Abstract A critical challenge facing the integrity of many assets throughout the oil and gas industry is directly related to corrosion under insulation (CUI). Unfortunately, the lack of adequate inspection technologies adds to this well-known industrial challenge. Presented in this paper is an inspection tool enhanced using Artificial Intelligence (AI) that can provide field inspection engineers with a facility heat map of insulated asset integrity allowing inspection prioritization. The approach used in this research, and presented here, was to enhance the output of already known and field approved thermographic technologies using a purpose built AI based on Machine Learning (ML). By examining the progression of thermal images, captured over time (<20 minutes), corrosion and factors that cause this degradation are predicted by extracting thermal anomaly features and correlating them with corrosion and irregularities in the structural integrity of assets verified visually during the initial learning phase of the ML algorithm. Additional benefits to this technique include enhanced safety through remote inspection and additional cost savings from monitoring assets online. To develop and verify the CUI technology results from in-house laboratory tests followed by field validation outcomes will be presented. Laboratory trials were carried out using a series of insulated field assets with different levels of degradation and structural integrity set up to mimic the thermal behavior of in-process assets. This initial feasibility study allowed the definition of key parameters required to build an effective ML model. Following in-house trials a series of field tests and visual verification was performed on both hot and cold insulated assets to gather a sufficient amount of datasets to train the predictive algorithm. To enhance this learning process, synthetic data was created based on real field asset configurations and operating parameters. Finally, during the technology validation phase, again on field assets, the AI technique coupled with a commercial field approved thermographic camera returned a predictive accuracy in the range of 85 – 90%. The work presented in this paper provides a solution for the current lack of technologies to monitor the presence of CUI by enabling and enhancing the output from already known and field approved technologies, such as thermography, using AI. Additional benefits of this approach include safety enhancement through non-contact online inspection and cost savings by reducing the complexity of asset preparation (scaffolding) and downtime.

Abstract Corrosion of Oil Country Tubular Goods (OCTG) is a traditional concern in the Oil and Gas industry, as it represents a major component of well integrity management. Various corrosion mechanisms may affect the performance of materials in downhole applications, especially in corrosive environments containing large amounts of H2S, CO2, and Chlorides. In high sour environments, elemental Sulphur may also be present, in which case, it will act as a strong oxidizer, affecting the performance of the material selected. In this paper, a test methodology was developed to selected a technoeconomical fit for purpose material for application in the development of a Ultra Sour Reservoir Containing Elemental Sulphur. This methodology consisted in evaluation of the SCC (Stress Corrosion Cracking) behaviour of Corrosion Resistant Alloys (CRA) of group 4D, as per ISO15156-3/ NACE MR0175-3, at the border between 4D and 4E environmental limits including the simultaneous presence of dissolved and elemental Sulphur in the fluid. A testing set-up was developed to ensure the contact of elemental S with the material in order to ensure the strong oxidizing reaction at the surface of the material. The behavior of the materials was assessed by Slow Strain rate testing (SSRT), C-Ring Sulphide stress cracking and Crevice corrosion test, conducted on UNS N06985. Grades sourced from three (3) distinct manufacturers were tested to evaluate different manufacturing systems (routes) and levels of cold work, which are known to be critical in the performace of the cold worked CRA materials. Although, CRAs have a greater CAPEX due to the content of costly chemical elements: Chromium, Nickel, Molybdenum, etc, they may be cost effective in a life cycle cost analysis as they will prevent workovers, assure a higher HSE and well integrity level.

