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Alternatives to 28% Chrome for Production Tubing in Super-Giant Mediterranean Deep Water Gas Field, Zohr Field, Eni–Petrobel
Ibrahim, OMAR Yehya Abou Elseoud (Petrobel) | Gabr, Waleed (Petrobel) | Kortam, Mostafa Mahmoud (Petrobel) | Abdelrahman, Mahmoud (Petrobel) | Moawed, Mahmoud (Petrobel) | Elmasry, Hossam (Petrobel)
Abstract Zohr field was discovered in 2015 by the Italian energy company Eni and is the largest ever natural gas found in the Mediterranean Sea, with around (30 trillion cubic feet) total gas in place. Belaim Petroleum Company (Petrobel) (JV with ENI) is the Egyptian Petroleum Corporation arm and the owner of the project. Production started in December 2017 and since then 18 wells have been drilled for production. This paper describes the criteria for material selection of the production strings for Zohr’s deep-water gas producers and how pre-tested and approved cost-effective alternatives are available for such a top-class project. The paper details the qualification and deployment of glass reinforced polymer (GRP) Lined Tubing as an alternative to 28%Chrome tubing, including the testing work that has been performed, and the operational aspects of running the referred-to alternative in several deep-water projects. The choice of Duoline lined tubing results from the need for a cost-effective solution delivering the same operational requirements of 28% Chrome production strings. And since the Duoline GRE system will be integrated with the steel tubing therefore this system has to be previously fully approved and certified by the manufacturing mill of the lined tubing so there would be not even minor modifications to the specifications and the sealing performance of the premium connections and tubing body. The paper indulges into describing the laboratory tests and the field experiences of the Duoline Lined tubing system in various fields globally, where this system has been tested in severe operating conditions with elevated levels of H2S, CO2, Salinity, dissolved Oxygen conditions to investigate the capability and service limits of the fiberglass liner at different temperatures. In addition to mentioning the erosion tests that were performed, mechanical tests such as pressure loop and make & break tests, how these various tests ended with good results and its comparison to the exotic high chrome joints performance. This fiberglass lined tubing system has been applied in gas production wells since the 1980s, and ENI has been utilizing this technology in their production and water wells since 2005 in the north Africa, middle east, Kashagan regions and Norway offshore wells. On the other side, the technology has been successfully used world-wide in more than 55,000 wells since 1960s in various applications besides gas production strings. The paper will present the past experience of ENI with fiberglass lined tubing, the laboratory tests, the field experiences, the economic evaluation of implementing this system in such a high-profile project, In addition to the pre-qualifications performed on this system by the OCTG mills and approvals granted to integrate this technology with the patent premium connection joints.
- Africa > Middle East > Egypt > Mediterranean Sea > Levantine Basin > Shorouk Concession > Shorouk Block > Zohr Field > Abu Madi Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Egypt Field (0.97)
Abstract Tubular GRE lining technology has been globally applied used since 1960's in eliminating downhole tubular corrosion, replacing the elevated CAPEX of CRA OCTG and assuring steady oil, gas and water flow through the downhole string with its flow assurance benefits. Compared to conventional carbon steel whose failures are frequent, the GRE lined carbon steel provides long lasting protection which results in huge savings in life cycle cost. Likewise, compared to CRA material capable of withstanding corrosion issues, the GRE lined CS provides direct capital cost savings. Apart from the economic benefits, operators deploying GRE lined CS have enjoyed superior well integrity over the life cycle of the well. Abu Dhabi National Oil Company (ADNOC ONSHORE) implemented this technology in 2013 for the water disposal wells (5 wells as trial, all of them were successful). We will share the results of the caliper logs that have been run into these wells and the inspection of tubing pulled out of the disposal wells after 4 years in service. Following the assessment, which was satisfactory, the first Water Injection well with GRE lined tubing has been RIH in 2021, and plans for Oil producers with GRE lined tubing in Q2-2023. Till the time of writing this paper, 19 GRE lined strings have been RIH in Aon's water disposal wells, and 2 strings have been run in water injection wells (under study and field test and assessment). This paper shares the evolution of this technology within the Aon from the first installation to the development of a contract and how Aon geared to absorb this technology in their system. Some of the challenges that faced the company were: The modifications that were required to the wells’ designs. How the service provider was aware of Aon's operational well intervention jobs. How this is compatible with the lining system.
