Numerous solids including gas hydrates, waxes, and asphaltenes have the potential to form in the production lines of gas and oil fields. This creates a highly non-ideal scenario as the accumulation of said species leads to flow assurance issues, especially with long-term processes like deposition. Since an ever-increasing amount of material is deposited in place at the pipe surface, production stoppage or active mitigation efforts become inevitable. The latter production issues result in increased safety risks and operational expenditures. Therefore, a cost-effective, passive deposition mitigation technology, such as a pipeline coating or surface treatment is especially appealing. The ability to address multiple pipeline flow assurance issues simultaneously without actively disrupting production would represent a dramatic step forward in this area. This study is part of a long-term ongoing effort that evaluates the performance and application of an omniphobic surface treatment for solids deposition prevention in industrially relevant systems. In particular, this specific work concentrates on the efficacy and robustness of the treatment under fully flowing conditions. The apparatuses utilized for this include two flowloops: a lab-scale, high-pressure flowloop for gas hydrate and surface treatment durability studies, and a bench-scale, atmospheric pressure loop for crude oil and asphaltene experiments. Film growth in high-pressure flowloop tests corroborated previous reports of delayed gas hydrate nucleation observed in rocking cells. Without the aid of the memory effect, treated oil-dominated experiments never experienced hydrate formation, spending upwards of a week in the hydrate stability zone (at the subcooled/fluid test conditions). Subsequent tests which utilized the memory effect then revealed that the hydrate formation rate reduced in the presence of the surface treatment compared to a bare stainless-steel surface. This testing was part of a larger set of trials conducted in the flowloop, which lasted about one year. The surface treatment durability under flowing conditions was evaluated during this time. Even after experiencing ∼4000 operating hours and 2 full pressure cycles, no evidence of delamination or damage was detected. Finally, as part of an extension to previous work, corroded surface asphaltene deposition experiments were performed in a bench-top flowloop. Treated experiments displayed an order of magnitude reduction in both total oil (all fractions of crude oil) and asphaltene fraction deposited.

Pipelines are coated with insulating material that minimizes heat losses to the environment. Reeled pipe can experience nominal bending strain in the order of 1% to 2%. Thick coating on the pipe is inherently more highly strained, because of concentrations that occur at the interface between parent coating and field joint coating. Occasionally, contractors who specialize in pipe-lay using the reeling method have experienced difficulties relating to unexpected disbondment and cracks in coating at these interfaces. Any disbonded coating is routinely identified and repaired, but it is important to understand the influential factors that could lead to this type of coating disbondment. It is known in the industry that parameters such as temperature, reeling speed and pipe tension are influential but the relative influence of the factors is not well understood. In addition, there is currently no industry code or recommended practice that proposes the strain levels that the coating could safely withstand prior to cracking. This paper addresses thermo-mechanical aspects of coating design and presents a novel approach to quantify which parameters have the largest influence. In the presented assessments, coating strain was assessed using finite element analysis. Material input was selected from a combination of typical values and specific laboratory test results for polypropylene (PP) and injection molded polypropylene (IMPP). An essential aspect was that the mechanical and thermal properties of the PP were related to temperature and strain rate. Strain rates in the coating during reeling operations were obtained from global FE models. Detailed local FE models incorporated all the material and load inputs and temperature conditions that are necessary to determine peak strain values in the coating; the peak strain values would indicate the locations of potential coating disbondment. The study is purely a strain assessment and excludes any potential for defects or delamination in the coating that could result from its manufacturing process. This strain-based study revealed that coating temperature during reeling is the most influential factor on strain level in the coating. Reeling speed and pipe tension are parameters providing secondary influences.

