The operator relentlessly thrives for the minimum well construction cost. Continuous improvement and Innovative approach are the major drives for developing the marginal gas field, Myanmar offshore. Whereas, routine and consistent operations may mask up the operator and leave out many rooms for improvement from operation excellence during the development phase of the project life cycle. PTTEPI successfully started up the second development campaign, Myanmar offshore in early 2016. Since then the team has brought up many ideas to continuously improve the operation and achieve milestones for both safety and performance. This paper will share the best in class for well construction of Myanmar offshore on well design, drilling engineering, rig selection, offline utilization, drilling and sand control practices and fit for purpose procedures. The performance is significantly improved on both drilling and sand control operation which results in total days per well reduction over 50% and 80% for drilling operation and sand control operation respectively. Total days per well for drilling performance on the last platform in 2019 is reduced to 4 days per well compared to 9 days per well when the first development platform was drilled in 2013. Sand Control performance is improved further. Total days per well for Sand Control performance on the last platform in 2019 is reduced to 3.5 days per well (dual-zone completion) compared to 18 days per well when the first development platform was completed in 2013. Recommended practices and well designs are shared as a case study of drilling and sand control operation for Myanmar offshore development. This can be a guideline for another operator to develop oil and gas field offshore Myanmar.

Bottomhole pressure is one of the most important sources of data used to determine reservoir characteristics. By analyzing the manner in which bottomhole pressures change with time and flow rate, properties can be derived such as permeability, skin, boundaries, and reservoir pressure, which can enable the evaluation of hydrocarbon reserves and make economically feasible decisions. Downhole pressure data in production wells are most commonly acquired by running downhole pressure gauges on slickline into the wellbore. However, in offshore wells in remote locations, there can be major deterrents to capturing bottomhole pressures using slickline. Examples of these limitations include equipment and manpower availability, crane functionality, and offshore accommodations. Furthermore, there can be physical limitations to data acquisition from the presence of sour gas, high bottomhole temperatures, high wellbore deviation, or mechanical obstructions that can prevent the use of downhole gauges in the well. This paper presents an innovative method for acquiring the needed bottomhole pressures in production wells when traditionally used methods may present challenges. An operator in the Gulf of Thailand wanted to obtain downhole pressures on their production wells but did not wish to run slickline and downhole gauges because of the concerns specified above. A new self-powered intelligent data-retriever system was suggested to the operator as it offered a method that could derive accurate bottomhole pressures without running downhole gauges. The new system consists of a high accuracy, high resolution pressure gauge and a companion bottomhole pressure conversion algorithm. The pressure gauge is installed on the wellhead and captures high-frequency surface-pressure data. The conversion algorithm uses the surface pressure data, along with wellbore information, and fluid properties to calculate downhole pressures. The results of a series of tests with the self-powered intelligent data-retriever system demonstrated that the system can provide accurate bottomhole pressure results in production wells. These facts will be verified by the test results as well as the case history, both of which will be presented in this paper. This technology was designed to reduce the cost of capturing downhole pressure data, lessen many of the logistical concerns that could occur when using traditional systems, eliminate the risks of a downhole gauge getting stuck in the wellbore, and acquire necessary data when downhole environments are corrosive.