Khaled Abdalla Elraies

The Synthesis and Performance of Sodium Methyl Ester Sulfonate for Enhanced Oil Recovery

Abstract Due to the high cost of surfactant production caused by petrochemical feedstocks, much attention has been given to nonedible vegetable oils as an alternative source of feedstock. A new nonedible oil-derived surfactant based on the Jatropha plant is synthesized. A single-step route was used for synthesizing sodium methyl ester sulfonate (SMES) for enhanced oil recovery application. The performance of the resultant surfactant was studied by measuring the interfacial tension between the surfactant solution and crude oil and its thermal stability at reservoir temperature. The SMES showed a good surface activity, reducing the interfacial tension between the surfactant solution and crude oil from 18.4 to 3.92 mN/m. The thermal analysis of SMES indicates that 26.1% weight loss was observed from 70°C to 500°C. The advantage of the new SMES is the low cost of production, which makes it a promising surfactant for enhanced oil recovery application and other uses.

Development of a New Polymeric Surfactant for Chemical Enhanced Oil Recovery

Abstract This work presents a new alkaline–surfactant (AS) flooding formulation that replaces and improves the traditional alkaline–surfactant–polymer (ASP) flooding slug. With the design of a cost-effective AS slug, a new series of polymeric surfactants was produced based on agriculture material. In this article, the polymeric surfactant was produced by a graft polymerization process using several surfactant-to-acrylamide ratios. This surfactant was designed to graft the sulfonated group to the polymer backbone as one component system for interfacial tension (IFT) reduction and viscosity control. The performance of the resultant surfactants was studied in the presence and absence of sodium carbonate as an alkaline agent at reservoir temperature of 90°C. The feasibility of applying the AS formula was based on IFT measurement between crude oil and AS solution and viscosity tests. As a result, the ratio of 1:0.5 (S:A) was selected as the optimum ratio for IFT reduction and viscosity control. A combination of alkali and surfactant with a concentration of 0.8 and 0.4% was found to significantly reduce the IFT while maintaining the desired viscosity of the solution.

A New Approach to Low-Cost, High Performance Chemical Flooding System

This paper presents a new Acid-Alkali-Surfactant (AAS) flooding formulation as an alternative to conventional alkaline/surfactant/polymer (ASP) process. It is a cost-effective formula that is able to overcome precipitation problems prevalent with ASP flooding when natural sea water was used. The acid was evaluated in an AAS formulation using sodium carbonate and introducing a new polymeric surfactant derived from Jatropha oil. The feasibility of applying the new AAS formula was demonstrated by a series of experiments involving fluid compatibility test with natural sea water having a large quantity of divalent metal cations, interfacial tension between Angsi crude oil and AAS solution, surfactant adsorption, and core flood using Berea core samples. The acid effectively prevented divalent metal cations from precipitating and all solutions remained clear for 90 days at 90oC. The optimum acid concentration was found to be proportional to alkali concentration in the ratio of 1.66:1. A combination of the new system was found to significantly reduce the IFT and the adsorption level of the surfactant. The best chemical concentrations were then validated in core flood tests using various alkali and surfactant concentrations. The optimum alkali and surfactant concentrations were confirmed as 0.6% and 0.6% respectively. Using the optimum concentrations, another series of core flood tests were conducted by changing the injection volume. Only a small incremental recovery was obtained with slugs higher than 0.5 PV. Injection of 0.5 PV of the formulated slug followed by chase water produced an additional 18.8% OOIP over water flood, accomplishing a total oil recovery of 77.3% OOIP. This makes the new AAS formula an attractive and cost-effective agent for CEOR particularly for offshore field application.

Design and Application of a New Acid-Alkali-Surfactant Flooding Formulation for Malaysian reservoirs

