Abstract The High-Performance DEH-PiP is a new technology for electrical heating of subsea tie-back flowlines, that minimizes disturbances to the construction and installation process wrt. to standard PiP avoiding the use of internal heating cable, while reaching the same electrical efficiency as e.g. Electrical Heat-Traced (EHT) pipe-in-pipes. It thus boasts a much higher efficiency than a Wet Insulated DEH pipe. However, no comparison has been done so far on the CAPEX needed. Is a DEH PiP worth its value? Is the second pipe wall worth the expense? The aim of this paper is thus to present a novel comparative study between DEH-PiP and a traditional Wet Insulated DEH single pipe A complete engineering study has been made (flow assurance, pipeline design, electrical engineering, installation engineering) based on real cases. Full EPCI costs have been evaluated, local content for fabrication quantified, and associated carbon emissions as well during operations The study concludes that High Performance DEH Pipe-in-Pipe is difficult to compare to Wet insulated Single pipe The technology was 3% more expensive in CAPEX on the 30km tieback studied, but the margin remains small, and other factors may influence the conclusion. The two technologies remain comparable in a 20-40km range. A DEH-PiP offers more thermal and power efficiency, and other benefits such as greenhouse gases emissions savings. Operational downtime and production fluid properties should also be considered in decision making.

Abstract Objective Scope Geothermal energy is gaining attention worldwide as an attractive and vastly underutilized renewable energy source due to its abundance, baseload capability, resiliency, and reliability. While there are many types of geothermal energy concepts, the holy grail of geothermal – that would enable geothermal drilling and production in most places in the world – is hard rock or superhot rock concepts. Developing these systems requires drilling into granitic basement formations, often at temperatures exceeding 300º C. There are two main technological challenges associated with hard, hot rock concepts. Firstly, very hard rock, such as granite or basalt, limits the rate of penetration (ROP). Secondly, the temperature of the drilling system exceeds the operational limits of electronic tools like measurement while drilling (MWD) and Rotary Steerable. This paper discusses the modeling, design, and testing of a drilling system that solves both challenges. Methods Our approach to the ROP problem was to optimize the drilling system for drilling cold hard rock from 0º to 175º C and optimize the system for drilling hot hard rock where temperatures exceed 175º C. We will discuss the design and performance of both PDC drill bits and Hybrid Particle Impact/PDC bits in hard rock formations and the best application of the two methodologies moving forward. Our approach to the temperature problem was to model the entire wellbore and drillstring and investigate the effects of, but not limited to, the starting temperature of the fluid, flow rate of the fluid, type of fluid, impact of the thickness, type of insulation on the inside of the drillpipe, the diameter of the pipe, and continuous circulation. The objective of the modeling was to understand the relative impact of changes to the system on the temperature of the drilling fluid and the most cost-effective way to deliver a 150º C fluid to the bottom of the hole. Results, Observations and Conclusions This paper will discuss the results, observations, and conclusions of testing and running PDC drill bits and Particle Impact Drilling/PDC hybrids in hard formations. The results will derive from lab testing and geothermal drilling projects. The paper will also discuss the field testing and running of components of a drilling system optimized to deliver as cool a fluid as possible to the bottom of the wellbore. Novel/Additive Information The results shown in this paper suggest that we have solved, or are very close to solving, two of the major challenges which prevent geothermal energy from being economically viable worldwide and not just restricted to the small geographic areas where you have very high temperature gradients associated with volcanic activity. The results would also have significant benefits for oil and gas wells where the bottom hole temperatures exceed 175º C.

Abstract Reinforced Thermoplastic Pipe (RTP) is one of the solutions considered using instead of metal pipe to avoid the corrosion problem. As RTP is a non-metallic pipe that is subjected to damage or deformation when get fire. A protective fireproof system is required to protect RTP from cellulosic fire for at least 2 hours. and pipe surface temperature not over 82 °C per RTP specification and should be reusable and has a long service life. From the performance test results, there are two materials of PFP (Passive Fire Projection) that passed the requirement. One is intumescent (Composite fiber glass fabric with external polyurethane "PU" coating 0.7 mm.) and the other one is rockwool insulation (Reflective heat guard 3 mm. + Rockwool insulation 50 mm. + Aluminium 1 mm.). The rising of the surface temperature of the Reinforced Thermoplastic Pipe (RTP) is in the acceptable criteria. The RTP pipe appearance is still in good condition. For PFP appearance, the intumescent will be damaged after burning while rockwool insulation is not changed and is reusable. In terms of material cost, the price of intumescent including material cost and installation cost is lower by about 20%. Both options are interesting and shall be considered again for usage purposes. Replacement of metal pipe with spoolable pipe with PFP has advantages in terms of low maintenance cost and higher corrosion resistance. The Reinforced Thermoplastic Pipe with PFP can be installed on existing pipe support with enough space for inspection. This solution can eliminate the weak point of RTP and allows the application of RTP without pull through carbon steel pipe. The PFP rockwool insulation is a good option to protect pipeline damage from unpredictable fire with low material and installation costs.

