A method consisting in an optimal combination of conventional topography from a terrestrial acquisition and satellite derived topography is presented. The solution recently implemented in the UAE for the engineering and the construction of a gas export pipeline allows significant cost reduction, time saving, and safety hazard reduction as fewer terrestrial operations are needed. The survey area is split into 2 sub-areas: area with infrastructures requiring a high accuracy is surveyed with terrestrial topographical acquisition methods such as GNSS receivers, the other one with desert conditions is mapped from satellite stereoscopic imagery. Stereoscopic mode refers to when the satellite sensor acquires two images of the same location taken from different angles. Using photogrammetric techniques, it produces a 3D elevation model of the area. The native satellite imagery allows a mapping of the surface features as well. Terrestrial and satellite datasets are finally merged and adjusted to provide engineering and construction contractors with a unique survey dataset. Terrestrial survey methods provide generally 5-10cm horizontal and vertical accuracies whereas satellite topography has accuracy of a few meters, so satellite topography must be controlled and adjusted from terrestrial ground control points which allow to reach an average 50cm absolute accuracy. This is good enough in desert areas with neither particular ground feature nor steep relief requiring complex design. Satellite acquisition has limitations: vegetation masking the ground, steep slopes and dense infrastructures. It is therefore necessary to combine conventional and satellite topography to meet engineering requirements. This is considered when defining the satellite and terrestrial survey areas. Beyond these limitations, this solution has strong advantages. Satellite grid resolution can be better (1-2m versus 5-10m for GNSS surveys). Acquisition and processing are faster (about 2 weeks versus a few weeks or months), and costs are from 10 to 100 times cheaper than conventional methods. No need for personnel and equipment on site, no management of logistics and permitting as well. Finally, it reduces safety hazards such as car accident, harsh weather, manual handling, etc. In addition, limiting the area to be surveyed with conventional equipment may avoid the need to mobilize Airborne photogrammetry or lidar systems usually operated by foreign companies. This limits complex Call for Tender, permitting management and give more opportunity to contract local companies. Satellite topography is widely used for preliminary studies, but the innovation here consists in an optimal combination of terrestrial and satellite datasets for engineering and construction purposes. This solution has however some limitations as it requires suitable conditions for satellite optical imagery acquisitions: no vegetation, limited cloud cover, smooth topography, and limited infrastructures. This is of interest basically in Middle east and North Africa.

COVID-19 pandemic is accelerating the transition to decarbonized energy systems. In this context, major Operators and Contractors are bound to promote innovation and technological development. The paper describes how this is being applied to the design of offshore pipelines that are now required to transport not only Hydrocarbons but also anthropogenic CO 2 and low-carbon Hydrogen. In order to evaluate all the new technical challenges presented in designing CO 2 and H 2 pipelines, a state of art has been carried out and is here presented focusing on all the new technical aspects associated to the main disciplines involved in the pipeline network design. Different technical aspects (such as performances evaluation of Equation of State in CCS, Design Standards application to both CO 2 and hydrogen pipelines, energy capacity of hydrogen pipelines and others) have been also analytically or numerically addressed simulating credible pipeline operating scenarios. To achieve that, an intensive engineering effort is being dedicated to the development of knowledge, engineering tools, methods and procedures that will be the basis for the execution of future projects concerning H 2 and CO 2 transportation and storage. A particular focus has been dedicated to offshore pipeline design both for new installation and repurposing of existing ones. In parallel, the cooperation started between Operators, Contractors, Manufacturers, Institutions and Universities, as described in the present paper, acts as a "booster" for the consolidation of knowledge and for the advancing of technology to put in place to overcome those new challenges. Recommendations are made in relation to the gaps found in experimental evidence present in literature and gaps in Standards coverage for the proper pipeline design in those new scenarios.

