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Summary Hydrochloric and organic acids have been extensively used to enhance well productivity or injectivity in tight carbonate formations (10 to 50 md). The use of these acids, however, can cause instances of complete production loss. This is especially common due to incompatibilities of the acidizing fluid and oil, which can lead to the formation of acid/oil emulsions and sludge formation. Consequently, it is necessary to properly identify and remove such emulsions or precipitations without causing any further damage. Compatibility studies were conducted using representative crude samples and hydrochloric acid (HCl). The experiments were conducted at various temperatures up to 240°F using high-pressure/high-temperature (HP/HT) aging cells for both live and spent acid samples, in which some of the experiments included an antisludge, an iron-control agent, and a demulsifier. In addition, another set of experiments was performed in the presence of ferric ions (Fe3+). The total iron concentration in these experiments was varied between 0 and1,000 ppm. The results showed that commonly used acid systems were not compatible with representative oil field samples. The amount of sludge formed and the stability of formed emulsions increased significantly in the presence of ferric ions and was more severe in the presence of hydrogen sulfide (H2S). Using a field case, this paper will cover the methodology used to ascertain the source of formation damage from acidizing, study the different factors that influence the formation of acid/oil emulsion and sludge formation mechanism, and show how they can be removed. In this example, acid/oil emulsions, sludge formation, and improper drilling mud filter-cake removal were the reasons behind the production loss. However, the methodology can be expanded to cater the many acidizing failure cases faced in the industry worldwide.
Summary Hydrochloric and organic acids have been extensively used to enhance well productivity or injectivity in tight carbonate formations (10 to 50 md). The use of these acids, however, can cause instances of complete production loss. This is especially common due to incompatibilities of the acidizing fluid and oil, which can lead to the formation of acid/oil emulsions and sludge formation. Consequently, it is necessary to properly identify and remove such emulsions or precipitations without causing any further damage. Compatibility studies were conducted using representative crude samples and hydrochloric acid (HCl). The experiments were conducted at various temperatures up to 240°F using high-pressure/high-temperature (HP/HT) aging cells for both live and spent acid samples, in which some of the experiments included an antisludge, an iron-control agent, and a demulsifier. In addition, another set of experiments was performed in the presence of ferric ions (Fe3+). The total iron concentration in these experiments was varied between 0 and1,000 ppm. The results showed that commonly used acid systems were not compatible with representative oil field samples. The amount of sludge formed and the stability of formed emulsions increased significantly in the presence of ferric ions and was more severe in the presence of hydrogen sulfide (H2S). Using a field case, this paper will cover the methodology used to ascertain the source of formation damage from acidizing, study the different factors that influence the formation of acid/oil emulsion and sludge formation mechanism, and show how they can be removed. In this example, acid/oil emulsions, sludge formation, and improper drilling mud filter-cake removal were the reasons behind the production loss. However, the methodology can be expanded to cater the many acidizing failure cases faced in the industry worldwide.
Heavy oil extraction requires heat introduction to the reservoir to enhance the mobility of oil. While steam injection is one of the most reliable thermal EOR methods for heat introduction, it has several operational, technical, economic, and environmental limitations. This study investigates the effectiveness of a newly developed downhole steam generator which not only minimizes the heat losses due to distance the between generation and injection but accomplishes oil production with lower steam and energy requirements. A test of the downhole steam generator took place in a small 20 acre area northeast Texas with 13 wells accessing a shallow (540 feet TVD) heavy oil bearing sandstone. The viscosity and API gravity of the heavy oil was reported as 3,000 cP at 100 °F and 19 °API. The initial oil and water saturation were approximately 65% and 35% respectively. Steam injection was started in April of 2013 at steam rates of up to 1300 bbl/day of 600°F steam, producing a total of 540 million BTU per day. The steam front was carefully monitored with temperature readings through oil sampling, both on an individual well basis. According to the temperature readings, steam front movement was faster than typical steam flooding cases in such high viscosity oil reservoirs. Preferential steam propagation occurred towards the northwest of the field due to reservoir dipping towards the southeast. The oil production increased on both the 20 acre test site and wells outside of the test site. The varying distances between injection wells and production wells enabled us to observe steam propagation at varying length. Thus, we could acquire produced oil sampling at varying steam exposure times at different locations and depths. Viscosity, density, and compositional analyses were carried out on the produced oil samples. It has been observed that the viscosity and density of produced oil were not improved due to emulsion formation which is a common concern for any steam injection project. However, further analysis revealed that emulsion breaking is possible with the use of asphaltene insoluble solvents or cationic surfactants. Since the novel design of the downhole steam generator allows injection of any additional chemical with steam during the process, these chemicals could be added to the steam stream to enhance the effective steamed area and reduce the flow assurance related problem. The new downhole steam generation tool provides an opportunity to generate steam in-situ and co-inject steam with additional chemicals to prevent emulsion formation and asphaltene precipitation. Thus, this study proves that downhole steam generation can be feasible for heavy oil extraction, even for small, low-rate fields, if all drawbacks (such as emulsion formation and asphaltene precipitation) are considered and the chemicals injected with steam are selected properly.
This study investigates the role of heavy oil polar fractions in surfactant-steam flooding performance. Performance analyses were done by examination of the dipole-dipole and ion-ion interactions between polar head group of surfactants and charged polar fraction of crude oil, asphaltenes. Surfactants are designed to reduce the interfacial tension between two immiscible fluids (such as oil and water) and effectively used for oil recovery. They reduce the interfacial tension by aligning themselves at the interface of these two immiscible fluids, this way, their polar head group can stay in water and non-polar tail can stay in oil phase. However, in heavy oil, the crude oil itself has high amount of polar components (mainly asphaltenes). Moreover, polar head group in surfactants is charged and the asphaltene fraction of crude oils carry reservoir rock components with charges. The impact of these intermolecular forces on surfactant-steam process performance was investigated with 10 coreflood experiments on an extra-heavy crude oil. 9 surfactants (3 anionic, 3 cationic and 3 nonionic surfactants) were tested. Results of each coreflood test were analyzed through cumulative oil recovery and residual oil content. The performance differences were evaluated by polarity determination through dielectric constant measurements and by ionic charges through zeta potential measurements on asphaltenes fraction of produced oil and residual oil samples. The differences in each group of surfactant tested in this study are the tail length. Results indicate that longer hydrocarbon tail yielded higher cumulative oil recovery. Based on the charge groups present in the polar head of surfactants anionic surfactants resulted in higher oil recovery. The further examinations on asphaltenes from produced and residual oils show that the dielectric constants of asphaltenes originated from the produced oil gives higher polarity for surfactant-steam experiments conducted with longer tail length, which provide information on polarity of asphaltenes. The ion-ion interaction between produced oil asphaltenes and surfactant head groups were determined through zeta potential measurements. For the most successful surfactant-steam processes, these results showed that the changes on asphaltenes surface charges getting lower with the increase in oil recovery, which indicates that once asphaltenes are interacting more with polar head of surfactants, then, the recovery rate increases. Our study shows that surfactant-steam flooding performance in heavy oil reservoirs controlled by the interaction between asphaltenes and polar head group of surfactants. Accordingly, main mechanism which controls the effectiveness of process is the ion-ion interaction between the charges in asphaltene surfaces and polar head group of crude oils. Since crude oils carry mostly negatively charged reservoir rock particles, our study suggests the use of anionic surfactants for the extraction of heavy oils.
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