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Thailand state oil and gas explorer PTTEP looks set to take over Myanmar's biggest gas field as TotalEnergies and Chevron confirmed their exits, citing the worsening humanitarian situation following a coup. A move by PTTEP to become operator of Yadana field, in which it already has a 25.5% stake, would keep vital gas supplies flowing to Thailand and Myanmar. Both TotalEnergies and Chevron were part of a group operating the Yadana gas project off Myanmar's southwest coast along with the Moattama Gas Transportation Company that runs a gas pipeline from the field to Myanmar's border with Thailand. PTTEP would have an 85% stake in Yadana if it took all the interest held by TotalEnergies and Chevron. PTTEP already operates Myanmar's smaller Zawtika field with an 80% stake; Myanmar's state energy firm Myanma Oil and Gas Enterprise holds the remaining 20%.
Wiwatanapataphee, Wiwat (PTT Exploration and Production Public Company Limited) | Kiatrabile, Thanita (PTT Exploration and Production Public Company Limited) | Lilaprathuang, Pipat (PTT Exploration and Production Public Company Limited) | Nopsiri, Noppanan (PTT Exploration and Production Public Company Limited) | Kritsanamontri, Panyawadee (Halliburton)
Abstract The conventional gravel pack sand control completion (High Rate Water Pack / Extension Pack) was the primary sand control method for PTTEPI, Myanmar Zawtika field since 2014 for more than 80 wells. Although the completion cost of gravel pack sand control was dramatically reduced around 75 percent due to the operation performance improvement along 5 years, the further cost reduction still mandatory to make the future development phase feasible. In order to tackle the well economy challenge, several alternative sand control completion designs were reviewed with the existing Zawtika subsurface information. The Chemical Sand Consolidation (CSC) or resin which is cost-effective method to control the sand production with injected chemicals is selected to be tested in 3 candidate wells. Therefore, the first trial campaign of CSC was performed with the Coiled Tubing Unit (CTU) in March to May 2019 with positive campaign results. The operation program and lesson learned were captured in this paper for future improvement in term of well candidate selection, operation planning and execution. The three monobore completion wells were treated with the CSC. The results positively showed that the higher sand-free rates can be achieved. The operation steps consist of 1) Perform sand cleanout to existing perforation interval or perforate the new formation interval. 2) Pumping pre-flush chemical to conditioning the formation to accept the resin 3) Pumping resin to coating on formation grain sand 4) Pumping the post-flush chemical to remove an excess resin from sand 5) Shut in the well to wait for resin curing before open back to production. However, throughout the campaign, there were several lessons learned, which will be required for future cost and time optimization. In operational view, the proper candidate selection shall avoid operational difficulties e.g. available rathole. As well, detailed operation plan and job design will result in effective CSC jobs. For instance, the coil tubing packer is suggested for better resin placement in the formation. Moreover, accommodation arrangement (either barge or additional vessel) and logistics management still have room for improvement. These 3 wells are the evidences of the successful applications in Zawtika field. With good planning, lesson learned and further optimization, this CSC method can be beneficial for existing monobore wells, which required sand control and also will be the alternative sand control method for upcoming development phases. This CSC will be able to increase project economic and also unlock the marginal reservoirs those will not justify the higher cost of conventional gravel pack.
Subsurface woes that have plagued Petronas' Yetagun development since the beginning of the year have prompted the Malaysian state-run oil company to declare force majeure and temporarily cease production from the field. Yetagun is in the Andaman Sea, offshore Myanmar, in Blocks M12, M13, and M14. According to Petronas subsidiary PC Myanmar Ltd. (PCML), following challenges in well deliverability, gas production fell below the technical threshold of the offshore gas processing plant. The operator did not give a timetable for the return of production from Yetagun, adding only that it will be halted until further notice. "There has been a drastic decline in production level due to subsurface challenges in the field since January 2021 and it has further deteriorated recently," said PCML country head Liau Min Hoe.
PTTEP, Thailand's national petroleum exploration and production company, signed a contract with Halliburton to design and implement a series of digital transformation projects as part of PTTEP's Advanced Production Excellence (APEX) Initiative. APEX aims to improve operational efficiency and production in four offshore fields: Arthit, Greater Bongkot South, Greater Bongkot North, and the Myanmar Zawtika Field. Halliburton's Landmark business segment will deploy its DecisionSpace Production Suite in the cloud to improve production operations from the subsurface to processing facilities. The DecisionSpace Enterprise Platform will integrate with Honeywell Forge, an analytics software solution providing real-time data and visual intelligence. Using advanced physics-based and data science models, the solution models surface and subsurface components to manage and optimize operations from the wells to the point of delivery.