In recent years, the global buckling assessment of offshore pipelines in High Pressure-High Temperature (HPHT) condition become increasingly challenging since more complex pipeline system arrangement e.g. pipe(s) or cable(s) is strapped onto a larger pipeline, are rapidly utilized in many areas. Yet, the detailed guideline to assess the buckle of bundles remains unclear, therefore this study will focus to investigate on a methodical and reproducible approach to analyze in-service buckling behavior of bundled offshore pipeline system. The global buckling behavior of bundled offshore pipeline system in this study is investigated using commercial Finite Element (FE) software. Two carbon steel pipelines with different diameter are bundled and the buckling behavior is studied under the influence of buckle triggers. In the actual condition, the rogue buckle trigger is generated from OOS (out of straightness) or imperfection e.g. due to laying tolerance. Varying dimension parameter such as diameter ratio between the main pipeline and strapped pipeline are considered to understand the impact of this parameter on the buckle behavior. The study begins with a comparison of the results using numerical and analytical approaches on a straight pipeline in an unbuckled condition for validation purposes. The design parameters including wall thickness, process data, and pipe-soil interaction data, are varied since it influences the buckle behavior. In addition, some design parameter such as material properties and pipeline length will be adopted from a typical offshore pipeline project and the values are fixed so the exercise can focus on the most governing parameters. Following this, two numerical modelling methods, the equivalent properties method and the connector method, are presented in this study to simulate bundled systems. With a good agreement between the analytical and numerical approach, some buckle trigger is introduced on the numerical model of the bundled pipeline so the system is able to buckle and the behavior can be evaluated further. The strain level, lateral displacement, axial feed-in and pipe integrity shall be reported in the post-buckle conditions for both main pipe and strapped pipe as per current code and standard requirement. With more reliable results of buckling assessment for bundled pipeline system, it gives technical confidence and a major saving in both Capital Expenditure (CAPEX) and Operational Expenditure (OPEX). Industry has put serious effort through various Joint Industry Projects (JIP) to develop the global buckling assessment guideline in order to ensure long term integrity operation. Although the JIP guideline is predominantly for single pipeline system, similar assessment is demanded also for bundled pipeline system which described in this study. Key findings of the assessment are presented along with an overview of the design process and the typical mitigation techniques to be considered for similar subsea pipeline projects.

"Optimization" or "Fit for Future" is the new norm for any industry in this competitive global environment. To encounter the challenges and to embed 100% HSE, efficiency, performance and profitability in operation, maintenance and new constructions, there is an urgent necessity to review and update existing design and construction specifications related to Pipeline. Hence, this paper summarizes the latest specification optimization efforts in pipelines material engineering without compromising the safety and integrity of the assets. In ADNOC Gas Processing, specifications for various engineering disciplines namely, process, automation, control, electrical, static/ rotating equipment, piping/ pipeline, civil/ structural are followed in engineering, construction and maintenance activities. These were developed over years to steer the Company towards unparalleled reliability, operability and integrity. Now, the challenging market demands adaptability, agility and forward thinking with a need to "balance the performance with efficiency and profitability", without compromising HSE. Hence, a "Lean" approach towards the specifications is emphasized by focusing on cost-saving and value addition in terms of optimized schedules and enhanced efficiency. A set of pipelines DGSs were reviewed internally based on International standards/specifications, best engineering practices, lessons learnt from involvement with Operation and Projects and consultants optimized specifications. Through this paper, major changes in pipeline specifications are elaborated highlighting potential areas of optimization and realized cost savings. ADNOC Gas Processing (AGP) plays a strategic role in ADNOC and the UAE hydrocarbon value chain by contributing significantly for the development of the Emirates. ADNOC Gas Processing (AGP) operates and manages an integrated Pipeline Network of approximately 3500km length of Pipelines with the mission of uninterrupted supply to its Customers and any impact on the upstream plants. Various fluids are transported via pipelines such as Sales gas, Crude oil, NGL, Condensate, Water, Nitrogen and associated gases wherein majority of network contains Sales Gas. AGP is involved in executing many Major Pipeline Projects. This paper presents "Fit for Future" initiative that has changed the organizational culture and reflects effectively in all activities across the Company. As all the technical activities are based on DGSs, update plan and potential cost realization are the main drivers for enhancing the performance without compromising HSE. This approach of re-visiting the technical specifications in the light of "high efficiency with low cost" can be adopted across other OPCOs and move towards common specifications for ADNOC.

