It is a common practice to run a contact-saturation log to confirm the oil column prior to oil gain activities such as adding perforations or infill drilling. From 2012 to 2017, a total of eight logging jobs were executed in Field B which were subsequently followed by oil gain activities. The eight contact-saturation logging jobs were comprised of pulse-neutron logs in both carbon-oxygen (C/O) and sigma mode. The logs were run in varied well completions targeting thirteen different zones. Four logs were run in single tubing strings while the remaining four were in dual string completions. Certain target zones were already perforated while others had completion accessories such as a blast joint or integrated tubing-conveyed perforating (iTCP) guns across them. Eight of the target zones were later add-perforated while two were used to mature infill well targets. Four of the seven add-perforations results were consistent with the logging results. One of the successful logs clearly indicated that the oil column had migrated into the original gas cap. Of the two infill wells drilled, only one was successful. These case studies in Field B indicate that in conditions of open perforations, trapped fluid across the annulus, and in low resistivity sand, distinguishing between original and residual saturation is difficult with pulse-neutron log. The log measurement was significantly affected. The most obvious lesson learned was that perforating and producing the reservoir would be the best method to confirm the potential oil gain. From a value point of view, it would have been more economical to perforate the zone straightaway if the oil gain activity had similar cost to the logging activity. The lessons learned also helped to establish clear guidelines in Field B on utilizing contact-saturation logs in the future. The paper seeks to present the logging results, subsequent oil gain activities, and lessons learned from the contact-saturation logging in Field B. These lessons learned will be applicable in other oilfields with similar conditions to improve decision making in the industry.

Maturing a secondary recovery project in an offshore multi-fault complex reservoir is challenging because considerable investment is required, especially in a low oil price environment and/or when the asset can no longer produce. However, an 85% reduction in cost with no reduction in reserves was achieved for such a reservoir through de-risking the opportunity and revising the development concept, allowing the project to be sanctioned during a low oil price environment. A water injection project with an estimated cost of 165 MMUSD was initially envisaged during the feasibility stage to increase the oil recovery of a depleted reservoir, and contractual expectations were agreed accordingly. This is due to the availability of seawater offshore and water injection being the standard improved recovery approach in the region. Without adhering to the familiarity, a reservoir simulation study was performed comparing multiple options of secondary recovery. The reservoir simulation indicated that gas injection would provide higher incremental recovery while the investment can be significantly reduced by utilizing the existing gas lift system as a gas injection system. Several improved oil recovery schemes were evaluated with the history matched dynamic model to address the depleted energy. This includes water dumpflood, water injection, and gas injection with recovery factors of 32%, 56%, and 58%, respectively, in comparison to the depletion drive recovery factor of 30%. The gas injection scheme provides the highest recovery factor and expected fastest response and thus was prioritized as the main focus over water injection. The existing gas compressor with ullage, gas source from current associated gas production, and existing idle wells are key enablers for the project. The existing assets also enable the acceleration and further de-risking by a pilot gas injection before drilling infills. The paper highlights the numerous examples of cost-saving initiatives while maximizing the oil recovery from the reservoir. This value-focused approach enabled the project to be sanctioned during a period where most offshore improved recovery projects were abandoned due to the low oil price.

This paper discusses an alternative study approach with multiple lessons learned from a recent successful infill drilling campaign in a medium-sized brownfield. The team conducted a practical and an optimized subsurface study, including the no-frills classical reservoir engineering and a simple sector model to justify the infill wells. From idea generation to monetization of the barrels, it was fast and cost effective without compromising technical assurance. Results of the infill drilling campaign and lessons learned are discussed in this paper. This is a case study on how a comprehensive understanding of reservoir complexity using creative data integration can be an adequate tool for field development. The results of the campaign demonstrated that an optimized study helps the operator and partners make an efficient investment decision in materializing development opportunities.