Abstract Striving to achieve high level of plant's reliability, and realizing the wide impact of piping misalignment on rotating equipment premature failures, Oil & Gas industry has come up with many standards and best practices aiming to eliminate or minimize to the possible extent the effects of pipe strain on rotating equipment. Pipe strain is considered as one of the most frequent reasons causing rotating equipment to fail. It occurs when there is a misalignment between the piping and the equipment's suction and/or discharge flanges. A case study of a vertical crude charge pump at Saudi Aramco plant, experiencing high vibration and repetitive mechanical seal failures due to piping misalignment and subsequent pipe strain effects will be considered in this paper, highlighting the corrective actions adopted following the relevant investigation and troubleshooting conducted by Operation, Maintenance and Engineering (OME) team. Moreover, a Finite Element Analysis (FEA) model will be presented, demonstrating the significant impact of pipe strain on the pump's shaft behaviour and the potential modes of failure in case pump-to-pipe flanges misalignments are not seriously considered.

Abstract Oil producing companies are targeting minimal modifications to existing facilities in an attempt to increase oil production with minimal capital investment and squeezed schedule, thereby maximizing overall return on investment. Such brownfield works impose numerous execution challenges which are dependent on availability of shutdown window. This paper focuses on challenges involved in brownfield tie-in execution and presents mitigation strategies for performing tie-ins without production shutdown based on recent projects executed by NPCC. Brownfield projects execution has various constraints due to limitations in design modification of existing facilities. Such limitations pertain to existing Facility Layout, Flare System, equipment and adaptation of new standards to existing facilities and various other design /safety compliance requirements etc. During execution of modification works, early tie-in and shutdown requirements are firmed-up in accordance with the Oil Producing Company's business targets and alignment with all stakeholders. Production shutdown is highly undesirable since it leads to revenue losses as well as schedule and cost implication on the project. Hence, brownfield tie-in strategies always aim to keep production shutdown minimal. In order to accomplish timely tie-in execution, it is necessary to freeze the Tie-in Execution Philosophy at an early stage of the design in compliance with the producing company's HSE standards. This can be achieved by resolving all brownfield related challenges specially ensuring the early alignment of all stakeholders regarding the requirement of early tie-in, plant shutdown and low production window and by conducting an early site assessment to ensure that As-built drawings are corresponding to actual site conditions. In one of the Brownfield EPC projects executed by NPCC, various operational mitigation strategies were considered for tie-in execution without shutdown such as providing a temporary flare relief arrangement during Flare Tie-ins, lowering operating pressure to safe limit during execution of Tie-in on Production Oil manifold with single isolation valve, Isolating Produced water system during low production window and continue production with reduced rate by functioning HP/MP Separator in two phase mode during Produced Water Tie-in, lining up an alternative uninterrupted fuel gas header / source during Fuel Gas Tie-in etc. Such strategic methods resulted in execution of all brownfield tie-ins without any production shutdown, thereby avoiding production loss during modification works in an existing facility. Based on extensive experience with execution of brownfield projects, NPCC is better placed in formulation of tie-in strategies that are aimed at avoiding production loss. This paper presents valuable suggestions and mitigation strategies from recent projects executed by NPCC that will serve as Tie-in execution philosophy for operating companies as well as Contractor companies in petroleum industry. These strategies will assist companies’ in effectively optimizing their resources, enhancing the efficiency and profitability of their projects.