A 20" gasoil pipeline was to be constructed from Sokhna Port to a Terminal at Al-Sadat area on the Suez Hurghada High Way, Arab Republic of Egypt. The 20" pipeline is a 34 Km long pipeline. The 20" pipeline runs parallel to and in close proximity to Over Head Transmission Lines. The location of steel pipelines in the vicinity of AC power transmission facilities has resulted in mutual electrical interference problems that can produce damaging effects on both utilities and an electrical hazard to pipeline personnel. The pervasive use of the utility corridor concept necessitates that the electrical interference aspects be clearly defined and guidelines to minimize the harmful effects be incorporated into pipeline and powerline specifications, designs, and operating procedures. There are three modes of AC interference that can cause damage to pipeline systems and present an electrical shock hazard to pipeline personnel, namely; inductive coupling, resistive (conductive) coupling and capacitive (electrostatic) coupling. This paper highlights the results of the AC interference study, its effects on the pipeline and the operators during the steady state and during fault current conditions. The paper also highlights the results before and after the AC mitigation measures were implemented. Methods The AC interference study together with the mitigation would start with data gathering this include; pipelines alignment sheets, pipeline design bases, Over Head Transmission Lines (OHTL) data both during steady state and fault current, pipeline coating specification and coating materials standard data, pipelines corridor obstacles and ancillary systems. These data were gathered along with some field measurements which included measurement of the soul resistivity at close intervals along the pipeline and OHTL common corridor in addition to field measurement of the steady state induced voltage along the pipeline route. The second step was to calculate the risk of AC interference in terms of; Risk to personnel during construction and operations both in terms of steady state and during fault currents. Risk of pipeline metal arcing. Risk of pipeline coating damage in addition to the risk of AC corrosion. A specialised software was used to calculate the values before and after a proposed mitigation system was done. Furthermore, post field implementation of these mitigation measures were done, results post mitigation between the software results and the actual results were compared. Results The risk of arcing was found acceptable. Damage to coating was also found acceptable. However the risk to personnel during steady state and fault current were found to have exceeded the acceptable limits of 15V AC touch potential suggested by NACE. Furthermore the fault current AC induced voltages reached an estimate of 49000 V AC. Mitigation measures managed to reduce the induced voltages to acceptable levels with a maximum mitigated value of 2.3 V AC. Novel The results obtained before and post implementing the AC interference mitigation measures were compared. Field measurements were also conducted. It was proven that the estimates of the induced vales of AC were found to be accurate with a very minor deviation. AC Stray Current Mitigation - A Success Story Houssam Sabry, Managing Director, ICE Hamed Aly, Cathodic Protection General Manager, Petrojet

This paper discusses on the methods of the installation of Corrosion Resistant Alloy (CRA) pipeline for High Pressure High Temperature (HPHT) including its challenges and the subsequent mitigations. The experience is based on the successful installation of Anjung Gas Development Project which consists of 18" diameter X 8km length of CRA Full Well Stream (FWS) pipeline installed utilizing the (Dynamic Positioning) DP-2 pipelay vessel. The methodology applied in the installation is via typical S-lay utilizing automatic welding system (for the pipelaying) and stalk-on (for the risers at both sides of the platforms). Additionally, Zero Radius Lay (ZRL) method was utilized at buckle triggers. On the existing KAKG-A platform, the riser installation is via suck-in method to avoid removal and reinstatement of the existing riser guard. Two (2) numbers of anode sleds were utilized for cathodic protection. The scope for pre-commissioning performed was flooding the pipeline with fresh water, cleaning, gauging, hydrotesting, air drying, nitrogen purging and packing. Multiple Concrete Weight Coating (CWC) thicknesses was used to cater for anchoring of pipeline walking. One (1) set of tensioner shoe pads was moulded to suit all CWC thicknesses in order to mitigate the issue of maintaining two (2) tensioners holding the pipeline during pipelaying. The other two (2) tensioners onboard the Main Work Barge (MWB) were installed with sets of tensioner shoe pads suitable for different thickness of CWC. Although with various weld defects experienced, mitigations that were executed proved that the layrate could be improved and finally achieved the target layrate. A wet buckle procedure including its equipments was prepared as a contingency plan. However, due to no wet or dry buckle, this procedure and equipment were not utilized. The project completed successfully with zero Loss Time Injury (LTI) and no major issues. Hence, it is an achievement for PETRONAS. It sets as a standard in moving forward in any new technologies that is developing. The overall schedule was improved by approximately 20% and cost was reduced by approximately 15% due to the above mitigations. The impact of the successfulness of this pipeline installation is a basis for PETRONAS future CRA pipeline installation as this is the first HPHT CRA pipeline installed by PETRONAS Carigali Sdn. Bhd. (PCSB). This proves one of PETRONAS' 5 Quality Principles, Right Things Right Every Time. The challenges including the mitigations are a good lesson learnt for any future CRA pipeline installation projects that the industry will be undertaking. In this project, the PETRONAS Technical Standard (PTS) 193004 Installation of Offshore Pipelines and Risers (Amendments/Supplements to ASME B31.8, ASME 31.4 AND DNV OS F101) and API 5LD is the basis for the installation.

Failure investigation of 12″(305 mm) high pressure steel welded pipe was carried out in this study using ASTM standards in all mechanical and metallurgical tests. Visual inspections was done immediately after receiving the failed pipe section. The pipe was then cut at approximately the center position of the failed-welded joint showing a circumferential crack at the joint along half of the outer surface periphery of the pipe. Tensile, hardness, chemical and microstructural analyses were performed on samples taken at different orientation of the pipe and the weld. Optical emission spectrometer were used to obtain chemical composition of samples. Microstructure testing of surfaces were prepared using grinding, polishing and etching. SEM was used to study failure at high magnification. Root cause of failure was found to be due to combination of operating conditions, oxidation cyclic stresses, and depletion of chromium in the matrix near grain boundaries, methods to reduce corrosion were discussed.

