Two (2) steam flood vertical injection wells are under operation for the last 15 months in a two- pattern pilot. Previous steam injection experience in this reservoir did not indicate serious issues due to the short injection periods for cyclic steam stimulation (CSS) but several well integrity issues have been faced during the steam flood period. Key issues include high wellhead growth, steam leak to the annulus A, annulus between 7” production casing and 4-1/2” injection tubing, and groundwater vapor behind 9.625” surface casing. Negative impacts from these issues on the continuity and effectiveness of the steam flood are recognized and need to be resolved comprehensively. All wells in the steam flood pilot were drilled and completed based on designs and procedures according to thermal well compliance including well equipment, and cementing specification. Production casing was equipped with thermal expansion collars to support reduction in wellhead growth. Completion strategy uses seal bore packer with bore extensions to accommodate tubing movement and Vacuum-Insulated-Tubing to provide maximum thermal insulation. However, the presence of a total- loss zone near the surface (starting from 50 m depth) affects the cement isolation between surface casing and 12.25” open hole. Daily monitoring is performed on each well where key injection parameters and well responses are recorded. Maximum wellhead growth reached 61 cm within the first week and steam leak from the injection string to annulus A started after 6 months of steam injection. Soon after that, groundwater vapor starts to arise from the gap between 9.625” casing and 12.25” open hole. These series of failures occurred in both injection wells within 3 months apart from each other. It is believed that the steam leak to annulus A resulted in thermal transmission to groundwater vapor. Hoist entries to both injectors indicated that Injector-1 has tubing seal assembly stuck inside seal bore and resulted in parted tubing collar while Injector-2 has tubing seal assembly damage. Both wells have thick oil covering the retrieved seal bore packer. Remedial actions were performed, including a complete change-out of the seal bore packer assembly and top-job cement fill up to surface using fast-set cement to isolate the gap between 9.625” casing and 12.25” open hole to reduce wellhead growth. As a result, the maximum wellhead growth became only 19 cm and 4 cm in Injector-1 and Injector-2, respectively. These remedial actions also led to restoring well and thermal integrity. Retrieved seal bore packer was sent back to manufacturer for appropriate failure analysis and providing useful feedback reports on the above issues. Monitoring and observation data along with failure analysis should provide vital information and possible improvement in completion strategy for steam injection wells that are planned for continuous steam flood projects in similar reservoirs.

Sand problem and heavy oil has been the major constraint in producing oil in Sesanip Field Tarakan. The field has unconsolidated sand reservoir with grain size D50 of 200 – 300 µm and oil gravity of 18-22 deg API. Under those conditions, Progressive Cavity Pump (PCP) performance and lifetime has been a major constraint in producing the field. Five production scenario been implemented to acquire the most optimum lifting method. Production scenario was divided into two phases. First phase was implementing PCP without sand control. This production scenario was used as a baseline for improvement. Second phase of the production scenario was to add sand control into the production system. Improvement between the two production scenario will be assessed using several criteria; lifetime, cumulative production, economic analysis. In the first phase, three production scenarios with PCP below perforation, PCP above perforation, and PCP with controlled production rate were implemented. Whereas in the second phase, results from downhole configuration of screen installed to pump intake, and installation of screen using seal-bore packer were compared with first phase results. Comparison between five producing scenario were analyzed according to the criteria determined. Based on the first phase results, excessive sand production was evident when producing in optimum rate. In order to minimize sand production, production rate must be limited and therefore sacrificing artificial lift potential. Second phase gave two different results. PCP installation with sand screen installed to pump intake gave the lowest cumulative production, lowest revenue, and longest pay out time. Although sand screen was used, the lack of sealing above screen meant that sand was allowed to pile up in the annulus and eventually restricting influx. PCP with sand screen installation using seal-bore packer delivers optimum trade-off between lifetime, cumulative production and economic values. By applying this production method, sand production from the reservoir will naturally form sand-pack between perforation and sand screen. Although this sand-pack would decrease productivity index, but it compensates with higher lifetime. Based on recent well service activity, no sand pile was present inside screen or above seal-bore packer.