Abstract Unconventional Resources (UR) are developing an upstream gathering network, a Gas Separation Plant (GSP), and transmission pipelines for a shale gas development project, based in the eastern region of the Kingdom of Saudi Arabia. The aim of these facilities is to produce nonassociated gas from several unconventional fields with minimum treatment, prior to transmitting both gas and condensate to existing facilities for further treatment. Uncertainties in subsurface and reservoir data for shale gas fields is one of the most challenging aspects of designing surface processing facilities, due to the varied behavior and properties of the production fluids, including rapid depletion in well pressure, Water Gas Ratio (WGR), and Condensate Gas Ratio (CGR). The intent is to design efficient, cost-effective facilities, which can accommodate the expected operating envelope throughout early-life, mid-life and end-life of the facilities. This abstract will focus primarily on three optimization areas already implemented in the facilities design: (i) Gas gathering system. (ii) Dehydration and propane refrigeration. (iii) Off-gas system. The gas gathering system has been designed to be operated in three separate phases: (i) Early Life; (ii) Mid Life; and (iii) Late Life, as the well pressures naturally decline. The selected configuration, compares with other facility designs which incorporates separate High Pressure (HP) and Low Pressure (LP) gathering systems. However, in order to minimize CAPEX, the facility has been designed in a flexible arrangement to be operated over the three different phases. Therefore, the operating pressure will be reduced and the wells choked back accordingly. Tri-ethylene Glycol (TEG) Dehydration unit design has been optimized in the GSP by pre-cooling the process gas upstream of the unit. A small propane refrigeration system was used to chill the upstream process gas. The system reduces the TEG Regeneration equipment sizes, heating duties, and minimizes TEG losses. In addition to that, the propane refrigeration system has been further optimized by utilizing a gas-gas Heat Exchanger (HEX) upstream of the chillers to reduce the required cooling duty. The GSP design includes an off-gas collection system which recompresses Low Pressure (LP) vent streams and recycles them back into the main process gas stream, avoiding the requirement for a LP Flare system. During the Front-End Engineering Design (FEED) stage of the project, the outlet of the off-gas system was routed to the gas transmission pipeline, to comingle with the dry gas from the TEG system. During the project EPC stage, the off-gas system was optimized by re-routing the off-gas to the Medium Pressure (MP) Separator where it is recycled back into the process. This optimization decreases the required off-gas compressor discharge pressure with associated CAPEX and OPEX reduction. Additionally, liquids separated within the off-gas system are also recycled back to the MP Separator instead of a closed drain system, which avoids venting gas that contains concentrated Benzene, Toluene, Ethylbenzene and Xylene (BTEX). This unconventional gas development project will be developed over several phases, and this facility is part of Phase 1 development.

Abstract ADNOC LNG natural gas export facilities (five Gas turbines driving centrifugal compressors) had experienced blade parts liberation at the first row of blades because of Chlorine and Sulphur presence in air intake system. The objective is to identify all integrity risks and to implement advanced technical enhancements to restore critical gas turbines integrity. ADNOC LNG team carried out Root Cause Analysis (RCA) study and investigation as per existing procedures. Team collected all the events and engaged turbine manufacturer to identify root cause through intensive analysis and studies. Also engaged metallurgical third part lab to identify the nature of encountered cracks and type of fractions. The investigation had the scope to identify the origination point of blade liberation studying the broken surfaces of the blades. From the metallurgical point of view, thorugh metal strucuture studies and magnifications of broken surfaces, it was seen a series of point where metal structure changed from its original composition, having a consequent drop in properties like strength. Furthermore, the broken surfaces was typical of a metal subjected to a constast stress. RCA concluded that gas turbine had suffered of Axial Compressor Blade Stress Corrosion. The major action plan to be implemented on fast track was to replace rotors with coated blades, then rest of RCA actions were applied. The implementations and enhancements are fulfilled jointly by ADNOC LNG and manufacturer successfully. Main implementations are blade coating, upgrade of air filter elements and blades tip clearance optimization. The recommended enhancements were implemented and successfully arrested the risk of blades liberation to assure gas turbine integrity and sustainable gas export revenues. ADNOC LNG has successfully upgraded all axial compressors rotors and eliminated the risk of blades failure. Since applied enhancements, no further blades failure encountered confirming sustainable operations and integrity assurance. The same successful enhancements were also implemented at ADNOC LNG utilities gas turbines generator sets. The aim of the abstract is to share and focus on success story of gas turbine integrity enhancements and improvements to assure gas export sustainability. Furthermore, it wants to draw reader attention to potential hidden issues that cannot be discovered during turbine operation in order to prevente major damages resulting in losing of turbine and production.

