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 Lateral vibration is the most commonly measured type of vibration in machinery. However, lateral motion in the XY plane does not completely describe all the possible directions of motion of machine components. Torsional vibrations do not get the attention that they should. Since torsional vibration is more difficult to measure than lateral vibration, it is often ignored, due to an "out of sight, out of mind" attitude. In fact, torsional vibration can be quite severe and can produce damaging cyclic stresses that can cause a fatigue failure. Rotating machines are all involved in the delivery or transformation of power, and power delivery requires transmission of torque. The applied torque causes the shaft to twist about its rotational axis. Thus, instead of measuring displacement relative to an equilibrium position, torsion requires measuring the angle of twist of the shaft at different axial positions. All rotating machineries undergo some fraction of degrees of torsional vibration during operations. In many cases, the torsional vibrations are not as easily identified as the translational vibrations, due to lack of simple and direct measurement devices. Typical damages developed under excessive torsional vibrations include shaft cracks, coupling cracks, gear wear, gear tooth failures, key failures, shrink fit slippage, etc. Today torsional vibration detection and monitoring becomes an important step in rotating machinery condition monitoring [ Eshleman 1977 , Muszynska, A. G. 1992 , Naldi, L. B. (June 9–13, 2008) , Naldi, L. G. 2011 ]. Today the machinery diagnostic services team of Baker Hughes, Bently Nevada uses ADRE raw data along with self-developed Matlab executable [ Huageng, L, Howard, B, Menon, A, Péton, N, Roengchai, C. 2013 , Luo, H. C. 2013 ] application for diagnostic purposes based on phase demodulation process to the signals generated by Keyphasor ® or zebra tape of tooth wheels. In this article torsional issues will be illustrated with data and pictures using 6 real cases from the industry.

Abstract The compression units installed on sales gas network face wide range of operating modes owing to the varying supply & demand scenarios and the associated network dynamics. It is very challenging to ascertain the real performance in such applications due to changing specific energy consumption. The paper presents development of a novel and robust monitoring system, enabling realtime energy performance monitoring of dynamic compression and revealing realistic opportunities for energy savings. The methodology comprised review of design and OEM data for the compression units, followed by review of operating envelope. Subsequently, developed a thermodynamic model of compression units encompassing all the operating modes. Then embedded the actual performance curves from OEM in the thermodynamic digital twin and validated the model with actual operating data. Carried out site visits and held discussions with technical teams as part of the comprehensive approach. A mathematical model additionally developed, in addition to the thermodynamic model, to enable operators for off-line monitoring of the compressors performance during unavailability of thermodynamic digital twin. Detailed performance analysis of centrifugal compressors is essential to ascertain their condition and functioning. A decrease in performance can be an indication of internal wear or fouling, which if allowed to continue, may result in reduced throughput or excessive energy consumption or even unscheduled outages. Thus, the performance is not just an indication of energy or operating cost but also reflects other vital aspects like reliability. The integrated thermodynamic digital twin developed for large sales gas compression units, with total throughput capacity of more than 500 MMSCFD, has enabled and demonstrated effective energy performance monitoring even with changing operating scenarios. It facilitated real-time comparison of actual performance (specific energy consumption) with model based expected performance. It also aided real-time trending of polytropic efficiency as well as real-time display of potential energy savings opportunities. The digital twin has proven to be a reliable and low cost tool to predict compressor performance for various operating modes on real time basis. The data from the compression digital twin can be tied into process simulation models for process optimization. The model can complement supervisory capabilities, diagnostics, control capabilities and even facilitate in predicting failures ahead of time.