The industries using floating facilities such as FPSO and offshore wind turbine are increasing. Since these vessels have been fixed and operated in the installed area for a long period of time, they cannot be regularly docked, inspected and repaired as opposed to normal ship case, and limited to the inspection of the hull outer plates from under the water and the inspection of inside the tanks are conducted once every five years. These inspections involving visual inspections and thickness measurements at representative points, only examine the current state, and don’t evaluate quantitatively the future potential (remaining life) over the subsequent long operation period. To predict residual life in order to maintain the integrity of these structures, digital twin technology is proposed to realize this demand. This paper shows the method to develop digital twin assessment which solve the insufficiency of conventional monitoring and simulation method in order to utilize for risk-based inspection (RBI) and condition-based maintenance (CBM) to the operators.

Pipeline corrosion is a major identified threat in the offshore oil and gas industry. In this paper, a novel computer vision-based digital twin concept for real-time corrosion inspection is proposed. The Convolution Neural Network (CNN) algorithm is used for the automated corrosion identification and classification from the ROV images and In-Line Inspection data. Predictive and prescriptive maintenance strategies are recommended based on the corrosion assessment through the digital twin. A Deep-learning Image processing model is developed based on the pipeline inspection images and In-Line Inspection images from some previous inspection data sets. During the corrosion monitoring through pipeline inspection, the digital twin system would be able to gather data and, at the same time, process and analyze the collected data. The analyzed data can be used to classify the corrosion type and determine the actions to be taken (develop predictive and prescriptive maintenance strategy). Convolution Neural Network, a well known Deep Learning algorithm, is used in the Tensorflow framework with Keras in the backend is used in the digital twin for corrosion inspection. CNN algorithm will first detect the corrosion and then the type of corrosion based on image classification. The deep-learning network training is done using 4000 images taken from the inspection video frames from a subsea pipeline inspection using ROV. The performances of both the methods are compared based on result accuracy as well as processing time. Deep Learning algorithm, CNN has approximately 81% accuracy for correctly identifying the corrosion and classify them based on severity through image classification. The processing time for the deep-learning method is significantly faster, and the digital twin generates the predictive or prescriptive strategy based on the inspection result in real-time. Deep-learning based digital twin for Corrosion inspection significantly improve current corrosion identification and reduce the overall time for offshore inspection. The inspection data loss due to the communication interference during real-time assessment can be eliminated using the digital twin. The image data can recover the required features based on other features available through the previous inspection. Furthermore, the system can adapt to the unrefined environment, making the proposed system robust and useful for other detection applications. The digital twin makes a recommended decision based on an expert system database during the real-time inspection. The complete corrosion monitoring process is performed in real-time on a cloud-based digital twin. The proposed pipeline corrosion inspection digital twin based on the CNN method will significantly reduce the overall maintenance cost and improve the efficiency of the corrosion monitoring system.

The use of aerial robotic systems that physically contact oil and gas structural assets to obtain measurement data in offshore and marine environments carries unique challenges and operational variables. The objectives of this paper are to demonstrate, with examples, how these aerial robotic systems afford safer, cheaper, and better nondestructive testing (NDT) measurement collection methodology and allow more robust insight into assets conditions than the slower, less safe, and more expensive manual method. To take NDT measurements such as Ultrasonic Wall Thickness (UT) Measurements at height, currently one needs to utilize a lift, ladders or other solutions to reach areas on certain assets. This can be both dangerous, due to the possibility of falls, and time consuming. Utilizing an aerial robotics platform for contact based (not visual) NDT measurements such as Ultrasonic Thickness (UT) allows workers to remain safely on the ground. Drones, with robotic arms, have the potential to improve inspection, testing and data collection. This paper explores an aerial robotic system that flies up to a structure with a metal sub-straight, then under full autonomous software control, touches a UT measurement probe to the target and records the measurement data compliant with American Petrolium Institute (API) and other standards. The use of aerial robotics systems for NDT is still a new and novel application utilizing existing technologies such as electronic measurement readers, drones, etc. with a system of complex integrations that allows for a better application of science. Aerial Robotic NDT systems have the potential to improve the inspection, testing and data collection aspects of coated and uncoated assets, in part, by making the NDT measurement process easier and safer thus allowing for more frequent measurements and/or a larger quantity of measurement samples. When possible, working at heights should be eliminated as part the hierarchy of fall protection stipulated by both OSHA and ANSI. For this reason alone, the use of aerial robotic systems is important now and in the immediate future Oil & Gas infrastructure, including Offshore. This paper intends to provide readers an awareness of this new technology as well as provide information about its efficacy, limitations and operational requirements.