Lophongphanit, Chaowarit (PTTEP) | Sookkij, Kanlaya (PTTEP) | Thippayawarn, Anucha (PTTEP) | Oonkhanond, Pariyachat (PTTEP) | Medheethunyapong, Napa (PTTEP) | Theinkaew, Sornnarong (PTTEP) | Kulavong, Passakorn (PTTEP) | Hongtong, Pongpat (PTTEP) | Viriyasomboon, Napas (PTTEP) | Chotmongkol, Prasitsan (PTTEP) | Juengsiripitak, Jirat (PTTEP)
Abstract Zawtika Project is an offshore gas field located in the Gulf of Moattama, Myanmar with water depth ranges from 120 meters to 160 meters. PTTEPI has operated Zawtika field and brought it to production since 2014 with conventional wellhead platforms (CWP) development. The future prospects are expected to be smaller gas reservoirs which are not commercially developed with CWP. Thus, a minimum facilty platform concept study had been initiated after CWP cannot be economically justified to develop and maintain gas production plateau. The basic engineering study was conducted on the selected wellhead platform options namely Zawtika optimized conventional wellhead platform (ZOCP) and Zawtika minimum facility platform (ZMFP). These platform types will be chosen for EPCI based on the size of the candidate prospects after the post-appraisal well result is confirmed. ZOCP is merely a conventional wellhead platform with partial design optimization. On the other hand, ZMFP is a true minimum facility platform. This paper will focus on this type of platform. ZMFP capacity is reduced to match with the target prospects at 90 MMSCFD gas production. The facilities equipment and intra-field sealine are also reviewed and optimized. ZMFP is expected to reduce the CAPEX approximate up to 20% from (1) minimized well slots (2) commingled the flowlines (3) sweet gas material compatible selection. The unique design of ZMFP is the power supply comes from 100% solar power which is a new implementing concept. Estimated of the base weight of ZMFP is 17% lower than CWP leading to estimated CAPEX reduction almost 20% compared with CWP. However, due to the stability of platform under the water depth of Zawtika field condition makes the wellhead platform design to be a 4-legged jacket. Small improvement can be done at the jacket which is about 65% of the total CAPEX. Then an economic evaluation is carried out to compare the NPV of the existing platform design with the improved ZMFP, it found that NPV improve significantly almost 15 %. With the lowering down of the CAPEX, at this stage ZMFP design currently enables 3 sub-commercial prospects to be economically developed. ZMFP design is already selected to implement with the coming Zawtika phase 1D development for 3 wellhead platforms and now it is under EPCI preparation. Zawtika minimum facility platform demonstrates PTTEPI aims to maximize the resource recovery of the field by developing and monetizing sub-commercial reservoirs. With the above-mentioned objective, a new platform is engineered and designed to sacrifices some options down to its fit-for-purpose facility yet maintain the integrity and environmental friendly designs.
Buntoengpesuchsakul, Chanwith (PTTEP) | Limsakul, Chanapol (PTTEP) | Prakitrittanon, Chatchai (PTTEP) | Phongchaisrikul, Nannawat (PTTEP) | Kijkla, Pruch (PTTEP) | -, Zin Phyo (PTTEP) | -, Zay Yar (PTTEP) | Khetdee, Chanawan (PTTEP) | Viriyasomboon, Napas (PTTEP) | -, Thant Zin (PTTEP) | -, Yan Naing (PTTEP) | Vattanajaroen, Nattapong (PTTEP) | Burik, Surin (PTTEP) | Pengsri, Jumnongwit (PTTEP) | Sapchaophraya, Worrawut (PTTEP) | Promlert, Paradorn (PTTEP) | Eadkaew, Monchai (PTTEP)
ABSTRACT The square exhaust duct and the improper insulation design of the Gas Turbine Compressors in Zawtika field initiated the premature failure on the duct, expansion joint and heat insulation. The exhaust duct's temperature over the limitation is considered as a severe consequence in the hazardous gas area. The valuable lesson learnt from the deviation on the safety issues that we had struggled during operation phase and the final safe condition shall be shared with other oil and gas operating asset. The high temperature on the GTC exhaust duct was firstly assumed from the degraded external insulation. After the insulation rectification for a while, the over limit temperature was appeared again. The exhaust insulation was removed and inspected the internal duct and expansion joint. The severe crack at each duct's corner were found. The crack on the duct's corner and expansion joint's metal frame were rectified by welding and the expansion joint's flexible parts were replaced. However, the problems continued to happen again. Maintenance team had engaged with the specialists to redesign the expansion joint's corner and facilitating the external convection. The external exhaust duct's surface temperature was reduced significantly after the new solution implementation, but it could not be reduced to be lower than the limitation of Zone 2, T3, IIA which the maximum limit temperature is 200 degC in some area. The risk assessment had been carefully reviewed to ensure the actual risks were in the "ALARP" level and the mitigation investment was well optimized. After revisiting the ZPQ hazardous area classification, most of the locations on the ZPQ could be considered safe to be deviated to Zone 2, T1, IIA which the maximum limit temperature can be extended to 450 degC. However, the T3 limitation was still maintain in some locations which the condensate can be accidentally leaked. The possibility of heat accumulation area under the T3 Zone had to be solved with the optimized solutions which are composed of 3 main items as follows: Install internal duct insulation Replace the sharp edge corner to curvature in order to reduce the heat stress over the material strength Install external fin on the heat conducted area of the expansion joint to facilitate heat convection over the high temperature zone Three years of struggling journey would be valuable to share with the other operating assets. Previously, the risk of high temperature on the surface of exhaust duct in the hazardous area was unknown. Then it was addressed and recommended to monitor the hot surface temperature. Some other operating assets had also requested to share the optimized solution to mitigate their own problem from the similar exhaust rectangular duct design. This struggling journey can help not only Zawtika but also help the other operating assets in the industry to live safely in the hazardous area.
