Near-surface casing corrosion has been observed to occur on operating steam-assisted gravity drainage (SAGD) wells in the Surmont field. The corrosion issue could pose risks to containment assurance and have negative implications on well economics throughout the life cycle. This paper discusses how the corrosion was first identified and then successfully mitigated using a high temperature coating solution on the production casing. The methodology used for coating testing, evaluation, and selection is also discussed.
A two-tiered testing program was developed to qualify suitable coatings for the Surmont application. Eleven coating systems from various suppliers were first tested in the lab in a screening exercise to identify the best-in-class coatings for further evaluation. The top six performing coatings were then tested in the field environment to complete the evaluation. Coating performance was evaluated using a series of standard test methods.
Out of the eleven candidate coatings, only two coatings qualified for the high temperature application in Surmont. These coatings are expected to provide long-term corrosion protection of the production casing at an optimized cost. One of these two coatings was successfully applied on an operating well and has provided reliable corrosion protection after four years of service.
The methodology discussed in this paper for coating evaluation and application has been successfully implemented in the Surmont field. The findings from this work can be used to mitigate near-surface corrosion which will result in improved containment assurance and well economics.
Phi, Thai (University of Oklahoma) | Elgaddafi, Rida (University of Oklahoma) | Al Ramadan, Mustafa (University of Oklahoma) | Ahmed, Ramadan (King Fahd University of Petroleum & Minerals) | Teodoriu, Catalin (University of Oklahoma)
Most untapped promising energy resources in the world are associated with extreme downhole environment conditions. Applying the conventional method of well construction and operation for extreme downhole conditions poses severe challenges for the safety and longevity of the well. Governments and independent standardization organizations have developed several regulations regarding maintaining well integrity. Nevertheless, methods of completing and operating Extreme High-Pressure-High-Temperature (XHPHT) wells as well as geothermal wells have not yet been standardized. Preserving well integrity throughout the life cycle of a well is very crucial. Failure in well integrity can lead to huge operational and environmental risk and increase the energy cost.
This paper critically reviews the causes and solutions of well integrity issues in XHPHT and geothermal wells. After giving an overview of these wells, the paper discusses the well barriers at different ages. It also presents the conditions that lead to well integrity issues. Furthermore, the article discusses comprehensively the influence of acidic environment on cement and casing degradation at HPHT and summarizes the most recent research findings and development strategies in mitigating the integrity issues.
Previous studies revealed that the integrity of well barriers is highly affected by the degradation of drilling and completion fluids, cement, and tubular materials. The main causes of the well integrity loss are the lack of understanding of downhole conditions, inappropriate well construction practices, poor selection of the casing material and cementing type as well as inadequate design verification and validation on the downhole specimen. The well barriers are inter-related to each other as the destruction of one barrier may lead to the dismantling of the entire well barrier envelope. The XHPHT and geothermal wells share numerous similar barrier integrity issues, but they also have some unique problems due to the nature of their own operations. Although there is a significant advancement in solving the well integrity issues for the extreme downhole conditions, a sizable technology gap still exists in constructing and operating XHPHT and geothermal wells.
The current market conditions and the advancement in technologies are making the development of XHPHT wells more economically feasible. This paper serves as a review of the current research and development regarding well integrity issues for XHPHT and geothermal wells.
Li, Jiankuan (University of Alberta) | Sun, Chong (University of Alberta) | Roostaei, Morteza (RGL Reservoir Management Inc.) | Mahmoudi, Mahdi (RGL Reservoir Management Inc.) | Fattahpour, Vahidoddin (RGL Reservoir Management Inc.) | Zeng, Hongbo (University of Alberta) | Luo, Jing-Li (University of Alberta)
This study presents an investigation of the on-site corrosion of carbon steel pipes with stainless steel mesh screens in a steam flood well in the Athabasca oil sand reservoirs to determine the failure patterns and mechanisms. To mitigate the corrosion of carbon steel, several candidate materials were selected, and their corrosion resistance was investigated. In this work, the corrosion behavior and film characteristics of carbon steel pipes were studied by surface analysis techniques such as scanning electron microscopy, energy dispersive spetrocsopy and X-ray diffraction. Corrosion resistant alloys (proRSf and proRSc), anti-corrosion coating (proRA05a) and pretreated steel (proRAQa) were considered as alternative materials to carbon steel (proRAa and proRAb) and their corrosion protection performance in brine solution was evaluated by electrochemical methods such as potentiodynamic sweep and electrochemical impedance spectroscopy. Results show that severe erosion-corrosion occurred on inner wall of the pipes and caused significant wall-thinning of pipes along with localized corrosion damages, which is the dominant reason for base pipe failure. In spite of the slight corrosion on outer wall of the base pipe, severe localized corrosion appeared at the interface between the carbon steel pipe and stainless steel mesh screens due to the galvanic corrosion effect of dissimilar metals. The corrosion rates of the corrosion-resistant materials were two or three orders of magnitude lower than that of carbon steel.
During the lifetime of an oil/gas well, wellbore tubular structure might be subject to combined damage caused by both corrosion and mechanical wear. Therefore, it is necessary to conduct detailed stress analyses including these factors at the stage of tubular design.