Summary Electrical submersible pumping (ESP) remains the preferred artificial lift method for high rate production when technically viable. ESP, on the other hand, is sensitive to downhole conditions and pumped fluid. Sour fields, in particular, are considered as a major challenge for producing facilities and well completion elements. Reservoirs producing fluids with hydrogen sulfide (H2S) present a special challenge to ESP systems. This paper uses ESP field observations and pulled equipment findings from many dismantle inspection and failure analyses (DIFAs). The findings confirmed H2S behavior and root causes of electrical and mechanical failures within multiple ESP components. The outcome of these investigations and the recommended system upgrades to enhance ESP reliability in corrosive environments will be illustrated. Critical ESP system materials will deteriorate and fail when subjected to sour environments. H2S can penetrate the pump’s cable insulation, attack the copper, and react to form copper sulfide, resulting in electrical failure. It can also permeate the seal bags and o-rings, diffuse in the seal dielectric oil, and attack the bronze and copper components in the seal and the motor. To improve reliability, a new version of motor lead extension (MLE) using three individually armored connectors and a seal with H2S sacrificial anode scavenger inside each chamber were introduced. The improved design encapsulated the insulated conductors individually within metal tubes made of high nickel alloy. The tubes can be terminated individually at the motor and above the production packer with proven swage type connectors. By utilizing high nickel alloy tubes as barriers against H2S and removing all connections below the packer, the H2S effect has been eliminated. On the other hand, the seal with H2S passive scavenger will retain most of the H2S in the dielectric oil before it reaches the motor. These novelty technologies resulted in a threefold improvement, leading to longer up time, less workover jobs, and more sustainable production.

Abstract In this work, we present a novel Artificial Intelligence (AI) powered non-destructive testing (NDT) system for the detection of potential corrosion under insulation (CUI) inspections, code named DPCUI, developed by the Research and Development Center (R&DC) at Saudi Aramco in partnership with Baker Hughes. This inspection system enables fast external thermographic screening of large facilities by covering many condition monitoring locations (CML), and without any contact with the asset surfaces. It examines temporal thermography datasets that are collected using a high-resolution IR camera, such as those provided by FLIR, and on one or more RGB images that provide context of inspected areas. The collected data is analyzed by a dedicated AI engine to detect the presence of abnormal heat transfer signatures that occur due to defects present within the targeted CMLs. The novelty of this AI powered technology has several advantages. It provides a contact-less, smart, easy, fast, automated, safe, and reliable risk-based repair and maintenance decision making on the integrity of assets, enabling asset owners to efficiently prioritize their operations and processes in a seamless manner while the assets are kept online. Here, we enhance and extend the performance of our AI models to predict not only the presence of potential CUI or not, i.e. binary classification, but also various types of potential CUI, i.e. multi-class classification, a first of its kind.

Abstract Geothermal energy is considered a reliable, sustainable and abundant source of energy with minimized environmental impact. The extracted geothermal energy may be utilized for direct heating, or electricity generation. The main challenge to access this energy is tremendous capital expenditures required for drilling and completion. Therefore, this work discusses and evaluates retrofitting abandoned petroleum wells to geothermal as a commonly proposed solution to the mentioned challenge. There are many oil and gas wells globally which are not used for production, injection or other purposes. Well abandonment is commonly considered as an essential measure to ensure safety and integrity of these wells, bearing huge costs and concerns for the petroleum industry. By converting abandoned or nonactivated oil and gas wells to geothermal wells, it is claimed to be possible to produce geothermal energy and generate power. As a crucial stage for the claim verification and evaluation of feasibility or efficiency of this conversion, it is important to be aware of the practical and simulation studies which have been already implemented. Therefore, in this work, this work presents a comprehensive overview and analysis of 20 case studies published from different countries, followed by important downhole and surface parameters. In terms of downhole characteristics, production scenarios either open-loop or closed-loop, optimization of open-loop systems, borehole heat exchangers with their different types and dimensions, and insulations are covered. Next, surface cycles including organic Rankine cycle (ORCs), selection of circulation fluids, flow rates, and working fluids are covered, followed by produced and net powers with evaluation of coefficient of performance (COP) and thermal efficiency. This investigation shows there is good potential for using geothermal energy from abandoned and old petroleum wells.