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > UAE Government (0.56)
- 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)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
- (2 more...)
Experience with Fiberglass GRE Lined Carbon Steel Tubular for Corrosion Protection for Oil Production Applications
Sharif, Qamar J. (Saudi Aramco) | Esmail, Omar J. (Saudi Aramco(Retired)) | Radhakrishnan, Gokulnath (Maxtube Limited) | Simpson, John A. (Maxtube Limited) | Bremner, Martin R. (Maxtube Limited)
Abstract Saudi Aramco experienced serious corrosion problems in oil production tubing in one offshore field, attributed to presence of H2S, CO2 and varying levels of water cut. In early 2002, the company installed on trial test basis Glass Reinforced Epoxy (GRE) or commonly known as fiberglass lined carbon steel tubing in three wells. The fiberglass lining was installed to provide a corrosion barrier to protect the steel tubing from internal corrosion. As far the technology, the fiberglass lining or sleeve is carried out joint by joint by inserting a solid fiberglass tube into the low cost carbon steel tubing and cement is pumped into the narrow annulus between the fiberglass liner and the carbon steel tubing. The connection area is protected by the combination of end flares and a corrosion barrier ring. The company examined various methods to evaluate the performance of the fiberglass lined tubing, without having to pull out the tubing from the well as these wells are oil producers. After review of the evaluation options, it was decided to run a multi finger caliper to evaluate the condition of the fiberglass lining and check for any internal corrosion in the steel tubing. The log showed the fiberglass lining to be in good condition with no damage indicating that the steel tubing was protected from corrosion. The other two wells had no tubing leaks indicating the GRE lining is providing corrosion protection. Based on successful trial test results, the company adopted the technology to protect tubing strings deployed in corrosive environments in oil producers, water injectors and water supply wells. Field experience has shown that the use of fiberglass lined tubing is a low "life cycle cost" solution compared to other options. There has been no workover in these wells since installation. Today fiberglass lined tubing is applied in Saudi Aramco in high water cut oil producers, water injectors and combined water source and injection wells. The paper shares the history of corrosion, challenges and lessons learned during the implementation of the solution, various performance assessment methods evaluated and the results and interpretation of the caliper log.
- North America > United States (1.00)
- Asia > Middle East > Saudi Arabia (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.96)
Flow Assurance in High-Pressure Water Injection Flowlines using GRE Composite Lined API 5CT Threaded and Coupled Tubing
Abdel-Aleem, Mohamed Ibrahim (Petroleum Company Shell Egypt J/V) | Abdel-Mottleb, Mohamed Kamal (Petroleum Company Shell Egypt J/V) | Mohamed, Mohamed Sobhy (Petroleum Company Shell Egypt J/V) | El-Dardiery, Mahmoud Mohamed (Petroleum Company Shell Egypt J/V) | El-Din, Reda Aly (Petroleum Company Shell Egypt J/V) | Radhakrishnan, Gokulnath (Maxtube Limited) | Youssef, Etman (Maxtube Limited) | Fernandes, Alwyn (Maxtube Limited) | Khouly, Amr Al (Maxtube Limited)
Abstract In a first ever case within Shell assets worldwide, Badr Petroleum Company (Bapetco) - a Shell Joint Venture Company in Egypt, has embarked on a project of replacing a 20 km Water Injection network, originally constructed with Welded API 5L carbon steel pipe, with fiberglass lined API 5CT Threaded and Coupled tubing. The original network is a conventional pipeline system of welded pipes transferring brine from 3 Water Source wells to 23 Water Injectors through the Egyptian Western Desert. The water is of a high salinity of 180,000 ppm saturated with dissolved oxygen up to 1,000 ppb before chemical treatment. After injecting oxygen scavenger the concentration of the dissolved oxygen is 100 ppb. As a result, Bapetco has been facing severe corrosion related failures in Water Injection flowlines. The 20 km surface pipeline network had to be totally replaced approximately once every two years. Many of the Water Source and Water Injection wells in this network were completed using GRE lined tubing for internal corrosion protection. However, corrosion by-products from the carbon steel flowline were a cause for concern given the risk of plugging the reservoir. Basic remedial solutions such as clamps, chemical inhibitions, patches etc. were carried out on the flowline. Nevertheless a more manageable approach was sought especially after reviewing the life cycle costs of maintaining the network and the impact of frequent drops in injection rates on the overall production from the field. Bapetco embarked on an ambitious plan to use API 5CT Threaded and Coupled Steel Tubing internally lined with fiberglass for corrosion protection to replace the bare Carbon Steel pipeline. Shell's confidence in GRE lining has been established over 20 years of using GRE lined tubing downhole in 11 countries. This endeavor also helps Bapetco utilize unused inventory of tubing instead of additional capex required for flowline replacement with API 5L pipes manufactured from more exotic steel. The integration of API 5CT specification threaded and coupled tubulars into Pipeline Engineering design, considering flow dynamics and make up compatibility with standard valves and fittings, is a huge challenge given the lack of applicable design codes, standards and Engineering common ground. Special components were engineered to provide a transition between GRE lined tubulars and plain end unlined fittings and flanges. Also, pressure testing, pigging and connection make-up procedures were reviewed and/or revised to accommodate the use of GRE lined API 5CT pipes in flowlines. This paper chronicles the history of the Water Flood project, the nature, reasons and consequences of the multiple corrosion failures and the failed corrosion mitigation strategies. Furthermore, the paper will shed light on the techno-commercial analysis and engineering that forms the basis for this mammoth effort.