An integrated well construction workflow was established for life-time well design. The temperatures and casing/tubing loads were obtained through numerical simulations of operations such drilling, stimulation, and production. All these simulations were accomplished using commercial software tools, including a thermal flow simulator and stress analyzer. On one hand, a commercial casing-wear simulator was used to predict the cumulative wear amount. On the other hand, a corrosion simulator was employed to predict pipe metal losses during each operation. The total amount of corrosion loss and mechanical loss were then compared against the maximum allowable wear for a safety check of the design.
The corrosion simulator was implemented in a computer program and integrated with the aforementioned commercial software of thermal flow and stress analysis. In a plot of maximum allowable wear versus depth, the curves of predicted wear, predicted corrosion, and predicted total metal loss are superimposed with the maximum allowable wear. This plot gives a straightforward and clear picture of the overall lifetime safety of the design.
A field case was studied with those integrated simulations. The production casing internal wear and internal/external corrosion were simulated. The predicted wear and corrosion data were in good agreement with the measured results. Further predictions provide rationales for future maintenance/workover operations.
Corrosion simulation and casing wear simulation were coupled with wellbore thermal flow analysis and stress analyses, helping proactively prevent tubular failure during the lifetime of the well. It is therefore valuable to include the integrated workflow during the wellbore tubular design where both corrosion and wear are involved.
The corrosion of carbon steel tubing, pipelines and process equipment during Oil and Gas production due to salt water saturated by corrosives gases, such as carbon dioxide and hydrogen sulphide, can lead to substantial environmental and economic consequences. A lot of different technics are used to reduce the corrosion in the pipelines: use of specific alloys, biocides or H2S scavenger. One of the proven and most widely used mitigation techniques is the addition of film-forming corrosion inhibitors into production streams. Those compounds have affinity with metals and will thus form a film at the surface of the metal, creating an electric resistance between the metal and the corrosive species. The products used offshore and released in the North Sea are currently controlled by OSPAR Convention requiring to meet environmental criteria on three different parameters: Biodegradability, Toxicity and Bioaccumulation. Passing 2 out of 3 criteria is enough to comply with the OSPAR Convention. This paper presents the performance results obtained with novel biodegradable compositions used as corrosion inhibitors for continuous injection with a thermal stability up to 135 C. A superior performance against sweet corrosion was obtained at 80 C in brines of different salinity, both in the presence and absence of a hydrocarbon phase. Additionally, new compositions exhibit low critical micelle concentrations and their structure can be further modified to adapt to various salinity conditions.
As part of their integrity management system, Oil and Gas operators carry out internal inspection of their pipelines by intelligent pigging. State of the art MFL and UT inspections are used to detect and accurately size the defects, which are present in the pipeline. The predominant type of defects reported is due to internal corrosion.
It is well established that corrosion is a naturally occurring phenomena. When the conditions are right for corrosion to develop, it starts by a single defect or very few defects which are shallow. Then as the pipeline is operated and corrosion further develops the defects increase in size and numbers.
This paper review several intelligent pigging reports data, and analyze the reported defects in terms of numbers and depth for several pipelines, in order to establish a correlation (mathematical model) between the number of internal corrosion defects and their depth. Defects counts will be made and equations will be developed for several pipelines. These equations will basically establish the number of defects as a function of their depth or vice versa.
More over when multiple intelligent pigging runs on same line are available, these derived equations will be compared with the objective to establish a novel model to determine corrosion growth rate in a non-conventional manner. In fact the models (# of defects and their depth equation) established for different inspections will be compared and a corrosion rate model establishing the increase in number of features and their number over time will be thereafter derived.
ADNOC Onshore is one of the leading Middle East Oil Operator has more than 60 Pipelines and 3000 Well casings. All buried structures are externally protected against soil-side corrosion with Coating and CP.
Corrosion and subsequent failure, particularly on pipelines/well casings is one of the main factors upsetting any upstream/downstream production facilities. Maintaining adequate level of CP system is always a challenge for corrosion engineers due to complex corrosion phenomena. Failure of these pipelines/well casings during production stage due to corrosion can be catastrophic with following consequences: Loss of life (fatality) Safety and Environment (Fire, Toxic gases and Oil Spill) Resource and downtime cost impact Damage to asset/company reputation.
Loss of life (fatality)
Safety and Environment (Fire, Toxic gases and Oil Spill)
Resource and downtime cost impact
Damage to asset/company reputation.
As per current industrial practice, the buried structures is designed to be protected externally by coating wherever possible along with ICCP system. However, the CP effectiveness often becomes challenging due to the CP interference caused by Ground beds and other structures since adequate separating distance cannot be maintained practically due to the field congestion.
This paper focuses on case study of a Ground bed in the vicinity of a buried pipeline, CP interference during CP effectiveness evaluation, Interference tests, crowding effect due to two or more deep anode bed systems operating in single rectifier, possible corrosion and damage mechanism and also strategy for remedial measures like ‘Shielding’ to nullify the Interference effect along with recommendations.
