Khurais central processing Facility is a hydrocarbon plant consists of 5 GOSPs with a stabilizer (i.e oil train), 3 gas plants and power plant with their associated utilities. Each oil train has one HP gas compressor to send the gas from oil trains to gas plant. These compressors is oversized and running each compressor alone results in excessive recycling and wasting energy. In 2018 Khurais introduced a new energy optimization initiative which is swing line that is a common header connects all HP compressors together with the objective of maximizing operating loads in each gas compressor. In doing so, the last compressor can be shut down for as long as the capacity of the other compressors is still adequate to accommodate the extra gas rate from the shutdown compressor.[ 1 ] (Refer to Figure 2 ) Although this approach resulted in maximizing energy efficiency of the facility it introduced a new challenge to the facility which is in case of any trip to a compressor connected to swing line all other connected compressors will trip. Recently Khurais introduce a new philosophy to shift the load from tripped compressors to other compressors through modifying swing line and compressors DCS control logics. This paper covers the swing-line control logic modifications and enhancement followed by Saudi Aramco Khurais producing facility to overcome multiple compressor outages challenge. This paper is aimed to: Share the challenge of multiple compressors trips with swing line operations that occurs if one of the compressors connected to swing line is tripped resulting in 100% of gas flaring. Present dynamic simulation modelling results and new logic modifications implemented for compressor controls to avoid such multiple trips scenario. Present Compressor trips cases before and after implementing the control logic enhancements. Highlight how this approach enhanced compressor's reliability and helped Saudi Aramco to reduce its carbon footprint. In this paper various dynamic simulation modelling graphs that showed the root cause for multiple compressor trips will be presented, evaluation of several control logic and their consequences. This topic will also cover the new proposed logic with zero investment to avoid multiple compressors trip scenario with operations of swing line. Details about behavior of compressor before and after the modification including the reaction of newly implemented control logic in flare control valves is included part of this paper. After the implementation of this logic the following results have been realized: No incident of multiple compressor trips happened due to proper functioning of logic. Eliminated 60-100 MMSCF/year of flaring due to multiple compressors trips scenario through having "quickest" handle to restoring flow to the swing line and stop flaring. Reducing carbon footprints due to flaring compared to old setup. Realized Recovered revenue worth approximately US$ 500,000/year The novelty in this paper is describing an approach of gradual load shifting from a tripped compressor to other running compressors to avoid multiple compressors trips which can be utilized in any facility that has a common suction header connects all its compressors. Such logics can be implemented in-house with no modification in compressors or swing lines or other equipment.

Well network simulation and optimization is an established technology within BP for production optimization. However, for simplicity, the processing facilities are usually only considered as fixed oil, gas and water flow rate constraints. Actual production limits vary as a function of operating conditions and/or cannot be measured directly (e.g. True Vapour Pressure (TVP) or gas velocity at the inlet separator nozzles). To improve on existing workflows, BP has expanded its existing petroleum engineering-focused toolkit and is now globally deploying an end-to-end production system digital twin that extends from the well choke to the facility export for system surveillance and optimization. The end-to-end production system digital twin is a cloud-based system that links sensor data from the asset historian with an equipment data model and third-party first principle steady state simulation tools for an accurate representation of the well network and processing facilities. It supports multi-discipline collaboration, particularly between Petroleum Engineers and Process Engineers, and is remotely accessible by a globally dispersed team. This integrated digital twin can be used in two modes: monitoring and what-if. In monitoring mode, the models are automatically updated hourly with real time data and key simulation results extracted and stored. These monitoring simulations generate virtual sensor output, providing insights that cannot be measured by real sensors. In what-if mode, engineers test scenarios risk-free to explore optimization opportunities. As well as routine optimizations to align with production forecast updates, this can also include scenarios during planned abnormal operations (e.g. facility equipment offline for maintenance or well flowback). An early pilot in a key production region delivered significant production upside and was foundational for the subsequent global roll-out program. This paper will illustrate two practical applications from early deployment activities: (1) condensate recovery optimization (2) well routing optimization / feasibility against variable processing facility limits.