Abstract Troubleshooting and Root Cause Failure Analysis (RCFA), of process equipment operations, is often hampered by an inability to measure all key quantities of interest. Frequently the only recourse is to utilise simulation techniques. The ease of use and accuracy of Computational Fluid Dynamics (CFD) continues to improve, however, successful CFD modelling frequently requires supporting analysis from process simulation and other analytical software. When considering troubleshooting studies on process systems with similar complexity to that presented here, it is important to appreciate how different simulation and analysis techniques can complement one another in obtaining the necessary process insight. Where the operator has not developed a simulation-based "digital twin" to properly characterise process streams and unit operations, it will be necessary to provide one. This may entail estimates and approximations needing verification. Here, commercial shell and tube heat exchanger modelling software was used in conjunction with the industry's leading process simulator to benchmark thermal performance predictions against those of the original process licensor. Plant data historian records were used to define Reference Operating Conditions (ROC) and these were modelled by a commercial exchanger modelling program. From this a set of Agreed Modelling Conditions (AMC) were defined, to account for process upsets. The AMC conditions provided flow, temperature, and pressure boundaries for CFD simulations. CFD modelling was conducted for the process side system to establish the magnitude and impact of tube side maldistribution in the condensers. This was found to be modest and was demonstrated to have minimal impact on thermal behaviour. CFD simulation of the shell side circulation system, including fully coupled heat transfer representation of both process side cooling and evaporation on the shell side was central to the studies. This revealed disruption of liquid recirculation was occurring within the shells, attributed to the way BFW was distributed within the shell.

Increase in the requirement of reduction of CO 2 emission / carbon footprint demands the need for CO 2 capturing units in existing gas treatment facilities. The location of the CO 2 capturing unit in the sour gas treating plant have economic impact with respect to CO 2 recovery and unit technical cost (UTC). A case study is presented to demonstrate the optimum location of the CO 2 recovery unit with available licensed technology. Based on production profile and composition for Asab 1 & 2, the potential acid gas removed from acid gas removal unit (AGRU) is quantified. The amount of CO 2 in acid gas to be recovered in view to having a SRU unit, had the choice of CO 2 recovery from: (1) low pressure amine based CO 2 capturing units, (2) high pressure CO 2 capturing units based on amine / physical solvents, or (3) CO 2 recovery from tail gas of sulphur recovery unit (SRU). A technology selection study was carried out to select appropriate technology for CO 2 capture with optimum unit technical cost (UTC). The study findings are summarized as below: Low pressure amine based CO 2 recovery unit, along with the tri-ethylene glycol (TEG) based CO 2 dehydration and conditioning and CO 2 pumping / compression units configuration, is considered to have optimum unit technical cost (UTC). The low pressure amine based CO 2 recovery unit acts as an acid gas enrichment (AGE) unit upstream of the sulphur recovery unit (SRU). As the CO 2 is recovered, the total enriched acid gas feed (with higher H 2 S concentration) to sulphur recovery unit will reduce, hence the size of the sulphur recovery unit (SRU) will come down. Tri-ethylene glycol (TEG) based CO 2 drying technology is considered with advantage over other available technologies like mole sieves, membrane based process etc. The CO 2 capturing unit scheme selected during the conceptual design stage will be further developed in detail during the FEED stage. The CO 2 recovered will be utilized for enhanced oil recovery, which will aid increased oil production and value to the company. As the CO 2 recovery unit is planned along with SRU, the CO 2 emission from the SRU unit will also be reduced.