The Production Assurance Tool is developed to calculate the potential oil production from any field for different operational scenarios considering well potential and pipeline network limitations. This Tool represents integration between the pipeline hydraulic model and the performance of the production wells. The developed tool utilized PIPESIM software to model the pipeline network and Microsoft Excel as database for well performance in the format of lift curve, applying reservoir constraints and best reservoir management practices and as a general user interface for inputs and results. The programming script is performed by visual basic code to link PIPESIM with Microsoft excel to run number of iterations until the net system capacity is concluded. The challenges in each field determine the objective and configuration of the tool. The tool is being utilized extensively by COMPANY as an efficient, accurate and swift method to support strategic decisions related to net capacity of the field considering reservoir potential and pipeline network limitations. Examples of applications include optimizing plans of new wells, identification of production loss and possible areas for compensation for specific operational scenario. The tool is totally controlled by the designed general user interface with no physical interaction with the PIPESIM software and it can be easily updated with latest well lift curves and guidelines via COMPANY database, which is regularly updated by subsurface team. As being an In House Tool, it can be always updated and tweaked as required for different objectives. The tool provided an efficient methodology to fill the gap between reservoir performance and pipeline hydraulics by using available tools in the COMPANY with no extra investments and reduced the time required to conclude the feasibility and production optimization of different flow assurance scenarios.

ADNOC Gas Processing (AGP) plays a strategic role in ADNOC and the UAE hydrocarbon value chain by contributing significantly for the development of the Emirates. AGP operates and manages an integrated Pipeline Network of approximately 3200km length of Pipelines with the mission of uninterrupted supply to its Customers without any impact on the upstream plants. Various fluids are transported via pipelines such as Sales gas, Crude oil, NGL, Condensate, Water, Nitrogen and associated gases wherein majority of network contains Sales Gas. Pipeline Network is scattered over Ruwais, Habshan, Buhasa, Asab, Shuwaihat, Jebel Danna, Al Maqta, Taweelah, Jebel Ali, Al Ain, Ghantoot, Al Dhabbaya, Al Romaitha, Saadiyat Island, Yas Island, Mussafah and in some other areas within the Emirate of Abu Dhabi. The Sales gas pipeline network connects gas plant facilities to consumers/ADNOC Plants through pipeline Distribution Facilities (Manifolds). The NGL pipeline network connects NGL plant facilities with manifolds to onward supply of NGL to AGP plant for fractionation into various products such as ethane, butane, propane and naptha etc. These manifolds are old and highly critical, hence their safety and reliability are paramount to ensure shareholders commitment to various consumers in UAE and abroad. Failure of these manifolds will have a major impact on upstream & downstream production chain. Shut down of these manifolds are not possible as there is no bypass arrangement or back up manifold for business continuity. Failure of any of the manifold will have major impact on AGP Business and reputation. Some of theses manifolds were constructed in late 70’s and have completed their design life. In line with current business scenario and fit for purpose approach being adopted by ADNOC, it is prudent to understand methods to assess the condition of existing ageing assets and apply techniques to enhance the reliability and integrity of the same. Ageing equipment is challenging and a systematic approach is necessary to decide on the life of ageing assets. AGP is one of the largest gas processing companies in the world, and it is considered as the major energy and feedstock supplier for the majority of the power, hydro carbon, and petrochemical industries based in the UAE. In view of the above, AGP has carried out an Integrity/Adequacy assessment study to check fitness for service of the manifolds with due consideration to business continuity, the impact on upstream/downstream production, Company reputation, asset integrity, process safety and HSE aspects etc. This paper presents the challenges faced and best practices adopted for ensuring/enhancing Process Safety (Prevention of Loss of Containment), improve integrity/reliability of the manifolds, minimize impact on normal operation and maintenance and reduce the risk of business interruption. AGP best practices are based on the requirements of Pipeline Codes, International Standards, industry practices, ADNOC Gas Processing Specifications/Standards, and good engineering practices etc. The Best Practices followed in this study have ensured the safety, efficiently and reliablty of operation of these manifolds. Confidence level in assuring integrity of againg facilities is boosted. Similar approach will benefit the oil and gas industries for ensuring safety and integrity of old ageing facilities.