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 ADNOC Onshore is operating Habshan gas production field on behalf of Abu Dhabi National Oil Company (ADNOC). The gas reservoir production zones were developed under different project phases. The field has 250 gas (production and injection) wells, which are placed and located in approximately 1200 square kilometers. All gas wells are designed to have SCADA system to monitor, operate and control the wellhead control systems. Current practice within ADNOC Onshore is to carry out monitoring for Cathodic Protection (CP) of well casing and Chemical Injection (CI) surveys on quarterly basis, this is carried out by mobilizing entire crews physically (visiting every single location) and reporting findings/conditions in order to carry out preventive maintenance and necessary repairs. The aim of the project is to establish a remote monitoring system utilizing the existing Supervisory Control and Data Acquisition (SCADA) setup in order to monitor the applied corrosion controls, CP and CI injection systems. Based on the implemented modification, essential information was collected, intensive review and analysis were performed and revealed that the system is functioning perfectly as per the operation's requirement for both (CP & CI). This approach forms a vital aspect of the integrity management of the asset by monitoring the effectiveness of the applied corrosion controls, in addition, the implementation will help Operations to optimize resources, efficiently monitor, maintain, and ensure safety of the facilities and its integrity. Moreover, the implemented method will drastically reduce the associated travelling risk, limiting exposure to the harsh environment (Desert) and potential cost saving.

Abstract Excellent mechanical properties and superior corrosion resistance in aggressive environments, recommends Super Duplex Stainless Steel (SDSS), for specific Oil & Gas applications requiring a high reliability and integrity of equipment. Generally, SDSS would be a solution for systems handling oxygen free or deoxygenated fluids with a relative high content of chlorides, such sea water or, with precautions, even well fluids. If exposed to sour service, additional precautions must to be taken for this class of materials in order to avoid occurance of cracking mechanisms associated with hydrogen sulfide presence and to comply with environmental and material limitations imposed by NACE standard MR 0175/ ISO15156. Despite of meeting material selection criteria, pumps faced major fabrication challenges and quality control issues subsequentlly reflected through a premature failure of equipment; generated by concomitent interaction of inappropriate fabrication aspects, including the pouring, quenching and welding of SDSS material. Specifically, quality control is a critical factor during fabrication to avoid unexpected in-service failures, involving major operational issues and unforeseen expenses. This paper aims to discuss SDSS casting issues encountered during fabrication of pump casings, from a failure case perspective, providing an optimized approach for successful completion of cast manufacturing process.

Abstract Fusion bonded epoxy coatings (FBEs), due to their zero volatile organic compound (VOC) and less production lines wastes, have increased the customers’ interest in this technology for pipes corrosion protection. However, the high-energy consumption used, to keep the oven at 438°F - 482 °F (225 °C - 250 °C), makes them not very competitive with liquid epoxy coatings (LECs). LECs, cheaper to be applied, using low curing temperatures ranging between 100°F to 212°F (38 °C - 100 °C), faster return-to-service, can perform like FBEs using lower thickness. Here a new LEC able to resist in petroleum, 50 bars CO 2 at 392°F, is reported. The protective behavior of the coating reported, has been investigated using electrochemical techniques too.

Abstract Zohr project includes the production of sour gas from the reservoir by a combination of offshore processing facilities in Egypt and pipeline systems to transport the gas from the field, to Onshore Processing Facility. Accelerated startup phase the main production line is based on 26inch pipeline where pipes are LSAW carbon steel pipe for sour service in material grade ×52. The automatic welding procedures for sour service lines have been developed on ceramic-coated steel shoes (copper shoes is not allowed) to achieve the target data to start of production. Scope of this document is to correlate evidence in the form of photographic, visual and NDT reports to be present, in order to determine whether ceramic debris from damaged shoes would adhere to the root & course detrimental effect to the internal root bead. Girth welds are performed with STT automatic welds with ceramic shoes. All girth welds are in the as-welded condition (no PWHT). Installation contractor confirmed that it is the first time that this type of shoes is used for a project. So, no field experience is available. During welder qualification onboard vessels required for pipeline girth welding, it was discovered that ceramic shoes could experience some damage when used in an unlimited manner and it could be a risk of inclusion to the root surface during production welding. The test campaign is designed to verify the corrosion resistance regards to SSC phenomena of girth welds in presence of ceramic debris due to ceramic shoes degradation. Company requested more testing for welding qualification including mechanical and corrosion testing which is performed with ceramic debris on the weld root. Start of alternative solution immediately by weld qualification without any shoes, following the common procedure for welding of carbon steel pipeline in sour service. This activity shall be carried out in parallel to the above test plan for ceramic shoes to have an alternative plan. Pre-production welding testing has been agreed with the contractor to get more stringent requirement for the number of ceramic shoes used during welding. A certain number have been agreed to dispose the ceramic shoes after each 40 welds in order to be sure it will not affect welding process. The approach of use of ceramic shoes during offshore girth welding is beneficial to speed up the laying activities during installation campaign and to meet the mechanical requirements for sour service. Maximum number of welds allowable for each individual shoe shall not exceed 40 welds by using ceramic shoes to avoid any contamination on root of weld bead has been demonstrated. Mechanical and Corrosion testing have been done on weld metal with debris and were acceptable.

