The first successful natural dump-flood in the Malaysian offshore environment provided numerous lessons learned to the operator. The minimal investment necessary for implementing the dump-flood coupled with the lack of recompletion opportunities in the subject wells suggested that direct execution without spending on expensive data gathering activity and extensive reservoir study makes more sense from a business point of view. A similar oil gain compared to a water injection project can be achieved at a significantly lower cost of USD 0.01 to 0.15 million in an offshore environment through dump-flooding. The existing oil producers in the depleted reservoirs in Field B were originally completed and successfully drained oil from in a high-pressured watered-out reservoir below, making it an ideal dump-flood water source. The dump-flood was initiated by commingling the target and water source reservoir through zone change, allowing water to naturally cross-flow into the pressure depleted target reservoir. Once a memory production logging tool (MPLT) confirmed the cross-flow, the offtake well was monitored to determine the impact of the dump-flood and produce once the pressure was increased. Minimal investment was necessary because the operations were executed using slickline. The reservoir model will be calibrated once the positive impact of dump-flood is realized in the offtake well. The first natural dump-flood in Reservoir X-2 has successfully produced 0.29 MMstb as of August 2018 with 600 BOPD incremental oil gain. The incremental recovery factor (RF) from the first dump-flood is predicted to be from 5 to 8%. Based on this success, it was decided to replicate the dump-flood project in other depleted reservoirs with Reservoir X-2 as an analog. Four reservoirs were subsequently identified, each with an estimated operational cost of approximately USD 0.01 million and potential incremental reserves of 0.10 to 0.20 MMstb per reservoir. The minimal investment necessary, the idle status of the wells and reservoirs, and the potential incremental reserves suggested that it is more appealing to proceed with implementing the dump-flood without undergoing an extensive and costly reservoir study. With reservoir connectivity being important to the success of dump-flooding, a more cost-effective approach would be to confirm the connectivity by monitoring the offtake well after the dump-flood is initiated. This approach provides more value because the cost of interference or pulse testing is significantly more expensive than the cost of the dump-flood itself while reservoir connectivity was already indicated as likely by geological data (map and seismic). Through a value driven approach, these dump-flood opportunities become more economically viable, allowing the operator to prolong the life of the assets and maximize the field profit. This paper discusses using a value driven and business approach to implement the dump-flood in a mature field. Valuable insight into the business and technical considerations of implementing dump-floods are described, which are relevant to the industry, especially in today's low margin business climate.

Reservoir X-7, a watered-out reservoir in Field B, was successfully revived by perforating the original gas-cap zone to maximize oil recovery, which increased the recovery factor (RF) from 40% to 46%, resulting in approximately 2,300 BOPD through multiple perforations. Maintaining the oil column sandwiched between gas and water is the standard practice to maximize oil recovery in a strong water-drive reservoir. Despite having a strong aquifer and a thick gas cap, Reservoir X-7 has produced continuously for 30 years without any gas reinjection. The reservoir was producing at 99% watercut, indicating the original oil column was already swept. Subsequent material balance study and saturation log results confirm that oil migrated into the original gas cap. Given the reservoir condition, an unconventional approach was proposed to produce the oil column through the original gas-cap zone. The first gas-cap perforation for Well B-07 successfully produced 500 BOPD, so it was decided to perform three additional perforations (additional perforations) for Wells A-01, B-12, and B-16, which were successful with a total 2,000 BOPD oil gain from the three wells. Subsequent additional perforations was performed in Well B-07 after the original additional perforations watered out. However, the new additional perforations and subsequent ones in Well B-11 resulted in gas rather than oil. Both wells were shut in. Once the new perforations are watered out, the remaining oil potential in Reservoir X-7 will be confirmed by reopening well B-07 and B-11 until either oil or water is produced. The approach has so far provided approximately 2,300 BOPD of incremental oil production, extending well life by more than 24 months and allowing the RF to increase from 40% to 46%. It delivered encouraging results and opened up opportunities for other reservoirs. This paper provides valuable insight into the case study and lessons learned in terms of maximizing oil recovery using original gas-cap perforation. This approach is highly recommended as the production enhancement method for maximizing oil recovery, particularly in mature fields with similar reservoir conditions.

While it is true that reservoir simulation and new technology applications are crucial to unlocking reserves in a field, the first and most fundamental step in rejuvenating a mature field is to verify the existing data and evaluate the basis of the current understanding. This process, while seemingly "routine", can uncover ambiguous data and questionable interpretations, which can mislead the reservoir simulation results unless corrected. The older and more mature the oilfield, the more ambiguities that can be uncovered. The new understanding can be subsequently converted to "quick-gain" opportunities that can be quickly monetized, while maturing higher investment and more complicated opportunities with reservoir simulation. The approach applied in a sample field named Field B comprised challenging the established interpretation and understanding by taking a more thorough look and applying a different approach with the basic data. There are examples of reinterpreting the seismic data, cross-checking pressure and production reports with geological understanding, cross-checking well intervention reports, production and open-hole log data, and challenging the conventional approach and understanding. On top of the detective work, it is also necessary to judge whether the data "make sense" or seem unreasonable. Although simple, this approach was effective and successful in generating multiple opportunities in Field B. This paper provides valuable insight and examples in data verification and challenging established understanding to generate potential opportunities. Having a good grasp of the fundamentals is a valuable skill in a mature field environment. It pays to thoroughly understand the fundamentals, because otherwise, the "fancy techniques" will not work.

Infill Well B-23, which was recently drilled in the CIII-2 reservoir located in the Balingian Province, experienced a rapid pressure and production decline. The production decreased from 2,200 to 600 BLPD within 1 year. Analysis of the permanent downhole gauge (PDG) data revealed that Well B-23 production was actually influenced by two other wells, B-20 and B-18, each located 2,000 ft away. This paper discusses the ensuing analysis and optimization efforts that helped reverse the Well B-23 pressure decline and restored its production to 2,200 BLPD. Based on the typical causes of rapid production and pressure decline, operators initially believed Well B-23 was located in a small, separate compartment compared to Wells B-18 and B-20. Additionally, the Well B-23 behavior differed significantly from Wells B-18 and B-20. PDG data analysis provided clear evidence of well interference despite the significant distance between the well locations. Changes in the other wells immediately affected the Well B-23 pressure, thus leading to the conclusion that production from Wells B-20 and B-18 impeded the pressure support for Well B-23. To optimize Well B-23 production, Well B-20 was shut in while Well B-18 was produced at a reduced rate because of a mechanical issue. The optimization initially resulted in more than 500 BOPD incremental oil from Well B-23. The well pressure decline was reversed, with PDG data showing a continuous increase of bottomhole pressure (BHP) despite an increase in the production rate. Subsequently, production was fully restored from 600 to 2,200 BLPD, and reservoir pressure returned to its predrill pressure. Going forward, the optimum withdrawal rate from the CIII-2 reservoir will be determined to ensure maximum oil recovery from both Wells B-18 and B-23. The case study proved the significant benefit of PDG data, which helped identify well interference as the actual cause of the rapid decline in Well B-23, instead of a reservoir or geological issue. Through in-depth analysis and thorough understanding of the reservoir, the operator restored what initially appeared to be a poor well to full production. This case study shows the clear and strong effect of well interference and highlights how the subsequent results of the optimization effort were rapidly obtained. A comprehensive understanding of the reservoir behavior could not have been achieved at minimum cost without the pair of PDGs installed. The analysis and lessons learned from the Well B-23 PDG data provide valuable insight regarding the impact of well completions to the field of reservoir engineering.

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.