Two offset wells were drilled in a field in East Malaysia, the original well and a sidetrack from the original well. Both wells experienced total lost circulation and Pressurized Mud Cap Drilling (PMCD) was attempted, but was not successful. A total of 55 days were spent drilling both offset wells, without achieving the primary well objectives. After a 4-year gap, a re-drill well was planned and a specialist PMCD service provider was approached to drill the well. The PMCD team worked closely with the Operator's drilling team through the early stages of planning including well design, completions, fluids, logistics, BHA design, mud pit arrangements and drilling procedures. The lessons learnt from the previous wells were analyzed and precautionary steps were taken to avoid similar mistakes in the planned re-drill well. Field proven PMCD operational procedures were provided and experienced field personnel were assigned for on-site execution. The re-drill well hit total losses and was converted to PMCD after evaluating the characteristics of the well. The section was drilled to the planned Total Depth (TD) in one run, a section length of 430m. A Composite Bridge Plug (CBP) was stripped in hole and set in the previous casing to isolate the carbonate section. The 7″ liner was made up with a drill shoe and run in hole, and the CBP was drilled out. The well went back on losses after drilling the CBP and PMCD mode was re-established and the 7″ liner was stripped in to TD. The liner was then set and cemented at the shoe. The well primary objectives were achieved successfully. This paper elaborates on the planning, drilling and completion phases of a successful PMCD operation, with relevant lessons learned and recommendations for future solutions.
SDX was an exploration well drilled on a jack-up rig, which was located offshore on the west side of the Malay basin. The well was classified as an ultra high pressure high temperature (HPHT) due to 455°F (235°C) maximum formation temperature and 11,200 psi maximum formation pressure. SDX was a very important well for a major operator in the attempt to explore and evaluate the potential hydrocarbon prospects in the field. SDX field was well known for its drilling challenges due to extreme narrow window and HPHT condition. The pore pressure ramp steeply increased at shallower depth causing narrow drilling operating window between pore pressure and fracture gradient. Thus, the well was considered as conventionally "un-drillable" and managed pressure drilling (MPD) was a necessary enabler to achieve the well objectives.MPD was deployed to drill the last four hole sections, 12 ¼" ϫ 14 ¾", 8 ½" ϫ 12 ¼", 8 ½" ϫ 9 ½" and 5 ¾" ϫ 6 5/8" to mitigate the challenging wellbore issues. The drilling strategy was to use a lower mud weight (MW) in order to walk the pore pressure line and allow the use of optimum drilling flow rates. Two essential MPD procedures were implemented to safely verify drilling window. The pore pressure ramp was established by performing static flow check (SFC) and the losses limit was established by conducting dynamic formation integrity test (DFIT). Furthermore, total depth (TD) criteria for the MPD section was defined by the minimum window required to perform managed pressure cementing (MPC) for the liners.SDX well was successfully drilled to TD after overcoming defying wellbore challenges due to narrow window, pore pressure ramp uncertainty and HPHT condition. MPD was fully utilized to drill four most critical sections. MPC was performed splendidly for 11 ¾" and 9 7/8" liners without influx or loss. The paper will further explain on how proven MPD solutions were planned and executed to drill this exploration HPHT well. MPD and MPC lessons learned were also highlighted in this paper as part of the knowledge sharing.
Drilling narrow window wells conventionally have been well known to cause major wellbore issues to the Operator in the Gulf of Thailand. Therefore, managed pressure drilling (MPD) has been deployed since several years ago to mitigate the drilling problems. To ensure safety and optimize drilling time, it is necessary to identify the actual pore pressure while drilling wells with narrow marginin order to eliminate kick, ballooning and loss events. The use of automated MPD system to precisely control bottomhole pressure (BHP) during connections combined withthe evaluation of bottom up gas trend while drilling enabled the pore pressure to be predicted accurately in almost real-time condition without the need to stop drilling in the Gulf of Thailand. Thus, the narrow window wells were drilled faster with MPD, which was beneficial for the Operator in the area where the fast factory drilling was necessary to make wells more economical. Furthermore, the use of this new method in effectively determining the actualpore pressure provided solutions to the Operator in mitigating wellbore issues at the same time improving drilling timeafter several years of MPD technology implementations. The estimated pore pressure results acquired with the new methodon several narrow window wells were even comparable to the actual wireline logging measurement results. The objective of this paper is to introduce an effective and efficient method in determining pore pressure (PP) while drilling challenging wells with tight reservoir characteristic by utilizing MPD technology in the Gulf of Thailand. In addition, this paper also describes the drilling strategy, detail procedure and lesson learnedin verifying pore pressure with the new method.