Abstract The objective of this paper is to showcase the successful and innovative troubleshooting data analysis techniques in one of the gas compression systems in upstream gas oil separation plants (GOSP-A). The gas compression system using gas compressors, dry gas seal systems and due point controls is used in almost all of upstream operation. These proven data analysis techniques were used to tackle major and chronic issues associated with gas compression system operation that lead to excessive flaring, mechanical seal failures, and off-specification products. Dry Gas mechanical seals are an important key element in gas compression and its lifetime represents a concern to the operation personnel. Most gas compression systems have a mechanical seal lifetime of 2 years which in some cases limit production, increase the potential of unnecessary flaring and increase OPEX significantly. In this paper, comprehensive data analysis of the potential root causes that aggravate undesired premature mechanical seal failures and off-specification gas products will be discussed along with solutions to minimize expected impact. For example, improper gas conditioning that feeds dry gas mechanical seals increase the risk of premature failures. Additionally, improper product specification in some applications have been found to promote seal failures and incur additional flaring which is both costly and environmentally undesirable. In addition, after extensive analysis improper operation practices during compressor startups, steady state operation and gas conditioning have been linked with premature compressor failures, product off spec and safety device failures. The field trial proved the effectiveness of the proposed innovative troubleshooting data analysis techniques in reinstating the gas compression unit in GOSP-A to its recommended design conditions, eliminated compressors and mechanical seal failures and avoided the off-specification products at the lowest operating cost. This innovative technique was based on deep and extensive process data analysis, evaluating operating and design data, reviewing international standards, benchmarking against other facilities, process simulation using Hysys, and finally the actual field trial.

Abstract The cost of carbon capture is the major impediment in its mainstream acceptance, but its ability to abate the carbon emissions at a considerable scale, makes it a technology with promising potential. The paper presents detailed account of the energy optimization meticulous review carried out for a brownfield project to capture carbon from the Sulphur Recovery Unit (SRU) Tail Gas. The paper demonstrates the vital role of energy optimization in restraining the carbon capture cost. The methodology comprised development of an overall integrated heat & power model of the process encompassing energy supply sources, including power generation and import, and major energy consumers like CO 2 absorption solvent regenerator, CO 2 compressor and dense phase CO 2 pump etc. The optimization was achieved by setting the objective function to minimize energy cost in terms of steam & power demand, by relating the selection of major drivers i.e. electric motor or steam turbine, as well as solvent, with the total energy cost in conjunction with the associated CAPEX. It followed with a meticulous review of individual systems and components. Comprehensive energy optimization exercise, equating energy supply, major drivers’ selection and process decisions with the total energy cost and the associated CAPEX minimization, facilitated in carbon capture cost reduction by more than 10%. The optimized scheme helped in maximizing the utilization of available waste heat as well as in minimizing the spare steam dumping in condensers. The exercise confirmed the absolute significance of the energy optimization measures in reducing the cost of carbon capture.

Efficient Utilization of N2 during Commissioning and Startup In one of ADNOC's mega projects, Nitrogen was utilized for commissioning as well as start-up purposes, saving time and assessing equipment performance much earlier than planned. This paper which will be sectionalized in two parts, presents an extraordinary approach out of the norms for the usual nitrogen use in upstream oil and gas industries of purging and blanketing, resulting in significant savings in time and expenditure. Commissioning with N 2 There are many arguments about the risk / reward relation when it comes to applying Field test run with an inert gas (N 2 ) ahead of hydrocarbon in, involving high pressure centrifugal compression systems. This part aims to discuss the advantages of adopting N 2 testing well ahead of gas-in, challenges and rewards. Although the codes from API and ASME give details on the requirements of running compressors with gases different of design ones. The installation, the procedure, and the acceptance criteria are subject of agreement between vendor and company. Therefore, it's important to detail and agree with the Vendors on all process and mechanical criteria, limitations and necessary precautions ahead of adopting such tests. Additionally In this part, the various requirements to adopt testing high pressure compressor with N 2 gas will be presented and along with a discussion on their capabilities to detect a variety of problems. Some issues which occurred during the N 2 test run at site will be described. Based on test characteristics and at the related cases, recommendations are made when ordering new compression system with considerations regarding the return of investment of these tests. Startup with N 2 Nitrogen (N 2 ) was used as a stripping medium during the initial startup of the plant facilities. The target was to start producing stabilized crude simultaneously with the hot commissioning of the gas circuit. This part presents the overall results of adopting this approach. An assessment was carried out utilizing simulation software HYSYS prior to the startup. Post startup, actual field results were collected to analyze the effectiveness of N 2 stabilization. N 2 was proven to be an effective stripping medium in crude stabilization.

