Abdulhadi, Muhammad (Dialog Group) | Tran, Toan Van (Dialog Group) | Chin, Hon Voon (Dialog Group) | Jacobs, Steve (Halliburton) | Suggust, Alister Albert (PETRONAS) | Usop, Mohammad Zulfiqar (PETRONAS) | Zamzuri, Dzulfahmi (PETRONAS) | Dolah, Khairul Arifin (PETRONAS) | Abdussalam, Khomeini (PETRONAS) | Munandai, Hasim (PETRONAS) | Yusop, Zainuddin (PETRONAS)
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.
Abdulhadi, Muhammad (Dialog Group Berhad) | Tran, Toan Van (Dialog Group Berhad) | Chin, Hon Voon (Dialog Group Berhad) | Jacobs, Steve (Halliburton) | Wahid, Muhammad Izad Abdul (PETRONAS) | Usop, Mohammad Zulfiqar (PETRONAS) | Zamzuri, Dzulfahmi (PETRONAS) | Dolah, Khairul Arifin (PETRONAS) | Abdussalam, Khomeini (PETRONAS) | Munandai, Hasim (PETRONAS) | Yusop, Zainuddin (PETRONAS)
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.
Abdulhadi, Muhammad (Dialog Group Berhad) | Kueh, Pei Tze (Dialog Group Berhad) | Abdul Aziz, Shahrizal (Dialog Group Berhad) | Mansor, Najmi (Dialog Group Berhad) | Tran, Toan Van (Dialog Group Berhad) | Chin, Hon Voon (Dialog Group Berhad) | Jacobs, Steve (Halliburton Energy Services) | Muhd. Fadhil, Imran (PETRONAS Carigali Sdn. Bhd.) | Suggust, Alister Albert (PETRONAS Carigali Sdn. Bhd.) | Usop, Mohammad Zulfiqar (PETRONAS Carigali Sdn. Bhd.) | Ralphie, Benard (PETRONAS Carigali Sdn. Bhd.) | Dolah, Khairul Arifin (PETRONAS Carigali Sdn. Bhd.) | Abdussalam, Khomeini (PETRONAS Carigali Sdn. Bhd.) | Munandai, Hasim (PETRONAS Carigali Sdn. Bhd.) | Yusop, Zainuddin (PETRONAS Carigali Sdn. Bhd.)
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.
Hassan, M. Hafiidz (PETRONAS Carigali Sdn. Bhd.) | Rusman, Liyana (PETRONAS Carigali Sdn. Bhd.) | Chandrakant, Ashvin A. (PETRONAS Carigali Sdn. Bhd.) | Haslan, M. Hanif (PETRONAS Carigali Sdn. Bhd.) | Moktar, Nur Syazwani (PETRONAS Carigali Sdn. Bhd.) | Abdussalam, Khomeini (PETRONAS Carigali Sdn. Bhd.)
Matrix acidizing is an attractive treatment choice in clastic reservoirs to remove near-wellbore damage due to its relatively low cost. It has been executed countless times in brownfields East Malaysia with a moderate to high success rate to arrest production decline due to fines migration and scale deposition. Nonetheless, there is a critical need to look back on the choice of treatment chemicals and treatment approach in order to ensure optimum chemical volume, attractive production gain and higher success rate, especially in the current low oil price era. This paper will focus on the planning and successful execution of single-stage acid (SSA) combined with wax solvent stimulation treatments resulting in fourfold increase in net oil production post treatment in two wells in Field X offshore East Malaysia.
Well A18 and C33 experienced production impairment due to formation damage fines and organic scale. Combination of both wax solvent and SSA in the same treatment was used to remove the damage. Application of SSA eliminates the need for hydrochloric acid (HCl) pre and post flush thus reduces treatment volume, simplifies treatment execution and consequently reduces overall treatment time. Additionally, the usage of retarders eliminates fast reaction of hydrofluoric acid (HF) thereby allowing for deeper HF penetration. This paper also discusses the rapid decline observed post treatment for Well A18 is mainly contributed by re-mobilization of fines due to higher flow rates and re-buildup of wax within tubing and near wellbore. Proactive measures such as pressure drawdown management are suggested to prevent reoccurrence in future stimulation treatments.
In conclusion, this paper finds that the combination of wax solvent and SSA was successful in both removing the damage and optimizing treatment schedule. Correct identification of damage source coupled with good treatment design was able to quadruple production from well A18 and C33 in Field X.
This paper presents an innovative approach and cost effective solution in successfully mitigating formation damage caused by a combination of fines migration and organic scale. This single-stage stimulation treatment saves time, treatment volume and reduces job complexity.