A new Acid-Alkali-Polymeric Surfactant (AAPS) flooding formulation has been developed to overcome the precipitation problems caused by the divalent metal cations prevalent with conventional ASP flooding. The acid was evaluated in an acidalkali-surfactant formulation using sodium carbonate and introducing a new polymeric surfactant derived from Jatropha oil. The effect of the new formula on IFT, viscosity, and oil recovery was studied using natural seawater having a large quantity of divalent metal cations. The tolerance of the AAPS towards natural untreated sea water was monitored for 90 days at 90 C. No precipitations were formed with the acid additive, while precipitations were always generated without the acid. A combination of the new system was found to significantly reduce the IFT between Angsi crude oil and AAPS solution. The most outstanding feature of the AAPS formulation lies in its viscosity insensivity towards an increasing alkali concentration up to 1.2%. Core flood tests with alkali and acid concentrations of 0.6% and 1% respectively confirmed an optimum surfactant concentration of 0.6%. Using the optimum AAPS concentrations, another series of core flood were conducted by changing the injection volume. Only a small incremental recovery was obtained with AAPS slugs higher than 0.5 PV. Injection of 0.5 PV of the formulated AAPS slug followed by chase water produced an additional 18.8% OOIP over water flooding. The benefit of the new system is the use of seawater rather than softened water while maintaining the desired slug properties. Introduction In Malaysia and many other countries, most mature reservoirs are already waterflooded, or are presently being subjected to secondary and tertiary recovery processes. In Malaysian oil reservoirs, only about 36.8% of original oil in place (OOIP) is produced through the entire life of mature reservoirs that have been developed under conventional methods (Hamdan et al., 2005). A significant amount of the hydrocarbon would not be recovered utilizing the current production strategies, and that has motivated Malaysia to attempt Enhanced Oil recovery (EOR). Recognizing the potential of EOR in the fields, the national oil company (PETRONAS) endorsed a comprehensive EOR screening in year. The screening study on seventy two reservoirs has identified almost a billion barrels of additional reserves can be achieved through EOR (Samsudin et al., 2005). The Chemical Enhanced Oil Recovery (CEOR) was identified as one of the key EOR processes that have good potential for field implementation to increase ultimate recovery in Malaysian oil fields (Othman et al., 2007). Chemical EOR processes are being considered for large field applications with recent high price of crude oil (Ibrahim et al, 2006). These include surfactant (S), surfactant-polymer (SP), and alkali-surfactant-polymer (ASP). ASP flooding has been used widely in a field application with great success (Pitts et al., 2006; Pratap and Gauma, 2004; Clara et al., 2001; Wang, et al., 1997; Hong-Fu, et al., 2008). It uses the benefits of the three flooding methods simultaneously and oil recovery is sufficiently improved by decreasing the interfacial tension (IFT), increasing the capillary number, and improving the mobility ratio (Pingping et al., 2009). Despite the potential of ASP flooding, the approach towards ASP in Malaysia has taken a conservative route. This could be attributed mostly to the fact that all of the producing fields are located offshore. Offshore environment poses a number of challenges (Hamdan et al., 2005). One of the primary considerations for chemical flooding application in Malaysia is the use of seawater rather than softened water as injection water (Hamdan et al., 2005). However, using seawater adds other problems to the process. Adding alkaline agents such as sodium carbonate or sodium hydroxide will result in precipitation of the anions with divalent metal cations (calcium, magnesium, potassium. etc) in the seawater. The alkali has also a detrimental effect on polymer performance and in

The Effect of Water Salinity on Silica Dissolution Rate and Subsequent Formation Damage during Chemical EOR Process

During chemical EOR process, silicate scale has significant impact on the well productivity, rod pumps and other surface facility. The formation of silicate scale is a complex process involving silica dissolution, polymerization and subsequent precipitations. This paper presents the results of static and dynamic experiments that describe the effect of injection water salinity on silica dissolution rate and subsequent impact on formation permeability. Various synthetic brine salinities were utilized to determine the change in the silica dissolution rate using sandstone core samples. Results from static experiments indicated that 6.5% of the original silica was dissolved with the highest brine salinity of 60,000 ppm. Additional results demonstrated that the silica dissolution ratio has a significant effect on the initial core permeability. Using 60,000 ppm brine and 2.5% alkali, the initial permeability was reduced from 25.3 mD to 20.3 mD. The corresponding permeability reduction ratio for this case was 19.76%, which is equivalent to silica dissolution ratio of 15.99%. Finally, it is found that the brine salinity and pH has a pronounced impact on silica dissolution rate during chemical EOR process.

Erratum to: Experimental investigation of immiscible supercritical carbon dioxide foam rheology for improved oil recovery

The original version of this article unfortunately contained a mistake. The presentation of an author’s name was incorrect. The corrected one is given below.

The application of acrylic acid as precipitation inhibitor for ASP flooding

Alkaline-Surfactant-Polymer (ASP) flooding has shown incredible successes for enhancing oil recovery for both sandstone and carbonate reservoirs. However, the main constraint of ASP flooding in carbonate reservoirs is the presence of undesired minerals either within the reservoir rock or reservoir brine. These minerals could react with the added chemicals to form their insoluble salts as precipitations. In this paper, the performance of the acrylic acid was evaluated in the presence of sodium metaborate as an alkaline, alpha olefin sulfonate as a surfactant and AN-125 SH as a polymer. The effect of various acrylic acid concentrations on alkalinity, interfacial tension reduction and polymer viscosity were investigated using hard brine with a total salinity of 59,940 ppm. Fluid-fluid compatibility test indicates that acrylic acid has the potential to prevent any precipitation when hard brine is used. The acrylic acid to alkali ratio of 0.6:1 was found to be the optimum ratio for keeping the solution without precipitations for 30 days at 80oC. It was also observed that the combination of ASP with acrylic acid has a positive effect on interfacial tension and solution viscosity. This makes the new system more flexible for offshore application in which hard brine or sea water could be used to prepare ASP slug without any negative effects.

