Sand production has been highlighted as one of the critical challenges for Zawtika Project. Throughout the years of field experiences, sand production management has brought up many challenges, especially in terms of field potential sustaining, well productivity and investment justification. Alternative sand control technique is one of the keys to overcome these challenges with continuous improvements driven by lessons learnt. Chemical Sand Consolidation (CSC) is the chemical sand control technique using the resin to bond the formation grain and strengthen the formation strength whereas Thru-Tubing Gravel Pack (TTGP) is retrofit sand control method, which the sand control principle is similar to conventional Cased-Hole Gravel Pack (CHGP), but can be installed in a smaller completion size. In Zawtika existing development phases, almost 150 zones of sand producing intervals are handled by CHGP completion design. In addition to CHGP, these mentioned alternative sand control techniques have been successfully implemented in 3.5-inch-tubing monobore completion for selected deep reservoir intervals after some degree of depletion. Field trial of CSC and TTGP had been implemented during 2019-2020 with 5 reservoirs in 7 monobore completion wells (4 CSC wells and 3 TTGP wells). All wells showed positive results with no sand production from the post-job production; and with a reasonable increase in Maximum Allowable Sand Free Rate (MASR). Based on well performance monitoring until early of 2022, all 3 TTGP wells as well as 3 CSC wells no longer have any sand production issue. Nevertheless, only 1 CSC well with water production history record prior to CSC implementation shows poorer performance on sand production prevention. Following the positive results of TTGP from the previous campaign in term of sand production prevention and well life extension, 8 more TTGP well candidates have been implemented in early of 2022. At the early phase of production, sand free production has been observed for all wells with 51 mmscfd incremental MASR. With all aspects of technical and fiscal evaluation proven to be successful, sand retention and production performance of CSC and TTGP are continuously monitored to confirm long-term performance efficiency for full application in the future. Zawtika sand management strategy through alternative sand control completion has been improved upon accumulated lesson learns and production experiences. The lesson learns and experiences from both operation and well performance monitoring will be integrated for further improvement for the next implementation phases. Maximizing gas potential through alternative sand control methods is also believed to be the cost-effective approach which strengthens PTTEP's competitive performance.
The oil and gas industry has been plagued by formation sand production for decades because of negative impacts on wellbore stability and equipment, despite the fact that it has been demonstrated to be a highly effective technique to increase well productivity (Wang, J. et al., 2004). The consequent sanding problem of sand production has been conducted, wearing down production equipment and necessitating environmentally acceptable disposal criteria. The sand production from unconsolidated sand formations in shallow depth have been reported 10% to 40% sand cuts with 5% in heavy oil reservoir (Tremblay, et al., 1999) and averaged 40% in light oil reservoir (Papamichos, et al., 2001). The objective is to increase operation efficiency of sand monitoring and control by using a sand prediction model to estimate sand production per well based on current operating conditions, as well as to calculate sand operating envelope for each well to guide the production planning and management. Vardoulakis I. and et al (1996) were the first proposed the hydro-erosion model based on rigid porous media in 1996. The erosion models were extended to include the effect of the deformation of porous media in a consistent manner (Wan and Wang, 2002) and include a fully coupled reservoir-geomechanics model as representative elementary volume (REV) to account for the effects of multiphase flow and geomechanics in a consistent manner (Wang et al., 2004). Methodology was starting from data collection, conducted Simplified Representative Elementary Volume (SREV), Integrated Asset model of well, model calibration, monitoring, integration of well, facility for prediction of sand accumulation and wall thickness condition. In addition, a data driven was imbedded to integration as well as workflow automation and user surveillance dashboard in web-based interfaces. The calibration process has been proved the models results with greater than 90% accuracy of sand production. It was found that SREV and IAM approach to sand prediction and control monitoring (SPCM) successful gave an improvement in operations efficiency by reducing time spent on manual analysis and decision-making process through dashboards with predictive results.