Abstract In line with the ADNOC HSE Policy, our goal is to minimize gas flaring to environment from Acid gas flare common for four plants as much as possible, using best available technologies. The requirement is to recover the flare gases instead of being burnt in the Acid gas flare systems during normal plant operations and compress to the required pressure for injecting back into the processing facilities at the suction of Medium Pressure (MP) Compressors. Hydrocarbon liquids and sour water separated in the Acid gas flare recovery system (AGFRS) sent to existing sour water stripper. The World Bank introduced the "Zero Routine Flaring by 2030" initiative, which serves as the foundation for our objectives to reduce acid gas flaring and recover flared gases. This is achieved by successful implementation of acid Gas Flare Recovery Systems in one of the existing ADNOC Gas Processing complexes. This paper presents the stages involved and detailed design, i.e. Study, FEED and EPC. The journey of implementing state of the art AGFRS commenced by conducting a thorough in-house study of all existing acid gas flare discharges from various operating plants in the complex, which were connected by a common acid gas flare system. After measurement and tally of flare flowrate during normal plant operations over a period, it was possible to forecast flow rates through the common acid gas flare header for various scenarios. The in-house study and analysis indicated potential recovery of approximately 1-3 MMSCFD of gas from existing operating plants. This study prompted subsequent FEED and EPC detailed design phases, with HAZOP and SIL sessions to derive an inherently safe design to overcome implementation challenges. The project successfully commissioned in September 2014. The AGFR system found to be capable of operating at flowrates up to the design flowrate across the full range of molecular weights. The predicted recovery of acid gas was in the range of 1-3 MMSCFD. However, the actual average annual recovery of acid gas for a period of five years, after commissioning of the project, 2.5-3.27 MMSCFD for the period 2015-2019. Total Cost benefits for a period of five full years (Jan 2015 to Dec 2019) accumulate to US$ 14 MM (Basis: 2.61 US $/MMBTU, 1000 BTU/SCF). Total saving of CO2 emissions for a period of five full years (Jan 2015 to Dec 2019) accumulate to 325 KT (Basis: 140 billion cubic meters annually = 300 million Tonnes of CO2, 1MMSCFD= 22.14 KT of CO2/year). The acid Gas Flare recovery unit has helped to achieve significant benefits by minimizing acid gas flaring to the environment and thereby reducing the carbon footprint in support of environmental norms, while still maintaining process safety for the existing plants. The successful implementation of AGFRS is first of its kind within ADNOC Gas Processing. The project demonstrates tangible benefits to minimize continuous flaring with an operational record of accomplishment of nearly five continuous years. The experience demonstrates that it offers reliable means to recover acid gases across a wide range of gas compositions without affecting the safety of the existing facilities and thus achieves 100% HSE, and increases profitability with a reduced environmental impact.

Abstract Gathering system optimization is no longer an option for any operator, it is a necessity. The primary objective for an operator is to match the demand at the sales point to avoid penalties due to minimum volume commitment (MVC) agreement. With time, operators face challenges to adhere to this demand due to inefficient production surveillance, production optimization & capital project evaluation. Also, with oil & gas price at its lowest, operators are now facing increased cost pressures leading to less personnel for field operations. Operators are now collecting & managing a lot of data than ever from their operations as part of their digital journey, which enables them to improve the network performance using machine learning. Insights or details missed by operators or conventional first principle-based models can be derived & explained using these models. The paper talks about this novel approach of machine learning-based collaborative platform called ‘Digital Twin’. Digital Twin is based on automated data flow from ingesting data from SCADA system, pushing required data to the steady-state simulator, receiving simulated results, & finally viewing the machine learning augmented simulation results on the platform. In this solution, the Bayesian Changepoint model is trained on wellhead flowrate & line pressure to identify critical wellpads & pipeline sections needing intervention, in real-time. Deep learning-based neural network algorithm is then integrated as part of the digital twin to accurately predict the scenario of field changes. This neural network algorithm is trained on the actual field data along with steady-state simulation results. The model output helps the operator to identify the deviation of the simulation results from actual field data, then improving the simulation results for certain scenarios of field changes. The improvement in accuracy by about 15% was realised with the neural network structure of 5 layers (3 hidden layers + input layer + output layer) through its machine learning augmented simulation results. With improved accuracy, operators are accepting the solution to make real-time operational decisions through the automated architecture resulting in a 95% reduction in time for simulating scenarios. This paper aims to provide a blueprint of the digital twin solution & explaining its potential for easy scalability across different gathering networks.