A Rheological Study of Polymer Using Precipitation Inhibitor, Alkali, and Surfactant for High Salinity in Carbonate Reservoirs

In the present study, a new chemical formulation is designed by combining acrylic acid with the conventional alkali-surfactant-polymer (ASP) components. Acrylic acid generates precipitation inhibitor that dissolves insoluble salts. The salts known as precipitations are formed by the reaction of added chemicals with carbonate reservoir minerals or brine compositions. Various fluid-fluid compatibility tests were first performed to find an optimum acid-alkali ratio to keep ASP solutions without any precipitations for 30 days at 80°C. Using the optimum ratio, a comprehensive study was conducted to investigate the impact of acid, acid-alkali, and acid-alkali-surfactant on the viscosity of copolymer. The optimum acid-alkali ratio was found 0.6:1.0. It was observed that blend of acid with ASP solutions did not cause significant impact on the polymer viscosity. This new chemical combination provided sufficient viscosity for mobility control in the hard brine environment. Hence, the main feature of this work is the development of acid-ASP formulation, which can be more feasible for enhanced oil recovery in carbonate reservoirs as compared to conventional ASP.

Effect of polymer additives as foam stabilizer for CO2 foam flooding

T prolific Niger Delta basin is a mature petroleum province. Therefore, further prospectivity in the basin lies within deeper plays which are high pressure and high temperature (HPHT) targets. One of the main characteristics of the Niger Delta is its unique diachronous tripartite stratigraphy. Its gross onshore and shallow offshore lithostratigraphy consists of the deep-seated Akata Formation and is virtually exclusively shale, the petroliferous paralic Agbada Formation in which sand/shale proportion systematically increases upward and at the top, the Benin Formation composed almost exclusively of sand. This stratigraphic pattern is not exactly replicated in the deep offshore part of the delta. The downward increasing shale percentage in the older and deeper parts of the basin poses a great problem to drilling. Increasing shaliness usually leads to wellbore instability and such other problems as pack-offs and stuck pipe. These hazards are the main causes of non-productive time in expensive deep-water or high temperature and high pressure (HPHT) drilling operations. Moreover clay mineral diagenesis generates mixed layer clays at higher temperatures and this tends to cause overpressures that may lead to disastrous kicks, losses and even blowouts. Predicting and managing drilling in such over-pressured or problem sections will form a major part of the evaluation for exploration and development in these parts of the delta. A formation sensitivity test consisting of the detailed study of the influence of various ions on the degree of formation damage of one of the main producing fields in the eastern Niger Delta has been studied. Analytical results of clay mineral composition obtained using X-ray diffraction (XRD) methodology were successfully applied to predict the various types of clay minerals present and hence intervals problem of shales. Further experimental formulations derived using Capillary Suction Time (CST) tests found that addition of 7% KCl to the original water based drilling fluid made drilling through the problem sequences easier leading to very good cost savings and compliance with the Nigerian environmental regulations. The operator has planned deeper drilling and further development of the field.Introduction and objectives Due to the increase in oil price and its cumulative usage, enhanced oil recovery (EOR) processes have been introduced worldwide in the last two decades. The capillary and viscous forces lead to oil recovery using the primary and secondary recovery processes, and the remaining trapped part of oil is produced. Since the new technologies emerged in oil industry for viscous oil recovery, the perspective of the world’s oil provision has been changed. Cyclic Steam Stimulation (CSS) is a thermal recovery method which is applied for heavy oil reservoirs. Other techniques include, in-Situ Combustion (ISC), Steam Assisted Gravity Drainage (SAGD), and Continuous Steam Injection ].Steam Assisted Gravity Drainage (SAGD) is one of the common thermal processes in which a pair of horizontal wells is drilled. This process was later modified to reach to higher efficiency values by introducing Fast SAGD, and NCG’s SAGD processes. In Fast-SAGD process, the system is equipped with offset wells using cyclic steam stimulation to increase the rate of growing the chamber sideway. The CSS process then begins at higher pressures in respect to SAGD wells. Following this approach, the steam chamber is grown laterally. In the present study, the effect of operating parameters including CSS well elevation, CSS well injection pressure and rate, CSS well starting time, spacing of SAGD wells and SAGD wells injection rate are studied on oil recovery factor. The optimum operating conditions is obtained using the CSOR and net present value (NPV) as the goal function.

Controlling Gas Mobility in Water-Alternating Gas Injection by Surfactant Blend Formulations

Controlling the viscous fingering in water-alternating gas injection, addition of foam with injection water is more favorable. The use of foam surfactant is one of the potential solutions for reducing the gas mobility. The main objective of this study is to generate stable foam for gas mobility control using surfactant blend formulations. Surfactant blend synergistically exhibit better foaming properties than those of individual surfactant. The blend contains anionic as primary surfactant and amphoteric as a foam stabilizer. Surfactant blend improves the foam stability and reduces the destabilizing effect of crude oil. Alpha olefin sulfonate (AOSC14−16) is selected as a primary surfactant. Amphoteric surfactant lauryl amido propyl amine oxide (LMDO) is selected as an additive. The foam was generated in the absence of crude oil in porous media by using Berea sandstone core samples at 96 °C and 1400 psi. The increase in differential pressure showed reduction in gas mobility. The average mobility reduction factors of surfactant blend 0.6%AOS and 0.6%AOS + 0.6%LMDO at reservoir conditions were resulted as 2.5 and 4.35, respectively. The experimental results showed that the blend formulations play an imperative role in minimizing gas mobility during water-alternating gas injection.