Abstract Crude oil dehydration is one of the first, most important and challenging steps in oil production and processing. To achieve rapid and energy-optimized demulsification of water-in-oil emulsions, Saudi Aramco and TechnipFMC have jointly developed a high performance electrostatic coalescence technology. This paper discusses the performance test results of this technology. Physical separation of emulsified water from produced crude oil is challenging due to the small water droplets, presence of surfactants covering the water droplets that inhibit the otherwise natural coalescence process, as well as the high viscosity of the continuous phase and the narrow density difference between oil and water in the mixture. Conventional mechanical and thermal methods are proven for viscosity reduction and efficient separation, but they also require high capital expenditure and large footprint. Deploying conventional electrostatic coalescers for demulsification proves to be uneconomic at remote locations. Chemical methods, namely the injection of chemical demulsifiers to dissolve the above mentioned surfactants, is expensive and makes the production process highly dependent on the supply of such chemicals, which can be affected by geo-economical as well as environmental circumstances. In this paper the performance results from tests conducted jointly between TechnipFMC and Saudi Aramco using the compact high performance electrostatic coalescer (HPEC) technology are presented. The HPEC was tested successfully on an Arab Medium crude oil under different process conditions, including different temperatures, electric field strengths, and two geometrical configurations of the electrostatic cell internal features. The study results demonstrate the rapidity and effectiveness of the HPEC in destabilizing Arab Medium crude oil emulsions.

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 Asphaltens presence in the reservoir fluid has great implications on downhole as well as surface facilities. These problems are not only related to production impact, but also significant integrity as well as surface facilities operational challenges are seen to affect the upstream oil and gas production facilities. Handling the asphaltenes rich fluid brings inherent challenges with it starting from well bore to the production facilities. Adequate engineering solutions need to be integrated into the design of production facilities as well as wellhead equipment which would greatly enhance production efficiency while successfully facing asphaltens challenges. The nature of asphaltens as well as their growth rate are not very well understood due to their complex chemistry with different hydrocarbons. Therefore there will not be a 100% success while managing the asphaltens, however these proactive steps would upto great extent would reduce the downtime and other asphaltene related impacts. This paper presents an effective way to address asphaltenes challenges as faced by surface and subsurface facilities in oil and gas production operations. Best industry practices for mitigating asphaltenes related challenges, which not only sustained the production but also enhanced asset integrity performance, have been presented for experience sharing and enhancing the asphaltenes handling capability. The reservoirs with asphaltenes presence are quite difficult to handle and maintain due to complicated nature of asphaltens, which result into various problems with downhole as well as surface facilities. These problems result into scales blockage of well bore and flow lines thus causing blocked flow and in most of the cases complete seizure of wells fluid flow.

Abstract Economic development of marginal oil fields usually requires utilization of nearby existing processing facilities to minimize Capital and Operational Expenses. However, tie-back of multi-phase well fluid to other existing processing facilities has challenges in fiscal oil allocation among various Shareholders. This paper presents the fiscal oil allocation experience in development of marginal fields, wherein well fluid is tied-back to existing facilities for further processing and export. Bu Haseer field is one of the marginal field in the offshore concession area of Al Yasat Petroleum Operations Company. Due to low oil production, standalone development of Bu Haseer field was not economical. Therefore, well-fluid from Bu Haseer fields is tied-back to existing facilities at Das Island. During the initial phase of production, well fluid from Bu Haseer field was measured using Multi-Phase Flow Meter (MPFM) prior to tie-back to the existing facility. Fiscal allocation of Bu Haseer oil production was based on MPFM measurement and converting the measured oil flow at operating conditions to stock tank conditions using PVT correlations. However, oil measurement using MPFM does not meet the accuracy acceptable for custody transfer, thereby not realizing the full commercial value of the production. Measurement accuracy is improved by installing a dedicated separator to partially stabilize the oil, and measure the separated oil flow as single phase using Custody Transfer Meter, complying with API MPMS (Manual of Petroleum Measurement Standards). The separated oil is pumped through Custody Transfer Meter, to avoid flashing across Custody Meter, which would have otherwise impacted its measurement accuracy. To convert the fiscally measured partially stabilized oil to fully stabilized oil at stock tank conditions, a Shrinkage Factor is applied to account for dissolved gases at separator operating condition. Shrinkage Factor is a function of separator operating pressure, temperature and well fluid composition; which could vary during operations as well as with producing life. Estimation of Shrinkage Factor becomes more challenging when production is from multiple reservoirs sources and downstream crude stabilization process parameters vary. A pre-defined algorithm for Shrinkage Factor is configured in flow computer considering all credible operating modes. Measurement of multi phase well fluid or partially stabilized oil is usually not recognized in the industry for fiscal allocation, mainly due to measurement inaccuracies and uncertainty in estimation of shrinkage. This paper presents Al Yasat operating experience and challenges with partially stabilized oil measurement and methodology implemented for estimating the oil shrinkage for fiscal allocation.