Integrity management is an ongoing lifecycle process for ensuring safe operation and fitness for service of offshore oil and gas production systems, including risers. Risers offer a means of transporting fluids between subsea wells and the host platform crossing the splash zone that is probably the most critical region for corrosion and exposure to external damages. Furthermore, with their proximity to the personnel on the platform and to the topside equipment, risers are considered safety critical, and are therefore, subject to planned inspections followed by an engineering assessment of the findings. This paper discusses the motivation and business driver for developing and implementing a new and cost effective risers’ inspection methodology in the splash zone based on innovative robotic platforms. The technical features and the capabilities of the robot are outlined. Traditionally, risers’ inspections are carried out by rope access technicians and divers or ROV below the water line using conventional technologies as spot ultrasonic thickness measurements, traditional radiography and visual assessment. This type of inspection is based on a first visual assessment followed by NDE testing only if some finding is spotted. Internal defects or defect under coating, e.g. splashtron, can be easily overlooked, compromising the entire assessment process. Additionally such activities are often limited by accessibility, weather, and Personnel On-Board (POB) accommodations, but primarily they involve risks to inspector's safety. Backbone of the presented methodology is the use of a robotic crawler that has the key advantage to inspect autonomously the risers, navigating over obstacles like clamps and supports. The robot can carry a variety of payloads for visual inspections, surface profiling, and NDE examinations with the ability to scan large surfaces with or without coating and detect internal and external defects. It can operate in the topside, splash zone and subsea sections of the riser. The inspection data are processed in real time for an immediate assessment of the integrity of the asset. Examples are presented and comparison is made between traditional inspection methodologies and robotic autonomous methodologies to demonstrate the improvement of inspection effectiveness and efficiency. The paper also discusses the potential areas of future development, which include Artificial Intelligence (AI) algorithms to further automatize the process and methodologies of risers’ inspection and data analysis.

The use of additive manufacturing (AM) technology is growing rapidly for offshore use, whilst established production technologies such as powder metallurgy near-net-shape (PM-NNS) continue to be used. New standards are being introduced and many of the oil and gas majors are now developing supply chains to ensure rapid supply of high-quality complex parts. Environmental concerns are helping to drive this with use of near-net-shape technologies to reduce carbon dioxide emissions through more efficient designs and metal forming methods. Hot isostatic pressing (HIP) has been used to remove shrinkage porosity and internal defects in cast products for many years, predominantly to improve mechanical properties and fatigue resistance. Recently, there has been an increasing focus on AM processes for demanding applications where localized corrosion and similar internal defects and porosity are a concern. HIP technology is being used to either produce PM-NNS parts, or for the post processing of AM produced components to ensure defect free material prior to service in demanding environments. This paper will present a broad overview in the use of HIP equipment to produce parts and components to the offshore industry.

This paper discusses the development and deployment of a specialized online and offline integrated model to simulate the CO 2 (Carbon Dioxide) Injection process. There is a very high level of CO 2 in an LNG development and the CO 2 must be removed in order to prepare the gas to be processed into LNG. To mitigate the global warming effects of this CO 2 , a large portion of the CO 2 Rich Stream (98% purity) is injected back into a depleted oil field. To reduce costs, carbon steel flowlines are used but this introduces a risk of internal corrosion. The presence of free water increases the internal corrosion risk, and for this reason, a predictive model discussed in this paper is designed to help operations prevent free water dropout in the network in real time. A flow management tool (FMT) is used to monitor the current state of the system and helps look at the impact of future events (startup, shutdowns etc.). The tool models the flow of the CO 2 rich stream from the outlet of the compressor trains, through the network pipeline and manifolds and then into the injection wells. System behavior during steady state and transient operation is captured and analyzed to check water content and the balance of trace chemicals along with temperature and pressure throughout the network helping operators estimate corrosion rates and monitor the overall integrity of the system. The system has been running online for 24/7 for 2 years. The model has been able to match events like startup/shutdown, cooldowns and blowdowns. During these events the prediction of temperature/pressure at several locations in the field matches measured data. The model is then able to forecasts events into the future to help operations plan how they will operate the field. The tool uses a specialized thermodynamic model to predict the dropout of water in the near critical region of CO 2 mixtures which includes various impurities. The model is designed to model startup and shutdown as the CO 2 mixture moves across the phase boundary from liquid to gas or gas to liquid during these operations.