The rapid induction of Fiber Reinforced Plastics (FRP) into process industry due to high corrosion resistance and cost effectiveness made End Users to overlook FRP's specific design, fabrication and quality control aspects. This also affected various Utility and firewater networks in ADNOC Gas Processing plants. It is addressed by enhancing Vendor pre-qualification, relevant specifications and construction procedures. This paper presents measures adopted to ensure reliable design, supply and installation of FRP piping systems. FRP piping systems have unique design/construction requirements that was not followed in totality in AGP past installations. Also, international standards do not offer adequate guidance on design, resins selection, fabrication methods and joint systems. Vendors were trusted upon for complete design. A campaign is initiated to engage FRP pipe manufacturer having binding single point responsibility from beginning of project for particular FRP system design to ensure desired performance of FRP piping system with extended warranty. Measures have been taken to improve quality material supply through enhanced vendor pre-qualification, ADNOC Gas Processing specifications and CONTRACTORS pre-qualification having certified site crew. Studies revealed that material quality, velocity/surge pressure were the main contributing factors for failures which were not adequately addressed in design of FRP piping systems. Gaps noticed in previous projects were use of inadequate Codes, Composite's mechanical properties, design approach, inadequate joint preparation and QA/QC in construction phase. During manufacturing using wrong resin can be a cause for premature failure. Absence of certified personnel for project execution and Non-compliance of manufacturer's instructions were also key lapses noted in construction phase. The gaps in design process, necessitated improvement and consolidation of ADNOC Gas Processing existing design specifications/criteria and analysis requirements which now mandate that the required hydraulic / surge / static analysis shall be carried out by pre-qualified FRP manufacturer. Material property issues were addressed by clearly specifying the material composition & properties requirements and procedural requirements for storage are incorporated into the manufacturing process, along with mandating minimum prior experience for the manufacturers for material supply and design. Certification of contractor's personnel and presence of FRP manufacturer's representative at site during construction and pre-commissioning has been emphasized as mandatory requirement. In addition Specialist 3rd party inspection/supervision must be deployed to ensure quality control during every step of construction and commissioning Design specifications, procedures, manufacturing process, QA/QC and installation methods for FRP piping systems are available, but lacked activity interface between consultant, vendor and contractor. ADNOC Gas Processing enhanced the FRP specification ensuring single point responsibility with Vendor and procedures to ensure consistency from the design phase coherent with manufacturing process and appropriate implementation during the execution phase, in order to ensure the safety and integrity of FRP Piping systems.

Piping systems having service temperatures lower than ambient present a challenge for the pipe support design. Pipe supports for these cold piping systems are different from normal type of supports on pipes with service temperatures above ambient. Normally hot insulated piping systems have shoe type of supports directly welded to the pipe. In this case there is no relative movement between pipe support i.e. shoe and pipe while the pipe displaces due to changes in fluid service temperature inside the pipe. As the pipe expands when temperatures rise inside pipe, it displaces from its mean position of structural support. The shoe having been welded to pipe moves along with the pipe. On the other hand, shoe type supports on cold service pipes are not directly and permanently connected to pipe. This is due to the fact that the pipe insulation on cold service piping is designed to be seal tight so that outside air cannot get inside the insulation and reach pipe surface where it starts condensation. The condensation in turn causes corrosion issues. To avoid this moist air ingress inside the insulation, the shoes are made of clamp types and are placed outside the insulation cladding. This causes problem of clamp type shoe slippage on cladding and total displacement of pipe shoe from its structural support. This paper presents an engineering study of a piping system with cold fluid service (propane) where multiple supports had fallen from the structural supports or had dislocated considerably. At few support locations, cladding was found to be damaged and ice formation was noticed. In addition, many clamped shoes had rotated as shown in figure 1 . The solution as outcome of study was simple, economical and easy to implement. A comprehensive study was conducted to identify the root cause of piping supports dislocation, displacement and rotation. The static/dynamic stress analysis of the piping system was carried out. The results revealed that the displacements in the piping system were not so high to cause the supports dislocation or high displacements of shoes. In addition, the stresses on the piping system due to the contraction of pipe upon cooling were within allowable limits. Figure 1 Rotated and dislocated Clamp support on Cold Service Pipes As a part of study process, operation was enquired if any upset had happened which might have caused the dislocation and abnormal movement of pipe and hence transferred to its supports. Operations informed that there was no such incident and the line had been operating normally without any trouble. The process study including review of hydraulics, verification of line size and surge was performed to identify the root cause of piping abnormal movement. The process study concluded that line size was adequate and no surge scenario was identified for the line's concerned portion. So following reasons which could cause abnormal pipe movements and dislocation of supports were ruled out based on above study: Operation upset in the piping system (such as sudden opening or closing of a valve or sudden starting/stopping of a pump), Line sizing or surge flow, Contraction of line due to cooling of piping system or piping configuration. The next step in the study was to review the support configuration in detail. Study found basic design problem with the support configuration that was the cause of supports dislocation, excessive movement and rotation of clamped supports.

