This paper presents a method used in combination with Managed Pressure Drilling (MPD) to determine real time pore pressures while drilling a deepwater exploration well. Not only was the pore pressure accurately determined but additional procedures were implemented to improve efficiency. This deepwater well was the first time MPD used on a semisubmersible rig in Myanmar by both operator and the drilling contractor. MPD was used on all the well sections below the surface casing with the main objectives for MPD listed as follows: Safe and efficient drilling of the well to planned TD. Elimination of contingency casing strings. Enhanced influx detection. Determination of pore and fracture pressure while drilling. The expected pore pressure based on seismic interpretation for the well was provided by the geoscience team. It was presented as minimum and maximum pore pressures. Fracture pressures were provided as sand fracture (minimum) and shale fracture pressures (maximum). A large uncertainty in pore pressures was expected. MPD was combined with real time pore pressure prediction to estimate pore pressures. MPD procedures were reviewed and amended as required to reflect the actual well architecture, actual equipment, and rig capabilities. Most MPD projects are designed to maintain a Constant Bottom Hole Pressure (CBHP) and not to determine pore pressures. Since a significant pore pressure ramp was expected as soon as drilling started below the surface casing a solution had to be found. Methods to make connections and dummy connections were reviewed and discussed to assist the determination of pore pressures using connection and background gas indicators. The devised procedure could be used for all drillstring connections including any dummy connections made throughout the entire well to provide the real time pore pressure team with consistent data. Additional procedures were developed to ensure that bottom hole circulating pressures were maintained using a combination of MPD choke pressures and increasing mud weights while drilling. The paper presents the procedures that were developed and implemented to successfully drill the exploration well to TD. These procedures have now been field tested and proven to be successful not only to accurately determine pore pressures but also to ensure mud weight management. The procedures will be used again on future wells to determine pore pressures and manage BHP to ensure that maximum benefits are derived from MPD operations on deepwater exploration wells.

In August 2014, PTTEP International started an appraisal drilling campaign in M9 block offshore Myanmar. The scope of work was 10 wells to be drilled using a moored semi-submersible rig. The purpose of these wells was to further firm-up the hydrocarbon potential of the field and also to find additional reserves within the Zawtika gas prospect to support field development plans which included platform installations in future project phases 1B & 1C. Therefore, ensuring integrity and proper well isolation for drilling, testing and well abandonment purposes was of critical importance. Maintaining operational integrity and surface efficiency is also highly required considering the challenging conditions typical of any remote location like Myanmar.Offshore project management in Myanmar is quite challenging. Many operators find that the far distances from out-of-country support facilities and load-out points to well locations make logistics a critical success factor with huge potential to affect cost and key performance indicators. In this project, the requirement from fast-drilling and high frequency of cement jobs it was important to eliminate any issues arising from design and preparation. One of main technical challenges was overcoming the risk of lost circulation. The top-hole operation required the dual 30Љ ϫ 13-3/8Љ casing with both annuli being cemented in single operation and achieving cement returns to seabed.For operation integrity, a project support model has been set up to manage and achieve flawless service delivery starting with a comprehensive Project Readiness Assessment (PRA) tool enabling full analysis of all requirements: technical engineering, project logistics coordination necessary between bases in Thailand and Myanmar, detailed materials preparation & load-out procedure, equipment maintenance procedure, and communication protocol. During the project, deepwater operation integrity management tools were deployed to manage processes as per standard for every single cement job to satisfy design, execution and evaluation requirements. As a result, 10 out of 10 wells in M9A project have been delivered to expectation without any operational failure or cementing-related non-productive time. To maintain equivalent circulating density within limits imposed by formation properties, all primary casing cement slurries were pumped at densities below 15.0ppg, including gas-tight slurries where necessary. To mitigate the risks of loss circulation across the critical intermediate formations, a proprietary, new fiber-based LCM technology was introduced and deployed successfully, notably for the first time in Myanmar.The Appraisal campaign has been completed in May 2015 with all wells successfully drilled and abandonment barriers installed without any annulus communication incident, well barrier leak or regulatory-recordable HSE or well integrity issue. The project is a real example of team work between the operator and service company, application of fit-for-purpose solutions, and use of transformative quality man...

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.

Oil and gas industry continues to increasing demand of more cost-effective well design and operations. Thus, PTTEP Thai onshore drilling team response to the mission by enhancing well design of deep wells in Sirikit Field from three strings to two strings well. This optimization not only reduce cost per well but also unlock reserve in deeper section which used to be uneconomic. To implement two strings design for deep wells with long open hole section (more than 2,000 mMD), there are key challenges which has to be overcome as per listed below; Directional control issue Higher torque, drag and side force Difficulty for wireline logging and casing running operation Formation stability and lost circulation Revised Casing Design To overcome these challenges, not only suite of tools and technologies have to be studied and field proven but drilling practice also has to be reviewed. Risk assessment and feasibility study has been conducted to ensure that this design optimization would results in positive outcome Since the first implementation in 2015, more than 50 wells have been successfully drilled and completed. The longest open hole section of 2,899.3 mMD with TD of 4,202 mMD has been achieved and average cost saving of more than 25% per well has been realized. Below list the technology applied to overcome challenges; All targets have been penetrates without directional control issue using Rotary Steerable System (RSS). High drilling torque have been mitigated using high torque drill pipe and torque reduction tools. Reamer and back-reaming out of hole have been used to smoothen wellbore which facilitate wireline logging and casing running operation. Eccentric casing shoe and low-friction centralizers have been used to further aid running casing in high angle wells. High drilling fluid weight has been used in advance to combat formations stability issue. Hence, lost circulation materials (LCMs) have been prepared to mitigate loss circulation due to high ECD. Polymer based spacer system have been used for the wells which have potential of lost circulations while cementing.

The Sirikit field is a mature reservoir located in the Phitsanulok Basin in north-central Thailand. The field produced first oil in late 1981. Typical logging programs include a complete set of openhole (OH) logging suites such as a triple combo, including gamma ray-neutron-density-resistivity, or quad combo including gamma ray-neutron-density-sonic-resistivity. The reservoir production and injection are carried out with commingled completion. Therefore, wireline formation testing, and sampling tools are usually included for acquisition. Development wells with highly deviated trajectories pose challenges to conventional wireline logging (WL) operations, especially in deep wells exceeding 3,000m. In sections with high dogleg severity, the tools are prone to sticking, and the cable can become key-seated due to hole conditions, deviation, washouts or caving. Log data is a vital component for studying geological complexity, completion and production planning. Therefore, there is a need for an alternative method to convey WL tools to reach the bottom of the hole. In 2015, an alternative conveyance method called "through drillpipe logging" (TDL) was proposed to mitigate the risk of WL tools sticking or hanging up in an openhole environment. This method uses a slim-chassis, 2.25 in. outer diameter (OD), WL logging suite that enables the tool to be run through the drillpipe. The first TDL job was trialed in Thailand in May, 2016 as the second run after the WL run hung up. This TDL run hosted a full triple-combo suite and WL formation testing tools, which reached total depth (TD) while overcoming hole-condition issues that had been experienced during the first run. Following this successful log run, the TDL has become the preferred contingency planning option to support WL operations in challenging wells. To date, a total of 64 jobs, including triple combo (TC), quad combo (QC), formation testing & sampling (FTS) and cross-dipole sonic (CDS) have been executed successfully with less operating time than conventional contingency processes involving wiper trips, tool pushing, or pipe conveyed logging. This track record confirms that TDL provides a fit-for-purpose solution for logging in challenging conditions.