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.

The objective of this paper is to communicate lessons learned, best practices and process enhancement initiatives identified during an actual implementation of Integral Wellhead Gas Compressor technology. The compressor installation was a technology trial test in a challenging high condensate sandstone environment in a conventional gas field. Several technical lessons learned were identified especially in the areas of liquid handling, produced solids management, as well as downhole well intervention requirements. The methodology was based on collecting and documenting operational challenges and their root causes and corresponding technical solutions as the project progressed. In addition, a benchmarking study was conducted to identify additional areas of improvement to address the root causes of these challenges. Addressing these challenges by implementing the lessons learned highlighted in this paper will ensure expedited project delivery at a reduced cost. Examples of such challenges include unexpected severe liquid slugging, high amounts of solids production, as well as corrosion resistant alloy (CRA) metallurgy requirements. The benchmarking study resulted in the identification of several areas of potential improvement and multiple engineering process enhancement initiatives were recommended. Examples of such initiatives include the utilization of integrated Liquid Handling System (LHS) to mitigate severe liquid slugging and reduce assembly lead-time. In addition, the utilization of surface cyclonic sand filter systems to mitigate solids production. In addition, conducting downhole tubing drift runs to ensure no restrictions are present that can reduce compressor performance along with several other relevant initiatives. In summary, the paper provides a deep dive into several technical operational challenges during the actual implementation of wellhead gas compressor technology in a challenging high condensate sandstone environment. Also, several new initiatives are proposed in this paper with the objective of achieving significant cost savings. It is intended for these initiatives to be adopted as best practices not only to yield cost savings but also to supplement the existing best practice literature in the areas of liquid handling, solid management systems, quality control and well intervention.

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.

The objective of this paper is to showcase successful and innovative means and techniques to improve and enhance centrifugal gas compressors (CGCs) performance, using methods to minimize power consumption, with no need for capital investment. These techniques will assure, if effectively followed, considerable reduction of the consumed energy. CGCs are the most widely used equipment in the oil and gas industry to boost gas, mainly hydrocarbons, to satisfy process treatments and pipeline requirements. In addition, CGCs are one of the major energy consumers, and therefore present an exceptional opportunity for saving energy. Focusing on lowering inlet gas temperatures, considering suction throttling of discharge pressure instead of the traditional discharge throttling, will help to reduce energy consumption. In this paper, a detailed analysis of factors aggravate or lead to undesired CGCs performance will be discussed along with solutions to minimize adverse impact. For example, operating the gas compressors at relatively high inlet temperature will result in higher energy consumption. After performing need analysis, results prove that we would save 3-7% of running compressors consumed energy. In addition, during compressor design phase, it was found that most motor driven compressor system uses discharge throttling, which incurs high-energy consumption. Instead, it is recommended to consider suction throttling to control discharge pressure, as will be explained. This paper will focus on a detailed case study in one of the running CGCs in an upstream gas-oil separation plant (GOSP-A). This paper proves the effectiveness of the proposed techniques in reinstating the CGCs in GOSP-A, to ensure better performance and save energy. This innovative technique is based on extensive process data analysis — evaluating operating, design data, related performance curves, and reviewing international standards. It will be illustrated that this type of analysis and techniques is a valuable tool for saving energy, in most cases, at oil and gas industries

