Phummanee, Sutthipat (PTT Exploration and Production Public Company Limited) | Rittirong, Ake (PTT Exploration and Production Public Company Limited) | Pongsripian, Winit (PTT Exploration and Production Public Company Limited) | Phongchawalit, Natthaphat (PTT Exploration and Production Public Company Limited)
The objective of this paper is to demonstrate the implementation of downhole water drain (DHWD) technique to improve gas recovery factor for bottom-water-drive gas reservoir in the multi-thin reservoirs system in Arthit field. This technique was selected as an alternative method to defer water loading in the wellbore by preventing early water breakthrough meanwhile enhancing gas expansion. Project planning, operation, and performance evaluation are the gist of the discussion here.
Candidate selection was the critical first step to the success of DHWD technique. The suitable wells require a gas-water contact reservoir at the upper part of the well and totally depleted reservoirs below it. After identifying candidates, bottomhole pressure survey was performed to investigate the reservoir condition for reservoir simulation. Both gas and water layers above and below the gas-water contact were perforated as designed. A plug was set between the perforated gas and water layers to isolate the flow. This allows gas to be produced to surface while water flows downwards to the depleted reservoirs.
The key parameters used in evaluating the effectiveness of DHWD technique are incremental gas recovery and water breakthrough time. According to the production history of existing gas-water contact reservoirs in Arthit field, massive water production generally starts to intrude after 1.35 months of production at which water-gas ratio increases above 50 STB/MMscf. As a consequence, the gas production sharply declines and eventually ceases to flow. The water breakthrough time of the two trial wells in which DHWD technique was applied is significantly slower than the field average. One was observed water breakthrough after 2.05 months and the other was after 5.40 months of the production. Gas EUR gain is the difference between the EUR when applying DHWD technique by declined curve analysis and the expected EUR of conventional production by statistical method. The results from the two trial wells indicate that DHWD technique can significantly improve the EUR by 110% and 871%.
Downhole water drain is a groundbreaking technique that can be practically implemented to enhance gas recovery of bottom-water-drive gas reservoirs. This technique is recommended for gas field as an alternative strategy since it yields substantial additional reserves gain while required only a small additional cost from the additional perforation of water sand and permanent bridge plug.
Is Surfactant Environmentally Safe for Offshore Use and Discharge? The current presentation date and time shown is a TENTATIVE schedule. The final/confirm presentation schedule will be notified/available in February 2019. Designing Cement Jobs for Success - Get It Right the First Time! Connected Reservoir Regions Map Created From Time-Lapse Pressure Data Shows Similarity to Other Reservoir Quality Maps in a Heterogeneous Carbonate Reservoir. X. Du, Y. Jin, X. Wu, U. of Houston; Y. Liu, X. Wu, O. Awan, J. Roth, K.C. See, N. Tognini, Shell Intl.
By International Petroleum Technology Conference (IPTC) Monday, 25 March 0900-1600 hours Instructors: Olivier Dubrule and Lukas Mosser, Imperial College London Deep Learning (DL) is already bringing game-changing applications to the petroleum industry, and this is certainly the beginning of an enduring trend. Many petroleum engineers and geoscientists are interested to know more about DL but are not sure where to start. This one-day course aims to provide this introduction. The first half of the course presents the formalism of Logistic Regression, Neural Networks and Convolutional Neural Networks and some of their applications. Much of the standard terminology used in DL applications is also presented. In the afternoon, the online environment associated with DL is discussed, from Python libraries to software repositories, including useful websites and big datasets. The last part of the course is spent discussing the most promising subsurface applications of DL.
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.)
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.
This review of technical challenges facing oil and gas producers in the Gulf of Thailand arose from last month's meeting in Bangkok, Thailand, of the SPE Board of Directors with the SPE Asia Pacific Advisory Council, which is represented by senior executives from across the Asia Pacific region and industry value chain. It was an opportunity for Board members to meet with the leadership of the major oil and service companies and discuss how best the SPE can serve its membership in the region. The SPE Board of Directors meets three times per year. One meeting is held in conjunction with the SPE Annual Technical Conference and Exhibition (ATCE), usually during September or October; the other meetings are held in locations around the world chosen for strategic reasons by the SPE President. Thailand is an oil and natural gas producer.
Lee, Kangsu (Korea Research Institute of Ships & Ocean Engineering (KRISO)) | Park, Byoungjae (Korea Research Institute of Ships & Ocean Engineering (KRISO)) | Kim, Hyun-Seok (Korea Research Institute of Ships & Ocean Engineering (KRISO)) | Kim, Doyoub (Korea Research Institute of Ships & Ocean Engineering (KRISO)) | Sung, Hong Gun (Korea Research Institute of Ships & Ocean Engineering (KRISO))
This research suggests a guideline on the design of leg mating unit (LMU) for float-over installation of 20,000-ton class topside. Initial design of LMU is obtained to fit the specifics determined in the design of supporting structure and topside. By utilizing design optimization, the performance of LMU is enhanced to satisfy the requirements defined by recognized codes and standards and simulated load cases. Design optimization is performed for multi-objective functions based on the design sensitivity analysis.