Maintenance costs and machine availability are two of the most important concerns to gas turbine equipment owner. Therefore, a well thought out maintenance program that reduces costs while increasing equipment availability should be instituted. The correct implementation of planned maintenance relying on preventive maintenance optimization through perfect inspection frequency and scope provides direct benefits in the avoidance of forced outages, unscheduled repairs, and downtime. Major overhaul is carried out for each gas turbine every 48,000 firing hours which costs around 1 M USD for each engine and with more than 8 months unavailability for the unit. To increase equipment availability and enhance cost and time efficiency, alternatives approaches were evaluated including Service Exchange of gas turbines. It is found that service exchange is the best option for optimizing time and cost of overhaul of such engines. This paper is written to improve Major Overhaul practice for existing Gas Turbines from ongoing practice of routine major overhaul including engine strip down, inspection and repair to Service Exchange of Gas Generator and Power Turbine every 48,000 firing hours.

This paper discusses how the application of large, gas turbine-based power blocks (>50,000-hp) in pipeline compression stations can contribute to lower capital costs, improved lifecycle performance, and reduced carbon emissions. For illustrative purposes, two compression facility power block configurations (nine 30,0000-hp trains vs. five 55,000-hp trains) are compared on the basis of capital expenditures (CapEx), operating expenditures (OpEx), availability, efficiency, and operating flexibility. A summary of the study's results are as follows: – Net present value (NPV) analyses show that 5x55,000-hp ISO trains can result in up to $50 million reduction in CAPEX vs 9x30,000-hp ISO trains – By having fewer trains, operations & maintenance (O&M) costs can be reduced by as much as 20% – Lifetime fuel savings with a 5x55,000-hp train configuration vs. 9x30,000-hp trains are estimated at $40 million, owing to the increased operating flexibility of modern gas turbines, even at partial loads. The paper will also present considerations for digitalization, modular construction, and package integration – with a particular focus on how these measures can be leveraged to lower execution risk and enhance the lifecycle performance of gas turbine-driven compression trains.

To explore the opportunity for maximum utilization for a Sales Gas Compression Facility (SGCF) in line with ADNOC strategy to enhance profitability and asset utilization. A technical study was conducted to increase the processing capacity up to 133% of its design limit by utilizing the available design margins. This was to identify the potential bottlenecks in the facility and suggest debottlenecking options (if bottlenecks are there). The Technical study covered the following activities: Simulation: Process simulation was performed and H&MB (Heat and Material Balance) was generatd. Engineering: Compressor adequacy checks on increased plant throughputs. Static Equipment rating and adequacy checks performed with the concurrence of original equipment menufacturerers. Line sizing adequacy checks and detailed evaluation of the piping. Adequacy check for In-line instruments like control valves, flow elements/transmitters (Note 1) Relief, blowdown and flare system adequacy check. Utilities adequacy checks. Risk assessment workshop was conducted before the capacity test run. Preparation of Test Run procedure before the actual test run. Actual plant capacity test run to verify the study findings. Note 1: Adequacy check of thermowells had been peformed separately prior to the study. It had already been established that the thermowells were adequate for the increased plant throughputs. The study has concluded the following observations for processing 133% of the design capacity Theoratically, the Sales Gas Compression Plant is adequate to handle the sales gas throughput up to 600 MMSCFD (2 running machines) considering the facts that Sales Gas Compressor suction pressure must always be kept at 32 barg through close monitoring by the operaters. If compressor suction pressure starts dropping below 32 barg, the study outcome would no more valid and the plant throughput would be reduced back to the original design capacity of 450 MMSCFD. Moreover, it was recommended to perform a field test run to validate the study outcome by following the Manageement of Change Procedure as applicable. Based on the successful 48 hours test run, it was established that the facility could handle the increased plant throughput of 600 MMSCFD by following the instructions given in the adequacy study.

