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.

Beam pump and ESP are common artificial lift techniques in pumping systems. They are widely used as primary oil recovery methods, but system failures lead to production deferments and increases in operating expenses. Employing decades of our field data, promising data science techniques are discussed here to analyze the factors governing failures in both beam pump and ESP approaches. These data are then applied with machine learning models to predict service life, failure mechanism performance, and production deferments. The data analytics process begins with data preparation. Field data were extracted, transformed and loaded into a data warehouse for further processing. These data were categorized by failure information, pump configuration, wellbore geometry, and production information. The significance of each parameter causing pump failures was derived using a process called "Attribute Forward Selection (AFS)." Then several machine learning algorithms were implemented and compared with to determine the most appropriate model to predict pump service life. More suitable pump configurations to improve pump service life were conceptually recommended based on the analysis. Differences in parameter significance was identified by attribute forward selection, and is displayed in a heat map. It was seen that the use of beam pumps in highly tortuous wells received the number one ranking as the main cause of failures whereas sand production was revealed as the most significant parameter relating to ESP failures. Correlations for these parameters were mapped by machine learning algorithms, resulting in multivariate failure prediction models (i.e. involving more than one parameter at a time) to predict the service life of beam pump and ESP systems. For both artificial lift systems, the models with the best correlation found thus far are based on a neural network, which resulted in the highest R-squared values when compared to other techniques. This neural network model was validated with the actual information, and the outcomes using this model are presented via a scatter plot in this paper. The plot shows that the prediction for ESP forms a trend around the theoretical best match line. In contrast, the prediction for Beam pump still needs improvement, with the data being scattered around the straight line with a unity slope. Data science is an emerging technology that recently has provided breakthrough results for big data analysis. This paper will demonstrate the application of such discipline to the area of artificial lift. Machine learning is a promising tool which could help improve human understanding of complex problems, and, in this case, could furnish a durable competitive advantage to the oil and gas industry.

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.

Zawtika gas field lies approximately 300 km south of Yangon in the Gulf of Mottama, offshore Myanmar focused on laminated Plio-Pleistocene reservoirs. The formations comprises of mixed deltaic and young shallow marine clastic sediments considered amongst the shallowest unconsolidated, poorly sorted with a high percentage of fine sands on the planet. Phase 1A sand control development wells Basis of Design (BoD) underwent considerable extensive laboratory core testing, equipment & stimulation design verification studies prior to successfully completing Seventeen (17) Wells on three (3) Wellhead Platforms. Four (4) additional Platforms with thirty six (36) wells planned to be completed during Phase 1B and further plans to increase Platforms numbers in subsequent Phases. The optimum Cased Hole Gravel Pack (CHGP) completion design shall allow the well to maintain solid-free gas production with selectivity, longevity and integrity throughout the life cycle. This type of completion design was implemented for the first time in PTTEP during Zawtika development, Phase 1A. Due to its complexity and its criticality to the success of the well, the operational approach implemented in Phase 1A was focused more on conservative approach rather than the performance optimization in order to ensure the success and to prove the design concept. The operation went successful and achieved all objectives; where the average times for completing a single and a dual-zone CHGP well were thirteen (13) and eighteen (18) days respectively. Since the CHGP completion design of the Phase 1A proved to be a great success where most of the wells can produce as per or better than the design expectation solids free, the significant operation efficiency improvement drive is one of the main targets of the Zawtika Phase 1B. PTTEPI reviewed Phase 1A post-completion operations and tendered the work with similar design specifications based on the fact that earlier wells completed with Sand Control continued to produce at expected gas rates solids free. In order to improve operational efficiency, many areas were investigated i.e. operational steps, procedures, lesson learns, equipment designs, rig up diagrams, site layouts and integrated knowledge from the Gulf of Thailand (GOT) drilling practices such as batch operation and offline activities were analyzed for implementation in Phase 1B. Concept of Batch Completion strategy is continued and improved from previous Phase 1A that used a Hydraulic Workover Unit (HWU) deployment method onto Phase 1B utilizing a new generation Tender Assisted Drilling (TAD) Rig with Offline Activity Cantilever (OAC) with further emphasis on batch completion approach. To implement a step change in batch completion strategy, the new concept called "Factory-Batch CHGP Completion Strategy" involving comprehensive detailed job planning, semi-permanent pumping package rig up concept, fit for purpose and robust-design of completion equipment, living Standard Operating Procedure (SOP) documents, full implementation of Simultaneous Operation (SIMOP), effective lessons learnt captured and shared, including cross trainings of all parties on the rig site are the main key factors that contribute to the improved operation safety & efficiency. By incorporating and implementing all these factors, PTTEPI is able to reduce the CHGP completion time and cost of Zawtika Development Phase 1B more than 67% comparing to Phase 1A performances in 2014 – 2015. This paper summarizes the fundamental conceptual approach and detailed features of PTTEPI's "Factory-Batch CHGP Completion Strategy" executed in Zawtika Sand Control Development, Phase 1B.

The permanent tubing patch is a primary method widely used to isolate water production zones, especially in slim-hole wells. As the name implies, the permanent tubing patch is non-retrievable equipment and presents a significant challenge when removal is needed. None of the global records of permanent tubing patches installed in slim-hole wells demonstrate successful removal. This paper will discuss the methods used to achieve the first-ever Coiled Tubing (CT) milling of a permanent tubing patch in a slim-hole well. CT was selected to convey the BHA for milling the tubing patch sealing section. An eccentric pilot milling bit (2.780 in OD) was carefully designed as it needed to pass an ID restriction (2.813 in) in the Downhole Safety Valve (DHSV) while still being able to peel off the tubing patch sealing ID (2.250 in) until reaching the full drift of tubing ID (2.992 in) and ensure that the tubing wall would not be damaged during the milling operation. Once the tubing patch sealing section was removed, a braided-line (WL) operation was run to pull free and retrieve the tubing patch body to surface. The well was then restored to enable further intervention and production. CT performed the milling operation flawlessly, and a carefully designed surface equipment stack-up design provided downhole tool deployment accessibility and convenience for both CT and WL intervention. Nitrified fluid was used with CT to mitigate loss problems in several depleted zones above the milling depth. As a result, the tubing patch seal was successfully milled without jeopardizing the tubing integrity. Once the tubing patch seal element was successfully removed and the patch body became free, the WL was deployed through the CT stack to fish the tubing patch body. This is the first-ever operation to remove and retrieve a permanent tubing patch to the surface in this way without damaging the primary completion. Its success results from a well-thought-out pilot mill bit design and careful execution. This case study can now be shared across the industry to improve intervention efficiency and minimize the chance of early plug and abandonment due to permanent tubing patch removal issues.