Liquid Product Recovery is an important metric to assess the quality of Gas and Oil Separation plant design and is required to be achieved at minimum CAPEX & OPEX to improve the overall economics. This paper presents a structured approach for an optimal solution to minimize loss of valuable components to the gas phase, thereby maximizing liquid recovery. Ideal Liquid Recovery is defined as the theoretical maximum liquid recovery possible by successively separating the lightest components from the well-fluid until the crude oil specifications are met, i.e. separating all the Methane (C1) and Ethane (C2), just the right proportion of Water, Propane (C3) and H 2 S to meet the specifications. In real life separation systems, however, such sharp separation is unachievable, i.e. some amount of intermediate and heavier components are likely to migrate to the gas phase and some of the lighter components may end up in the liquid phase. Accordingly, %Liquid Recovery is defined as: % Liquid Recovery = Actual Liquid Recovery Ideal Liquid Recovery × 100 Oil and gas production is a complex process wherein many equipment and systems are closely coupled and interdependent. The art of designing an optimal process for Gas and Oil Separation plants lies in rigorous selection of appropriate process configurations and operating conditions. The design largely depends on several factors such as fluid compositions and properties, product specifications, etc. There is no single configuration or set of process conditions that can be the solution under all scenarios; thus each case requires to be analyzed independently. This paper uses a structured approach to evaluate the impact of each parameter individually as well as collectively, to select the optimum process configuration for separation and stabilization of the crude oil. A Gas and Oil Separation plant with multiple stages and a stabilizer column is used to demonstrate that the liquid recovery for a specific well-fluid composition can be maximized by varying separator operating conditions, column operating parameters and process configurations. The focus of the paper is on the ‘Design Process’ to achieve and assure an optimal design as well as understand its limitations. The suggested design approach demonstrates that liquid recovery values in excess of 95% can be achieved in comparison to typical liquid recovery values of around 93% for low GOR oil production plants. Even two percent increase in liquid recovery is quite significant, as on a 100,000 STBOPD plant it translates to 2,000 STBOPD production gain which is equivalent to more than US$ 33 million per year in additional revenue at crude oil price of US$ 50/bbl. This should be read with a caveat that incremental absolute revenue will be lower in a smaller capacity unit and hence, additional CAPEX, if any, should be evaluated accordingly. Higher liquid recovery also contributes to improvement in API gravity of the crude, and thus further adds to its value.

Hydraulic fracturing technology has grown popular with the rapidly increasing development of tight conventional and unconventional reservoirs. A major concern with this technique is the use of large amounts of water in these treatments. The use of water causes many potential damaging issues in the formation and limits the amount that can be saved for future generations. One solution is waterless fracturing treatments, which were developed to reduce or eliminate the need for water in hydraulic fracturing. Hydraulic fracturing treatments consume at least 200,000 gallons of water in conventional wells and up to 16,000,000 gallons of water in unconventional wells. The pumped water must include clay stabilizers to deal with the sensitive clays in the formation. Additionally, using water poses a risk of inorganic scale precipitation near the wellbore. Water can also cause severe emulsions that can lead to emulsion blockage cases. Moreover, there are significant reports of water blockage cases in tight gas wells. Only a mere 10-30% of pumped water flows back after the treatment, with the rest attached to clays, or stuck in the pores due to high capillary pressures. Water-based fluids can also cause alterations to relative permeability, and liquid holdup cases in many gas wells. These issues can certainly increase near wellbore skin and reduce production rates. At the end of the treatment, water still causes issues related to disposal and separation prior to diverting it to the plant. The main challenges in developing waterless fluids include feasibility, environmental friendliness, and effectiveness to stimulate the reservoir. This review will cover the various waterless fracturing methods such as hydrocarbon-based, liquid CO 2 , energized, and foamed fluids (CO 2 and N 2 foams) as well as their advantages and disadvantages. Studies into the properties of these fluids, such as rheology, solubility, compatibility, will also be discussed. Field trials will be examined where applicable. This literature review examines various waterless alternatives to traditional fluids for hydraulic fracturing. From this paper, readers can better understand the nature of waterless technologies and be able to better evaluate these technologies for fracturing purposes.

Maintaining the high level of reliability of Instrument Air compressor is essential for safe operation of Oil and Gas facilities however challenges remains to maintain high level of reliability in integrally geared design instrument air compressor due to exceptionally high speed (50,000 rpm) and minimal clearance bearing..etc. This paper presents success story of such compressor`s Reliability and MTBF improvement from 30 days to more than 36 months. Integrally geared compressor was installed and commissioned in year 2002 as facility upgrade project and never run continuously more than 30 days due to frequent high vibration trip and lead to consequence Risk of plant operation and upset due to non-availability of compressor Extremely high maintenance cost > $120,000 per year due to repeated maintenance intervention Identifying the common vibration malfunction like unbalance, misalignment, rubs, cracks, shaft bows are relatively easy, as the behavior/characteristics of these problems are well understood, however challenge remains for identifying the rare uncommon problems with limited information so this paper details interesting achievement of, how we diagnose and eliminate vibration issues. Structured root cause analysis of high vibration revealed cause of high vibrations are Bearing Frosting /Pitting contributed by buildup of Electrostatic current and discharge through bearing High residual magnetism, and compounded by Yellow deposits /varnish formation due to thermal oxidation which is result of high operating temperature and Oil disintegration. To eliminate above uncommon problems, following solution were identified as. Installation of current diverter rings (CDR) in motor, which avoided development of high shaft voltage from either motor or compressor by discharging to the ground. Removal of residual magnetism from rotor by On Site degaussing process. Maintained the lube oil supply temperature less than 60°C by upgrading the temperature control elements. To identify varnish formation, Perform proactive varnish potential test like membrane patch colorimetric (MPC) Implementation of above recommendations enhanced the equipment uptime with reduced maintenance effort and cost, which permanently resolved the high vibration issues and made the compressor reliable for uninterrupted supply of instrument air to process plant without major overhauling for more than 7 years as of now.

