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BACKGROUND: Microbial corrosion is a serious challenge for the oil and gas industry worldwide, leading to huge economic losses and production issues. Successful mitigation of microbial corrosion requires a complete characterization of the microbial community present in the system. This paper deals with the extensive microbial analysis and study of performance of biocide formulations for different water types in an oilfield. RESULTS: Water, solid and coupon samples were collected at various points in the production system and analyzed for total microbial numbers by quantitative polymerase chain reaction (qPCR) and microbial diversity using next-generation sequencing (NGS). A high-throughput multi-well system was used to screen eight different biocide formulations at various dosage levels.A pipeline simulator reactor was developed and used to represent field conditions such as temperature, flow and shear rates.The tests showed that the dominant microbial species causing corrosion were sulfate-reducing Desulfovibrio spp. in seawater and brackish water systems and acid-producing fermentative Halanaerobium spp. in effluent water. The results showed that different biocide treatment strategies have to be adopted for treating different water types. Biocide formulations containing ADBAC and THPS + surfactant showed the most promising results for seawater, whereas biocide formulations of ADBAC and THPS + glutaraldehyde performed better for brackish and effluent waters. CONCLUSION:The study has shown that molecular methods such as qPCR and NGS provide better and accurate evaluation of the microbial community in the field compared with conventional growth-based methods, leading to optimized mitigation strategies. Microbial community structure analysisMicrobial community structure analysis was investigated by targeting and amplifying the 16S rRNA gene sequences of bacteria (region V1-V3) and archaea (V4-V6), subsequently sequenced J Chem Technol Biotechnol 2019; 94: 2640-2650

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Carbon dioxide miscible flooding is a proven EOR method. It faces two significant challenges: gravity override and early CO2 break through. Many researchers have investigated different methods to control CO2 mobility and improve its sweep efficiency. This paper, for the first time, investigates the use of a new and unique CO2-foam (emulsion) to control CO2 mobility and also as a conformance control technique in heterogeneous reservoirs with high permeability contrast within carbonate rocks. The new CO2-emulsion system consists of 50-70 vol% supercritical CO2, 50-30 vol% of water-based polysaccharide linear polymer and a foaming agent (surfactant). Several experiments were conducted using HPHT visual cell to assess the CO2-emulsion stability as a function of temperature, pressure and time. In addition, the rheological properties of the CO2-emulsions were investigated at different shear rates, different pressures and mixing ratios, and at an operating temperature of 220°F. Special dual core flooding experiments were conducted using live oil at reservoir conditions to investigate the effectiveness of CO2-emulsion system in enhancing oil recovery. Several experiments were conducted to explore the effect of injection rate, injection mode and slug volume on incremental oil recovery. These experiments were performed using dual core holders with different permeable carbonate composite stacks, and permeability contrasts up to 35. Results based on this study have shown that the CO2-emulsion system is stable at 210°F for extended periods of time without any emulsion breakage or phase separation. The effective viscosity of CO2 was increased by 3-4 orders of magnitude and approached 100 cP at reservoir conditions. Results also show the emulsion's ability to severely reduce permeability of the higher permeable cores resulting in significant incremental oil recovery from the lower permeable cores. This new and unique emulsion system has the ability to be created in-situ to provide better mobility control of the injected CO2. Additionally, this paper provides optimal design parameters of the new emulsion system to behave as a conformance control agent, and also to enhance the recovery of oil following water and CO2 floods.

Tracers are increasingly being deployed as an effective reservoir monitoring and surveillance (M&S) tool in the oil and gas industry. In particular, the single-well chemical tracer test (SWCTT) is being widely used to estimate remaining oil saturation (ROS) or residual oil saturation (Sor), especially in improved oil recovery (IOR) and enhanced oil recovery (EOR) operations. The test provides a direct measure of ROS in a wider reservoir volume compared to the measurements made by near wellbore logs or cores. A SWCTT was designed and implemented in a carbonate field to determine fluid saturations. The reservoir is heterogeneous with layers of high to low permeability limestone, porosity in the range of 20–30%, and interspersed with patchy layers of dolomites and a very competent anhydrite seal. The SWCTT was conducted in a very mature part of the field near the peripheral water injectors, to determine the residual oil saturation before a planned IOR pilot test. This paper presents the complete design and implementation of the test, operational challenges, and the analyses and interpretation of the results. The depth of investigation was 13–14 feet from the wellbore. Laboratory results of determining the partitioning coefficient of the chemical tracer are described and presented. The design of the tracer test taking into consideration the reservoir properties are shared. Considerable operational challenges in the field and appropriate solutions to overcome them provide a very interesting case study. The returns and analyses of the samples provided a unique set of data that were interpreted using a simple analytical tracer model which was comparable to the reservoir simulations predictions. The Sor was obtained after fitting the tracer return data to a model of the classical convection-dispersion equation. The results indicate that there was no displacement or drift that occurred during the shut-in period. The mass balance of the tracers suggests that more than 98% of the tracers were recovered with negligible tracer adsorption during the test duration. The results are in close agreement with a similar test benchmarked independently by a commercial vendor using a different injection design scheme.