Using Computed Tomography (CT) for 3D spatial analysis is a well-established technique primarily used in the fields of medical imaging and precision defect analysis of materials such as aircraft CT technology is gradually evolving for asset integrity within the Oil and Gas sector for two main applications: in-line inspection (ILI) verification and non-intrusive inspection (NII) of coated subsea pipelines. The CT scanning philosophy for both types of inspection challenges varies significantly and in this paper is considered in terms of alignment of inspection deliverables with scan definition. This paper explores the redesign of the traditional CT approach to optimize scanning for high-density target volumes by implementing a ground-up approach to all hardware and mathematics. The advanced algorithms used in the InspeCT TM technology enables a novel technique for image reconstruction; allowing for cleaner images than are possible using traditional CT whilst using less data and hence smaller radioactive sources. In addition, this paper demonstrates a selection of important findings from the InspeCT TM system qualification to API Standard 1163. To maximize the effectiveness of the subsea campaign, use of automated analysis is demonstrated to provide consistency in interpretation and reduce the considerable time demands of high-volume data analysis enabling any remediation decisions or change to inspection strategy to be actioned at the time of inspection rather on a future campaign.

Many pumped storage hydropower plants have long large diameter steep steel pipes (penstocks) between reservoirs. The coating inside such pipes protects the surface from corrosion. Lifetime of the coating is limited and it has to be renewed several times during expected lifetime of the hydropower plant. The coating renovation was a manual process until now. A modification of the process is proposed. The modification of the process includes changes in the technological steps as well robotization of these steps. The new process provides more stability in the quality of coating and eliminates unnecessary presence of people in confined spaces. Using a robot also makes the renewal of the coating much faster. Therefore, it can bring a lot of profit to the owner by shortening the production downtime and re-starting production significantly earlier in comparison to the existing renovation process. The new process was verified in a pilot project at a selected pumped storage hydropower plant and the results were evaluated in cooperation with the hydropower plant owner. Laboratory tests of samples have shown that the coating has two times higher adhesion to the substrate in comparison to the manual coating application. The results also showed that the owner can save around 600 days of downtime on each of both penstocks when using this new process. This is a clear economical advantage which each owner of the infrastructure can understand easily.

During the annual In-Service Inspection of a spar hull, several regions of pitting corrosion on the upper portion of the north and south moon pool external wall plating were identified. The moon pool walls are constructed as typical stiffened panel structures. Visual, ultrasonic (UT), and pulsed eddy current (PEC) inspections indicated regions of corrosion with roughly 40% to 70% averaged localized wall loss. This paper discusses the analytical assessment of the structure to determine the effect of the corrosion on the structural integrity of the moon pool wall and any similar structural panel. To determine the impact of corrosion on the stiffened panel integrity, a finite element (FE) based analysis approach is used to perform a comparative assessment of the "as-built" and "corroded" configuration of the moon pool wall. The nominal plate and stiffener thicknesses are modeled in the "as-built" configuration; whereas, the measured plate thickness from the inspection is modeled in the "corroded" configuration. The structure is subjected to design loads based on the storm damaged design condition. The analysis is performed by uniformly increasing the applied loads until failure occurs, maintaining a constant ratio between the nominal loads. Two different analyses are performed as a part of the strength assessment: (1) a linear-elastic eigenvalue analysis to estimate the elastic buckling capacity and mode shapes of the structure and (2) an elastic-plastic post-buckling analysis to estimate the ultimate capacity of the structure. In addition, the results from the linear-elastic eigenvalue analysis are compared to the results from analytical buckling calculations. The analysis results indicate that the corrosion reduces the elastic plate buckling capacity significantly. However, the overall capacity of the stiffened panel is not significantly reduced. Therefore, from a global strength perspective, the stiffened panel remains acceptable in its corroded condition. The upper portion of the moon pool wall is typically fatigue insensitive in spars. Therefore, the effect of the corrosion wall loss on the fatigue performance was not assessed. Since there is limited guidance in design and assessment codes for assessing corroded stiffened panels, this approach can be used to address future stiffened panel corrosion wall loss. In addition, this method allows for inclusion of future corrosion allowance, if applicable. Determining the capacity of corroded panels using FEA-based numerical methods, like those described in this paper, allows the operators to manage their risks, repair costs, and inspection frequency by determining the actual capacity of the damaged components. This allows the operators to determine the appropriate mitigation measures based on a quantitative risk calculation.