Abstract The proposal of this paper is to share the knowledge learned in this new procedure and techniques implemented in HP/HT Unconventional wells, created by the Unconventional (UC) Drilling Department at Abu Dhabi which involve around ten different services, where each has a high importance and contribution for the collective success of the well at the moment to frac and hence the feasibility of the project. In order to assure the integrity and accessibility of the Frac String during Plug and Perf hydraulic fracturing operations of one of the toughest rock in Unconventional business worldwide, one procedure has been developed for running operations best practices. Pressure testing the Frac String (FS) during running in hole in stages while in vertical section to sure safe and successful Wireline setting and retrieving nipples plug with more than 30% solids in the system (high mud weight) to guarantee no leak in the string prior reaching total depth (TD). Hanging and testing cross over (XO), assuring compatibility with the wellhead connections. Cementing up to18.7 ppg. Flexible and expandable slurries, cement inside previous casing and apply pressure on surface to avoid gas percolation during the cement setting period. Cleaning out with Coiled tubing (CT) to ensure no obstruction and using different completion fluids for future accessibility. And finally, Pressure testing the Frac string up to 14ksi all are new practices and proven mitigation measures for all assessed risks for hydraulic fracturing operations. This paper is about sharing this new procedure in Abu Dhabi for having a cemented FS in UC wells High Pressure / High Temperature (HP/HT) with 100% integrity and internal accessibility to run plugs, perforations, logs and be able to apply high surface pressure to frac the tight reservoir in the planned zone, creating the desired permeability for future production.

Abstract The two Field gas compressors are categorized as critical equipment. After 5 years of operation a serious fouling on the compressor’s impeller was identified and resulted in high vibrations. The dominant fouling component was solid corrosion particulate. The objective of this paper is to discuss the effectiveness of improved corrosion inhibition program to minimize the dominant fouling component and make the corrosion inhibitor to be carried over to the downstream of suction scrubber. The effort to reduce corrosion product in the main gas line was done by optimizing 3 phase corrosion inhibitor performance injected upstream of the compressor suction scrubber. A series of laboratory tests on selective corrosion inhibitor products was undertaken to measure the effectiveness of some inhibitors to reduce the corrosion rate whilst also being carried over to downstream of the compressor suction scrubber. Some additives such as Iso-Propyl Alcohol (IPA), Glacial Acetic Acid (GAA) and Mono Ethylene Glycol (MEG) on the corrosion inhibitor were also included to improve some key parameters such as volatility, emulsion tendency and chemical stability. Significant improvements were observed with the modified 3 phase corrosion inhibitor which was carried over to the downstream of suction scrubber and which did provide improved corrosion protection to the main gas line and ultimately did reduce the solid corrosion product which had been seen to be the main component of the fouling on the compressor’s impeller. Improvement of corrosion inhibitor performance by adding some additives effectively can improve the key performance and the capability to be carried over to the downstream of the suction scrubber. The efforts to improve the corrosion inhibitor performance resulted in a reduction of the corrosion rate and solid corrosion product as the main component of fouling which directly contributed to improved compressor reliability.