ABSTRACT Successful identification, evaluation, and management of bottlenecks in a complex, offshore production processing system—though challenging—can significantly increase daily production for the system owner. Historically, such optimization plans were developed in relative isolation of the entire production system from wellhead to export pipeline. That approach benefits simplistic systems with sufficient ullage and in which discrete changes do not affect other flow system components. However, the Constitution platform in the Green Canyon area of the Gulf of Mexico, which was commissioned in 2006 with a nameplate capacity of 70,000 BOPD, is a complex system with four fields in varying stages of development. These fields have both dry and wet tree wells with varying fluid compositions and pressures flowing through the facility, which necessitates varying process requirements, making it challenging to manage. Such a system requires a holistic and focused approach by all technical and commercial disciplines. This paper focuses on a multidisciplinary process developed to identify, evaluate, and eliminate interdependent bottlenecks on the Constitution platform and its flowline network during a 16-month period. A multidisciplinary study was kicked off in 2017 to address these complex bottlenecking issues, and the resulting project achieved a 30% improvement in deliverability of the process system.

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 ADNOC Gas Processing is looking into the energy saving opportunities to improve plants energy performance, aiming continual improvement and also for sustaining the already achieved efficiency improvement in varying operating scenarios. It is in line with the ADNOC Sustainability Strategy target for the Year 2030 which requires reducing the Green House Gases (GHG) intensity by 25% in Year 2030 considering Year 2018 as the baseline. Therefore, multiple avenues and opportunities were looked into to contribute towards this ambitious target. One of the promising contributors, having substantial potential of energy savings, is the Waste Heat Recovery. In this context, ADNOC Gas Processing has evaluated the option of utilizing waste heat from different heat sources across different plants using the Organic Rankine Cycle to generate power. Waste heat sources like exhaust gases from power generators, mechanical drive gas turbines, heaters and incinerators stacks, and low pressure steam condensers have been assessed. This opportunity of waste heat recovery exhibits substantial potential to contribute towards GHG emissions intensity reduction, reduce power import, improve energy efficiency and reduce the operating costs. The paper presents the techno-economic appraisal of the opportunity for the selected waste heat sources.

Abstract Objectives/Scope A field trial was conducted for deoiling produced water at a Saudi Aramco GOSP. The objective of the field trial was to prove the concept of the centrifugal separator and test its capabilities to deoil produced water at varying feed rates and inlet concentrations. Methods, Procedures, Process The centrifuge was fed from the common water outlet line of a gravity water oil separator. Samples were taken for oil-in-water measurement using ASTMD7678. The testing covered various flowrates and inlet concentrations, which were adjusted by manipulating upstream conditions. Several parameters were used to determine the adequacy: Outlet oil-in water content (expected significantly less than 50 mg/l) and sufficiently high separation efficiencies to achieve the specification Unit downtime due to trip and failure of the unit and due to filter/screen cleaning and replacement Results, Observations, Conclusions The feed rate was adjusted by manipulating a valve at the inlet of the separator. A sample at the inlet and outlet of the separator was taken at each flowrate and condition as per the test guideline. It was noticed that inlet oil-in-water concentrations to separator were mostly on-spec, with only a few of them above 100 mg/l, as a result of temporarily lowering the dehydrator interface level for the the trial. The following observations can be made based on the test run data: The outlet oil-in water met the spec, far exceeding expectations Oil in water removal efficiency varied significantly, varying from 65-90% depending on rate and inlet concentration There were no issues in terms of unit downtime related to trips and filter/screen plugging Novel/Additive Information This was the first trial for a Saudi Aramco field. The process was applied to a facility with tight emulsions and a challenging environment that requires a highly efficient deoiling process, which the centrifugal separation has proven to be. Potential applications for produced water treatment and waste water handling can be derived from the field trial result.