Early detection of corrosion in well casings is of great importance to oil and gas well management. A typical well completion includes a production tubing inside a number of nested casings, which provide necessary well integrity and environmental protections. A multifrequency electromagnetic pipe inspection tool with multiple transmitter and receiver arrays was designed to accurately estimate the individual wall thicknesses of up to five nested pipes. The tool uses an axis-symmetric forward model to invert for wall thicknesses, among other pipe parameters. However, in cases where production occurs from two or more segregated zones, the well is generally equipped with more than one production tubing, which breaks the axial symmetry. In this paper, we show how the tool can further be employed to inspect the integrity of non-nested tubulars, such as dual completions. The performance of the tool is demonstrated using a full-scale yard mockup with known defects. A data-processing workflow, including multizone calibration and model-based inversion, is proposed to estimate the tubulars electrical conductivity, magnetic permeability, wall thickness, and eccentricity. An in-situ, multizone calibration method is applied to remove adjacent tubings influence, thus enabling accurate estimation of the thickness of outer casings without having to pull out the production tubing. In order to demonstrate the capabilities of the tool in wells with dual completions, a log was run in a 150 ft-long yard mockup with two strings of 2⅞ inch. tubing, two outer casing strings, and four different man-made defects on the casings. The tool is logged inside each of the tubing strings, and the two logs are inverted for the thickness and eccentricity of the tubing as well as the thickness of outer casings. Results from the yard test reveal that when the tool is logged in one tubing, it can accurately detect various kinds of defects on outer casings, even in the presence of a second tubing. The interference from the second tubing is shown to be minimal due to the employed calibration algorithm. A high degree of consistency is seen between the logs run in each tubing string. This suggests that if the goal is solely to monitor corrosion in the outer casings, it suffices to run the tool in only one of the tubing strings, further cutting nonproductive time. The techniques presented here enable pipe integrity monitoring without pulling the production tubings; tubings, therefore, minimizing inspection time and cost. The information provided by this tool can significantly improve the efficiency of well intervention operations, especially in areas with high corrosion rates.

Pipelines are coated with insulating material that minimizes heat losses to the environment. Reeled pipe can experience nominal bending strain in the order of 1% to 2%. Thick coating on the pipe is inherently more highly strained, because of concentrations that occur at the interface between parent coating and field joint coating. Occasionally, contractors who specialize in pipe-lay using the reeling method have experienced difficulties relating to unexpected disbondment and cracks in coating at these interfaces. Any disbonded coating is routinely identified and repaired, but it is important to understand the influential factors that could lead to this type of coating disbondment. It is known in the industry that parameters such as temperature, reeling speed and pipe tension are influential but the relative influence of the factors is not well understood. In addition, there is currently no industry code or recommended practice that proposes the strain levels that the coating could safely withstand prior to cracking. This paper addresses thermo-mechanical aspects of coating design and presents a novel approach to quantify which parameters have the largest influence. In the presented assessments, coating strain was assessed using finite element analysis. Material input was selected from a combination of typical values and specific laboratory test results for polypropylene (PP) and injection molded polypropylene (IMPP). An essential aspect was that the mechanical and thermal properties of the PP were related to temperature and strain rate. Strain rates in the coating during reeling operations were obtained from global FE models. Detailed local FE models incorporated all the material and load inputs and temperature conditions that are necessary to determine peak strain values in the coating; the peak strain values would indicate the locations of potential coating disbondment. The study is purely a strain assessment and excludes any potential for defects or delamination in the coating that could result from its manufacturing process. This strain-based study revealed that coating temperature during reeling is the most influential factor on strain level in the coating. Reeling speed and pipe tension are parameters providing secondary influences.