Following the trend of energy efficiency, the Oil&Gas sector is looking continuously to sustainable solutions aimed to reduce carbon footprint while maintaining competitiveness. The market shows that a clever way for O&G field is the implementation of Organic Rankine Cycle technology, which turns waste-heat into useful power, with minimum impact on the existing facilities. An ORC unit can exploit waste heat from several sources. Different ORC applications within the O&G field were studied. The study conducted evolved in two phases. The first one aimed to identify the most suitable waste heat sources unexploited in the O&G facilities. The second one explored the technical and economic analysis of different configurations, in order to understand the best ORC solution for this industrial sector (in terms of process parameters, equipment and layout). A proved ORC application was in the Gas-compressor-stations along the pipelines where multiple gas-turbines operating in open-cycle are used as prime-movers for compressors. Although reliable and flexible, they waste a significant amount of energy that can be converted into useful power by means of an ORC system, a clear opportunity to boost the overall efficiency of the plant. Other applications regarded the exploitation of hot streams in associated petroleum gas (APG) process carried-out within refineries. Due to its poor chemical composition, APG are typically burned via torches, thus wasted. ORC can exploit that energy to produce electricity by means of a flare-gas-boiler which heats up a vector fluid to feed the turbogenerator. Beside those waste-heat streams, another potential form of energy was available in gas pressure-letdown stations, where lamination valves dissipate the potential energy contained in the pressurized gas. In this scenario, the Gas-expander technology (similar to ORC) can be a valuable alternative and a more efficient solution. It consists in a turbine through which the NG at high pressure, rather than being laminated, expands to produce work, thereafter converted into electricity by a generator. This paper will present the above-mentioned solutions, employed both individually or combined. Considering a large-scale application, the paper will show how the implementation of the ORC recovery systems represents other than a way to meet sustainability targets also a remarkable and profitable business for O&G companies. Furthermore, the Gas Expander technology represents a solution to improve the energy efficiency of NG transmission and distribution networks, as well as upstream and downstream facilities.

The compression units installed on sales gas network face wide range of operating modes owing to the varying supply & demand scenarios and the associated network dynamics. It is very challenging to ascertain the real performance in such applications due to changing specific energy consumption. The paper presents development of a novel and robust monitoring system, enabling realtime energy performance monitoring of dynamic compression and revealing realistic opportunities for energy savings. The methodology comprised review of design and OEM data for the compression units, followed by review of operating envelope. Subsequently, developed a thermodynamic model of compression units encompassing all the operating modes. Then embedded the actual performance curves from OEM in the thermodynamic digital twin and validated the model with actual operating data. Carried out site visits and held discussions with technical teams as part of the comprehensive approach. A mathematical model additionally developed, in addition to the thermodynamic model, to enable operators for off-line monitoring of the compressors performance during unavailability of thermodynamic digital twin. Detailed performance analysis of centrifugal compressors is essential to ascertain their condition and functioning. A decrease in performance can be an indication of internal wear or fouling, which if allowed to continue, may result in reduced throughput or excessive energy consumption or even unscheduled outages. Thus, the performance is not just an indication of energy or operating cost but also reflects other vital aspects like reliability. The integrated thermodynamic digital twin developed for large sales gas compression units, with total throughput capacity of more than 500 MMSCFD, has enabled and demonstrated effective energy performance monitoring even with changing operating scenarios. It facilitated real-time comparison of actual performance (specific energy consumption) with model based expected performance. It also aided real-time trending of polytropic efficiency as well as real-time display of potential energy savings opportunities. The digital twin has proven to be a reliable and low cost tool to predict compressor performance for various operating modes on real time basis. The data from the compression digital twin can be tied into process simulation models for process optimization. The model can complement supervisory capabilities, diagnostics, control capabilities and even facilitate in predicting failures ahead of time.