Unconventional Resources (UR) are developing an upstream gathering network, a Gas Separation Plant (GSP), and transmission pipelines for a shale gas development project, based in the eastern region of the Kingdom of Saudi Arabia. The aim of these facilities is to produce nonassociated gas from several unconventional fields with minimum treatment, prior to transmitting both gas and condensate to existing facilities for further treatment. Uncertainties in subsurface and reservoir data for shale gas fields is one of the most challenging aspects of designing surface processing facilities, due to the varied behavior and properties of the production fluids, including rapid depletion in well pressure, Water Gas Ratio (WGR), and Condensate Gas Ratio (CGR). The intent is to design efficient, cost-effective facilities, which can accommodate the expected operating envelope throughout early-life, mid-life and end-life of the facilities. This abstract will focus primarily on three optimization areas already implemented in the facilities design: (i) Gas gathering system. (ii) Dehydration and propane refrigeration. (iii) Off-gas system. The gas gathering system has been designed to be operated in three separate phases: (i) Early Life; (ii) Mid Life; and (iii) Late Life, as the well pressures naturally decline. The selected configuration, compares with other facility designs which incorporates separate High Pressure (HP) and Low Pressure (LP) gathering systems. However, in order to minimize CAPEX, the facility has been designed in a flexible arrangement to be operated over the three different phases. Therefore, the operating pressure will be reduced and the wells choked back accordingly. Tri-ethylene Glycol (TEG) Dehydration unit design has been optimized in the GSP by pre-cooling the process gas upstream of the unit. A small propane refrigeration system was used to chill the upstream process gas. The system reduces the TEG Regeneration equipment sizes, heating duties, and minimizes TEG losses. In addition to that, the propane refrigeration system has been further optimized by utilizing a gas-gas Heat Exchanger (HEX) upstream of the chillers to reduce the required cooling duty. The GSP design includes an off-gas collection system which recompresses Low Pressure (LP) vent streams and recycles them back into the main process gas stream, avoiding the requirement for a LP Flare system. During the Front-End Engineering Design (FEED) stage of the project, the outlet of the off-gas system was routed to the gas transmission pipeline, to comingle with the dry gas from the TEG system. During the project EPC stage, the off-gas system was optimized by re-routing the off-gas to the Medium Pressure (MP) Separator where it is recycled back into the process. This optimization decreases the required off-gas compressor discharge pressure with associated CAPEX and OPEX reduction. Additionally, liquids separated within the off-gas system are also recycled back to the MP Separator instead of a closed drain system, which avoids venting gas that contains concentrated Benzene, Toluene, Ethylbenzene and Xylene (BTEX). This unconventional gas development project will be developed over several phases, and this facility is part of Phase 1 development.

Electrical system design in capital projects takes place very early in the cycle because large motors and gas powered generators are long lead time items and plant assets require power during installation. This means that electrical design employs only preliminary process design data and instead relies on simple load factor formulas. Under-designing the electrical system could mean the process cannot reach nameplate capacity, which could have significant financial consequences. If a similar process unit has already been built, an accurate simulation of that process could be used to right-size the electrical system, especially if the process simulation is connected to an equally accurate electrical simulation. This would allow engineers to evaluate process and electrical dynamics to ensure electrical power always meets process demand and that the electrical design is adequate for a variety of real life scenarios, such as plant startup and shutdown, process upsets, and unplanned grid outages. This paper explores the potential cost savings during a capital project and into the operational phase, the significant challenges in creating an accurate process simulation, and other use cases for a mixed process and electrical simulator can provide. A simple study was performed for a client where both the electrical design data and the process simulator was available to determine if the simulator was accurate enough to calculate load demand and if the motors were oversized in the unit. The crude unit was selected because it contained the largest number of medium voltage motors and was relatively easy to operate. The model and the historian predicted that the motors were oversized between 15–63%. Extrapolating the excess power to cost could reach 1.3 MUSD per year.