Major Overhauls (MOH) of major Rotating Equipment is an essential activity to ensure equipment and overall plant's productivity and reliability requirements are met. This submission summarizes Maintenance cost reduction and MOH extension benefits on an integrally geared centrifugal Instrument Air (IA) compressor through a first of its kind Predictive Maintenance (PdM) solution project in ADNOC. Appropriate planning for Major Overhauls (MOH) in accordance with OEM, company standards and international best practices are crucial steps. Digitalization continues to transform the industry, with enhancements to maintenance practices a fundamental aspect. Centralized Predictive Analytics & Diagnostics (CPAD) project is a first of its kind in ADNOC as it ventures into on one of the largest predictive maintenance projects in the oil & gas industry. CPAD enables Predictive Maintenance (PdM) through Advanced Pattern Recognition (APR) and Machine Learning (ML) technologies to effectively monitor & assess equipment performance and overall healthiness. Equipment performance is continuously assessed through the developed asset management predictive analytics tool. Through this tool, models associated with the equipment were evaluated to detect performance deviation from historical normal operating behavior. Any deviation from the historical norm would be flagged to indicate condition degradation and/or performance drop. Moreover, the software is configured to alert for subtle changes in the system behavior that are often an early warning sign of failure. This allows for early troubleshooting, planning and appropriate intervention by maintenance teams. Using the predictive analytics software solution, an MOH interval extension was implemented for an integrally geared centrifugal IA compressor installed at an ADNOC Gas Processing site. The compressor was due for MOH at its traditional fixed maintenance interval of 40,000 running hours in Nov 2019. Through this approach, the actual performance and condition of the compressor was assessed. Its process and equipment parameters (i.e. casing vibrations, bearing vibrations, bearing temperatures and lube oil supply temperature/pressure, etc.) were reviewed, which did not flag any abnormality. The compressor's performance had not deviated from the historical norm; indicating that the equipment was in a healthy condition and had no signs of performance degradation. With this insight, a 15 months extension of the MOH was achieved. Furthermore, a 30% maintenance cost reduction throughout the compressor's life cycle is projected while ensuring equipment's reliability and integrity are upheld. A total of 7 days maintenance down time including work force and materials planning for the MOH activities was deferred. The equipment remained in operation until its rescheduled date for MOH. Through the deployment of predictive analytics solutions, informed decisions can be made by maintenance professionals to challenge traditional maintenance practices, increase Mean Time Between Overhauls (MBTO), realize the full potential of a plant's process & utilities machinery and optimize operational costs of plant assets.

The purpose of this paper is to present the various technological solutions optimized for the use of hydrogen, in transport, distribution, storage and utilization, analyzing their criticalities and advantages. Hydrogen compression is a fundamental step in the transportation and storage segments and continuous improvement are required. The greatest technological challenges are certainly the high pressures required for the various fields of use, the need to maintain a clean gas and to use materials that are not subject to embrittlement. The choice between the different compression technologies is based on the need for pressures and flow rates; in the case of high flow rates and low compression ratios a centrifugal compressor is preferable, while for low flow rates and high compression ratios the choice goes to piston compressors. To prevent gas contamination, dry reciprocating compressor are preferred because they allow to avoid an oil separator filter on the discharge. Current technology of reciprocating compressors allows to compress hydrogen up to 300 bar with lubricated machines, while with dry technology it is possible to reach up to 250 bar. A second criticality on reciprocating compressors is maintenance: the parts subject to wear need to be serviced every 8000 hour of operation. The use of innovative materials will increase the maintenance intervals reaching higher pressures without lubrication. To increase the pressure ratio with centrifugal compressor, it's needed to increase the rotating speed, therefore the peripheral speed, with materials suitable for H2, stages get high compression to reduce the number of compressor bodies. If the process conditions require high delivery pressures combined with large flow rates, a solution of centrifugal compressors alone would be able to manage the flow rate but not the required delivery pressure. On the other hand, the use of reciprocating compressors would require a considerable number of units. In this case, therefore, the optimal solution is to combine the two technologies, centrifugal and pistons, using the best features. A case study in which the superior performances of the hybrid solution in terms of total cost of ownership will be described and compared with traditional single technology compression train