Abstract Shell Autonomous Integrity Recognition (AIR) on C3 AI Platform is an Artificial Intelligence (AI) application that allows pressure equipment and structural steel inspectors to quickly and easily make use of automated image capture and evaluation to support execution of external integrity inspections. By processing data in the cloud coming from inspections carried out with handheld devices, drones and robots, this application enables inspectors to objectively evaluate issues, identify items that may have been overlooked, reduce the time needed to generate reports, and improve inputs to maintenance planning. By using Shell Autonomous Integrity Recognition on C3 AI Platform, users can improve the quality, efficiency, and standardization of visual inspections.

Abstract This paper describes the applications of digitalization technologies specifically Industrial Internet of Things (IIOT) to predictive Corrosion Management with an attractive use case of corrosion under insulation. The available technologies and case studies of field use cases will be presented. Hidden corrosion such as corrosion under insulation (CUI) can be better managed with digital data harvesting and with predictive tools using data of the assets such as knowledge of moisture locations and temperature etc. This method involves use of this data set to manage the assets holistically, prioritizing the risky locations and scheduling their inspection and maintenance. A predictive method is described which can help the asset owners not only manage the assets in a cost-effective way but in a safer way too if the risks are pre-identified and acted upon. In this article the predictive CUI monitoring technology is introduced. The technology includes sensing conditions under the insulation and predictive modeling to estimate risks in a very rapid manner. In this paper, use-cases and applications will be explained and shown. The new method of using sensing and industrial IOT to detect and predict corrosion in the field will be a huge impact for the asset integrity struggling with the threat of hidden corrosion such as corrosion under insulation. The paper will reveal the latest case studies from the field usage of monitoring thereby building confidence in it and advancing the knowledge base in corrosion industry.

Abstract A Design responsible for more than thirty parameters of drilling projects, and a computer program to create groupings of the wells of a pad with consequent calculations of technical-economic characteristics, are developed and tested, covering a small surface area on land and a maximum interference with the reservoir downhole. PAD wells are mainly installed with Packers/penetrators, SSSV (subsurface safety valves) for well bore protection from any abnormal high pressure, the casing is secured with the non-beaded packers and the tubing is secured with an SSSV that is activated manually through a capillary tube connected up to the surface. Here we present the performance of electrical submersible pumps in PAD wells installed with TDV (Tubing drain valves) and without TDV and the effect of the gasses accumulated in the annulus that can affect the performance of the electrical submersible pumps which can cause gasses locks or ESP trips and this can be classified as below: PAD Wells with TDV PAD wells without TDV The above classification can be further branched into the below: Higher Distance between Packer and Intake less distance between Packer and intake using the daily monitoring and the sensor parameter charts and studying the history and performance of the ESP we will analyze each cases separately to get to conclusions and recommendations on which case is better to design for PAD wells that can efficiently increase the performance of the ESP and increase the ERL (Equipment run life). In addition, this paper will discuss the effect of accumulated gasses trapped in the annulus on the ESP cable. Based on the conclusions for each case, this paper will provide recommendations to enhance the equipment run life of the ESP system to avoid premature failures, gas lock and smooth operation for such cases.

Abstract Throughout the past decades, the Electrical Submersible Pumps (ESPs) have been deployed across different oil fields in an Arena of Artificial Fields. It was a proven fact that the typical run life of an ESP can exceed multiple years. However, that fact could be reversed especially in designated fields with high Hydrogen Sulfide (H2S) partial pressure; where specialized ESP design is required. The presence of the Hydrogen Sulfide (H2S) can result in various and vast forms of corrosion products attacking the ESP components which eventually resulted in an ESP shorter run life compared to average. Hydrogen Sulfide (H2S) can also react with formation water (H2O) and form Sulfuric Acid (H2SO4) or free Sulfur; which is another source of corrosion product affecting the installed ESP system. As part of continuous improvement in equipment's reliability, several Dismantle inspection and failure analysis (DIFA) were done for ESP premature failures to identify the root causes along with the recommendations and forward plan to enhance ESP run life. The results of these DIFAs indicated a common root cause of ESP failures are related to Hydrogen Sulfide (H2S) presence and well fluids entering the ESP internal components. In particular, the packer penetrator, Motor-Lead-Extension (MLE), and the pothead interface were found to be the main reasons. Consequently, an effort was rolled out to control the Hydrogen Sulfide (H2S) presences at these three locations in order to maintain the ESP reliability and prolong its run life. This presented paper will demonstrate the methodologies and fit-to-purpose ESP design that contributed in extending the ESP run life in a high Hydrogen Sulfide (H2S) pressure fields. Also, a captivated practice along with related technologies have been adapted for the sour environment which resulted in sustaining the ESP run life.