Industrial processing such as crude oil refining, petrochemical production, power generation and other may involve the transport of hot and cold utilities (fluids or gases) through heat transfer equipment such as heat exchangers. Over time and under various conditions, this transport of such utilities may result in fouling and scale deposits forming within the preheat trains or heat exchangers. Fouling and scale deposits reduce the performance of the equipment, leading to heat energy losses which has a negative productivity impact as well as overall negative economic and environmental impact on the industrial process. Due to the lack of existing technologies oil refineries clean their key heat transfer equipment during major overhauls or roughly once in 2-4 years. Between these stops heat exchangers work below 50% of their heat transfer efficiency. Cognitive Cleaning systems and methods integrates chemical innovation, process innovation and business model innovation into a single solution aimed to maximize technical, economic and environmental performance of the industrial processes through reducing energy intensity of the processes via cleanliness of heat exchangers. Cognitive Cleaning is applicable for wide range of equipment geometry: shell and tube, plate, spiral heat exchangers. According to laboratory tests and on-site implementation's it is safe for equipment and has no harmful residues after cleaning. Cognitive Cleaning technology was successfully commercialized on operating bitumen units, CDU, VDU, acid alkylation unit; on spiral, plate, shell-and-tube heat exchangers of several refineries of Gazpromneft, LUKOIL, TANECO demonstrated boost in equipment efficiency. Companies were able to extract real value out of previously done investments into digital infrastructure. Applied cognitive cleaning can keep cleanliness of equipment increasing heat transfer efficiency up to 70%-80%, reduce CO2 emission and return around $2.4B to oil refineries of GCC countries.

Troubleshooting and Root Cause Failure Analysis (RCFA), of process equipment operations, is often hampered by an inability to measure all key quantities of interest. Frequently the only recourse is to utilise simulation techniques. The ease of use and accuracy of Computational Fluid Dynamics (CFD) continues to improve, however, successful CFD modelling frequently requires supporting analysis from process simulation and other analytical software. When considering troubleshooting studies on process systems with similar complexity to that presented here, it is important to appreciate how different simulation and analysis techniques can complement one another in obtaining the necessary process insight. Where the operator has not developed a simulation-based "digital twin" to properly characterise process streams and unit operations, it will be necessary to provide one. This may entail estimates and approximations needing verification. Here, commercial shell and tube heat exchanger modelling software was used in conjunction with the industry's leading process simulator to benchmark thermal performance predictions against those of the original process licensor. Plant data historian records were used to define Reference Operating Conditions (ROC) and these were modelled by a commercial exchanger modelling program. From this a set of Agreed Modelling Conditions (AMC) were defined, to account for process upsets. The AMC conditions provided flow, temperature, and pressure boundaries for CFD simulations. CFD modelling was conducted for the process side system to establish the magnitude and impact of tube side maldistribution in the condensers. This was found to be modest and was demonstrated to have minimal impact on thermal behaviour. CFD simulation of the shell side circulation system, including fully coupled heat transfer representation of both process side cooling and evaporation on the shell side was central to the studies. This revealed disruption of liquid recirculation was occurring within the shells, attributed to the way BFW was distributed within the shell.

ADNOC LNG natural gas export facilities (five Gas turbines driving centrifugal compressors) had experienced blade parts liberation at the first row of blades because of Chlorine and Sulphur presence in air intake system. The objective is to identify all integrity risks and to implement advanced technical enhancements to restore critical gas turbines integrity. ADNOC LNG team carried out Root Cause Analysis (RCA) study and investigation as per existing procedures. Team collected all the events and engaged turbine manufacturer to identify root cause through intensive analysis and studies. Also engaged metallurgical third part lab to identify the nature of encountered cracks and type of fractions. The investigation had the scope to identify the origination point of blade liberation studying the broken surfaces of the blades. From the metallurgical point of view, thorugh metal strucuture studies and magnifications of broken surfaces, it was seen a series of point where metal structure changed from its original composition, having a consequent drop in properties like strength. Furthermore, the broken surfaces was typical of a metal subjected to a constast stress. RCA concluded that gas turbine had suffered of Axial Compressor Blade Stress Corrosion. The major action plan to be implemented on fast track was to replace rotors with coated blades, then rest of RCA actions were applied. The implementations and enhancements are fulfilled jointly by ADNOC LNG and manufacturer successfully. Main implementations are blade coating, upgrade of air filter elements and blades tip clearance optimization. The recommended enhancements were implemented and successfully arrested the risk of blades liberation to assure gas turbine integrity and sustainable gas export revenues. ADNOC LNG has successfully upgraded all axial compressors rotors and eliminated the risk of blades failure. Since applied enhancements, no further blades failure encountered confirming sustainable operations and integrity assurance. The same successful enhancements were also implemented at ADNOC LNG utilities gas turbines generator sets. The aim of the abstract is to share and focus on success story of gas turbine integrity enhancements and improvements to assure gas export sustainability. Furthermore, it wants to draw reader attention to potential hidden issues that cannot be discovered during turbine operation in order to prevente major damages resulting in losing of turbine and production.