Drag reducing agents (DRA) have been applied to pipelines since they were first commercialized by Conoco, Inc. in 1979, and have proven to be a reliable tool for the pipeline industry. Over the past 40 years, adoption of DRA has been widespread across the globe, in a broad range of climates and in a variety of hydrocarbon fluids. DRA are valuable tools as they can reliably provide flexibility in the operation of a pipeline. Because DRA can be applied over a range of dosage levels in the pipeline, they offer a range of options in terms of operating points at higher flow rates or lower pressures. DRA can be used to substantially increase flow rate in a capacity limited pipeline, or maintain flow rate in a derated line. They can also be used for energy savings, bypassing pump stations. DRA can bring substantial value to pipeline operations through aversion of flow loss, and through minimizing capital and energy costs. The latest generation of DRA have demonstrated very high performance potential in terms of drag reduction performance and supply logistics. New pipelines are increasingly considering DRA usage and flexibility during the design stage, which can minimize capital and operating costs.

The objective of this paper is to demonstrate the potential benefit of using site- and project-specific pipe-soil interaction (PSI) inputs in HTHP pipeline design. The paper first explains the overall approach used to generate site-specific PSI inputs to pipelines. This includes showing the importance of site investigation (geophysics, in situ testing and sampling) and onshore lab testing which should be integrated to select appropriate seabed parameter ranges for the derivation of site-specific PSI inputs. Then, the importance of using geotechnical calculation methods which consider the unique properties of carbonate soils to calculate pipeline friction factors is discussed. Finally, the paper demonstrates, for a regional case study, how the provided PSI inputs changed pipeline design and reduced project costs.

The objective is to study and develop the economical clamp to use for leakage repair caused by pipe crack at piping supports in gas regeneration system, which is operated under thermal cyclic condition and not possible to call the ad-hoc plant shutdown window. The process of this study is to analyze the thermal expansion of piping and clamp, which is a cause of the gap at contact surface between 8″ piping and clamp. The clamp design is developed with understanding the influence of heat conduction as well as the material expansion. The experiment has been setup to verify the clamp design in the scope of performance and endurance test. The expected end result is the efficiency of clamp to secure the pressure while gas leakage is occurred under thermal expansion effect. The result from design, development and experiment to prove its performance and endurance is indicated that this ecomomical clamp is in good condition and can secure the pressure under gas leakage situation. This project now generates the benefit to preserve production and sale (prevent unplanned plant shutdown), prompt response (perform as an emergency repair) and very low fabrication cost (able to reduce fabrication cost for 40%, approx.). It's not only for one operating asset, but for all and for company as the whole business units. Besides, it's potentially to continue the design development in various sizes of piping operated under thermal cyclic condition. It much more commercial in the following day. In the monetary aspect, earlier (from 2014 until now), company has to bear with the Lost Production and Sale Opportunity for 12 million USD from unplanned shutdown caused by gas leakage at piping crack nearby pipe support in regeneration gas system, which is operated under thermal cyclic condition. From the loss occurred, it compells company to study and develop effective emergency response plan and equipment to prevent the loss and control the risk from the piping leakage issue in the gas regeneration system.

Piping systems under multi-phase flow are subjected to unbalanced forces during plant operation and they experience vibration. Usually, the piping vibrations can be minimized by either modifying piping configuration/supports or alteration of operational modes. This paper presents an engineering study of a challenging piping vibration problem, which was resolved by an inventive and cost optimizing solution, as there are limitations in modification of existing pipe support/configuration. The inventive resolution reduced implementation cost to the Company without impacting the operations. A comprehensive study was conducted to identify the root cause of piping vibration in rich amine piping system (36" pipe) from heat exchanger to amine regenerator, a tall column. The vibration screening and likelihood-of-failure calculations were carried out based on Energy Institute's guidelines and observed that the piping system is in concern/problem zones. The process study including review of hydraulics, verification of line size and control valve design was performed to identify the root cause of piping vibration. The piping stress analysis (static/dynamic) was carried out with actual operating conditions, which is under multiphase flow with varying density/forces. The process study revealed that the flow velocity and momentum are within process design requirements. However the flow in the piping system is multi-phase type, which generates unbalanced forces due to slug loads at each elbow of the piping system. Based on piping stress analysis results, it was identified that the natural frequency of piping systems is variable as the whole weight of the vertical piping system is resting on spring type supports, which in turn, are supported from vertical vessel cleats. These supports are provided to take care of relative displacements between vessel and vertical piping systems. Piping configuration cannot be modified considering large bore piping and requirement of huge structural supports. The existing supports also cannot be modified as they are connected to pressure vessel and will impact its design. In this scenario of multiple limitations, the indispensable flow induced vibrations of piping can only be minimized by damping the effect of flow-induced excitation with dampers. The dampers have elastic-viscous material in its main restraining body which can absorb the piping vibrations. The damper vendor performed the stress analysis, considering the effect of the damper in the whole piping system, and ensured the integrity of piping system. The challenge of maintaining existing spring supports and achieving required damping of piping vibration was successfully accomplished. Considering large sized piping and requirement of major structural supports in case of modifications, proposed solutions could be treated as cost effective and innovative. Though it was not possible to eliminate the root cause, this alternate innovative solution helped to not only to minimize vibration, but also optimize implementation/shutdown costs. Vibration damper in piping systems is unique to piping installations.