The cost of carbon capture is the major impediment in its mainstream acceptance, but its ability to abate the carbon emissions at a considerable scale, makes it a technology with promising potential. The paper presents detailed account of the energy optimization meticulous review carried out for a brownfield project to capture carbon from the Sulphur Recovery Unit (SRU) Tail Gas. The paper demonstrates the vital role of energy optimization in restraining the carbon capture cost. The methodology comprised development of an overall integrated heat & power model of the process encompassing energy supply sources, including power generation and import, and major energy consumers like CO 2 absorption solvent regenerator, CO 2 compressor and dense phase CO 2 pump etc. The optimization was achieved by setting the objective function to minimize energy cost in terms of steam & power demand, by relating the selection of major drivers i.e. electric motor or steam turbine, as well as solvent, with the total energy cost in conjunction with the associated CAPEX. It followed with a meticulous review of individual systems and components. Comprehensive energy optimization exercise, equating energy supply, major drivers’ selection and process decisions with the total energy cost and the associated CAPEX minimization, facilitated in carbon capture cost reduction by more than 10%. The optimized scheme helped in maximizing the utilization of available waste heat as well as in minimizing the spare steam dumping in condensers. The exercise confirmed the absolute significance of the energy optimization measures in reducing the cost of carbon capture.

Efficient Utilization of N2 during Commissioning and Startup In one of ADNOC's mega projects, Nitrogen was utilized for commissioning as well as start-up purposes, saving time and assessing equipment performance much earlier than planned. This paper which will be sectionalized in two parts, presents an extraordinary approach out of the norms for the usual nitrogen use in upstream oil and gas industries of purging and blanketing, resulting in significant savings in time and expenditure. Commissioning with N 2 There are many arguments about the risk / reward relation when it comes to applying Field test run with an inert gas (N 2 ) ahead of hydrocarbon in, involving high pressure centrifugal compression systems. This part aims to discuss the advantages of adopting N 2 testing well ahead of gas-in, challenges and rewards. Although the codes from API and ASME give details on the requirements of running compressors with gases different of design ones. The installation, the procedure, and the acceptance criteria are subject of agreement between vendor and company. Therefore, it's important to detail and agree with the Vendors on all process and mechanical criteria, limitations and necessary precautions ahead of adopting such tests. Additionally In this part, the various requirements to adopt testing high pressure compressor with N 2 gas will be presented and along with a discussion on their capabilities to detect a variety of problems. Some issues which occurred during the N 2 test run at site will be described. Based on test characteristics and at the related cases, recommendations are made when ordering new compression system with considerations regarding the return of investment of these tests. Startup with N 2 Nitrogen (N 2 ) was used as a stripping medium during the initial startup of the plant facilities. The target was to start producing stabilized crude simultaneously with the hot commissioning of the gas circuit. This part presents the overall results of adopting this approach. An assessment was carried out utilizing simulation software HYSYS prior to the startup. Post startup, actual field results were collected to analyze the effectiveness of N 2 stabilization. N 2 was proven to be an effective stripping medium in crude stabilization.

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.

Gathering system optimization is no longer an option for any operator, it is a necessity. The primary objective for an operator is to match the demand at the sales point to avoid penalties due to minimum volume commitment (MVC) agreement. With time, operators face challenges to adhere to this demand due to inefficient production surveillance, production optimization & capital project evaluation. Also, with oil & gas price at its lowest, operators are now facing increased cost pressures leading to less personnel for field operations. Operators are now collecting & managing a lot of data than ever from their operations as part of their digital journey, which enables them to improve the network performance using machine learning. Insights or details missed by operators or conventional first principle-based models can be derived & explained using these models. The paper talks about this novel approach of machine learning-based collaborative platform called ‘Digital Twin’. Digital Twin is based on automated data flow from ingesting data from SCADA system, pushing required data to the steady-state simulator, receiving simulated results, & finally viewing the machine learning augmented simulation results on the platform. In this solution, the Bayesian Changepoint model is trained on wellhead flowrate & line pressure to identify critical wellpads & pipeline sections needing intervention, in real-time. Deep learning-based neural network algorithm is then integrated as part of the digital twin to accurately predict the scenario of field changes. This neural network algorithm is trained on the actual field data along with steady-state simulation results. The model output helps the operator to identify the deviation of the simulation results from actual field data, then improving the simulation results for certain scenarios of field changes. The improvement in accuracy by about 15% was realised with the neural network structure of 5 layers (3 hidden layers + input layer + output layer) through its machine learning augmented simulation results. With improved accuracy, operators are accepting the solution to make real-time operational decisions through the automated architecture resulting in a 95% reduction in time for simulating scenarios. This paper aims to provide a blueprint of the digital twin solution & explaining its potential for easy scalability across different gathering networks.