The aim of this abstract is to focus on the Maintenance Management System (MMS) that was implemented at ADNOC LNG to accomplish operation excellence, effective decision-making regarding maintenance activities, and utilization of the Risk Management Process to assure asset integrity and major production revenues. Risk-based MMS is a continuous improvement (CI) system to proactively prevent failures through the early identifications of risks, failure modes, failure criticality, and risk mitigation by utilizing cost effective predictive maintenance tasks and routines. Risk-based MMS effectively provides support for high critical decisions to assure asset integrity, minimize plant trips, avoid unnecessary forced shutdowns, and guarantee safe operations. Asset Integrity Management (AIM) is important in the oil and gas business because it ensures reliable assets, performance, efficiency, cost effectiveness, sustainable production revenues, and achieve business objectives and operational excellence. Maintenance, Operations and Engineering are the key partners and custodians to assure asset integrity in compliance with HSE. The very close interface between the three result in high levels of asset reliability and availability. In 2016 ADNOC LNG's Maintenance Division deployed the Maintenance Management System (MMS) driven by the Risk Based Reliability Approach. The objective was to perform consistent maintenance activities and asset integrity assurance by identifying risks and mitigations to reduce the risks in early stages to As Low As Reasonably Practical (ALARP). The MMS Policy and Strategy was developed on the foundation of the risk-based approach in line with ADNOC LNG's corporate objectives, ADNOC's code of practice, and internationally accepted best practices. The alignment of MMS with the Risk Based Approach was achieved by ADNOC LNG through successful implementation of Streamlined Reliability Centered Maintenance (SRCM) as a risk-based reliability asset integrity management tool. SRCM implementation achieved +98% reliability, cost reduction, work force utilization, proactive maintenance, and sustainable production. SRCM is mainly for rotating equipment, electrical equipment, and instrumentation. RBI (Risk Based Inspection) is already utilized for static equipment. The combination of both RBI and SRCM are successfully assuring the integrity of all assets at ADNOC LNG. The key topics, which will be focused on, are criticality assessment, risk management, and asset integrity management reliability system SRCM (Streamline Reliability Centered Maintenance). The main challenges to implement MMS were: receiving the team's buy in, making sure the team was aligned with MMS policy and strategy, and cultural challenges. The system was successfully deployed with consistent processes and procedures helping maintenance end users perform in accordance to best practices.

A prosperous business player must gain a competitive advantage over other companies to survive and dominate the market. In Japan, electricity market has progressively started its liberalization in 2000, and full liberalization in 2016 allowed all consumers to freely choose the power retailer. In response to these dramatic changes in the business environment, we have proactively introduced KAIZEN and digital technology to gain a competitive edge. KAIZEN was introduced in Japanese automobile manufacturing and based on the philosophical belief that "nothing is seen as a status quo and everything can be continuously improved by racking one's brain." Simply saying, it is an initiative to improve efficiency value-adding work, and to eliminate non-value-adding work and waste & loss which we can not recognize. In addition, the advancement of digital technology enabled us to analyze the big data which we have storaged from the past more easily and in more detail. As a result of introducing of KAIZEN and digital technology, the periodic inspection of thermal power plants has been shortened by over 40 %, and maintenance costs have been reduced by over 30 %. This paper illustrates the details of our initiatives implementing KAIZEN and digital technology and our challenges in optimizing the LNG value chain applying the KAIZEN knowledge.