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- (2 more...)
Abstract This paper is a two-part discussion describing Glass Reinforced Epoxy composite linings manufactured and installed in oilfield tubular goods where the material functions as a barrier to corrosion. The paper first focuses on GRE composites in terms of effectiveness and product life compared with less-costly corrosion solutions (such as internal plastic coatings (IPC) and thermoplastic materials like HDPE and PVC). Next, actual case history economic data is presented to qualify the use of Glass Reinforced Epoxy-lined tubular goods over IPC for corrosive seawater injection service in the North Sea. These data are then extrapolated to construct a similar economic model based on workover costs in the Permian basin of West Texas. Additionally, net present value (NPV) analysis can be used to illustrate the saving s in long term operating costs over the life of the project. Introduction Though used extensively worldwide, GRE composite-lined tubular goods have demonstrated an especially wide acceptance in the Permian Basin of West Texas and eastern New Mexico as injection tubing for secondary and tertiary recovery of oil where injected formation water and CO2 combine to form some of the world's most corrosive downhole environments. This acceptance is a direct function of the material's durability and long product life. Although GRE-lined tubular goods are most commonly used in corrosive service where the downhole temperature is below 300° Fahrenheit, novel manufacturing techniques have enabled tolerance of higher temperatures and generally harsher environments. This ultimately provides the end user a lower cost alternative to expensive steel alloys and opens up new opportunities in corrosive gas production and gas-lifted oil production where previously chromium-nickel alloys have been the exclusive choices. The new generation of GRE-lined tubular products can now be reasonably utilized in deep gas production and corrosive high-temperature injection on land and in offshore environments. A major North Sea operator qualified GRE linings over internal plastic coating for seawater injection. This qualification was premised on favorable workover economics made possible by the increased product life of GRE as opposed to that of IPC. Use of GRE-lined injection tubing resulted in substantial savings of funds that would have been spent for high-cost workovers and material replacement costs. When Net Present Value (NPV) of these savings are compared to the higher capital expense to specify the premium material (vs. selection of the less durable, lower costing material) the fundamentals of this model are born out in all environments. The Cost of Corrosion The impact of corrosion throughout nearly every industry in business today is devastating. NACE estimates that $300 Billion per year is subtracted from U.S. industrial operations alone. About $150 Billion of these costs can be prevented by various forms of corrosion engineering and project planning (1). It is estimated that tubular corrosion by itself costs the oil and gas industry billions of dollars per year. Kermani and Harrop define the cost of corrosion to the oil and gas industry in terms of capital expenditure and operating expenditure and also point out the costs to HSE (Health, Safety and Environment) relative to oilfield corrosion (2). Four cost categories are identified as follows:The cost of designing corrosion control into the project (Capex). For example, costs in this category are incurred where specialty metals and materials are purchased to avoid corrosion. The premium paid for GRE lining would fall into this category. The cost of maintaining and repairing corrosion-damaged equipment (Opex). The recurring costs of chemical maintenance or the occasional workover unit operation costs are examples of operating expense incurred due to corrosion.
- North America > United States > Texas (1.00)
- Europe (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.93)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Thompson Field (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (22 more...)