Abstract Well integrity management is a prime global focus area for all oil and gas operators. Any field-wide corrosion challenge requires a substantial investment to manage the integrity of assets and, consequently, to maximize life expectancy and efficiency. Over decades, the industry has concentrated its efforts toward containing fluids from any unintentional release at the surface occurring as a result of corrosion. This paper highlights the most recent electromagnetic (EM) logging technology developments to address well integrity challenges. Three primary corrosion mechanisms occur in oil and gas wells: chemical, mechanical, and electrochemical. Electrochemical corrosion is the mechanism responsible for most of the failures in which the outermost casing is exposed to corrosive fluids and is consequently penetrated first. As the corrosion process continues, subsequent well barriers are progressively corroded until the inner casing or tubing is in direct contact with a corrosive environment and at direct risk of a major well integrity failure. As a result of this outside-to-inside corrosion mechanism, the early diagnosis of the outermost casing status is especially important as a proactive measure to identify any potential weak zones in the completion string. This early diagnosis is a major step to optimize well integrity intervention and to optimize workover operations costs. Cathodic protection and coated casing are used to extend the life of the well by controlling corrosion; however, these are only mitigation measures that slow down but do not eliminate corrosion. EM logging technology provides an effective method for monitoring and identifying the effectiveness of these corrosion mitigation measures. Time domain EM pulse eddy current (PEC) technology has facilitated corrosion evaluation by logging through tubing, thereby avoiding the cost of pulling completions solely for surveillance purposes. The latest EM PEC technology, the enhanced pipe detection tool (ePDT), provides individual barrier thickness measurements for four concentric pipe strings. The innovative features of ePDT include: (1) A fractal transmitter (Tx) coiled array that improves the performance of the tool with enhanced signal-to-noise ratio (SNR) covering a wide signal dynamic range, and adaptability for various logging speeds and spatial resolutions for varying pipes; (2) a synthetic aperture of the receiver (Rx) coil array for noise compensation from extraneous tool motion; and (3) a wide-spatial aperture Rx coil array which, when combined with (1) and (2), enables the compression of the inner pipe remnant magnetization interferences without sacrificing spatial resolution. This paper demonstrates ePDT benefits by benchmarking to other technologies and control environments. The results are discussed in detail to provide an overview of EM technology, as well as the advantages and limitations. Ultimately, the answer product from this technology is integrated with other current and historical information related to the well or field being evaluated as part of the well integrity management system (WIMS). Finally, it is important to expand the technology operating envelope beyond the standard applications to address larger completions challenges, such as gas wells and landing base inspection, by extending the tool capabilities while optimizing data acquisition and processing methodologies.

Abstract ADNOC Offshore in 1988 started implementing a corrosion management strategy for Offshore oil field located in Abu Dhabi. A robust Corrosion Management System developed to protect producer wells equipped with carbon steel tubing from sweet corrosion. With water break through many wells were in high corrosion risk, the effective approach provided completion protection to assure well integrity and extended tubing operating lifetime, which saved production and allowed for OPEX and CAPEX allocation. Presented in this case study a thoroughly review for the field implementation, performance, and economic impact. In addition to cost impact, implementing a strategic solution to replace tubing with Corrosion Resistance Material was challenging for immediate implementation due to the large number of wells with corrosion risk. Moreover, wells initial design did not consider capillary line for continues chemical inhibition system. The only visible solution was to implement corrosion inhibition chemical by squeeze to formation and flow it back with production fluids creating a protective film over tubing wall. This approach required effective monitoring system to optimize priority and evaluate chemical performance. Combing logging and simulation tools and collected data over 30 years present the process performance and value. In place corrosion management system provided a systematic corrosion protection that is effective and efficient in sweet corrosion environment. Many factors can impact corrosion rate and inhibition efficiency such as, water cut, deviation angle, flow velocities, pressures and temperatures, all contributing to the corrosion process. CIS treatment if applied regularly can significantly mitigate the corrosion process and consequently extend the operating well lifetime. Implementing CIS regularly dropped the immediate need to replace tubing with corrosion resistance alloy material (CRA), which allowed allocating workover rigs to serve different requirements. Corrosion management system in oil field offshore Abu Dhabi is an important safety tool that protected environment by maintaining well integrity and extending well life up to 30 years, delaying rig operation and optimized recourses. Setting up a state of the art system and saving cost. This paper, presents a real case study of a comprehensive Corrosion Management system provided a cost saving and safety tool. Expanding the implementation to other fields where water cut started to increase, can provide a cost effective solution against corrosion.