Abstract The Badamyar project is an offshore gas field located 220 km south of Yangon in the Republic of the Union of Myanmar. In February 2017, four gas wells were successfully drilled and completed using horizontal openhole gravel packing in the Badamyar gas field. The downhole completion design adopted was an alternate path technique using filter-cake breaker deployment for effective well cleanup. Initial geomechanical studies performed in the field show that the sands have low mechanical strength; consequently, they are unconsolidated. This was verified with sonic measurement of 120 us/ft (more than 110 us/ft). An active sand control technique was deemed necessary to ensure a robust well completion with longevity for expected gas production. Based on the comparative risk analysis conducted by the operator for various types of sand control and reservoir drainage, a horizontal openhole gravel pack method was selected to complete the four wells. During the well planning stage, the following specific challenges were identified for the installation of the lower completion: Openhole gravel placement method; alpha/beta wave vs. alternate path technique considering low fracture gradient to achieve 100% pack efficiency Efficient gravel pack carrier fluid for the selected method Expected long drain hole in a clay sensitive environment Effective filter-cake cleanup post-gravel pack Very fine, poorly consolidated, and immature shaly sands Downhole sand control equipment deployment, gravel pack placement, filter-cake removal, and initial production results have proven the selected gravel pack method to be successful in the Badamyar field. This paper presents the measures taken to address the project challenges during the design and execution phase and the results achieved. The success achieved can be adopted for the completion of high-rate gas wells with similar reservoir conditions in this area and beyond.
Wongkamthong, Chayut (PTT Exploration And Production Public Co., Ltd.) | Wongpattananukul, Kongphop (PTT Exploration And Production Public Co., Ltd.) | Suranetinai, Chaiyaporn (PTT Exploration And Production Public Co., Ltd.) | Vongsinudom, Varoon (PTT Exploration And Production Public Co., Ltd.) | Ekkawong, Peerapong (PTT Exploration And Production Public Co., Ltd.)
Abstract Several gas fields in South East Asia share some common traits among them, obviously on their geological features but also on their complex field operation. With a large number of small gas accumulations spreading across a large area with high degree of lateral compartmentalization, production from these fields are usually accomplished by hundreds of wells through multi-branches field networks. The scope of this paper is to present the challenging journey of the company's in-house innovative methodology which resulted in the development of a robust software to address the above challenges. The main objective of the software is to optimize field production under numerous constraints present in these fields. With the target to optimize field production and enhance predictive capability, the company integrates the experiences from operating several fields and proposes an innovative approach to tackle these field management challenges. The resultant software optimizes and solves the network calculation by simplifying and formulating the production network into a system of linear equations, then applying optimization techniques as large-scale simplex and mixed-integer linear programming algorithms, to search for the best production scheme while taking user-selected objective function into consideration. The workflow was developed using MATLAB optimization toolbox to work in conjunction with a familiar Excel-formatted input. Moreover, with the incorporation of the Decline Curve Analysis (DCA), it is also applicable for generating long term production forecast. The tool was further combined with Production Data Management System (PDMS) to provide a more efficient automated workflow. It was used to maximize condensate production in Arthit field, where the main constraints are to capture the production loss from CO2 removal unit and to limit mercury concentration in sales condensate. While, in Zawtika field, the application exploits quadratic programing to minimize the sum of gas production rate square hence controlling wells to produce at optimal rate, mitigating sand production problem. In this paper, successful implementation examples and benefits gained will be discussed. It ensures that the condensate production in Arthit field is kept at optimal level compared with about 91% efficiency when subjected to conventional practices while, in Zawtika, applying the workflow and operation resulted in dramatically lower sand production problem. For future forecast, a look-back study was performed to make sure that the method of calculating future potential is accurate. Not only does this new tool provided a more efficient way for the teams to manage their assets but, more importantly, it also helps to save costs by reducing man-hours through its rapid computation.
