Producing more oil, but with less input power consumption challenges all E&P companies as they pursue sustainable energy resources. The innovative gaslift technique makes surmounting this challenge possible. The conventional gaslift well system has long been in use worldwide, but the design itself results in depth limiting of the lifting capability. Locating the side pocket mandrel just above the packer, where the gaslift valve is installed, as deep as possible is a well-known design. This might not be significant for short pay zone intervals with higher reservoir pressures, but, clearly, constraints arise in long true vertical perforation intervals with lower reservoir pressures. A new gaslift well design has been developed and studied by the PTTEP Well Engineering Team under the Company's "DeepLift" Project. This design has proven to be suitable for use in many types of wells, particularly those containing long true vertical perforation intervals. This new design was granted, by the U.S. Patent and Trademark Office, Patent No. 7,770,637 B2, on August 10 th , 2010. The design comprises a single completion using the same tubing for producing hydrocarbons and delivering gaslift. The top section of the tubing targets producing hydrocarbons while the bottom section aims at delivering gaslift down to the wellbore. Gaslift flows through the perforated tube above the secondary port of the dual-packer, and then through bypass packer downward via a modified bypass string connected to the lower tubing section. Gaslift is injected out of the bottom side pocket mandrel via reverse gaslift valve to the wellbore, approximately at the bottommost perforation intervals, to improve outflow by decreasing the hydrostatic column or increasing the drawdown pressure. Wells that contained 500 -600 mTVD, which is a significant long distance between the top and the bottom perforation depth, were selected for a field trial. An enormous percentage of production gain is due to genuine higher drawdown pressure improvement from 150 psi to 300 psi. This results in a significant production improvement, which is the primary discussion of this paper.

Zawtika field, Block M9, Myanmar offshore is one of the gas fields that has been developed and been producing since 2013. Two types of well designs have been selected and drilled from platforms; Monobore (Tubingless completion, Gulf of Thailand technique) and Sand control well (cased hole gravel pack). Over the course of production operation many challenges and difficulties have been encountered; one of which is sand production resulting in excessive corrosion and damages to the surface facility and shorten the well life. Hence, sand control completion has been chosen as the main design for field development. During 2013-2014 Zawtika M9 Phase1A sand control wells were drilled with a drilling rig and later completed completion with a 2nd unit hydraulic workover. Though this strategy could bring a well to production soonest, it comes with additional cost and risks; mobilization, stand by, wait on weather, overheads, etc. Up to now, Zawtika M9 Phase1B for sustainable gas production delivery, previous strategy has been adapted for more cost effective operation during an ongoing oil price crisis starting 2014. "One rig strategy" has been implemented with a tender assist drilling rig (TADR). The strategy is to drill all required wells on the platform, then to convert the drilling rig to completion mode and to run sand control completion. Drilling rig has large deck space, high deck load capacity and capability to accommodate 170 people, and sand control equipment can be installed permanently on drilling rig without major impact to drilling operation. The key completion personnel onboard shall relentlessly prepare and commission equipment to perform completion operation right after drilling operation is completed. Ultimately drilling rig can be converted from drilling to completion mode within 3-5 days, compared with a 15 days move of 2nd unit per platform. With this strategy, risk exposure to heavy lift and marine operation reduce significantly. In fact the unpredicted rig stand by due to bad weather in Zawtika M9 Phase1A becomes manageable due to lesser number of rig moves. Sand control completion has been operated efficiently by using rig equipment, space and experienced crews. Many offline operations and activities can be performed concurrently, e.g. cement bond evaluation, wellbore cleanout, packer installation with wire-line, rack back tubular capability, etc. Likewise the drilling rig performance can be continuously optimized and improved. This also eventually extends to running speed enhancement, non-productive time mitigation by proven equipment and crews. With this strategy, the rig has so far completed 3 platforms in Zawtika M9 Phase1B with significant improvement and remarkable record. The total drilling and completion well duration has significantly decreased from Phase1A 18 days to 10 days in Phase1B. Therefore, millions of cost reduction and saving from "One Rig Strategy" claimed.

Low-permeability sandstone formations in deviated exploration wells were drilled and completed in 2013 in northeast Thailand. Reservoir simulation modeling indicated that a well would not produce as a result of the tight formation. Hydraulic fracturing was then considered, and a plan was adopted to use this method to improve the well's production using reservoir simulations. Microseismic fracture monitoring was implemented to correlate data with actual fracture propagation to understand the formation's geomechanics. The fracture design methods were combined with completion and cleanout strategies to help improve well performance. The fracturing design was incorporated into a complete operational procedure, along with contingency plans, a decision tree, and an integrated communication plan, to allow for possible contingencies. Careful planning, fluid testing, and a fit-for-purpose completion design resulted in a successful hydraulic fracturing operation. The microseismic equipment was installed and monitored during the fracturing operation to provide actual fracturing propagation noise signals. This paper presents the well fracturing technology, operational procedures, and microseismic technology used to better understand reservoir behavior and geomechanics characteristics. The geophone installation and surrounding control on location provided minimum noise interference for more accurate actual fracture propagation data. The computer program then forecasted fracture propagation. Comparisons between actual fracture propagation and the simulated fracture design allowed the operator to better understand subsurface parameters and characteristics for building the reservoir database. The operator was also able to forecast fracturing dimensions to help prevent water production zones. This significant reservoir information can be used for field development to maximize hydrocarbon production. Fracturing technology and seismic technology were combined to improve the probability of successful hydrocarbon production. Microseismic results demonstrated the actual fracturing plane dimensions and dynamic fracture propagation, and the fracturing computer program provided fracture simulation dimensions and direction. Combining these technologies allowed the operator to obtain more reservoir data for future field development.