Angsi field in Malaysia consists of 5 (five) production platforms and has long provided the backbone of domestic oil and gas production for PETRONAS in Malaysia. Located in the Malay Basin, about 167 kilometers off the East Coast of Peninsular Malaysia in a water depth of 70 m, Angsi is a joint venture development field between PETRONAS and ExxonMobil Exploration & Production Malaysia (EMPMI), with PETRONAS as the operator. Angsi ERD AST-2 (not actual well name) is an Extended Reach Drilling (ERD) well of 2.7 ERD ratio, one of the three (3) successful wells drilled in the un-drained area of Angsi E under the Angsi Early Monetization Project Phase 1.0. Previously, the well experienced two (2) stuck pipe incidents which resulted in lost in hole (LIH) in both the original 8-1/2" hole (ERD A) and the sidetrack hole (ERD AST-1) at the similar true vertical depth (TVD) which was due to wellbore instability issues. Deviation from the original plan by utilizing the Managed Pressure Drilling (MPD) application and adopting best bottome hole assembly (BHA) selection strategy in the final hole (ERD AST-2) has turned these failures into success. Target well total depth (TD) was achieved and the liner was cemented in MPD mode with minimal issues. In the process of drilling this ERD well, the extended reach and highly deviated production hole section carry drilling risks, complexities, and operational challenges which relate to wellbore instability, high torque and drag, poor hole cleaning, cutting bed formation, differential sticking, and also excessive equivalent circulation density (ECD). Reservoir depletion had led to changes in rock stress and a reduction in pore pressure, creating more complications such as wellbore stability and ECD management. The consequences of not utilizing MPD will create a huge potential risk associated with stuck pipe, lost hole sections and failure to complete the well. Managed Pressure Drilling was introduced to control cyclical fatigue forces by maintaining the bottom hole pressure (BHP) constant across the weak formations and use the ability to drill with low mud weight in order to reach higher flow rates and as a consequence, improve hole cleaning. The drilling mud weight (MW) was designed to be 2 ppg below the mechanical stability point and the ECD was maintained within a window of 0.3 ppg during the entire drilling and tripping operations. Scheduled MPD rollovers from light to a heavy and heavy to a light MW at the shoe were carefully followed in order to maintain ECD within the pre-established window prior to pulling the BHA out the hole or changing rotating control device (RCD) sealing element. This paper aims to describe the application of Automated MPD for this specific ERD case from conceptual, planning to execution. Moreover, it is intended to share the challenges observed during the execution phase as well as the decisions taken to overcome these challenges and share the strategy of ensuring the wellbore being stable prior to POOH and proceed with MPD liner running and cementing.
The JST-1 well is an offshore High Pressure and High Temperature (high pressure by gradient which was more than 0.1 psi/ft) exploratory well, located in the block SK 301A.The primary objective was to evaluate the hydrocarbon potential in Cycle VII and Cycle VI, at the depth of 2374 and 2794 mTVDDF respectively with anticipated reservoir pressure of 5476 and 6898 psi with temperatures from 226 to 264°F at well TD 3477mMDDF/TVDDF the pressure and temperature was predicted to be 9276 psi and 302°F.The well was initially planned to be drilled to 2979 mTVDDF in 12 ¼" hole section and 8 ½" hole section until 3477 mTVDDF. The degree of uncertainty in JST-1 pore pressure and fracture gradient estimates are highly uncertain. This was due to the reason that the offset wells, S-1 and L-1 are very far away from JST-1, approximately 33 km away to the North West and 35 km to the North East respectively. In addition, none of the offset wells have been drilled deeper than 2879 mMDDF. Therefore, high case pore pressure and fracture gradient estimates were used for the well design and planning.Based on cementing simulation for the 11 ¾" liner, 9 5 ⁄8" casing cementing jobs, the resultant cement slurry Equivalent Circulating Density (ECD) will fracture the formation while the cement is pumped into the open hole. Hence, the Managed Pressure Drilling (MPD) method was used to drill hole sections lower than 13 3 ⁄8" casing as well during the cementing job and running in hole with 9 5 ⁄8" casing.This paper aims to describe the application of Automated MPD on this specific well from conceptual to planning to finally execution. Moreover, with the intention to share the challenges observed during execution as well as the decisions taken to overcome these challenges and finally the 5 steps strategy to ensure the well was stable. Well ChallengesDuring drilling, Dynamic Flow Checks (DFC) and Dynamic Formation Integrity Tests (DFIT) were performed using the MPD system to identify and confirm operating window. The target total depth for
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