The impact of brine salinity and its ionic composition on oil recovery on chalk formations and to less extent in carbonate reservoirs have been investigated extensively in recent years due to the potential of extra oil recovery. Surface wettability was suggested to be the main reason behind such extra recovery. This study investigates the wettability alteration of calcite crystal and carbonates outcrop rock surface aged in model oils of total acid number of 2 and then treated with different brines. Model oils were prepared by mixing toluene with short chain (Heptanoic acid) and long chain (Stearic acid) carboxylic acids and the investigated brines included range of salinity and the effect of individual ions such as SO42−, Ca2+ and Mg2+. The results of this study showed that the long chain fatty acid (stearic acid) strongly adsorbs onto the calcite surface from the oil phase compared to the short chain (heptanoic acid) as confirmed by the measured contact angles. Twice dilution of Arabian Gulf seawater has been found to be a less effecient EOR fluid for wettability alteration as compared to undiluted Arabian Gulf seawater. This was confirmed by the changes in the measured contact angles toward more water-wet for aged calcite in heptanoic acid model oil, aged calcite in stearic acid model oil and aged carbonate in stearic acid model oil systems. Also, it was observed that significant wettability alteration was observed for the twice diluted Arabian Gulf seawater with higher concentrations of SO42− and Mg2+.
Total has been operating oil and gas production from a series of heterogeneous reservoirs offshore Abu Dhabi since 1974. One of the main oil producing reservoirs of Jurassic age has been the subject of a number of EOR studies at lab and field scale to achieve a higher ultimate recovery factor. In 1991, TABK initiated its first gas injection EOR Pilot with full-field expansion in 1997. In 2014 a successful Chemical EOR Pilot was carried out that showed a significant drop in residual oil saturation around the target well. As all the pumping equipment was available for the Chemical EOR project a window of opportunity opened up at short notice to perform a second EOR test on other wells. The literature has recently highlighted successful applications of a relatively cheap commercially available enzyme in mature oil wells around the world with no environmental impact. This would be the first Enzyme EOR application in the Middle Eastern carbonates and, if successful, could provide a logistically simple, cheap method for enhancing oil recovery and assist Abu Dhabi to achieve its objective of 70% recovery factors. Although there had been no time to evaluate the product in Total’s labs it was decided to go ahead with the test anyway in the spirit of supporting ADNOC’s initiative to accelerate the application of emerging technologies. This paper discusses the design, reservoir monitoring and lessons learnt from a "Huff-n- Puff" application of Enzyme EOR. In terms of operations, the campaign was completed successfully; it demonstrated that the application poses no risk of flow assurance or to the environment and has provided invaluable experience of incorporating an EOR Pilot in day-to-day operations. In terms of EOR effect, an increase in oil rate is observed in only one well with no significant decrease in the water cut; in addition, the increase could be equally explained by well stimulation and/or better well stability (less slugging).
The super-giant offshore carbonate oil field started production in 1968 and has been under pattern water flood since 1982. The field is undergoing a major redevelopment utilizing artificial islands and maximum reservoir contact 10,000 ft horizontal wells in a 1:1 line drive. As part of the re-development, Chemical EOR (CEOR) is being assessed for potential application in one of the main oil producing reservoirs. This paper reports on laboratory results of a CEOR study addressing the major challenge of chemical retention in carbonate reservoirs and investigates the feasibility of increasing oil recovery through CEOR processes. In this paper, CEOR processes investigated include surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) for temperature of 100°C, formation salinity of 200K ppm total dissolved solids, hardness of 15K ppm, and reservoir permeability of <10 mD. In the screening and optimization process, more than 100 surfactant formulations and 3,000 pipette tests at ambient pressure and reservoir temperature utilizing surrogate oil were completed to identify two potential formulations: a SP and an ASP which were stable under reservoir conditions. The polymer qualification includes the polymer rheology and transport tests in reservoir cores using different polymer molecules (HPAM, AMPS), pre-shearing rates, and co-solvent types and concentrations. The identified high-performance SP and ASP formulations were further tested in two live oil corefloods where oil recovery and retention were evaluated. A history match of the core flood experiments was performed and input data were obtained for large scale simulations. The chemical formulation design results showed that an SP formulation having high solubilization ratio can be prepared in Arabian Gulf seawater. Large-hydrophobe alkoxy carboxylate surfactant and sulfonate cosurfactant showed promising performance for the given harsh reservoir conditions. Polymer injectivity core flood tests were also performed to assess transport of the identified polymers. Results indicate that the pre-sheared viscous polymer solution transported without plugging or filtering out in a 1 -ft long 6 mD composite core. The live oil corefloods of the SP and ASP formulations resulted in an overall recovery factors of 97% and 93.5%, respectively. However, surfactant retention was high at 0.99 and 0.58 mg surfactant/g rock for the SP and ASP core floods under similar injected PV of chemicals. The analysis of the surfactant retention indicates phase trapping and adsorption on minerals are believed to be the dominant mechanisms for most of surfactant retained in the core. The current study represents a continued expansion of industry experience and includes the identification of two high-performance surfactant formulations which are stable and provide ultra-low IFT under the high temperature, high salinity, and high-hardness characteristic of Middle East carbonate reservoirs.
The concept of an Inflow Performance Relationship (IPR) has long been used to predict or estimate the relationship between pressure drop in the reservoir (drawdown) and well flowrates (production). Such relationships are used to monitor and optimize the producing life of a reservoir; and also for design calculations. Engineers often make use of the IPR to understand the deliverability of a reservoir, as well as to identify and resolve problems which may arise from the exploitation of a field. The IPR concept provides an engineer with the means to determine the performance of a given well by relating inflow (flowrate) to the pressure condition in the well and reservoir at a given time. The most common application of the IPR concept is to consider the effects of different operational conditions on the pressure and flowrate profiles for a given well at conditions other than the initial condition. Except Harris, the models reviewed in the literature were all following Vogel's approach for two-phase vertical wells. This study consists of the innovative approach to regress the coefficients of Harrison Exponential equation. Hence a new correlation for the horizontal two phase IPR was proposed to estimate well performance. The Comparison of the absolute error of the flow rate of available IPR correlations and the proposed correlations was done for statistical analysis. A field case study was also considered in the study and the absolute error calculated for proposed correlation was (0.5468%) which was again the lowest error as compared to the other correlations. The proposed IPR model works as well as the other models at the normal flow condition. It can be used to estimate horizontal well performance conveniently.However, the results produced from the case study gave us further confidence in the correlation proposed in this study since it gives us the least average absolute error of 0.546812%. Statistical analysis and comparison of empirical correlationsUsing the Matlab, the statistical error analysis, the average percent relative error, average absolute percent relative error, root mean square and the correlation coefficient were computed.The average absolute relative error is an important indicator of the accuracy of empirical models. It is used here as a comparative criterion for the accuracy of correlations.The results for the case study are summarized as follows:Vogell (Linear Regression Calculation): The average absolute relative error is 6.06. The standard deviation is 10.99.Fetkovich (Non-Linear Regression Calculation):- The average absolute relative error using is 10.27. The standard deviation is 19.35. Retanto & Economides (Linear Regression Calculation): The average absolute relative error is 5.80. The standard deviation is 10.58.Jabbar `s (Non-Linear Regression): The average absolute relative error is 0.5468. The standard deviation is 1.067.
Enhanced oil recovery (EOR), also referred to tertiary oil recovery, is becoming more critical in the industry as oil production from natural reservoirs is declining and its consumption is increasing. Conventional methods of oil production recover less than 30% of initial oil in place; therefore, EOR techniques are becoming more attractive to recover additional oil from the reservoirs.
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