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 Produced water and industrial waste water contamination is given by a combination of the creation of stabilized oil emulsions and the presence of soluble oil components. Typical components include alkanes, BTEX (benzene, toluene, ethylbenzene and xylenes), high amounts of dissolved solids, suspended solids, heavy metals, high content of biochemical oxygen demand (BOD) and chemical oxygen demand (COD). Failing to clean-up this oily water before disposal can have severe environmental consequences. Since most conventional water-treatment technologies are also negatively impacted by the presence of emulsified oil, development of appropriate oil removal technology is also in the best interest of any water reuse scheme. This paper includes several trials that have been carried out with industrial wastewater water containing both emulsified and dissolved oil for the evaluation of performance of two polymeric resins. The present study has tested synthetic oil emulsions in a controlled environment to evaluate the impact of typical operating conditions on removal efficiency. Bench testing and piloting have been carried out with real wastewater originated from various sources in the Tarragona industrial petrochemical complex (Spain). Samples with oil content ranging from 10 to 1000 mg/L of Total Petroleum Hydrocarbons (TPH) have been tested. Results show that a coalescer-type resin can effectively target emulsified oil, and in the correct operating conditions can achieve up to 90-98% removal. Furthermore, this is a technology that is not negatively affected by high concentrations of oil. On the contrary, results indicate that higher concentrations of insoluble oil contribute to improving overall efficiency. It has been identified that residual TPH can be attributed to water-soluble species, because a second pass does not improve performance. A polymeric adsorbent can remove dissolved oil components-such as phenols, BTEX and PAH-with an efficiency of over 99.9%. However, rapid saturationa and its fouling problems when confronted with emulsified oil indicates ideal solution for treating oily waters would be successive treatment with a coalescer and an adsorbent resin. This study shows, through testing of real-life samples from industrial wastewater that polymeric resins are able to remove both the emulsified and dissolved oil from oily water, and how composition has a significant influence on its removal.

Abstract ADNOC has completed the second phase of its ambitious integrated capacity model (ICM) with the overall aim to optimize its fluid production portfolio from the well level to the processing facilities. The business drivers are to establish capabilities to optimize high-value products and proactively react to market demand changes effectively. Such capabilities required a robust thermodynamics engine with component-wise tracking based on a country-wide capacity model network comprised of a myriad of wells, pipelines, and separators. Fluid samples are not available for all the wells in a field. An innovative workflow was created to assign appropriate composition at the well level based on the data set available for a subset of wells. The captured compositions were then passed to the ICM's hydraulic calculation engine to track the fluid compositions at the required nodes across the network. The existing data model was expanded and user interfaces were created to capture the complexities within the network and visualize the changes in fluid properties, particularly composition, density, and flow rates, at the defined nodes. This digital transformation initiative had to overcome the following complexities to improve accuracy and enable faster decision-making: Incorporation of data from more than 20 fields, 150+ reservoirs, 5000+ wells Optimizing the country-wide network model comprised of wells, pipelines, and separators Performing multiple pre-conceived daily scenarios with 60-month forecasts for production and injection rates Accounting for lateral and vertical composition variation within a reservoir Mixing of fluids at different points in the network at different pressures Implementation of a unified equation of state (EOS) to enable component tracking The network model successfully captured this complexity and predicted capacities for all custody-transfer points between upstream and downstream networks demonstrating a good match (>90%) between the actual laboratory-based measurements and the ICM results. The tool also offered the capability to maximize production of desired components at the source level to meet the dynamic energy demands of the country, allowing a 1-3% profit improvement in the base operating plans. Alternate scenarios offer additional views on how to obtain the same upstream liquid production targets while maximizing downstream gas revenues, hence overall country profitability. The ICM recommended suitable targets during crisis conditions to react accurately to unexpected market fluctuations. Implementation of the unified EOS along with component tracking creates new avenues for digital transformation by allowing the operator to optimize high value products and answer to demand changes quickly. Multiple scenarios can be analysed and visualised to support decision makers to increase profitability in a highly competitive hydrocarbon market from rock to stock.

