Medco LLC has initiated cyclic steam stimulation of XYZ formation in one of a green field located at South Oman. The fields contains under-saturated and waxy medium to heavy oil (18 °API) with initial viscosity ranging from 650cp to 1200cp at reservoir conditions. The reservoir is unconsolidated sand with average porosity and permeability of above 30% and 3 Darcy respectively. The XYZ formation are continental deposits with thick units of coarse-clastic channel fills including conglomerates with high clay matrix content, rapid (proximal) deposition, and rare lignitic sediments indicating perhaps a more arid rather than humid environment. The unit is confined to South Oman in an approximately 300 km long NE-trending depositional low. This is associated with salt withdrawal along the Eastern Flank of the South Oman Salt Basin. Samples from the core well indicated dominantly quartzarenitic sandstone. Quartz grains are dominantly moderately sorted with few poorly sorted sections that are mostly bioturbated. Overall digenesis is dominated by generally moderate compaction, infiltration of detrital clay, precipitation of quartz overgrowth. Calcite cements present as typically pore-occluding developments, with common effect on overall porosity. Primary intergranular pores are common; dissolution porosity is noted with dissolution of grains or cement. Horizontal wells typically yield a higher primary recovery than vertical wells due to their larger contact area with the reservoir. The original expectation for primary production performance of these wells has not been achieved for three reasons: high oil viscosity, formation damage and sand accumulation around the liner during the early production. Following performance during period of primary production, it was considered to utilize vertical wells configuration under thermal stimulation using cyclic steam, with the use of steam as both heating and lifting agent; additional recovery is expected to be achieved. Cyclic steam stimulation has been implemented in three selected wells spread over the field to give a better understanding of various reservoir characteristics response to stimulation process. The treated wells are vertical wells at 800 TVDSS / 1150 MD with initial reservoir temperature and pressure is 55 °C and 11000 kPa respectively. The total steam injection varies from 2000 to 3600 ton of steam with 85% steam quality in order to acquiring the valuable data and operation experience. Actual results are better than predicted in simulation studies with CSOR (cumulative steam-oil ratio) of about 0.5 to 1.0. This paper described the started from the completion design, cold production performance, preparation and the execution as well as well evaluation of the practical application of CSS are the main keys to understanding reservoir performance and identifying that opportunities of steam stimulation will improve the ultimate recovery.

Increasing oil production and recovery for Heavy Oil can be achieved by reducing oil viscosity. With reference to Darcy law, reducing the oil viscosity results in an increase in oil productivity. The current technologies for reducing viscosity are Steam injection and Miscible Gas (hydrocarbon or carbon dioxide) injection. However both steam and miscible gas has technical and economic limitations, and an alternative technology is required to extend beyond the limitations in both steam and miscible gas injection.The technology described herein is based on reservoir fluid and rock modification by chemical technology approach. Reservoir modifications are made by ability to mix between oil and water, and the mixed viscosity is designed to be reduced to close to, but higher than, water viscosity. Because the viscosity is still higher than water viscosity, the fluid flow becomes slower and will have enough time to react with oil and divert to the oil bank. When the modified chemical is diverted to the oil bank, then wettability alteration acts to peel out oil from the rock surface and has ability to pass through pore throatand hence flow to producing oil well.The research programewasconducted by mimicking reservoir behaviorby implementing mixture viscosity sensitivity performance test, imbibition tube test and coreflood test. The tests are implemented usingactual reservoir oil, water and rock. The result of viscosity reduction is able to reduce oil viscosity from more than 376 cp at reservoir temperature to less than 10 cp mixture viscosity at temperature between 60 and 90°C. For comparison, steam injection is able to reduce viscosity of heavy oil to become less than 10 cp, but requires a temperature of 350°C instead of 60 to 90°C. The imbibition test has shown incremental oil recovery at 14.7 psi (atm pressure) of two times that of reservoir water only, while the laboratory result with coreflood shows additional recovery after chemical injection of 30% to 50% beyond primary and water injection stage.The implementation is technically simple and it is able to be conducted at relatively low cost. The result from implementation by well basis injection yielded a significant increase in oil production. By sharing this road map experience from laboratory result to field implementation of the new method of chemicalstimulation forheavyoil production, it provides an alternative to improve production and recovery of heavyoil, especially in the Middle East.