Abstract. Water injection has been employed in the Tempino oil field since 1996. The current oil recovery factor is 35% of OOIP. Even though the pressure is still high, the oil production rate has declined rapidly and the water cut is approaching 89%. In order to mobilize the oil from the reservoir more effectively, surfactant flooding is one of the solutions that can reduce residual oil saturation. Interaction between crude oil and compatible surfactant generates microemulsion, as an indication of low interfacial tension. Hence the oil is expected to move out of the pore throat easily. In this research, thirty types of surfactants were evaluated. The hydrophilic lipophilic balance (HLB) was calculated and the interfacial tension (IFT) with the reservoir fluid was measured. HLB criteria were established as an indicator of low IFT, which was then tested for Berea core flooding. The results indicate that an HLB between approximately 2.7 and 3.1 (on Davies' Scale) or greater than 11.5 (on Griffin's Scale) gives low IFT (~10 -3 dynes/cm). This characteristic is possesed by surfactant ethoxy carboxylate with a linear hydrophobic structure. This surfactant produces a high incremental oil recovery according to Berea core flood tests. The AN2NS and AN3 surfactants recovered 90% and 86% of OOIP respectively.

The successful implementation of carbon dioxide-enhanced oil recovery (CO2-EOR) is crucial in increasing oil production and reducing carbon emissions. For this reason, screening criteria are needed for the initial characterization of a suitable CO2-EOR reservoir. The existing screening model treats the screening parameters independently. Therefore, each parameter has its criteria limit and does not relate to the others. However, in reality, several screening parameters are interdependent, so we need a method that treats the interdependent parameters simultaneously. This research develops a new simultaneous screening model using the interdependency of the parameters. Quantitative and actual data were collected from CO2-EOR field documentation worldwide with a comprehensive analysis. A statistical approach with a correlation analysis method was used to determine the interconnected screening parameters. The results were synchronized with the expert domain to match actual physical conditions. The limit of simultaneous screening criteria was acquired by multivariate quality control (MQC) based on the principal component analysis (PCA) method. The proposed screening model was compared with 13 actual projects, and demonstrated improvements to previous models. The results match actual operations and follow the expert domain rules. If the miscible CO2-EOR is met, then the immiscible should also be appropriate but not vice versa. Nevertheless, four different immiscible projects are predicted to be slightly optimistic as miscible or immiscible.

Significant portion of CO 2 is dissolved in reservoir brine during CO 2 -Enhanced Oil Recovery. Dissolved CO 2 forms an acidic environment which could modify rock-fluid interaction. One of the phenomena that could happen due to this interaction is clay swelling which may affect enhanced oil recovery performance.Several experiments were conducted in a number of sandstone core samples, i.e. Imbibition test, Core flood test, Conductivity test, and pH measurement. Imbibition test was conducted to evaluate CO 2 -saturated brine (approached with carbonic acid) performance toward oil recovery during five days measurement compared with brine imbibition performance. Moreover, core flood experiment was run to determine the effect of dissolved CO 2 in brine on injection in sandstone. This is simulated by injecting brine (base case) followed by carbonic acid under 68.3 O C. Thus, conductivity and pH of the imbibed fluids (before & after running imbibition test) were measured to justify occurrence of cation exchange.Interpretation of imbibition test indicated that imbibing carbonic acid, at pH value of about four, resulted in loss of oil recovery about 15% compared with brine due to formation damage caused by clay swelling as sandstone contains clay. The existence of this phenomenon was confirmed by flow resistance at low pH in core sample which was higher than that in brine. This apparent plugging was expected due to severe clay swelling. Meanwhile, the existence of such phenomenon was also clarified with conductivity and pH measurement as there was a great amount of cation exchange.It can be inferred from this study that the rock-fluid interaction from CO 2 -saturated brine can result in adverse effect, such as injectivity problem and loss of recovery. This finding must be considered in planning CO 2 EOR operations, especially when facing condition of watered out oil zone.

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Corrosion is a critical problem during Oil/Gas production, especially in sour field, Hydrogen Sulfide is the biggest contributor in the corrosion of production facilities. During the production period, pipeline will be corroded with reaction between H 2 S and Fe. This reaction will be occured differently in various temperature which determines the rate of your pipeline becoming thinner and thinner then will be unsafe. This paper presents a study about corrosion phenomena in production pipeline in sour field by analyzing the heat transfer to determine the corrosion rate in every part of the pipeline. An analytical model for heat transfer is coupled with fluid flow model, frictional heat and considering the Joule Thomson effect for steady-state condition. Then, from the analysis of the heat transfer, the corrosion rate in every section of the pipeline, 300 ft, will be obtained. This corrosion rate is determined from the analytical model. This model is applicable to be used in onshore and deepwater cases, depending on the surrounding condition. Thus, the position in which corrosion happened worst can be located. Coating or doing material selection for the several part of the pipeline could be a solution to prolong the age of the pipeline. Effectiveness is about how long the coating or the material selecting would be placed. Then, it could finally contribute in economical analysis about how much would be invested to reduce the impact of corrosion to assure the better production.