fax 01-972-952-9435. AbstractThis paper presents an enhanced oil recovery (EOR) evaluation for two heavy-oil fields in Africa. The objective of the evaluation is to identify the technically and economically viable EOR techniques for the fields. A total of thirteen established and emerging EOR techniques were evaluated in this study. The study included the first degree approximation of the oil recovery for the viable EOR techniques and the stand-alone project economics estimation.The data required for the study include: 1) fluids and rock properties; 2) driving mechanism; 3) production data; 4) OOIP and recoverable reserves; and 5) relative permeability curves. Various EOR technique screening criteria, consisting of a list of reservoir parameters and their ranges which are likely to lead to a success, were applied to match the parameters of the study fields. The oil recovery predictions were estimated utilizing general reservoir parameters and developed correlations 1 . The economic feasibility of the potential EOR techniques was then evaluated based on the stand-alone project economics that accounted for the revenue from the incremental oil and the associated operating and capital costs.The evaluation results showed that the thermal EOR techniques: steam flooding and in-situ combustion are technically the most viable EOR techniques for the fields. It was then followed by the chemical EOR techniques. The performances of steam flooding and in-situ combustion are both very promising, with oil recovery of up to 49% OOIP. Comparing to the oil recovery of water flooding, a significant incremental oil recovery of 24% OOIP was obtained. However, the in-situ combustion process is able to accelerate the oil production, which significantly impacts the economic viability assessment, rendering the in-situ combustion process as the most technically, and economically feasible EOR process for the fields.Based on the EOR evaluation, the oil recovery predictions and economic assessments of the thirteen EOR techniques, including the chemical, gas, thermal and microbial EOR techniques, served as a guideline to develop the long term corporate strategy regarding the EOR potential of the fields.

After 30 years of waterflooding, distributed temperature sensors (DTS) data on an oilfield has recorded up to 50% reduction in reservoir temperature from its initial value of 120°C. Literature review showed previous efforts are more inclined towards interpretating DTS data to determine layer contribution in a single well rather than studying the impact of temperature change on the field performance and recovery factor. Changes in reservoir temperature will cause a change in reservoir fluids properties and fluids mobilities and subsequent recovery factor will be impacted. In order to determine the impact of reservoir cooling on IWAG (immiscible water-alternate gas) performance, a comprehensive study has been performed combining coreflood experiment with a 3D reservoir modeling. 3D thermal reservoir model has been constructed and calibrated for the purpose of determining the temperature distribution across the field. The model indicates that with higher injection volume of water; reservoir temperature is lowered with temperature distribution highly influenced by the reservoir properties, injected volume, and fluid properties. The coreflood experiments have been performed under isothermal and reduced temperature using a stack of native cores with average properties closely match the reservoir rock that carry most of the oil in place. The results showed an incremental IWAG recovery factor of up to 4% (STOIIP) higher in the reduced temperature experiment compared to IWAG experiment under isothermal conditions. This research paper has demonstrated that ignoring the effect of reservoir cooling in IWAG project can lead to an underestimated IWAG recovery factor and eventually impacting the overall project economics.

An oil sample, collected from the wellhead of a shallow sandstone reservoir, was identified as a very stable crude oil emulsion. This micro-emulsion type crude could not be separated in field separation facilities by gravity settling alone. The emulsion was so stable that it required either a high speed centrifuge or high doses of emulsion breaker to be demulsified. Hence, from the perspective of field operational cost, it is critical to further investigate the potential factors that have contributed to the stability of the crude oil emulsions.The field of interest has been producing for over 30 years and its reservoir pressure has dropped below the original bubble point pressure. All the wells in the field are gas lifted to enhance well productivity. Due to the unconsolidated nature of the reservoir rock, fines migration is one of contributing factors to formation damage. The reservoir crude was identified as biodegraded with missing of intermediate components from the reservoir fluid composition. As such, a structured bottom-hole sampling program was developed and bottom-hole samples were collected below gas lift mandrels while the gas lift was shut-in to thoroughly investigate the contributing factors to the formation of the crude emulsions and to identify the in-situ status of the crude.Potential factors which could contribute to the formation of stable crude oil emulsions include 1) mixing of two or more incompatible crudes; 2) emulsifying agents including surface active materials (asphaltenes and resins, organic acids and bases, injected surfactants or oilfield chemicals) and finely divided solids (clay particles, sands, asphaltenes, wax, scale etc.). This study has investigated several potential contributing factors related to formation of the stable crude emulsions. It was concluded that naturally occurring fines could be the major contributing factor for the formation of the observed stable crude emulsion from the reservoir under study. Effect of gas lift on formation of the crude emulsion was found very minimal since the crude was at emulsion state even at reservoir depth.

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