Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Corrosion Management Framework: A structured Approach to Managing Corrosion in Oil and Gas Facilities
Odinde, Paschal (Shell Petroleum Development Company Ltd) | Ezeifedi, Humphrey (Shell Petroleum Development Company Ltd) | Akanni, Joseph (Shell Petroleum Development Company Ltd) | Anyachor, Nnaemeka (Shell Petroleum Development Company Ltd) | Oladipo, Alonge (Shell Petroleum Development Company Ltd) | Ohia, Chibueze (Shell Petroleum Development Company Ltd) | Orajiaka, Chinenye (Shell Petroleum Development Company Ltd) | Sangoyinka, Habib (Shell Petroleum Development Company Ltd) | Onuorah, Chris (Shell Petroleum Development Company Ltd)
Abstract The rising cost of corrosion is alarming especially in ageing oil and gas production facilities. This situation is necessitated majorly by absence of corrosion management framework (CMF) which is a blueprint for identification and mitigation of common threats associated with corrosion in production assets. This paper explores the gains, challenges and improvement areas arising from development and implementation of robust corrosion management framework in fifty (50) oil and gas facilities. The CMF was developed and implemented using threat identification, barrier design and barrier maintenance philosophy. The result of the CMF implementation revealed that most of these facilities are laced with unmitigated corrosion threats which predisposes the assets to hydrocarbon leaks. The results also provide insight as per the status of the pressure equipment, information for development of risk-based inspection plan and continuous improvement of corrosion management system. Some of the challenges encountered in effective CMF implementation for these facilities includes incompleteness of inspection data, unavailability of design data, absence of leadership commitment, competence gap and cost. This study has shown that CMF implementation is very critical in demonstrating sustainable asset integrity management and return on investment (ROI). However, to deepen the gains of CMF implementation in asset integrity management, there is need to have a well-defined roles and responsibilities, clear leadership commitment, visible corrosion management policy, digitalization of corrosion and inspection data acquisition, as well as competence development.
Abstract The use of subsea one-atmosphere chambers for early petroleum production schemes or for wells beyond the reach of platforms has been a reality for seven years. Such chambers are currently in use in the Gulf of Mexico and offshore Brazil for Shell, Union Oil, Tenneco and Petrobras. Everyone-atmosphere chamber has two basic functions in common to isolate the equipment it contains from the subsea environment, and to allow trained oilfield technicians access to that equipment for servicing and trouble-shooting. The type and function of the equipment installed in the chamber is unlimited. This paper deals with two applications of the one-atmosphere chamber: first, with well production chambers and equipment, and secondly with manifolding chambers and equipment. Design considerations, fabrication, installation and service techniques are discussed. Typical servicing operations are described. Introduction The one-atmosphere early production system consists of the subsea chamber (s), the enclosed production equipment, production flow lines, connections to a production riser and a surface support system. Figure 1 (Garoupa) illustrates the early production scheme using one-atmosphere chambers in use offshore Brazil. Satellite one-atmosphere Wellhead Chambers (WHC) enclose the Xmas tree packages, a Manifold Center (MC) gathers and commingles the flow from all wells via flow-line bundles and transfers it to a floating process facility tied to a single point moor type riser. A one-atmosphere servicing system consisting of a tethered diving bell type Service Capsule (SC) and Surface Support Vessel (SSV) provide subsea servicing capability for the one-atmosphere system. The chambers provide an encapsulated area isolated from ambient sea pressure and the corrosive effects of salt water. The environment inside the chamber is controlled to ensure that as near as possible, dry land conditions exist. Internal pressure is at one-atmosphere. Normal air is provided for breathing without masks. Using a one-atmosphere chamber to encapsulate equipment on the ocean floor eliminates the need for production equipment specially designed to operate in ambient sea pressures and in a highly corrosive environment. Equipment, tested and proved in land applications, can be selected from regular stock and suppliers. Using a one-atmosphere chamber also eliminates the need to use divers to perform commissioning and service tasks. Instead, oilfield hands and technicians may be used for the many complex servicing and trouble-shooting activities that occur during the 20-year operating life of a subsea unit. It also allows the use of a well-proven subsea flow line connection or pull-in technique and manned intervention during the critical Xmas tree installation. Chamber Design The design of anyone-atmosphere chamber for use subsea is affected by the following: the working environment, both in terms of water depth and the corrosive effects of salt water; the type of production equipment to be encapsulated; life support and safety systems for periods of servicing and the installation technique to be used. Until 1978, design criteria for subsea manned habitats permanently attached to the ocean floor were not specifically included in any regulatory codes.