Fossil fuels currently supply more than 85% of world's energy, and global energy demand and consumption is forecasted to go up rapidly over the next 20 years [ Jamaloei et al., 2011 ]. Such demand can only be satisfied by sustaining the production of energy in existing fields. Therefore, Enhanced Oil Recovery from existing fields has become increasingly important. Polymer flooding is one of the most efficient EOR technologies that started as early as the late 1950s [ Standnes et al., 2014 ]. Adding polymers increases the viscosity of the injected fluid downhole, which helps to push out viscous crude oil for better oil recovery (up to 10-15% over water flooding) [ Standnes et al., 2014 ] [ Taylor et al., 1998 ]. Among them, Hydrolyzed polyacrylamide (HPAM) is gaining popularity in EOR: inexpensive, it can also withstand high mechanical forces during water flooding [ Li et al., 2016 ] [ Wever et al. 2011 ]. Depending on salinity and temperature, co and ter-polymers of PAM with ATBS may be more relevant to be efficient in highly stressed conditions. Depending on process conditions, industrial equipments such as water pipelines and flowlines are built in seamless carbon steel (CS), stainless steel (SS) and especially duplex (DSS) or superduplex stainless steel (SDSS), capables of transporting fluids at high temperatures and pressures. Since produced water or seawater used in EOR processes bring species prone to induce corrosion (most notably carbon dioxide, hydrogen sulfide and sulfate, dissolved oxygen), several corrosion modes are possible : uniform corrosion of CS, pitting and crevice corrosion of SS, Microbiologically Influenced Corrosion (MIC). Technologies such as upstream deoxygenation of the fluids, addition of oxygen scavengers and corrosion inhibitors and/or addition of biocide are used [ Voordouw, 2011 ]. The corrosion mechanisms of CS in synthetic and industrial brines in presence of CO 2 and H 2 S are often studied, but the effect of viscosifying polymers on corrosion is not well documented. This study aimed to improve the knowledge on the effect of PAM based viscosifying polymers on corrosion of CS and SDSS.

This study established the detailed root cause of complex layered scale deposition along the completion jewellery and production tubing, qualitative and quantitative scale composition, special design of the scale treatment and future mitigation plan to handle the scale/asphaltene issues in ADNOC Onshore gas wells. Gas producers are having scale problems due to corrosion products with mixture of organic material deposition which may be from produced gas and condensation of heavier hydrocarbon due to change in pressure temperature profile along the tubing. Gas injectors are having scale/asphaltene deposition indicating the lubricant components thus suggesting an exogenous source of scaling (i.e. external sources such as oilfield tools, seals, valves, upstream equipment). Two stage chemical scale treatment designed after conducting extensive lab test to reach the 75 – 80 % solubility cost effectively. Mechanical treatment with sterling beads evaluated for hard scale by considering the tubing integrity. Scale treatment operation executed with coil tubing at 3 wells and successfully achieved the desired results. Identified the root causes of scale build up and chalked out future mitigation plan to maintain the well integrity, flow assurance and cost optimization. In short term, scale issues can be handle by evaluating the suitable chemical with reference to well type, improving chemical injection system to minimize the corrosion products and improving the quality of injected gas for gas injection system. In the long term, scale formation can be avoided by squeeze inhibition treatment (scale/corrosion), mechanical treatment of scale removal for hard scale and improving in downhole completion jewellery maintenance.