The float-over installation method is one of the favored installation methods for heavy offshore structures due to its time and cost efficiency. In the float-over installation, topside and supporting structure of offshore platform are built separately and are installed with the aid of an installation vessel at the operating area. The procedure of float-over installation consists of load-out, transportation, docking, mating, and un-docking. Since the topside structure's weight is massive and the influence of changeable environmental condition during installation, various devices such as deck supporting unit (DSU), LMU, and fender are utilized for the procedure to absorb forces and prevent damage to both topside and substructures. Among them LMU plays a crucial role for damping out the vertical loads acting between topside and supporting structure during the installation. Generally, the load absorbing part of LMU is composed of hyperelastic materials. Understanding the behavior of the hyperelastic material is important in evaluating the performance of LMU. Especially, selection of the material model of hyperelastic material and the structural characteristic coefficients of the material model directly influences the LMU performance. However, not much studies have been conducted on the material characteristics of elastomeric pad of LMU and very few literatures are available. In 2008, Tan et al. discussed design considerations of LMU. In the paper they classified design parameters of LMU as location, height, installation period and axial stroke. Material characteristics of elastomer was determined by utilizing matrix combinations of three types of elastomeric pad to fit eight different leg reactions and target axial stroke. Yuan et al. (2012) utilized high-grade natural rubber on the LMU's elastomeric pad based on load-deflection hysteresis. They also considered temperature effect on the stiffness of the pad. Later, in 2015 our research group utilized 2-dimensional nonlinear analysis and the Mooney-Rivlin model to predict the reaction force performance of LMU elastomeric pad for float-over installation. Recently, based on the reverse engineering and the Mooney-Rivlin material model, we successfully estimated the structural characteristics coefficient of LMU elastomeric pad to satisfy the requirements.
A heat exchanger is a critical component in oil and gas process. The proper performance of shell and tube heat exchangers within a process can affect the cost of the final product, or even the production rate. Unfortunately, heat exchangers are prone to fouling caused by fluids flowing within and over the tubes, and the reduction in heat transfer that results, almost invariably has an impact on production cost. To reduce this impact, heat exchanger performance should be intelligently monitored and the tube cleaning is required to remove fouling and increase the heat exchanger performance. The existing tube cleaning method is Manual Water Jet Cleaning. Generally the Manual Water Jet Cleaning requires an operator to manually feed the nozzle. Holding on to a hose while high pressure water rushes through it can lead to operator fatigue over time and there is a risk to operator controlling the high pressure water jet near the water blasting and it can be time-consuming because there is only one nozzle to clean one tube at a time.
Robots have served in various industries for many years, but now the science of robot is developing at such a rapid pace that robots have become far more diverse, infinitely smarter and are being used in ways that we would not have dreamt possible as few years ago, especially in the offshore oil and gas industries. In keeping with modern trends, the team has developed the heat exchanger cleaning method through the application of the Robot system. The system can clean 3 tubes simultaneously, providing the highest level of productivity. Robot also provides the most protection and comfort to the operator because the lateral movements of the flexible hoses and the vertical movements of Robot can be controlled remotely. The original design of the Robot structure cannot be installed at the offshore location because of the limited area. Therefore the team has had an innovative idea to redesign the Robot structure in order to extend the cleaning space by mounting it on the scaffolding. This is a new structural design for oil and gas offshore operation.
The nature characteristic of the gas field in the Gulf of Thailand is having high CO2 and Mercury (Hg) content which pose significant operational challenges. Hg content ranges from 50 ppb to as high as 20,000 ppb, averagely at 3,000 ppb. More than half of those wells are required to be shut down under new sales condensate agreement which limit Hg content at 3000 ppb, resulting in a significant loss of opportunity in production. Since the production facility is already existed, it is challenging to maintain production and extend the field life by unlocking opportunities from those high Hg wells.
This paper will describe how to cope with Hg challenges to unlock potential from the field. Specifically, the short term and long term Hg handling and management plan, the operational challenges facing along the way and innovative yet simple solutions will be presented. With the successful Hg management project, the production from high Hg well is resumed. The long term solution by physical filtration method has achieved more than 80% of Hg removal efficiency. Hg filter operation together with the well integrated Hg management plan is the key to unlock field potential from high Hg wells.
M-9 Zawtika Project is a gas field development project located in the Gulf of Moattama offshore, Myanmar. The field lies approximately 300 km south of Yangon and 290 km west of Tavoy on the Myanmar coast. PTTEPI has operated under Production Sharing Contract (PSC) and gas production was commenced since year 2014. The characteristic of future prospects is expected to be small volume and scatter. The marginal field development study is then conducted to support the future development for maintaining production plateau after conventional wellhead platform cannot be developed. The study aims to identify and assess other development options to commercialize marginal and scatter prospects in M-9 Zawtika Field apart from conventional wellhead platform design.