Wang, Da (China University of Petroleum, Beijing) | Feng, Fuyong (China Oilfield Services Limited) | Wang, Gui (China Oilfield Services Limited) | Lu, Yan (China Oilfield Services Limited) | Zhou, Fujian (China University of Petroleum, Beijing) | Yang, Guowei (China Oilfield Services Limited) | Gao, Jichao (China Oilfield Services Limited)
The 185°C formation temperature of BZ-22 Offshore Oilfield in China poses a great challenge to the treatment fluid selection and acidizing design just because of the high corrosion rate and the inefficient wormholing using conventional acid systems.
A deep penetration chelating acid is presented in this paper. In comparison with conventional acid, it has a much lower Cl-content, which is the main source of tubing pitting corrosion under high temperatures. In addition, it has a much lower corrosion rate to production tubing and a much lower reaction rate with formation rocks by forming a thin film over the rock and tubing surfaces. Very important, different from original chelating acid acidizing operations, a temperature dependent acidizing design has been proposed, in which the volumes of different types of acid, not only chelating acid, are calculated based on the temperature field software simulation. So that the traditional HCl slug can also be used in this high temperature formation after the formation is cooled down to the designed temperature to ensure efficient wormholing.
The operation has been carried out in 2018 for a pilot gas well. Before operation, the gas production rate was only 500m3/d with nearly 0 wellhead pressure, but after operation the production rate was as high as 55,000m3/d with 1,100psi wellhead pressure. The high production increase ratio shows that wormhole rather than face dissolution has been achieved and the near wellbore damage has been successfully removed. Besides, the downhole temperature monitoring data showed that the measured temperatures for different types of acid stages were in accord with the software simulation results.
Although this low Cl-content chelating acid and the temperature-control design method have been developed and used in China offshore oilfiled, it can be applied in other carbonate formations with high temperatures.
Ofori, Bruce Agyapong (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Al-Kamil, Ethar Hisham Khalil (University of Basrah)
Loss of well integrity in many horizontal wells in the United States has resulted in huge capital losses to several operating companies. The occurrence of corrosion in horizontal wells in the US is attributed to several reasons. The deposition of iron (Fe) and manganese (Mn) from manufactured steel pipe and the inability to effectively treat the laterals plays a major role in corrosion mitigation in horizontal wells. Corrosion inhibitors are injected into the wells to help reduce the corrosion rates, however the effectiveness of these injection applications is hampered by the types of well design and fluid dynamics. Loss of Fe/Mn in the lateral sections of the well is a major concern for the oil industry. This research will investigate the amounts of Fe/Mn contributions from the laterals and also investigate the relationship between iron and manganese counts from produced water from oil fields in the US. This research will further investigate the mean time to failure in the laterals and suggest proactive plans for mitigating failures based on findings.
High Fe/Mn concentrations could lead to corrosion in producing wells. High densities of Fe/Mn found in produced water analysis reports has been attributed to the abundance of these two elements used in manufactured steel pipe. These elements are used due to their abundance in manufactured steel pipe and their lack of natural presence in formation fluids. Fe and Mn have a known ratio in steel pipe of approximately 100:1 (depending on steel type). These high concentrations could ultimately compromise the wells integrity.
This research emphasizes the need for considering iron and manganese counts as integral part of the corrosion monitoring. Moreover, considering the long lateral casings, which spans several thousands of feet in the US, injection of corrosion inhibitors will be ineffective in reducing Fe and Mn loss in the lateral sections. Monitoring of Fe and Mn over such long laterals is challenging and costly. It has therefore become crucial for oil companies to thoroughly understand the Fe/Mn contribution from the laterals that could lead to corrosion and develop mitigation strategies to lower corrosion rates in such high-risk wells. This will help to implement remedial measures to better define corrosion rates and quantify the risk of failure. This will also enable oil companies allocate resources for further development and not several remediation efforts.
Despite the long service life of heat exchanger with minimum maintenance, more and more tube rupture due to corrosion in heat exchangers are observed and become one of the most common cause of failure in any type of production facilities. In the recent cases studied by the Wood CFD team, it appeared that the main reason of the failure came to a bad distribution of the flow either on the shell side or within the tubes entraining an increase of the tube wall temperature. Computational Fluid Dynamics (CFD) have been used in several occasion in order to determine the detailed flow pattern of the shell fluid especially around the inlet of the heat exchanger in order to identify areas of poor flow distribution. The increase of computing power and the reliability of the modelling approach have allowed to develop more accurate models which can help the engineers to understand the detailed phenomena happening in the heat exchangers. The regions with recirculation or low velocity identified by the CFD are often matching the region where tube wall thinning due to corrosion are observed. The CFD modelling is not only limited to the shell fluid but can be also coupled with simulation of the tube fluid and conjugate heat transfer within the tube walls. The CFD simulation of the complete vessel allows the corrosion engineer to fully understand the mechanism at the origin of the failure. Through several examples, the author will demonstrate how CFD simulations have been used to understand the root causes of the failure and help the corrosion engineer and the heat exchanger designer to improve the performance and prevent failures.