. The wettability index obtained with the electrocapillarometer was also compared with an independent determination of USBM wettability index using the centrifuge at reservoir temperature. Both showed the samples to be water wet and the numerical value of wettability indices agree very well. A one dimensional two-phase numerical simulator was developed and used to perform a sensitivity analysis for the following situations: 1) desaturation at constant capillary pressure, 2) desaturation using constant injection rate followed by a waiting period to achieve equilibrium, 3) desaturation using continuous injection at constant rate without a waiting period to achieve equilibrium. In this paper we discuss guidlines to interpret and use results obtained from the above three methods.

Sensitivity studies and stochastic optimization of CO2 foam flooding

The use of CO 2 foam flooding for enhanced oil recovery is increasingly becoming common. In this type of enhanced oil recovery, the surfactant is dissolved into CO 2 to form foam and the CO 2 foam is injected alternately with water to improve the sweep efficiency of the flood. However, many parameters affect the effectiveness of this CO 2 flood. Some of these parameters are the concentration of surfactant dissolved in the CO 2, the ratio of the foam injection time to the water injection time (cycle ratio), etc. Large savings in cost can be realized if these parameters are carefully selected. In this work, we optimized CO 2 foam flooding by estimating the parameters that affect the flooding using stochastic optimization algorithms. First, we performed some sensitivity studies to determine the extent of influence of different parameters of the CO 2 foam flood. From the sensitivity studies, we were able to reduce the number of parameters to be optimized to three (cycle ratio, surfactant concentration, and well locations) that have significant effects on the flood. Subsequently, we adopted two optimization algorithms to estimate the three parameters.

Wettability Evaluation of a Carbonate Reservoir Rock from Core to Pore Level

Wettability evaluation was performed during stages of as received, cleaned, and restored states on core samples from a Saudi Arabian carbonate reservoir. The wettability behavior from the chemistry of brine-oil-carbonate rock interation was found to be neutral to slightly oil-wet. The pore-size distribution obtained from mercury injection data indicated that about 15-20 percent of the pore volume is not accessible to asphaltene particles in the crude oil. Therefore a mixed-wettability state can exist. These results were confirmed by the evaluation of the wettability on the cores using USBM and Amott techniques. The wettability at the pore level was studied using Cryo-Scanning Electron Microscopy. Rock samples were examined at irreducible water and residual oil saturations during cleaned and restored states. At irreducible water saturation, both oil and brine were present in the intergranular macroporosity and intragranular macropores and micropores. At residual oil saturation, oil was found in the form of isolated globules in the cleaned case. After aging, the oil is more loosely distributed in the porosity and generally contacts the pore walls. This indicates an evolution toward oil wetness with aging. These results are in agreement with the changes of wettability indices obtainted using USBM technique.

Adsorption of Ethoxylated Sulfonates on Limestone

Stastic adsorption experiments have been conducted to investigate the adsorption and precipitation behavior of various ethoxylated sulfonates from Saudi Arabian limestone samples under high-salinity (20%) and high temperature conditions (90°C). The effect of parameters such as salinity, pH, temperature, ethoxylation number, oil and alcohol addition has been investigated. Mechanisms governing surfactant adsorption on limestone are elucidated. A surfactant formulation has been designed to achieve minimum surfactant loss for Saudi Arabian limestone reservoirs.

Liquids Phase Holdup and Separation Characteristics as a Function of Well Inclination and Flowrate

The maturing Middle Eastern oil fields with natural aquifer support or water injection can pose a challenging produced water handling and disposal issues. The increased water-oil ratio also presents productivity problems: many wells will die prematurely due to increased water holdup. The produced water management cost @US