The design of new natural gas liquefaction facilities is closely aligned with the quality of the immediately available feed gas and the SPA’s agreed with customers. However, the lifetime of the facilities often extends beyond the lifetime of both the gas source and the duration of the SPA’s. Recent statistics indicate up to 60 MTPA of global liquefaction capacity is not utilized. Qualitative based approaches are often adopted to assess how an LNG plant responds to a change in feed gas specification. However a more valuable approach uses a quantitative analysis which can achieve an optimal outcome via individual tuning of a potentially large number of plant variables. Such an approach starts by performing actual plant capacity tests for different operating modes and process variables to capture baseline operation performance data. The plant test results are to validate a detailed plant simulation model which includes all the plant variables of interest. The validated model can then help identify the optimum operating condition and the benefits of a range of potential modifications. The methodology was used to identify solutions to a typical problem in a multi-train facility where a change from rich feed stock was accompanied by the presence of aromatics in a significantly leaner feed gas. Detailed modelling of the plant enabled an understanding of the solubility of the aromatics in the lean gas. The previously validated model of the real plant behaviour was then used to evaluate the benefits of changes to the key operating parameters and minor modifications to the plant itself. This resulted in a significantly more efficient and cost-effective solution than simply importing LPG which would have been the solution normally taken by a traditional "qualitative" approach. A similar approach was used to address an associated commercial challenge of satisfying a SPA demanding a high HHV with a leaner feed gas. In this case the solution relied not only on the technical insight afforded by the quantitative analysis but also a recognition that accurate tuning of the operational process allows a reduction in the conservatism of the product specification. Furthermore, with minor modifications, a multi-train process with segregated storage can be operated in multiple HHV mode provided careful procedures are employed to mitigate operational risks. This paper demonstrates how a holistic, detailed, quantitative analysis of gas liquefaction process can provide a good insight into the capability of existing plant to respond to changes in feedstock quality. The outlined methodology combined with a good understanding of the commercial features of the LNG business offers the possibility to better exploit the significant and growing amount of unused gas liquefaction capacity around the world.

ADNOC LNG (Train 3) processes HP gas from ADNOC Offshore and the gas goes through a series of processes to remove sulfur & other impurities, gets dehydrated before it is processed to separate the various products and cooled to the prescribed temperature to enable storage and shipping. Apart from LNG, Propane, Butane, Paraffinic Naphtha and Sulphur are also produced as secondary products. The refrigeration of the gas is achieved in two systems namely Propane refrigeration and Mixed Component Refrigeration. Propane refrigeration loop is the heart of the total cooling process in which "Cold Box" is a set of exchangers in series. The Challenge: Cold box consists of 12 exchangers/evaporators in series and the process is highly interactive. Disturbance in level of one results in cascading effect on others. It has been a challenge, during start-up, to stabilize the levels as we had to have substantial manual intervention. Any instrument fault or routine maintenance during normal operation required operator to take multiple level controls in manual to handle the situation. This had resulted in delayed start-up and poor temperature profile of chillers. Engineering and Operations teams jointly undertook an initiative to resolve this chronic problem, which was successfully demonstrated post-Train 3 T/A startup in May 2018. It was jointly agreed to find a solution that would Minimize manual intervention during start-up Maintain stability during normal operation Reduce manual interventions in case of instrument failure or calibration Feed Forward Control Scheme Implementation of a control scheme in DCS utilizing feed forward action from downstream controllers to upstream level controller. The solution was found simple and robust. Existing software tools available were used effectively to arrive at feed forward constants. Change was implemented during Train-3 Shutdown. A fall back strategy was kept ready – in case new scheme encountered unforeseen difficulties. Business Benefit Reduction in start-up time by around 1 Hr. will result in additional production of around 800 Tons of LNG per year which amounts to US$ 257K Reduced probability of unplanned plant outages. Assuming US$ 1.2 M loss per unplanned shutdown reduction in loss per year comes to US$ 480 K

Objective/Scope A localized tube rupture was observed in the convection section of Fired heater. To address this, improve Integrity and avoid Process Safety concerns, the existing convection section required replacement. This paper presents an alternate approach followed to reduce operating costs by enhancing the heater performance and efficiency while addressing high heat flux issue. Methods, Procedures, Process The new convection section was designed with an increased coil surface area to enhance the heat recovery and optimize heat flux. Fin materials were changed from original carbon steel to SS410 in high temperature zone to minimize fin burn-off issues. The challenges were phenomenal, as the heater was 40 years old and new convection section is twice heavy and size than existing. In order to overcome, systematic engineering approach was adopted, from sizing new convection section with optimum heat flux, Mechanical design with FEA to verify structure integrity and foundation adequacy for increased loads. As a step toward safeguarding the tube from similar future failure, tube skin thermocouples were installed in shield tubes to facilitate continuous monitoring. Results, Observations &Conclusions Analysis confirmed integrity of the heater with minimum modification on anchor bolt avoiding need major foundation and structural upgrade. Two furnaces have been upgraded with new convection section and continuous monitoring for period more than 1 year has confirmed performance with no tube failure ensuring 100% HSE. Post project implementation resulted in more heat recovery from flue gases due to increased. Flue gas temperature leaving convection section was reduced from 450°C to 220°C. Consequently, required fuel gas consumption was reduced considerably by 9031 MT per year for two heaters. In conclusion, similar reductions in fuel gas consumption can be achieved over the equipment's extended service life. The implementation has led to not only to increase in heater efficiency but in turn improved the heater duty for same burner capacity, there by supporting increase in plant throughput. Novel/Additive Information Conventional approach of replacing tube with improved metallurgy would have ensured process safety and structural integrity. However, the synchronized and pre-emptive engineering approach has yielded multiple benefits for the rest of the heater as well plant operational life. This also led to improved efficiency and Optimum Energy Conservation and save operating cost up to almost 1.1Million USD/year. Even a leak can lead us to peak if the opportunity is harvested in right way.