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (0.73)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (0.73)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Subsea processing (0.53)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Subsea production equipment (0.46)
Near Real-Time Corrosion Monitoring for Wellbore Integrity Management
Kumar, Amit (ADNOC Offshore) | Al Daghar, Tareq (ADNOC Offshore) | Al Shehhi, Ali (ADNOC Offshore) | Keinath, Brendon (ExxonMobil Global Projects Company) | Kulkarni, Mohan (ExxonMobil Upstream Research Company) | Beltramino, Pedro (ExxonMobil BSC Argentina) | Long, Andrea (ExxonMobil Upstream Integrated Solutions Company)
Abstract For safe operation of wells, it is critical to maintain the integrity of production tubing. Integrity management in the wellbore needs to address a variety of factors including exposure to harsh environments, accessibility limitations on inspection tools, cost-optimization and need for production interruption for running the downhole inspection tools. Such scenarios make regular corrosion measurements difficult, and can result in a reactive approach to integrity management. Corrosion prediction software provides a solution to alleviate this issue. Water-chemistry and flow parameters are key drivers for corrosion assessment. Generating these inputs for corrosion predictions using industry standard flow models requires significant expertise and is tedious which limits the frequency of assessments. Given the significant number of carbon steel tubulars in a giant offshore oil field in Abu Dhabi, the original process was too cumbersome resulting in only a select number of wells being modeled. To streamline the process, an automated application was developed which virtually integrates wellbore mapping, field data, multiphase flow physics, water-chemistry, and proprietary corrosion modeling software seamlessly. The corrosion monitoring application has allowed for more frequent and timely corrosion assessments of a significant number of wells. The results to date include optimization of corrosion inhibitor (CI) usage during early production and to drive decisions for timely CI squeeze treatments. In addition to CI optimization, the high fidelity corrosion predictions have also driven preventative mitigations in wellbores with high wall loss leading to improved integrity. Application of this tool in conjunction with advancement in field data management enables a systematic approach in assessing tubular integrity status of wells in near real-time and predicting remaining life of tubulars. Implementation of this unique, easy-to-use multi-disciplinary application assists in proactive management of integrity, avoids unnecessary workover, and enables cost saving by continued use of existing materials. The application was developed in a computational framework that allows quick integration of physics-based modeling tools for bespoke applications. Furthermore, it supports the development of corrosion monitoring plan, identification of wells with potentially high corrosion, and assists field engineers in defining inspection requirements to maintain well integrity.
- Well Drilling (1.00)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
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.
- Asia > Middle East > Saudi Arabia (0.29)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.16)
- Geophysics > Borehole Geophysics (0.95)
- Geophysics > Electromagnetic Surveying (0.85)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff C Formation (0.99)
- (4 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Use of Novel Test Setup to Simulate WAGI Well Flow Conditions for Corrosion Management
Kumar, Amit (ADNOC Offshore) | Willingham, Thomas (ADNOC Offshore) | Wang, Zhihua (ADNOC Offshore) | Kohata, Akihiro (ADNOC Offshore) | Alsowaidi, Alunood (ADNOC Offshore) | AlDaghar, Tareq (ADNOC Offshore) | Troshko, Andrey (ExxonMobil Upstream Research Company) | Fischer, David (ExxonMobil Upstream Research Company) | Pacheco, Jorge (ExxonMobil Upstream Research Company)
Water-alternating-gas-injection (WAGI) pilot wells are planned to be drilled in a giant offshore oil field in Abu Dhabi. To minimize pilot well cost, carbon steel is considered as one of the potential materials. Planned WAGI wells will have extremely long horizontal completions, and the incomplete displacement of water during gas,water displacement cycle may lead to significant corrosion. This paper describes the corrosion management methodology used to make material selection and corrosion control related decisions for pilot WAGI wells. A key aspect of the methodology is its structured approach that combines science-based corrosion modeling with field-specific laboratory testing and surveillance data. The corrosion models have been extensively validated with laboratory and field data, and are applied in conjunction with flow models to enable full wellbore corrosion predictions. Computational Fluid Dynamics (CFD) was used to simulate gas,water displacement efficiency. The laboratory testing was conducted in specialized high pressure, high temperature autoclave test cells. A corrosion testing program was created to reproduce corrosion conditions during incomplete gas-water displacement. Corrosion inhibition effectiveness as part of corrosion control strategy was also evaluated. During the WAG gas injection cycle, the hydrocarbon gas contains CO2; hence, there is the potential for corrosion due to water hold up in the well from either incomplete displacement of injected seawater or due to cross flow from the reservoir. Any damage to completion due to corrosion may affect the injection profile and may result in an underperforming injector. Moreover, deposition of corrosion products may lead to a reduction or even a complete loss of injectivity in some zones. Lab test results show that corrosion due to a long term gas-water wellbore mixing can lead to completion corrosion within few WAG cycles. Effect of water splashing and intermittent wetting on corrosion due to high gas flow during gas,water displacement cycle was also evaluated. Results show that submerged (continuous) and splashing (intermittent) exposure to CO2-containing seawater under WAG cycle conditions can create a very high corrosion risks for carbon steel. However, corrosion due to incomplete gas-water displacement mixing can be mitigated by injecting an optimal corrosion inhibitor prior to WAG switchover. Test setup demonstrates an innovative approach to replicate anticipated flow environment in WAGI wells in the laboratory. CFD model incorporates the key physical drivers envisioned in the WAGI process and includes modeling of the gas-water interface evolution and gas leaking into the formation. Learnings from this study will be deployed in the field in form of a corrosion management strategy, deployed completion design and surveillance plans to manage corrosion risks, extend well-life and ensure long-term WAGI reliability.
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)