Known as HFW-MLP, Mechanically Lined Pipe (MLP) with High Frequency Welded (HFW) host pipes are potentially the most cost-effective bi-metallic pipes for subsea pipelines when corrosion resistant alloys (CRA) are required. However, HFW-MLP has a very limited track record for subsea applications. This paper details a recent programme to qualify MLP with HFW host pipes. The qualification programme has been performed in accordance with DNVGL-ST-F101 (2017) and internal supplementary requirements for reelability and weldability. It considers material testing of HFW-MLP at each manufacturing stage and product qualification including full-scale reeling simulation, anti-corrosion coating simulation and girth welding. Qualification is supplemented with a detailed evaluation of the manufacturing process HFW-MLP is compared to traditional MLP which is supplied with seamless carbon steel as the host pipe or backing steel. This novel product lowers the supply cost, reducing the Capital Expenditure (CAPEX) for subsea pipeline projects. Detailed evaluation of mechanical test results and dimensional inspections using laser profiling assess the impact of the HFW host pipe longitudinal seam weld and conclude that there is no detrimental effect on the performance of the completed MLP. A comprehensive review of full-scale reeling simulations, coating simulations and welding trials is completed, with the conclusion that an HFW host pipe does not adversely affect the ability of the MLP product to be girth welded and to withstand the plastic deformation exerted upon the product during reel-lay installation. It is concluded that HFW-MLP is qualified for subsea pipeline static applications via the reel-lay, S-Lay or J-lay installation methods. The qualification of HFW-MLP provides a more cost-effective solution for the development of corrosive subsea fields by reducing overall product supply and installation costs.

Fast-track engineering to expeditiously deploy new technologies in upstream oil and gas heavily relies on timely agreement and synergy between the engineering team and stakeholders on (1) tool architecture (2) operational envelope and wellbore environment (3) qualification criteria(s) and overall verification & validation (V&V) strategy, among others which lead to the product specifications. Here we present a "Case Study" where two new technologies, were engineered to order for the Middle East and North Africa (MENA) regions: a first-generation Pressure-Temperature (P-T) flowable sensor from our "Teleo" product line, and a multilayered water reactive plug for multi-stage stimulation (MSS) and acid frac, designed from bulk ultrafine-grained light alloys and water reactive, nanocomposites.

