Mubadala Petroleum planned to drill a complex Extended Reach Well (ERD) from an existing platform. To reach the required geological targets, the preferred wellpath was required to pass within close proximity of an adjacent oil producer that had a resultant separation factor (SF) of 0.70. A SF of less than 1.0 presents a mathematical possibility of well collision due to overlapping Elipses of Uncertainties (EOU). As such there was the likelihood of the inability to drill the well with a consequencial impact to the Mubadala business plan. A novel solution was by implemented by utilizing High Inclination Drilling with Gyro (HIDWG) tool to safely manage and mitigate the risk of well collision. The Jasmine field is a mature, complex oil field containing multiple stacked sandstone reservoirs, largely having individual oil and gas water contacts that have been on production since 2005. One of the major challenges is safely and economically accessing the remaining bypassed oil. Wellpath collision is an ever increasing risk as the ageing assets become more congested, which could lead to property damage and losses of production. Collision avoidance is gauged with a SF that takes into account the well depth, toolface, and the error model of the electronic survey tool. A conventional Bottom hole Assembly (BHA) with Measurement While Drilling (MWD) tool was initially considered, however the proximity calcuations yielded a SF of 0.7, and the well could not be drilled according to the company's drilling standard. To manage the risk and safely drill the well, the survey error uncertainty needed improvement. Instead of a conventional MWD, a High Inclination Drilling with Gyro (HIDWG) tool was utilized to reduce the survey error uncertainty to yield higher precision drilling control at depth in excess of 10,000 feet and at an inclination higher than 70 degrees. As a result of the BHA upgrade, the SF was instantly improved from 0.70 to 1.0, the collision risk was reduced to an acceptable level, and the well design was compliant with the drilling standard. Furthermore, the HIDWG was utilized for the first time in the Gulf of Thailand. Mubadala Petroleum successfully executed the ERD well utilizing the HIDWG, in combination with an Advance Hybrid Rotary Steerable System (RSS). The HIDWG tool provided an all-inclusive real-time surveying solution that delivered highly accurate surveys and with the Advance Hybrid Rotary Steerable System (RSS)'s precise drilling control throughout the intervals of close proximity with other wells. This paper explains how the HIDWG tool provided an inclusive surveying solution that could deliver both high accuracy surveys and precision drilling control throughout the zones of anti-collision concern of the ERD well. The chosen solution enabled the ERD well to be drilled to the required target successfully and allowed production to be established as planned.
The first PTTEPI deepwater well in 1,003m water was drilled in the Gulf of Martaban, Myanmar in 2013. The tight deepwater rig market and single well program made it difficult to secure a rig, but a newbuild 6th generation drillship was eventually contracted. Non-Productive Time (NPT) is always the major concern when using a newbuild, especially in deepwater where the operational cost was 62,500 USD/hour. This paper explains how NPT was kept to acceptable level, describing the procedures employed.The drillship used was identical to a sister rig which had already started the operations and lessons were learned from that. Start-up NPT from the previous rig was found to be 12.4% in the first 2 wells and the majority of this resulted from drawworks, BOP and Top-drive issues. Sub-sea equipment downtime was especially damaging in deepwater due to the extended time required to pull and re-run the BOP. This area was, therefore, a primary focus.Third party inspection of BOP systems was witnessed by company representatives and a comprehensive testing and inspection program was designed to simulate operations wherever possible. Pre-running and Post-running tests were performed per API standard 53 and all tests were completed successfully. When the rig was in operation, BOP running procedures were strictly enforced. Contractual clauses were also agreed between the contractor and operator to minimise the impact of any start-up NPT.Logistics planning of equipment, bulk, and chemical also played important part of downtime minimization. As the turnaround time from shorebase to well location was 5 days, lots of loadings had been done before rig departed from Singapore.At the end of the well, drilling operations were found to have been performed efficiently. Rig NPT was only 6.9%, but with the majority of this resulting from problems with a new design of diverter system. This level of NPT was impressive for a newbuild high technology drillship, being 70% lower than the figure for start-up of the sister unit.
In 2013, PTTEP drilled a deepwater well in the Gulf of Martaban, Myanmar. The water depth was 1003m with riserless drilling over 1000m below seabed. Being exploration well without any reliable offset well, shallow hazards risk was high. Shallow hazards analysis was performed, showing the high risk of shallow water flow. Shallow water flow causes many incidents, including surface casing cement failure. It can happen during cementing, cement phase transitioning, and after the cement has set. Cementing with the shallow water flow presence is, therefore, the critical operation to achieve the well integrity. Using special cement systems, foam or ultra-lightweight, is expensive, logistically challenging, and operationally complicated. After thorough risk analysis and mitigation, conventional class G cement system was selected.Information from 12-1/4Љ pilot hole and actual 26Љ hole were analysed for cementing plan. Shallow water flow occurred at 1819m in pilot hole. Pump and dump was started from 1760m in 26Љ hole to prevent the flow. However, drilling to 2005m encountered another strong flow. So, the critical zone was identified from 2005m downward. For operational success, the critical zone was covered by gas tight tail slurry with API fluid loss control less than 50 mL/30 min, a SGSA transition timer shorter than 30 minutes and a short thickening time to prevent formation fluid migration. Lead slurry was designed for sufficient density and long thickening time to provide enough hydrostatic pressure, preventing fluid migration while tail slurry was setting. Not being ultra-lightweight cement, slurries were pumped with high excess and contain fibrous LCM to mitigate losses risk. Centralisation also contributed to the cementing success.During the cement job, good returns had been observed. No shallow water flow occurred during and after cementing. Operation was continued without subsidence issue.This paper summarises the process of assessing the risks and designing the economical cement operation to mitigate the risks, resulting in safe operation from shallow hazards.
Conductor jetting has been the preferred installation method for deepwater drilling. This type of installation depends on the skin friction between the conductor and the formation, making axial load capacity the critical success factor. Failure of axial load resistance causes well subsidence, incurring high cost in a deepwater environment. In principle, a longer conductor length gives higher axial capacity. The PSC Company has drilled deepwater wells in East Malaysia and plans to drill more wells in the future. The conductor was designed using the same parameters as the nearby fields and the historical data. In addition, third-party companies normally perform conductor analyses based on the Gulf of Mexico soil set-up rate, which is not similar to East Malaysia. These practices have inadequate theoretical support and could lead to failure. The paper objective is to analyse the conductor length requirement for East Malaysia with The PSC Company's planned conductor. The analysis includes the conductor length requirements for different well parameters. The soil profile was derived from the nearby field soil-boring data and previous well parameters to obtain the soil set-up curve. The soil profile was matched with various parameters to analyse the required conductor length. The result describes the significant effect of conductor and jetting bottom hole assembly weight. Higher weight gives more weight on bit, providing high immediate capacity and requiring a shorter conductor. In addition, setting long 20" casing imposes a higher load that requires a longer conductor. However, PAD mud weight and duration before land weight on the conductor do not provide a significant effect. Moreover, other conductor specifications that may be run in the future were analysed, showing the same tendency, where a heavier conductor requires a longer conductor. This analytical method can be recalibrated for other conductor configurations in the future. The information contained herein is provided with the understanding that the COMPANY makes no warranties, either expressed or implied, concerning the accuracy, completeness, reliability, or suitability of the information.
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