The purpose of this paper to emphasize the lessons learned by ADNOC Sour Gas of material upgrading in the Shah Sulphur Granulation plant due to severe corrosion of Aluminium components. The Sulphur Granulation plant was commissioned in 2015, the granulation unit consists of a total of 12 packaged granulating systems used for solidifying and granulating the liquid sulphur. The study focused on the corroded areas which are the GX Plenum chambers, lower section of Granulator exhaust stack, Scrubber inlet and discharge ducting. Root Cause Analysis (RCA) was undertaken to understand and identify the cause of the corrosion. The study indicated that the corrosion of Aluminium components is typical of wet acidic attack. Wet acid is being produced in the granulator drum where atomised liquid sulphur is quenched by demineralized water to produce sulphur granules. The highly acidic vapours further travel to the exhaust stack through scrubber. The paper discusses the typical damage mechanism indicating the source of acidic species, their generation, corrosive attack and mitigation under plant operating conditions. It has been observed that under full capacity the plant utilized all the 12 granulators, therefore insufficient time for cleaning and acid water disposal. Therefore, Aluminium which is a universally recommended material for sulphur granulation plant is suffering severe material degradation. This has led to go for a detailed material review with process requirement. Entire plant equipment was segregated in 2 parts as per severity of corrosion. After the engineering study, the Plenum chamber and associated piping to scrubber duct will be upgraded with Stainless Steel SS316L having less severe corrosion. The Outlet piping from scrubber to FD fan and Exhaust Stack were affected the most, and it was recommended to replace these areas recommended with GRVE. The current arrangement with upgradedmaterial will assist all new projects to design plants either with enough unit redundancies for routine cleaning or use more resistant material to combat corrosion.

ADNOC Onshore is operating Habshan gas production field on behalf of Abu Dhabi National Oil Company (ADNOC). The gas reservoir production zones were developed under different project phases. The field has 250 gas (production and injection) wells, which are placed and located in approximately 1200 square kilometers. All gas wells are designed to have SCADA system to monitor, operate and control the wellhead control systems. Current practice within ADNOC Onshore is to carry out monitoring for Cathodic Protection (CP) of well casing and Chemical Injection (CI) surveys on quarterly basis, this is carried out by mobilizing entire crews physically (visiting every single location) and reporting findings/conditions in order to carry out preventive maintenance and necessary repairs. The aim of the project is to establish a remote monitoring system utilizing the existing Supervisory Control and Data Acquisition (SCADA) setup in order to monitor the applied corrosion controls, CP and CI injection systems. Based on the implemented modification, essential information was collected, intensive review and analysis were performed and revealed that the system is functioning perfectly as per the operation's requirement for both (CP & CI). This approach forms a vital aspect of the integrity management of the asset by monitoring the effectiveness of the applied corrosion controls, in addition, the implementation will help Operations to optimize resources, efficiently monitor, maintain, and ensure safety of the facilities and its integrity. Moreover, the implemented method will drastically reduce the associated travelling risk, limiting exposure to the harsh environment (Desert) and potential cost saving.