The marginal field development study is based on three (3) development options comprised of MMFP (Myanmar Minimized Facilities Platform), Subsea Production Facilities and Reused wellhead platforms topside. The method of the selected development option is to identify the prospect with suitable development option based on prospect volume, number of development well requirement and economic justification.
The keys of each facility development optimization option are as below.
Myanmar Minimized Facilities Platform (MMFP) is to minimize/optimize the excessive equipment e.g. well slot number, flow line combination, and remove booster compressor unit/area, material design life, structure minimization. Subsea production facilities are planned to produce hydrocarbon with 1 - 4 wells and tie back to nearby existing wellhead platform. Reused wellhead platform topside in Zawtika field is planned to utilize the existing topside from non-productive location in order to minimize cost of topside facilities, however, this option is still have the cost and installation of jacket. This option is considered as long term plan when the existing production platforms are depleted and not economical to continue operate.
Myanmar Minimized Facilities Platform (MMFP) is to minimize/optimize the excessive equipment e.g. well slot number, flow line combination, and remove booster compressor unit/area, material design life, structure minimization.
Subsea production facilities are planned to produce hydrocarbon with 1 - 4 wells and tie back to nearby existing wellhead platform.
Reused wellhead platform topside in Zawtika field is planned to utilize the existing topside from non-productive location in order to minimize cost of topside facilities, however, this option is still have the cost and installation of jacket. This option is considered as long term plan when the existing production platforms are depleted and not economical to continue operate.
The study shows that these three development options are expected to apply for the marginal prospects and can provide longer production plateau comparing with development by conventional wellhead platform only. With these three (3) initiative development options, CAPEX is expected to reduce up to 15% compared with developed by conventional wellhead platform. Some marginal prospects are expected to be commercial and can be developed in the future. The novelty of this study is to identify the suitable development option for long term field development plan. The study will help optimizing CAPEX and improving the value of marginal prospects. Thus, the production plateau can be prolonged until the end of PSC.
Sillapacharn, Thitinun (PTT Exploration and Production PLC) | Srichompoo, Sireekorn (PTT Exploration and Production PLC) | Hoonsuwan, Phakhachon (PTT Exploration and Production PLC) | Aroonsangob, Peeradet (PTT Exploration and Production PLC) | Jirarungsakunruang, Sumate (PTT Exploration and Production PLC) | Nitipan, Tunchanok (PTT Exploration and Production PLC) | Vasansiri, Kritithy (PTT Exploration and Production PLC)
It is recognized that several problems, including equipment redundancies and valuable space consumption, exist in the wellhead platform. For example, there are separators installed to separate gas and liquid that come from reservoirs at various operating pressure conditions. The challenge is to integrate these separators in to a single separation unit for space reduction as well as to broaden operating conditions to serve multiple process conditions.
A three-phase test separator together with drain vessels are installed at the wellhead platform in order to execute reservoir management, well monitoring program, and well intervention activities – such as well clean-up during start-up and liquid unloading where gas flow rates are too low for export due to liquid obstructions in well tubing. Furthermore, booster compressor and associate separation system are installed when the wells deplete to the point where they cannot be produced at under natural production conditions. The operation of the booster compressor allows lowering of the wellhead flow pressure and increasing in the reserve recovery factors.
To address the concerns of the oil price crisis and smaller gas prospects in the field, an Innovative Booster Compressor Package has been developed to serve two aspects of value improvement, (i) to minimize an investment cost and (ii) to maximize and ultimate recovery reserve.
To minimize an investment cost, the booster compressor inlet separator and separator blowcase were re-engineered and modified in order to maintain functions of test separator. The gas and liquid flowmeters can work together with an additional watercut meter enabling the determination of fluids flowrate. During the well unloading operation, well fluids entering the inlet separator at very low pressures and will be transported to the export pipeline with assisted gas from the booster compressor discharge line. This modification results in the elimination of the three-phase test separator and the drain system.
To maximize an ultimate recovery reserve, a compressor will either be operated at a high pressure suction with two parallel cylinders, or at a low pressure suction with two cylinders in series configuration. This allows lowering of the abandonment pressure and increasing the recovery factors of these wells. As a result, this swicthable configuration concept can incrase gas protential and assist in sustaining gas production.
A successful development of the Innovative Bosster Compressor has two benefits. First, at least twenty percent (20%) less investment cost is achieved because of the direct cost savings from vessel integration and from topside-area optimization. Second, an estimated ultimate recovery gain from a switchable low pressure booster compressor is expected at about three percent (3%) higher. These are significant efficiency improvements in the economics of the E&P industry.