In today's challenging work and business environment, swift response to structural integrity concerns is the need of the hour to minimize the damages that will reduce down time, specifically in oil & gas sector. The solution devised to address structural concerns shall prevent further failure of structural members and avert major catastrophic accidents, as they support process equipment and piping. This paper outlines case studies of such structural failures, potential reasons of incidents and approaches followed in restoring structural integrity in a safe and economical way that ensures uninterrupted plant operation. Key parameters to be studied / considered while arriving solutions to structural damage / incidents include reliability of data, primary cause of incident, inventory of readily available material, execution feasibility under plant operating conditions thereby avoiding plant or unit shutdowns and manpower skillsets. Due to various constraints, the solution arrived may be temporary that averts multiple structural failures or a major accident. Further studies would be required to identify the root cause and to confirm or enhance the implemented solution that will reaffirm long term integrity of structure. In almost all of the incidents, some of the common steps followed for swift restoration of structural integrity include conducting a site survey to identify and judge the probable cause, reviewing available data, structural assessment and details of material in stock. After analyzing numerous factors, diverse approaches unique to each incident were considered in arriving a solution that is fit-for-purpose. Structural integrity issues, if not attended swiftly, can worsen the situation leading to safety concerns and major accidents. Solutions adopted for various incidents ensured restoration of structural integrity with minimal consequences. Suggested improvements and recommendations were implemented and no further issues were reported until this time.

Condition monitoring and defect inspection in the buried oil and gas pipelines, made of ferrous material, has always been a challenge for all organizations operating in the Oil & Gas sector. Pipelines can be inspected in two ways, internally and externally. Internal inspection by ILI tools require special infrastructures like pig launchers and receivers along with pre-preparation before inspection like internal cleaning there is the data collecting and analysis process which is time-consuming. Whereas in communally used external inspection a group of workers drive a vehicle along the pipelines to perform visual inspection of the pipelines for detection of leakage or any other kind of visible damages. Such manual external inspection is highly inefficient, expensive and hazardous. In such a way it is difficult to obtain any important information for the anomalies brewing in the buried pipes or cathodic protection layer. A lot of work has been done towards developing NDT technologies to inspect pipelines. However, most of the NDT sensors work only in close vicinity of the pipeline surface which requires an excavation of the pipelines and exposing the structure. This shortcoming of NDT techniques has attracted researchers towards other NDT techniques such as non-invasive magnetomatric diagnosis (NIMD) which allows non-contact detection of anomalies from distance in the core metal of the pipelines deeply buried underground. NIMD sensors work on principle of measuring distortions of residual magnetic fields conditions by the variation of the pipeline’s metal magnetic permeability in stress concentration zone due to combined influence of various factors such as residual stress, vibration, bending and loading of pipelines, installation stress and temperature fluctuations etc. These handheld magnetic sensors are used manually by field operators therefore inspection of long pipelines in extreme environmental conditions is not feasible. A non-contact external robotic inspection system, Autonomous Ground Vehicle (AGV), carrying such non-contact magnetic and visual sensors is designed and tested in this work. AGV is equipped with two kinds of sensors, the first navigation sensors and the second inspection sensors. Accurate autonomous tracking of the pipelines by the AGV is achieved by fusion of three navigation mechanisms based on visual data, GPS and pipe locator. The pipe locator in combination of CP post is one of the most extensively used sensors in the oil and gas industry for tracking the buried pipelines. In this work manually used pipe locator is now fully automatized for autonomous tracking of the buried pipelines by the AGV. For this purpose, a hybrid automata trajectory controller is developed for a non-holonomic AGV where a PID controller is combined with non-linear forward velocity of the AGV depending on the lateral distance error and angular alignment error. Field experiments are conducted successfully to demonstrate accuracy of the newly designed controller. Successful development of such complex mechanism requires solution of many critical challenges like teleoperation, system and supervisory controls, trajectory tracking, image processing and sensor data fusion.