Several essential parameters, that often form the basis of design activities performed during Front End Engineering Design (FEED), are oftenly modified at late stages of the FEED process resulting in the transfer of various critical activities to the subsequent Engineering, Procurement and Construction (EPC) stage, rendering the FEED open-ended. This paper presents the impact of an open-ended FEED on EPC projects, and provides an approach to enhance the overall effectiveness of Oil and Gas project execution. Basic Engineering, performed during FEED, comprises of various critical design activities such as Simulations, Material Selection and Sizing Calculations. Process simulations are prepared based on the extreme governing cases such as maximum flowrates extracted from the production forecast. Moreover, equipment material is selected to suite the specified reservoir composition since different chemical component combinations exhibit varying properties and behaviors. Furthermore, equipment size is calculated to satisfy the defined battery limits’ conditions such as Temperature and Pressure. The critical activities that are carried forward from FEED stage impose amplified risks of design variations during EPC stage, which may have significant schedule and cost implications on the EPC project. In recently executed EPC projects, the reservoir composition, production forecast, and battery limits conditions were modified after the completion of the FEED, which resulted in the reworking of various basic engineering activities that caused significant delays in the issuance of detailed engineering deliverable and the procurement of critical Long Lead Items (LLI). The alterations to the production forecast such as elevated water flowrate resulted in the reverification of the governing cases and the mitigation of the impact on the facility design. Additionally, the changes to the fluid composition such as increased Hydrogen Sulphide content led to numerous adjustments to equipment material specifications and coating requirements. Furthermore, the revision to the battery limits conditions such as Maximum Deadhead Pressure required several amendments to the size of control instrumentation and safety equipment. Clients are recommended to adopt the strategy of providing fixed and clear essential parameters during FEED stage in order to minimize the reworks/revalidations during EPC stage, enhancing the overall success of the Oil and Gas project. This paper aims to raise awareness of the risks associated with an open-ended FEED on EPC project execution. This paper also presents valuable suggestions and mitigation strategies that will assist all Oil and Gas project stakeholders in effectively optimizing their resources, enhancing the efficiency and profitability of their projects.

Approximately 40% of current global natural gas resources have high H 2 S and CO 2 concentrations. The H 2 S concentration in Middle East gas reservoirs can potentially reach up to 30 mol%. H 2 S is toxic; therefore, the produced natural gas must be treated and sweetened. In this high H 2 S environment, a membrane technology that can remove the bulk of H 2 S from produced natural gas will reduce the load on the amine treatment and sulfur recovery unit operations downstream in gas processing facilities. Bulk removal of acid gases with membrane technology will lower SO 2 emissions through a reduction in flaring, elemental sulfur production from sulfur recovery units, and reduce unit delivery costs for the life of the field. Since 1984, Schlumberger has deployed cellulose triacetate polymeric membranes for CO 2 removal in gas processing and EOR applications. In collaboration with a major oil and gas exploration and production company, our membrane science research team is testing cellulose tri-acetate acid gas removal membranes to characterize separation performance under a variety of process conditions. The team deployed a pilot system capable of testing gas with 25% H 2 S in the USA. These membranes will separate both acid gas components, CO 2, and H 2 S from the feed gas and retain hydrocarbons in the residue gas sent to the amine system for further processing. Low-pressure acid gas permeate can be reinjected into the reservoir for enhanced oil recovery or sequestration. Initial laboratory testing and predictive modeling of the membranes, completed with an American academic research institution, have shown promising results for bulk H 2 S removal. Pilot system testing data will further de-risk and validate the feasibility of technology deployment and facilitate economic modeling of this technology's business impact. We will present the results of the testing to date which will form the basis of the observations and conclusions of the paper. This paper will also present a case study to show the business impact of deploying a hybrid system (membranes + amine) in comparison to a conventional amine system. After testing, operators will have satisfactory information available to review alternative processing facility concepts and re-evaluate the economics of ultra-sour gas field development projects.

ADNOC Offshore in 1988 started implementing a corrosion management strategy for Offshore oil field located in Abu Dhabi. A robust Corrosion Management System developed to protect producer wells equipped with carbon steel tubing from sweet corrosion. With water break through many wells were in high corrosion risk, the effective approach provided completion protection to assure well integrity and extended tubing operating lifetime, which saved production and allowed for OPEX and CAPEX allocation. Presented in this case study a thoroughly review for the field implementation, performance, and economic impact. In addition to cost impact, implementing a strategic solution to replace tubing with Corrosion Resistance Material was challenging for immediate implementation due to the large number of wells with corrosion risk. Moreover, wells initial design did not consider capillary line for continues chemical inhibition system. The only visible solution was to implement corrosion inhibition chemical by squeeze to formation and flow it back with production fluids creating a protective film over tubing wall. This approach required effective monitoring system to optimize priority and evaluate chemical performance. Combing logging and simulation tools and collected data over 30 years present the process performance and value. In place corrosion management system provided a systematic corrosion protection that is effective and efficient in sweet corrosion environment. Many factors can impact corrosion rate and inhibition efficiency such as, water cut, deviation angle, flow velocities, pressures and temperatures, all contributing to the corrosion process. CIS treatment if applied regularly can significantly mitigate the corrosion process and consequently extend the operating well lifetime. Implementing CIS regularly dropped the immediate need to replace tubing with corrosion resistance alloy material (CRA), which allowed allocating workover rigs to serve different requirements. Corrosion management system in oil field offshore Abu Dhabi is an important safety tool that protected environment by maintaining well integrity and extending well life up to 30 years, delaying rig operation and optimized recourses. Setting up a state of the art system and saving cost. This paper, presents a real case study of a comprehensive Corrosion Management system provided a cost saving and safety tool. Expanding the implementation to other fields where water cut started to increase, can provide a cost effective solution against corrosion.