Abstract Halfaya oilfield in Iraq, discovered in 1976, contains multiple vertically stacked reservoirs. Currently main oil reservoirs are under primary development. The remaining deepest high GOR, HP/HT carbonate reservoir with original pressure gradient of 0.867 psi/ft has been drilled, tested, but undeveloped. An innovative production strategy has been put forward highlighting that high GOR crude can be injected into the upper oil reservoirs with partially pressure depletion, as energy-conservation measure, in view of its high wellhead pressure and good productivity during drill stem tests, therefore to achieve production enhancement and synergy among reservoirs. In-house studies indicate high GOR crude can be miscible with all oils from eight zones. Field results show that injection processes can bring dead wells back production, yielding the prolific output. Also, water cut can be reduced immediately and field water cut rising trend can be mitigated. The innovative injection processes are illustrated as follows: New development wells should be deployed at updip positions to penetrate the all the hydrocarbon reservoirs with the thick pay. Run tubing string with packer. Packer is used for isolation of upper oil zones and HP/HT environment. Huff and puff process. After perforation, high GOR crude travels up the tubing string, via surface choke and a manifold with flow meter, then enter the annulus. Choke regulates the injection rate. For low-permeability (<0.1md) carbonate reservoir, e.g., Sadi reservoir, huff and puff processes are applied post multistage fracturing treatment. High GOR flood is preferred in majorly producing reservoirs with high productivity and relatively low GOR, e.g. Mishrif reservoir. Injected high GOR crude (API=32.7) can dilute remaining oil (API=19.1-23.0), reduce its viscosity, and therefore achieve production enhancement. During primary development, asphaltene deposit occurred and chemical inhibitor has been applied. After oil blending, the risk of asphaltene deposit could be minimized. First perforate lower-pressure oil zones and then open the HP/HT zone for work safety. The production enhancement strategy and processes in this paper could be of strong reference value to similar stacked reservoirs.

Abstract Objective / Scope BOROUGE receives its ethane feedstock (De-Ethaniser Overhead DEO) from ADNOC Gas Processing to produce higher value polymer products. As polymer prices continue to rise, capacity utilization of the crackers is the prime concern for BOROUGE during low feedstock availability from ADNOC Gas Processing. To maximise profit, propane is slipped along with DEO from ADNOC Gas Processing to BOROUGE and co-cracked to produce higher market value polymer products. Methods / Procedures The following activities were carried out to evaluate the feasibility of slipping propane along with DEO. A simulation model was prepared to estimate the De-Ethaniser column overhead temperature, reflux rate required to achieve the desired propane slip. A detailed test run procedure was prepared for the same. A joint risk assessment session with Bouroge was carried out. Plant Change Management (PCM) was applied. A test run was carried out for a duration of more than 80 hours. Results, Observations and Conclusions During the test run, ADNOC Gas Processing’s Train 4 De-Ethaniser column top temperature was increased from minus -3.5°C to +19.5°C and Propane in Ethane product increased from 0mole % to 6 mole %. Since fractionation column is a multivariable system, disturbance in any process parameter can affect the overall performance and lead to production loss. Hence, the column temperature profile was increased gradually in multiple steps and sufficient time was given between each step change for system stabilization. When propane from De-Ethaniser column is slipped, Carbonyl Sulphide (COS) also gets slipped with the DEO stream. Higher level of COS in feedstock to BOROUGE may impact their polypropylene product specification. Hence, frequent lab sampling analysis were carried out by ADNOC Gas Processing as well as BOGOURE to make sure the product quality is not impacted. The test run was successfully carried out for a duration of more than 80 hours. From the test runs results it was concluded that 15 Tons/hr of propane can be slipped with DEO from ADNOC Gas Processing NGL Fractanation Train 4 to BOROUGE which can be converted to value added polymer products.