This paper explains how advanced digitalization concepts were employed in the development and construction of the Taweelah Gas Compression Plant in the United Arab Emirates (UAE). The plant began operation in late 2018 and is one of the largest and most modern compression facilities in the world. It is owned and operated by the Abu Dhabi National Oil Company (ADNOC) and comprises three compression trains, each with a processing capacity of 225 million standard cubic feet per day (mmscfd). Two operate at any one time, with the third on standby, giving the plant 450 mmscfd of total production throughput. Using the Taweelah Gas Compression Plant as an example, the paper describes how onshore oil and gas compression stations can be built efficiently and economically by leveraging advanced digital technologies, such as Digital Twins. Other concepts/strategies that the paper will discuss which can help accelerate project schedules and reduce costs include: Sophisticated hydraulic modeling software; Large power blocks to reduce the number of compression trains; Sole-source provisioning of compression drive trains; ‘Plug and play’ equipment packages that required minimal onsite commissioning; Remote diagnostics and analytics for condition monitoring and condition-based maintenance to ensure maximum uptime and availability; Using the combination of the above concepts, along with extensive collaboration/co-creation between Siemens Energy and ADNOC, the Taweelah plant was able to achieve first gas just 16 months after front-end engineering design (FEED).

In line with the ADNOC HSE Policy, our goal is to minimize gas flaring to environment from Acid gas flare common for four plants as much as possible, using best available technologies. The requirement is to recover the flare gases instead of being burnt in the Acid gas flare systems during normal plant operations and compress to the required pressure for injecting back into the processing facilities at the suction of Medium Pressure (MP) Compressors. Hydrocarbon liquids and sour water separated in the Acid gas flare recovery system (AGFRS) sent to existing sour water stripper. The World Bank introduced the "Zero Routine Flaring by 2030" initiative, which serves as the foundation for our objectives to reduce acid gas flaring and recover flared gases. This is achieved by successful implementation of acid Gas Flare Recovery Systems in one of the existing ADNOC Gas Processing complexes. This paper presents the stages involved and detailed design, i.e. Study, FEED and EPC. The journey of implementing state of the art AGFRS commenced by conducting a thorough in-house study of all existing acid gas flare discharges from various operating plants in the complex, which were connected by a common acid gas flare system. After measurement and tally of flare flowrate during normal plant operations over a period, it was possible to forecast flow rates through the common acid gas flare header for various scenarios. The in-house study and analysis indicated potential recovery of approximately 1-3 MMSCFD of gas from existing operating plants. This study prompted subsequent FEED and EPC detailed design phases, with HAZOP and SIL sessions to derive an inherently safe design to overcome implementation challenges. The project successfully commissioned in September 2014. The AGFR system found to be capable of operating at flowrates up to the design flowrate across the full range of molecular weights. The predicted recovery of acid gas was in the range of 1-3 MMSCFD. However, the actual average annual recovery of acid gas for a period of five years, after commissioning of the project, 2.5-3.27 MMSCFD for the period 2015-2019. Total Cost benefits for a period of five full years (Jan 2015 to Dec 2019) accumulate to US$ 14 MM (Basis: 2.61 US $/MMBTU, 1000 BTU/SCF). Total saving of CO2 emissions for a period of five full years (Jan 2015 to Dec 2019) accumulate to 325 KT (Basis: 140 billion cubic meters annually = 300 million Tonnes of CO2, 1MMSCFD= 22.14 KT of CO2/year). The acid Gas Flare recovery unit has helped to achieve significant benefits by minimizing acid gas flaring to the environment and thereby reducing the carbon footprint in support of environmental norms, while still maintaining process safety for the existing plants. The successful implementation of AGFRS is first of its kind within ADNOC Gas Processing. The project demonstrates tangible benefits to minimize continuous flaring with an operational record of accomplishment of nearly five continuous years. The experience demonstrates that it offers reliable means to recover acid gases across a wide range of gas compositions without affecting the safety of the existing facilities and thus achieves 100% HSE, and increases profitability with a reduced environmental impact.