A critical challenge facing the integrity of many assets throughout the oil and gas industry is directly related to corrosion under insulation (CUI). Unfortunately, the lack of adequate inspection technologies adds to this well-known industrial challenge. Presented in this paper is an inspection tool enhanced using Artificial Intelligence (AI) that can provide field inspection engineers with a facility heat map of insulated asset integrity allowing inspection prioritization. The approach used in this research, and presented here, was to enhance the output of already known and field approved thermographic technologies using a purpose built AI based on Machine Learning (ML). By examining the progression of thermal images, captured over time (<20 minutes), corrosion and factors that cause this degradation are predicted by extracting thermal anomaly features and correlating them with corrosion and irregularities in the structural integrity of assets verified visually during the initial learning phase of the ML algorithm. Additional benefits to this technique include enhanced safety through remote inspection and additional cost savings from monitoring assets online. To develop and verify the CUI technology results from in-house laboratory tests followed by field validation outcomes will be presented. Laboratory trials were carried out using a series of insulated field assets with different levels of degradation and structural integrity set up to mimic the thermal behavior of in-process assets. This initial feasibility study allowed the definition of key parameters required to build an effective ML model. Following in-house trials a series of field tests and visual verification was performed on both hot and cold insulated assets to gather a sufficient amount of datasets to train the predictive algorithm. To enhance this learning process, synthetic data was created based on real field asset configurations and operating parameters. Finally, during the technology validation phase, again on field assets, the AI technique coupled with a commercial field approved thermographic camera returned a predictive accuracy in the range of 85 – 90%. The work presented in this paper provides a solution for the current lack of technologies to monitor the presence of CUI by enabling and enhancing the output from already known and field approved technologies, such as thermography, using AI. Additional benefits of this approach include safety enhancement through non-contact online inspection and cost savings by reducing the complexity of asset preparation (scaffolding) and downtime.

This paper describes the novel experience of running Corrosion-Resistant Alloy (CRA) 25% chrome tubing with Dope-free connections in triple joint stands to reduce online running-in-hole (RIH) time. To achieve this, an international operator of a deepwater field development in Angola, defined a special set-up for the make-up and handling equipment, along with connections featuring Dope-free technology. 5 V2" production tubing strings were run in triple joint stands in 2 deep water wells offshore Angola. Well "A" had 14 triples while Well "B" had 67 triples installed. Running highly alloyed CRA tubing with Dope-free technology in stands, in conjunction with using the special handling equipment resulted in faster and safer installations, thus reducing operational risk and saving rig time for the operator. Furthermore, the thread compensator performed the make-up with the neutral point at thread pin thus minimizing stress at the thread's metal seal zone. Several other benefits recorded include savings in jet-wash water, zero dope discharge, reduced personnel exposure to risk, reusability of non-contaminated thread protectors and improved well productivity. The notion of installing highly alloyed CRA tubular in oil and gas wells initially considered too sensitive to be run in triples has been shown to be conservative. This paper shows that from field experience, running highly alloyed CRA tubulars with Dope-free connections in triples is achievable with demonstrable operational improvement and increased reliability.