This paper presents details of the development of the Middle East to India Deepwater Pipeline (MEIDP) providing information on the technical and commercial feasibility of the deepwater gas transportation system, which will reach a record water depth of 3450m, cross two continental slopes, an earthquake subduction zone (the Owen Fracture Zone) and outfall debris of the river Indus fan in 2500m water depth. High pressure trunk lines have proved to be the safest, cheapest way of transporting gas to market for short to medium distances up to 2,500 kilometers, making the proposed SAGE - Middle East to India Deepwater Pipeline the optimal solution for gas delivery to the Indian Subcontinent. Linking Middle East gas fields of Saudi Arabia, UAE and Oman to India across the Arabian Sea for an offshore distance of 1200 kilometers. The MEIDP gas transmission pipeline is designed to transport up to 1.1BCFD gas into the Indian energy markets. The economic and political drivers for such a project are presented together with details of the overall project cost and tariff calculation to allow successful gas utilization by India's gas starved and stranded power stations. The pipeline project history and current design status will be reviewed together with findings of the Marine Reconnaissance survey between Oman and India. The challenges faced by the project from both a design and installation perspective are discussed together with some of the detailed geohazard assessments performed for the pipeline crossing and active fault zone (OFZ) and the Indus Fan. The qualification plan developed with DNVGL is described together with details of the future construction schedule for first Gas. As a project that builds from the Oman-India project of the 1990's; the changes in risk profile in terms of industry and vessel readiness are reviewed, and the readiness of the next generation of installation vessels to install such a pipeline is discussed.

Objective This study aims at high-fidelity modeling and mechanistic optimization of gas dehydration and NGL (Natural Gas Liquids) systems of a commercial natural gas plant based in Abu Dhabi, UAE. Scope of the work includes development of models, validation of models with plant data, optimization analysis and real-time validation at the plant site. Method In this work, we developed a dynamic model for the gas dehydration system and a steady state model for the natural gas liquids recovery unit. An advanced process simulator that follows equation-oriented approach is employed as the modelling and optimization platform. We first show the comprehensive plant data reconciliation followed by the model validation using the operating data of the years 2016 and 2018, to ensure that the model predictions match the real plant operation. We then present how the mechanistic optimization entity result in the best operating conditions for the natural gas liquids recovery system. We also show the optimization analysis that aims at maximizing the adsorption cycle time for the dehydration unit while minimizing the total heating duty required for the regeneration of the molecular sieve beds. Results Optimization analysis reveals a significant increase in the annual net revenue of natural gas liquid recovery unit as a result of modifying various process operating conditions that lead to higher liquid hydrocarbon production and lower operating costs related to steam and refrigeration. Similarly, optimization analysis of the dehydration system indicates that adsorption-step time can be increased to a higher value, which results in significant reduction of regeneration costs. As a next step, we aim to carry out the validation tests on the plant site to verify and implement the model recommendations in the real plant to verify the model recommendations. We also plan to derive the set of operating guidelines that allow the operators to drive the plant towards optimal operation. Novelty & Significance To the best knowledge of authors, this study is the first effort to build a holistic model comprising of the dynamic dehydration model and steady state NGL model on a common platform. Rigorous validation of the model is performed using real plant data of two calendar years. Scope of this study also includes real time validation of the model recommendations through tests performed at plant site.

This paper focuses on cost-effectively designing, developing, and operating liquified natural gas (LNG) facilities in Arctic environments. It discusses the inherent challenges associated with engineering, constructing, and operating LNG infrastructure in harsh and highly remote conditions and outlines proven strategies for reducing risk. Specific areas that are discussed include the use of modular design techniques to mitigate overall project risk and drive efficient execution, as well as the deployment of digital tools/technologies for minimizing operating and maintenance costs and maximizing plant availability. For illustrative purposes, the paper discusses the strategies employed on two real-world LNG projects, both of which are located inside the Arctic Circle.