Abstract Sand and fines production in oil and gas wells are a major challenge that can result in production system failures. In unconsolidated sand reservoirs, proper sand-control practices are necessary to help prevent reservoir sand production. To remove formation damage and control fines migration, acid treatments are pumped ahead of sand-control treatments, which can be challenging because variations in mineralogy determine fluid performance and require a customized fluid selection. For this case, improvements in cased hole sand-control completions were initially sought by switching to high-rate water pack (HRWP) or fracture for placement of gravel (FPG) techniques; however, obtaining fracture conductivity and minimizing out-of-zone fracture growth was challenging. To accomplish the latter, fluid selection was optimized with linear-gel systems and relative permeability modifiers as prepad systems. Operators should know the formation's composition at the treatment point for a successful acidizing treatment to be performed. The dominant mineral component and temperature of the target formation determines the most effective preflush, hydrofluoric (HF)/hydrochloric (HCl) acid treatment blend, and preflush/treatment volume. The successful implementation of HRWP and FPG techniques produced excellent results with regards to skin minimization and production maximization. The HRWP technique was applied when gas/water contact was nearby, allowing flow from a moderate to high payzone kh (permeability × net pay), and FPG was used to produce a proper flow in low kh formations. The goal of sandstone-matrix acidizing is to remove siliceous microparticles blocking or bridging pore throats by injecting acid formulations containing HF acid. The presence of potassium feldspars, sodium feldspars, illite, and zeolites is a concern because these compounds can form or contribute to forming significant matrix-blocking precipitates, such as sodium or potassium fluosilicates and aluminum fluorides, during HF/HCl treatments. Variations in mineralogy determine fluid performance and make customized fluid selection necessary. The goal is to minimize the risk of over acidizing the near-wellbore region and to extend the reaction for deeper penetration when possible. In some cases, the acid systems with the equivalent strength of up to 1.5% HF acid were used. This paper describes the planning process, acid treatment selection based on laboratory testing, placement and diversion techniques, sand-control completions selection, operation summary, and evaluation of treatment success.
Abstract Free sand movement and fines mobilization during production in Zawtika field is one of the and can result in failures of production systems leading to SSHE exposure, loss of production or even well suspended. The optimum completion design Cased Hole Gravel Pack (CHGP) allows the well to maintain solid-free gas production with (limiting skin) selectivity, longevity and integrity throughout the life cycle. The Sand Control completion deployment, effectiveness and well productivity is directly related to the cleanliness of cased well bore and completion brine. The Total Solid Suspension (TSS) and Nephelometric Turbidity Units (NTU) or clarity of the fluid is the key indicator of well cleanliness. Zawtika Phase 1A post job review highlighted that Wellbore Cleanout (WBCO) is one of the most time consuming operation. To overcome this challenge and create areas of opportunities for improvement based on efficiencies, several possible solutions identified below. Excessive pipe dope, metal debris and rust from casing can collect within the well bore, bridge in perforation tunnels and ultimately damage reservoir or seriously hinder running completion components. The correct combination of Pipe Dope applying procedure, Chemical Displacement, Mechanical Movement and Hydraulic Displacement are the main key contributing factors to improved operation safety, deployment operational efficiency. Lab scale test conducted to simulate test for pipe dope removal chemical, Mechanical Casing Scraper and casing brush simulate testing in order to remove casing vanishing coating, also applying wellbore cleaning concept from drilling - rotational, pump rate and trip speed Recovery of metal or other debris in a limited number of runs gives several advantages: - Minimize reservoir damage - Reduces risks of screen plugging - Saves rig time. This paper will describe planning process, pipe dope procedure, wellbore clean out chemical / mechanical tool selection based on laboratory testing, displacement techniques, and operation summary. The potential cost saving to project can be more than 5 Million USD. The combination of this improvement in WBCO operation is able to reduce the operation time and cost in Phase 1B more than 71% comparing to Phase 1A performances in 2014-2015