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.
Abdulhadi, Muhammad (Halliburton Bayan Petroleum) | Kueh, Pei Tze (Halliburton Bayan Petroleum) | Zamanuri, Aiman (Halliburton Bayan Petroleum) | Thang, Wai Cheong (Halliburton Bayan Petroleum) | Chin, Hon Voon (Halliburton Bayan Petroleum) | Jacobs, Steve (Halliburton Bayan Petroleum) | Suggust, Alister Albert (PETRONAS Carigali Sdn. Bhd.) | Zaini, Ahmad Hafizi Ahmad (PETRONAS Carigali Sdn. Bhd.) | Jamel, Delwistiel (PETRONAS Carigali Sdn. Bhd.) | Dolah, Khairul Arifin (PETRONAS Carigali Sdn. Bhd.) | Munandai, Hasim (PETRONAS Carigali Sdn. Bhd.) | Yusop, Zainuddin (PETRONAS Carigali Sdn. Bhd.)
In the recent low oil price environment, a cost-effective solution was proposed to use through tubing bridge plugs to perform water-shut-off (WSO) in an offshore field. The solution consisted of using slickline to set a plug with a high expansion ratio followed by a cement dump. After three WSO jobs in different wells, the method has successfully proven itself. Watercut was reduced from 100% to 0% with a minimal cost of only USD100,000.
The through tubing bridge plug used is capable of passing through 2-7/8-in. tubing and expanding into 9-5/8-in. casing. After running a Gamma-Ray log, the plug was set across the perforation interval to give the anchor contact with a rough casing surface. The top of the plug, however, was above the perforation interval and became the base for cement. Cement was then continuously dumped on top using a slickline dump bailer in a static condition until the designed cement height was reached. Static conditions ensured no movement of cement during operation. The plug differential pressure limit is directly proportional to the cement height.
The first WSO job was a complete success with watercut reduced from 100% to 0%. The second job however, was partially successful as the cement dump was not completed due to unexpected appearance of a hold-up-depth (HUD). The HUD was created by leftover cement which had accumulated at the end of the tubing. Despite the setbacks, the end result was successful in reducing water production from 1000 bwpd to 200 bwpd. The third job faced a completely different problem. The original plug fell off deeper into the well after it was set. To rectify the situation, a second plug was set at the target interval. Despite the successful execution, there was no change in watercut after the well was brought back online. Since the same method was proposed for another upcoming well, Memory-Production log (MPLT) coupled with Temperature-Noise log was performed to assess the effectiveness of the WSO. The log results confirmed that the WSO was successful and the post job water production was caused by channeling behind the casing. The results so far concluded that the through tubing bridge plug WSO method was both reliable and cost-effective. It is exceptionally suitable for zones located at the bottom of a well and can be deployed using slickline.
The paper provides valuable insight to a WSO solution which should be a first-choice option due to its relatively inexpensive cost and high reliability. The solution has proven to provide tremendous cost saving for production enhancement activity.
A water injector located in an offshore Sabah field, Malaysia was sidetracked and completed as a single string completion on 13 September 2006. This water injector was designed for 10,000 barrels per day of seawater injection. It was completed as open hole with swellable packers targeting H sand only. However, due to differential sticking while running completions, the completion string became stuck at 700 feet above the intended setting depth. Since then, the well had been closed to avoid the risk of nearby fault activation.
Due to the initial injection behavior of the new injector and the fear of fault reactivation, it was decided to re-complete an injection well by isolating the area near the fault it was intersecting. This was achieved by setting bridge plugs to isolate existing zones and re-perforate a new zone above the plugs. The original consideration to recomplete the well in 2008 was to use a conventional coiled tubing unit to access the horizontal section of the water injector. Due to the small size of the platform at this well, there was not sufficient space for placement of coiled tubing surface equipment, a dedicated barge equipped with catenary system had to be considered. Total cost and anticipated risks were high and as such, recompletion of this water injector well by way of a conventional coiled tubing unit had to be classified as low priority due to limited barge time allocated in the 2008 coiled tubing intervention campaign, which naturally became non-feasible and non-viable to execute.
An unconventional method of recompleting the horizontal water injector purely on electric wireline and wireline tractor was then considered and evaluated in 2009, in terms of technical do-ability, economics and risks involved. Recompletion of the water injector was then executed successfully in the same year purely on electric wireline on a shore-offshore-shore daily tripping arrangement at one fourth of the originally anticipated cost when compared to a barge involvement. Successful reactivation of the water injector well realized a significant increase in reservoir ultimate recovery as well as oil gain over the following years of production from the H sand.
This paper will describe the background of the project, recompletion concept selection and well delivery process, actual execution and result of operations. The identified key success factors are also discussed.