DNV GL has recently carried out a JIP to propose rational design criteria for clad and lined pipes. Attention has been paid to pressure containment, local bucking/wrinkle, fracture and fatigue limit states. In DNV GL JIP design guideline, a strain criterion for the liner wrinkle limit state is proposed. The criterion is based on experimental test results and it does not include any safety factor. Advanced FE Model, purposely calibrated through dedicated experimental tests, can be developed to quantify the strength and deformation capacity of lined pipes considering installation and operational loads, pipeline geometry and fabrication technology and tolerances. The FEM analyses well reproduced the behavior of clad/lined pipelines subject to combined loads. The presence of liner contributes to the overall pipeline strength and deformation capacity, although introduces an issue due to the risk of wrinkling and detachment from the baking steel. For lined pipes with no or low internal pressure, the liner will normally separate, i.e. wrinkle, from the backing steel prior to reaching the local buckling capacity of the backing steel alone. Advanced FEM analysis approach can be very helpful for lined pipe strength and deformation capacity assessment, aiding engineer during the design process. The accurate reproduction of failure modes under combined loads can drive engineers through a proper design of clad/lined pipe in offshore extreme environment/loading conditions.

Multi-stage restriction orifices are being increasingly used for Oil & Gas facilities depressurization instead of single stage orifices in order to overcome noise and vibration constraints. These are typically in the range of 0.5 to 3.0 m long considering 6-10 stages used particularly for high pressure depressurization system. However, in reality Multistage Orifices impose layout constraints in offshore installations and especially for congested brownfield modifications. Multi-stage orifices are used in Gas and liquid service where large pressure drop is required to avoid choke flow condition and cavitation respectively. Multistage orifices help to eliminate noise, vibration in piping due to cavitation and choked flow. During depressurization of hydrocarbon inventory, the flow through the restriction orifice is inherently in choked condition, thus restrict the relieving rate allowing optimized vent/flare system design. Noise and vibration resulting from choked flow conditions can be addressed by piping design or selecting single stage multibore restriction orifice and thereby eliminating the use of a multistage restriction Orifice for depressurization. Multi-stage restriction orifices are recommended by suppliers wherever pressure drop is exceeding the choked pressure ratio, which is usually the case in facilities depressurization. The number of orifice stages is selected for limiting pressure drop at each stage below the choked pressure ratio. However, multistage restriction orifices application in depressurization service imposes various challenges such as potential blockage in any of the stages due to hydrate formation and draining of residual fluid from the assembly considering its complex geometry. These challenges get aggravated especially for brownfield modifications wherein single stage orifices are replaced with relatively long multistage orifices in existing congested facilities. Single stage orifices fulfill the requirement of depressurization provided piping design addresses the noise and vibration. Even these requirements can be relaxed by considering intermittent nature of the operation and actual operating experience. NPCC’s experience in many onshore/offshore oil and gas projects suggests that complex designs can be simplified based on better understanding of functional requirements of depressurization in consultation with suppliers. This paper discusses the constraints of installing multi-stage orifices in offshore installations based on examples from recent EPC projects and proposes to adopt simplified, safe and cost effective design. The paper also highlights benefits of conventional single stage orifices for depressurization service.

GASCO (Abu Dhba Gas Industries Ltd) commenced design and construction of processing facilities since 1978. The main plants and subsequent expansions were engineered in phases by different EPC Contractors. Piping Material Specifications (PMS) were developed for each Project as per EPC Contractor’s engineering understanding and as per the Project need. This resulted in having different PMS for similar fluid services in an identical process Units/Trains. This paper presents the outcome of the study to optimize the number of PMSs and generate a common PMS to satisfy all the existing plant requirements. GASCO has around 800+ Piping classes across all the sites. The selection of right PMS was a challenge during the modification projects in existing plants. It was also difficult for Store/Ware house personnel to maintain the inventory and track spares as because of large number of stock codes. A comprehensive study was undertaken to develop a master set of PMS involving following steps; data collection & review, checking the compatibility with latest Codes and Standards, study lessons learnt, generate back up calculations, documentation and publish the Design General Specification (DGSs). Through this comprehensive study, 800+ piping classes were optimized to 150 number of piping classes in a common PMS to suit overall GASCO’s requirement. The co-relation of existing piping classes having outdated materials with newly developed classes made the selection of required piping class much easier and user friendly. The new PMS, with new material classes ensuring good engineering practices and adapting the lessons learnt over the years of operation. This optimization campaign facilitated GASCO to formulate a definitive approach towards the selection of common piping material for specific fluids across the plants. The new PMS has segregated the material requirement for various fluids with different operating temperature and pressure conditions from different Units/Trains. Some of obsolete components had been taken out from PMS based on GASCO’s operating experience over last 30+ years. The selection of material has become easy at all level of work force when doing the modification work. Use of right piping material will save material cost with engineered material solution with minimal failures. Alignment with all the Plants with common piping classes will maintain optimum inventory across GASCO plants. The same philosophy can be used within all the OPCOs under ADNOC directives of cost saving and standardization.