Abstract This paper describes how the reservoir team at ADNOC Sour Gas developed the ability to dynamically adjust and manage their production strategy based on plant product output and market requirements, driving profitability and maximizing value of the sour gas assets of the UAE. The reservoir team developed and successfully implemented an extensive data acquisition program, enabling adequate characterization of a giant ultra-sour gas carbonate reservoir in the Late Jurassic Arab Formation in the western area of Abu Dhabi. The field is located in the southern part of UAE, in the Liwa province, and covers an area of 57 km 2 . It consists of four main reservoir zones: Arab A, Arab B, Arab C, and Arab D. Current development is focused on the central part of the field with most of the wells dedicated to Arab C. Future development plans will focus on the southern and northern areas of the field. Early during the appraisal stage, the data suggested the existence of an areal gradient in composition across the reservoir. As such, a clear understanding of this areal distribution in addition to the usual reservoir gas composition, properties and behavior was essential in optimizing field production and maximizing value. Over the course of field development, reservoir fluids from different well locations were sampled and analyzed. Various issues were encountered during this process including H 2 S stripping in down hole samples, contamination from stimulation fluids and quality assurance and quality control concerns in lab measurements. Resolving these issues allowed a coherent understanding of the compositional variation in the Arab Formations. To properly model the compositional variation, an innovative methodology was implemented by the team to initialize the dynamic model. The methodology consisted of two major steps. Firstly, PVT data was analyzed and correlations between H 2 S and other components were developed. Secondly, through PETREL, compositional maps were created. Ultimately, each grid block was assigned a unique composition honoring the areal variation in composition across each reservoir zone. In addition, empirical correlations between fluid components and plant product streams were developed through material balance analysis. Using product models, these correlations were input into the dynamic model which allowed estimated plant products to be output directly from simulation runs. Simulation forecasts of estimated plant products were later verified by actual plant yields, giving confidence in the methodology implemented. Further, this method allowed a quick turnaround in production planning and optimization thereby reducing the reliance on a fully-fledged plant simulator for short term gains and quick wins.

Abstract Rigless well commissioning is an important stage of well completion to deliver a new drilled or worked-over wells (oil producer or water/gas injector) ready for production or injection. Rigless well commissioning employs firstly slick wireline intervention for well accessibility verification, down hole safety valve operability, bottom hole pressure and fluid gradient survey that assists to design the flow to clean commissioning program. Secondly, it employs coiled tubing (CT) and flow to clean (FTC) packages to cleanup the well and if necessary to perform matrix acidizing to improve well productivity or injectivity. This paper highlights operational constraints of well commissioning and its effective approach from job design, execution and evaluation that have been performed over 250 wells in the span of 5 years operations. The commissioned wells are drilled in the carbonate formation with surface clustered operation in Onshore and Offshore Artificial Islands. It also describes HSE challenges that have been faced in safe handling of return fluid, management of volatile recovered crude oil, simultaneous operations (SIMOPS) with Drilling Rig, Project and Construction (P&C) activities and hydrocarbon flaring in the environmentally sensitive area. The implemented approach and methodology of well commissioning has evolved significantly to address operational challenges and reducing well commissioning cost by 60%. It proves improvement of operating efficiency of CT and FTC packages based on downhole pressure survey, smart well commissioning, eliminating high risk clean-up operation for injector well, cluster based well commissioning, in-situ return fluid management and arrangement of vertical flare stack in the constraint offshore artificial island. The overall outcomes have achieved technical objective with optimized cost and minimum risk, enhancing rigless package utilization and implementing sustainable and effective field rigless commissioning.