ADNOC Gas Processing Ruwais NGL Plant carried out a field surge testing of one of its Centrifugal type Refrigeration compressor units in order to accurately evaluate the real surge points. Centrifugal compressors used in Gas processing plants are critical machineries consuming significant amount of energy. Unavailability of the compressor due to any failure will cause revenue loss and downtime to the plant operators. Often failure of the compressor system happens due to unstable operation caused by surge. Manufacturers build surge control systems to protect the machinery during the project stages through simulation. However, inaccurate surge map or shifting of surge control lines during plant operation may result in energy losses or machinery damage. Surge test establishes the baseline for machine to help understand future issues better, for machinery protection, safe operation and efficiency. Performing high risk surge testing activity in a safe and successful manner during plant operation and re-mapping resulted in optimal utilization of existing assets without the need for costly upgrades. This innovative technique can lead to impressive improvements and benefits on equipment integrity, performance, energy efficiency, emissions and profitability. This best practice has great potential for transferability across Oil & Gas industry as such compressors and control systems are common across the industry. This paper highlights the methodology of accurate mapping of surge control lines in a safe manner during plant operation to enhance energy efficiency of the machine by reduced gas recycles and to enhance machine integrity by avoiding early surge possibilities.

Successful project management boils down to effectively and efficiently managing resources to meet the project's cost and schedule. The ability to manage project effectively becomes increasingly important to recover capital project expenditures in expiring Production Sharing Contracts (PSC) blocks. The longer the time needed for a project to complete, the higher the project capital and the lower the capital recovery. Referring to look back result of several major capital facility projects, the key challenge in meeting the project cost and schedule is related to procurement of long lead materials and key process equipment. In brown field blocks, there is an opportunity to perform reverse engineering by optimally utilizing the excess materials in the warehouse and idle/unused process equipment to solve the key challenges. As additional benefit, utilization of excess materials and idle process equipment will improve inventory management and capital stewardship, since the cost to relocate and modify the equipment are significantly lower than the cost of buying a new equipment. Field X Associated Gas Recovery Project (AGRP) provided an excellent case study of successful reverse engineering approach using excess material and idle equipment in design and construction of a new gas processing facility in brown field block. Field X AGRP is designed to recover and process associated gas from X field to be used as fuel gas for the gas turbines at the internal Power Generation Plant. However, based on lesson learned from similar opportunity in the past, the cost of construction and installation of a new gas processing facility using new construction materials and new process equipment is very high, which is uneconomic at the current oil price environment. Therefore, to make the project economic, the project team shall consider the utilization of available excess material in the warehouse and idle/unused equipment into design basis. Project team conducted assessment to several facilities across the concession area to gather equipment specification data of idle process equipment and the size of available excess materials. The gas processing facility design was reverse engineered to optimally utilize the idle process equipment and excess materials. The utilization of idle equipment and excess material in construction of the gas processing facility has successfully generated cost saving up to 5 times the project cost from avoiding purchase of new equipment and new construction materials. The project successfully recovered associated gas at the rate of 0.5 MMSCFD to be used as fuel to gas turbine and produced 60 BOPD condensate from gas-liquid separation process

The Fourth Industrial Revolution (4.0) in Oil & Gas Industry creates a dynamic landscape where Operational Excellence (OE) strives for stability, quality, and efficiency while continuing to serve an increasingly demanding customer. Operational excellence is a journey, not a sole destination. Abu Dhabi National Oil Company (ADNOC) Onshore, one of the South East Fields, oil production capacity was constrained due to the limitation of associated gas handling capacity of the compressors. Gas flow towards the compressor was not steady due to natural flowing wells non-steady behavior and this disturbance cannot be removed from the system. The situation was quite complicated. In order to produce oil, associated gas must be handled to avoid flaring. It was more than a challenge to increase the compressors effective capacity without any hardware modification. Since flaring is not permitted in ADNOC and running of huge capacity standby compressor was not economically viable, therefore, Field Operations by lateral thinking transformed this challenging situation into an opportunity and enhanced compressor effective capacity by expanding its operating envelope to handle additional gas. One innovative solution proposed by Field Operations was to expand the pressure-operating envelope of the machine to withstand high pressures without tripping. The idea was to increase the machine throughput by elevating the machine high-pressure trip set point along with Pressure Safety Valve (PSV) set point elevation. This submission shares success story of an oil field Operations in house efforts to enhance the gas injection compressor effective capacity by 600 MSCFD which subsequently increased the oil production capacity by 1700 bopd or 0.62 million barrels oil per year by Operational Excellence. Operational Excellence played its role with a value improvement objective. Rather than replacing successful practices and programs, Operational Excellence knitted them into a larger, fully integrated tapestry woven to increase value produced within the overall business strategy which is very evident in this scenario. This case study is blend of Operations Excellence and innovation representing Management support to employee to solve complex problems. Such support is always beneficial for the company and employee. Management of change process for followed to study, analyze and implement the idea.