It is well understood that strength to weight ratio is an important driver facilitating extended reach deviated wells, as such engineering corrosion resistant ultra-high-strength light-alloys (LAs) are an absolute necessity. High strength steels and nickel alloys, having yield strengths between 80 and 120 ksi, commonly used in oil & gas completions and production, have 3 to 5X higher specific gravity compared to LAs. In comparison, commercial coarse-grained polycrystalline light-alloys (CGP-LAs) have a much lower strength, typically less than 45 ksi yield strength and are not corrosion resistant. However, if strength of LAs can be increased to match that of steels and nickel alloys while simultaneously augmenting their corrosion and environmental assisted cracking (EAC) resistance through severe plastic deformation (SPD) routes, manifesting an ultra-fine-grained (UFG) microstructure, they will far surpass strength to weight ratios of steels and nickel alloys. As such the quest for a perfect alloy with the right combination of strength, ductility, corrosion, and abrasion resistance is ever ongoing. The advent of nanotechnology and advancements in engineering nanostructures with high strengths and reasonable ductility has motivated researchers globally [ 1 - 7 ]. We have bridged a few of these technology gaps by addressing challenges relating to the compromised ductility of these novel high-strength nanomaterials, however there is limited data on their EAC susceptibility. EAC encompasses stress corrosion cracking (SCC) related events or catastrophic failures due to the loss of ductility of a metal exposed to acid gases, such as hydrogen sulphide (H 2 S) and/or through absorption of hydrogen. To determine if grain refinement in a LA, and resultant Hall Petch strengthening, where strength of the UFG-LA surpasses that of commercial coarse-grained oil-grade steels, is instrumental in enhancing its EAC resistance, focused experiments were conducted. An aluminum-magnesium CGP-LA commonly used in offshore and marine applications was selected and subjected to SPD resulting in an UFG microstructure. Both CGP-LA and UFG-LA specimens were exposed to environmental conditions to compare their corrosion and EAC and resistance. It was observed from polarization measurements and immersion tests that UGF-LA had better corrosion resistance than CGP-LA. Uniaxial tensile tests in a neutral halide environment for various holding times confirmed that strength and ductility was maintained for UFG-LA specimens while catastrophic failures of CGP-LA specimens were observed. It was also evident from orientation images that grain boundaries in UFG-LA were predominantly high-angle in contrast to CGP-LA. The improved corrosion and EAC resistance of UFG-LA was due to a large number of purer grain boundaries with nanocrystalline impurities distributed infrequently along them. These results are very topical as they highlight the possibility of harnessing the enhanced strength to weight ratios of these unique alloys for designing buoyant thin walled flowable shells for deployment in high pressure high temperature (HPHT) oilfield environments, from vehicles being designed for interstellar gas giants to aggressive sour oilfield reservoirs.

The Eni Nikaitchuq field development on the North Slope of Alaska consists of the Spy Island Drillsite (SID) artificial island, tied back to shore at the Oliktok Point Pad (OPP) production facility via a 3.6-mile-long buried offshore flowline bundle which contains a 14x18-in pipe-in-pipe (PIP) production flowline. In late 2017, the presence of internal corrosion was detected in the 14-in production flowline, and a repair of the line was performed. This paper presents the work performed to complete the repair, and the engineering and construction challenges overcome by the project team to ensure a timely and reliable repair was executed. The engineering work was initiated in early 2018 and included initial integrity checks of the 14-in flowline, followed by an evaluation of feasible repair options, and the selection of the preferred repair option, which was to install a 10-in steel linepipe inside of the original 14-in flowline to create a pipe-in-pipe-in-pipe (PIPIP). The selected repair methodology allowed the total repair project to be undertaken in six months, from the time of repair concept definition to restart of production. Actual production downtime was limited to only seven weeks, with the insertion of the 10-in repair pipe itself taking only ten days. Production has been successfully ongoing since completion of the repair and resumption of operations at Nikaitchuq. It is believed that this is the first time such a repair has been successfully undertaken, where a steel flowline several miles long has been installed inside of an existing flowline and serves as a good example of how innovative engineering and construction methodologies can be reliably implemented in the Arctic.

Cleaning, applying and testing coatings on corrosion-susceptible surfaces, such as those in Oil & Gas and extreme environments such as offshore Oil & Gas assets, currently requires extensive manual labor. Further, cleaning, coating and measuring coatings at height can create a dangerous occupational environment. Drones, also known as unmanned aerial systems (UAS), unmanned aerial vehicles (UAV), or small unmanned aerial vehicles (sUAV) can be leveraged to perform some of these tasks, including cleaning, coating, and inspection while keeping workers safely on the ground. Of note are some current aerial robotic inspection platforms in the market that make physical contact with structures for nondestructive testing (NDT) in addition to visual inspection. Drone capabilities have significantly evolved over the past decade, and it is expected that the ubiquity of such systems will continue to increase in the years to come. While no coating or cleaning drone is commercially available at the time of this publication, one company has an existing prototype currently under development as part of a Joint Development Agreement with a large international coatings manufacturer for industrial application that is expected to be tested in industrial environments this year. This prototype is a custom-manufactured drone with a tether to the aircraft from the ground that delivers power and cleaning or coating material. An on-board computer manages flight navigation along with intelligent spraying. While the utilization of this new technology faces many challenges, it is important to recognize the potential and projected growth in use of such systems. An introduction to the current state of coating and cleaning drones will be discussed, along with limitations and benefits the system can provide to the coatings and corrosion control in the Oil & Gas industry.