PTTEP's Myanmar Asset Zawtika offshore field is located in the Gulf of Moattama, offshore Myanmar, referred to as the Zawtika Gas Development and Production Area. The area lies approximately 300 km south of Yangon and 290 km west of Tavoy on the Myanmar coast. Zawtika offshore gas field consists of Zawtika Processing and Living Quarter platform (ZPQ) which was designed to provide fully automatic, integrated and centralized platform/ process control, and ZWP1 which is connected to ZPQ via interconnecting bridge and 10 remote wellhead platforms which are ZWP2, ZWP3, ZWP4, ZWP5, ZWP6, ZWP7, ZWP8, ZWP9, ZWP10 and ZWP11, located in the Gulf of Moattama offshore Myanmar. In order to prolong field gas potential, the data analysis, planning and management on daily gas potential loss is important to better understand the field behavior. The issues of gas losses are captured and categorized based on difficulties of recovery. "Deferment" is defined as the short-term temporary reduction in Production Availability which results in delay of gas production due to the effects of system constraints/ limitations, scheduled shut down activities on wells or facilities associated with safety, production, maintenance, operation and unplanned interruptions. "Lock-in" is defined as the long-term gas potential reduction that requires longer time and higher investment to solve and unlock that potential. Under PTTEP Operation Excellent Management System (OEMS), one of the essential elements for optimized operation is deferment/lock-in potential management. With this importance in focus, this paper discusses Deferment Management Enhancement for PTTEP's Myanmar asset operation which goal is to enhance deferment analysis and management by using data analytics in information technology environment in alignment with PTTEP Digital Transformation direction. The data obtained from this enhancement can be used in short-term and long-term planning activities for production system optimization including project investments, reservoir management and integrated operations planning, and especially in providing in-depth analysis to minimize deferment volume to maximize return on investment. Production deferment/lock-in guideline is developed within PTTEP's Myanmar Asset to structure Hydrocarbon Availability Model (HAM) for Zawtika according to PTTEP Operations Standard and define deferment and lock-in gas potential data collection basis and their categorizations. ZPDMS deferment module is then enhanced based on this guideline with the extra capability to facilitate site data entry which has been a problem since start-up due to satellite link constraint from Zawtika offshore field. This enhancement also consolidates lock-in/deferment causes, and coding structures, integrates subsurface potential calculation and surface production data, and introduces key visualization pages (e.g. Deferment Dashboard, etc.) for better deferment management performance analysis. After the full implementation of Zawtika Deferment Enhancement project with the help of a digital platform, the gas potential loss due to deferment can be gained back by unlocking the lock-in potential and reducing the unplanned deferment events by troubleshooting as early as possible from the results of effective deferment analysis and planning. As a result, the yearly average of unplanned deferment was reduced from 68 to 34 MMscfd in 2020 and from 34 to 26 MMscfd in 2021 respectively.
In Greater Bongkot North (GBN) Gas Condensate Field located in Gulf of Thailand, many oil wells have recently encountered liquid loading problems. Numerous attempts of gas pressurizing and lowering wellhead pressure have been made but could not sustain continuous oil production. This paper describes the use of innovative technique, Single Point Gas Lift (SPGL) Application, to revive oil production and increase oil recovery from liquid loading wells without the need for an expensive workover operation. SPGL is a retrofit retrievable gas lift straddle that can be installed in the existing production tubing via slick-line unit. This fit-for-purpose solution requires 3 main stages of planning and execution. Firstly, design parameters are identified by simulation software e.g. injection depth, injection rate and pressure. Then, gas lift vale (GLV) is installed by punching the tubing at designed depth, followed by installation of gas lift assembly across the punched depth which includes orifice, check valve and pack-off. Lastly, gas supply is injected into annulus and passes through the installed GLV into production tubing. The pilot test was conducted at well Bongkot-1, a liquid loaded horizontal oil well. SPGL installation was completed successfully followed by deployment of nitrogen injection unit as gas supply in order to prove the concept of SPGL. The gas lifting operation was begun with well unloading and then varying injection rate to determine an optimum gas injection rate. As a result of total 16 hours of nitrogen injection, the cumulative oil production volume of 3,000 STB was realized, indicating the success of the SPGL application. Consequently, long term production phase by utilizing gas supply from high pressure donor well is being implemented. The result proves that SPGL helps to not only revive liquid loading well but also recover more oil reserves and generate more revenues with low cost and simple operation. In 2019, at least 4 oil wells have been scheduled for installation of SPGL application and later with more proven track record of success, it could be extendedly applied to other oil/gas condensate wells, having liquid loading problems, in Greater Bongkot North Field and other fields operated by PTTEP.
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