Due to an increase in gas lift demand on an existing field in Sarawak, an existing Gas Lift Compressor (GLC) on the processing platform requires to be upgraded to meet incremental oil production requirement. These sets of compressors consist of 2x100% reciprocating compressors that were designed for 1.5 MMscfd each, with discharge pressure of 55.1 barg (800psig). The gas from these compressors is used mainly for gas lift at the processing platform as well as gas lift, instrument gas and utility gas at adjacent wellhead platforms. From the Conceptual Study, the existing compressors are not able to be retrofit for upgrade and is to be replaced with 2 × 100 % new gas engine driven compressor that capable of delivery 3.0 MMscfd of compressed gas each. During the engineering stage of GLC package, Skid Dynamic Analysis has been carried out to evaluate the GLC skid structural design due to the operating dynamic load cases. The study recommended that the skid to be welded to the platform where the compressor is located to prevent the risk of high vibration. With the recommendation from Contractor's study, project team proceeded to carry out Structural Dynamic Analysis to assess the dynamic effect of the GLC skids to the platform deck. The Finite Element Analysis (FEA) results revealed that there are several modal modes mainly at the drilling deck and extension deck non-compliance to PTS guideline. Structural Dynamic Modification (SDM) and optimization was performed to dynamically stiffens the structures to shift the modal modes away from the operating range to fulfil PTS criteria. However, the SDM results was still unable to comply thus the need of Anti-Vibration Mounts (AVMs) is considered. Prior to application of AVMs, Structural Forced Response Analysis needs to be carried out to evaluate the risk of the system and confirm the requirement of the AVMs. Without the forced response analysis, the effect of AVMs, locations and numbers of AVMs cannot be addressed during the design study. This paper will discuss the issues concerning vibration from reciprocating compressors upgrade on an existing platform, changes in the existing operating and design philosophy, challenges in addressing compressor installation and utilization of AVM from the perspective of Project Team. The paper will also provide key lessons learn and recommendation for future considerations in Compressor upgrades on existing facilities from a Structural Engineering point of view. The project is currently at its detail design finalization and installation is expected to be completed by November 2021.

Hydrogen holds enormous potential in helping the world achieve its decarbonization goals and is set to play a key role in the Energy Transition. However, two central building blocks are needed to make the hydrogen economy a reality: 1) a sufficient source of emissions-free (i.e., blue or green) hydrogen production and 2) a needs-based transportation and storage network that can reliably and cost-effectively supply hydrogen to end-users. Given the high costs associated with developing new transportation infrastructure, many governments, pipeline operators, and regulatory bodies have begun exploring if it is both possible and economical to convert existing natural gas (i.e., methane) infrastructure for hydrogen operation. This paper outlines opportunities and technical challenges associated with such an endeavor – with a particular focus on adaptation requirements for rotating equipment/compressor drive trains and metallurgical and integrity considerations for pipelines.

Compressors are widely used to transport gas offshore and onshore. Oil rigs and gas processing plants have several compressors operating either alone, in parallel or in trains. Hence, compressors must be controlled optimally to insure a high rate of production, and efficient power consumption. The aim of this paper is to provide a control algorithm to optimize the compressors operation in parallel in process industries, to minimize energy consumption in variable operating conditions. A dynamic control-oriented model of the compression system has been developed. The optimization algorithm is tested on an experimental prototype having two compressors connected in parallel. The developed optimization algorithm resulted in a better performance and a reduction of the total energy consumption compared to an equal load sharing scheme.

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 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

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.

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.

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.

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.