Corrosion engineers take Nondestructive Testing (NDT) measurements at height as a method of determining the condition of Oil & Gas and other assets such as flare stacks, boilers, above ground storage and pressure vessels, piping and more. To do this at elevation currently the engineer may need to utilize a lift, scaffolding, ladders, or ropework or even inspection trucks with elevated baskets, sometimes cranes or even specialty access such as rigging catwalks, or other solutions. The engineer will often hold a handheld digital testing device to the asset to take the measurements in these scenarios. While NDT inspection programs can dramatically increase the safety and integrity of infrastructure, industrial and manufacturing assets, access requirements in performing these inspections at elevation introduces risk. NDT inspection sites often require access to elevated areas and require the use of personal fall protection equipment (safety harness and lanyard). Working at height is dangerous, due to the possibility of falls, as well as being time-consuming due to access. In certain instances, it may also require taking an asset, such as a flare stack or chimney stack, offline to allow it to cool so it can be accessed to take NDT readings. Utilizing an aerial robotics platform that makes contact with a surface in order to gather NDT measurements such as Dry Film Thickness (DFT), Surface Profile (SP), or Ultrasonic Thickness (UT) allows workers to remain safely on the ground. Since there is no need to move a lift, scaffolding or ladders and minimal movements required by the corrosion engineer or the robotic operator, the NDT measurement process can be faster in addition to being safer. Further, since the aerial robotic system (drone) contains onboard computers and sensors it is able to capture a lot of data during the exercise of an NDT inspection regime. Use of these aerial robotic NDT systems in offshore and marine environments carries unique challenges and operational variables. The Aerial Robotic System described in this paper afford safer, cheaper, and better NDT measurements and allow a more robust viewpoint into assets conditions than the slower and more expensive manual method. While early adopters in the offshore Oil & Gas and maritime industry stand to gain the most from implementing these systems they are also assuming the most risk until the systems become an industrial standard.

Following the drop of oil prices during 2015 we have seen an increased attention from operators on using new technology, in particular active heating technologies. This paper presents an update to experience from early implementation with lessons learned to recent technology development of what today is the only field proven electric heating technology for rigid flowlines per today - Direct Electric Heating (DEH). It also discusses Electric Heat Tracing as promising technology undergoing qualification – but the main focus is on DEH. DEH had its technology qualification carried out in the 90-ties and early 2000's while the more recent years has focused on achieving long distance tie backs, qualification for deep water projects but also design alteration opening for cost reduction. Increased number of operators: During the first 10 years, all projects were in operation in the North Sea whereas during the last 8 years other operators has started using the technology, as well as applications in harsher environment and deeper waters. Deep water: Following internal testing to gain more information on material data of steel and copper, combined with an update in analysis technique – previous over-conservatism in design process can be reduced such that a more accurate analysis can be carried out. Consequently, cable designs which previously only were applicable for depths down to less than 800m WD can now be used at 1500m WD. Long distance step-outs: Wet design XLPE insulation to higher electrical gradients has been now successfully qualified, allowing DEH to be applied on longer distance tie-backs than before Technology improvements A 3-year R&D on high frequency DEH gives both technical advantages for interference with other subsea equipment, reduced AC corrosion as smaller conductors which leads to a significant cost reduction. With the above technical improvements alone or combined, and a better DEH system than that was qualified in year 2000 is now available to the market.