Qualification Testing of Mechanical Pipe Joining Method

2014 ◽  
Author(s):  
Dave McColl ◽  
Adam Whiting
Keyword(s):  
Oil And Gas ◽  
Cost Effective ◽  
Operating Conditions ◽  
Performance Criteria ◽  
Innovative Technology ◽  
Pipeline System ◽  
Internal Corrosion ◽  
Regulatory Standards ◽  
Cost Effective Method ◽  
Pipeline Failures

Pipeline infrastructure is the backbone of the energy industry and remains the safest and most cost effective method for transporting oil and gas. For decades corrosion has presented a significant challenge to pipeline operators. According to Alberta Energy Regulator data, internal corrosion is considered to be the root cause for more than 54% of all documented pipeline failures in Alberta [1]. Spoolable composite pipeline technologies have become a mainstream corrosion solution over the last 10 years, however these products are limited to smaller pipelines, typically less than 6 inches in diameter. Traditional slip-lining (field installed plastic lined steel pipe) is used for internal corrosion protection of larger pipelines, however it is costly, requiring labour intensive field construction, often completed in inhospitable environmental conditions. As a result project delays and cost over-runs are commonplace. Recognizing the need for a cost effective pipeline corrosion solution for larger gathering pipelines, an innovative technology was developed that combines a unique mechanical pipe joining system with an integrated electro-fusion coupler. The new joining system enables insertion of an HDPE liner in a factory environment where costs and quality can be tightly controlled. The new joining system eliminates conventional welding of the pipeline in the field and instead uses a custom field press to quickly energize the mechanical pipe joint. Field scope is significantly reduced, construction completed in less time, and associated costs greatly reduced. This paper discusses the testing completed to qualify the new joining system for use in oilfield gathering pipelines. The qualification test plan includes all requirements identified in applicable regulatory standards (primarily CSA Z662-11), and prudent engineering requirements based on anticipated field handling and anticipated operating conditions. The test regime was ultimately designed to ensure the suitability of the pipeline system for intended service. Testing included hydrostatic burst, static gas pressure, bend, cyclic pressure and thermal, vacuum, tensile, and compressive tests on the joint. The test results show that in all cases the jointing system successfully met the established design performance criteria and in most cases exceeded the actual mechanical properties of the parent pipe, thus proving the joining system ready for field installations.

Inhibitor Selection for Internal Corrosion Control of Pipelines

1998 ◽  
Author(s):  
S. Papavinasam ◽  
R. W. Revie
Keyword(s):  
Laboratory Experiments ◽  
Cost Effective ◽  
Operating Conditions ◽  
Future Application ◽  
Experimental Conditions ◽  
Performance Simulation ◽  
Internal Corrosion ◽  
Cost Effective Method ◽  
Selection For ◽  
User Friendly

Addition of inhibitors can provide a cost-effective method for controlling internal corrosion of pipelines. To select appropriate inhibitors and their concentrations, several laboratory experiments are usually performed. Test methodologies to evaluate inhibitors for a particular field should be carried out to simulate the conditions in the pipeline. Because several interacting parameters influence corrosion, and hence inhibitor performance, simulation of field operating conditions in the laboratory is often difficult. In this paper, user-friendly software to optimize the laboratory experimental conditions to simulate field operating conditions is discussed. The merits of the program in selecting commercial inhibitors and in designing cost-effective inhibitors for future application are described.

CAD Of Anticorrosive Protection Of Steel Structures

2019 ◽  
pp. 18-23
Keyword(s):  
Protective Coating ◽  
Computer Aided Design ◽  
Steel Structures ◽  
Cost Effective ◽  
Operating Conditions ◽  
Computational Tool ◽  
Protection Method ◽  
Cost Effective Method ◽  
The Cost ◽  
Aided Design

The choice of cost-effective method of anticorrosive protection of steel structures is an urgent and time consuming task, considering the significant number of protection ways, differing from each other in the complex of technological, physical, chemical and economic characteristics. To reduce the complexity of solving this problem, the author proposes a computational tool that can be considered as a subsystem of computer-aided design and used at the stage of variant and detailed design of steel structures. As a criterion of the effectiveness of the anti-corrosion protection method, the cost of the protective coating during the service life is accepted. The analysis of existing methods of steel protection against corrosion is performed, the possibility of their use for the protection of the most common steel structures is established, as well as the estimated period of effective operation of the coating. The developed computational tool makes it possible to choose the best method of protection of steel structures against corrosion, taking into account the operating conditions of the protected structure and the possibility of using a protective coating.

Effectiveness of Ultraviolet Light For Mitigating Risk of Microbiologically Influenced Corrosion in Steel Pipeline

2015 ◽  
Vol 74 (4) ◽  
Author(s):  
M. K. F. M. Ali ◽  
N. Md. Noor ◽  
N. Yahaya ◽  
A. A. Bakar ◽  
M. Ismail
Keyword(s):  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Microbiologically Influenced Corrosion ◽  
Metal Loss ◽  
Desulfovibrio Vulgaris ◽  
Pipeline System ◽  
Long Distance ◽  
Gas Industry ◽  
Internal Corrosion ◽  
Steel Pipeline

Pipelines play an extremely important role in the transportation of gases and liquids over long distance throughout the world. Internal corrosion due to microbiologically influenced corrosion (MIC) is one of the major integrity problems in oil and gas industry and is responsible for most of the internal corrosion in transportation pipelines. The presence of microorganisms such as sulfate reducing bacteria (SRB) in pipeline system has raised deep concern within the oil and gas industry. Biocide treatment and cathodic protection are commonly used to control MIC. However, the solution is too expensive and may create environmental problems by being too corrosive. Recently, Ultraviolet (UV) as one of the benign techniques to enhance mitigation of MIC risk in pipeline system has gained interest among researchers. An amount of 100 ml of modified Baar’s medium and 5 ml of Desulfovibrio vulgaris (strain 7577) seeds was grown in 125 ml anaerobic vials with carbon steel grade API 5L-X70 coupons at the optimum temperature of 37°C and pH 9.5 for fifteen days. This was then followed by exposing the medium to UV for one hour. Results from present study showed that UV radiation has the ability to disinfect bacteria, hence minimizing the risk of metal loss due to corrosion in steel pipeline. 

scholarly journals Evaluation of Property Methods for Modeling Direct-Supercritical CO2 Power Cycles

2017 ◽  
Vol 140 (1) ◽  
Author(s):  
Charles W. White ◽  
Nathan T. Weiland
Keyword(s):  
Power Plants ◽  
Physical Property ◽  
Aspen Plus ◽  
Cost Effective ◽  
Operating Conditions ◽  
Working Fluid ◽  
Power Cycles ◽  
As Species ◽  
Cost Effective Method ◽  
Open Nature

Direct supercritical carbon dioxide (sCO2) power cycles are an efficient and potentially cost-effective method of capturing CO2 from fossil-fueled power plants. These cycles combust natural gas or syngas with oxygen in a high pressure (200–300 bar), heavily diluted sCO2 environment. The cycle thermal efficiency is significantly impacted by the proximity of the operating conditions to the CO2 critical point (31 °C, 73.7 bar) as well as to the level of working fluid dilution by minor components, thus it is crucial to correctly model the appropriate thermophysical properties of these sCO2 mixtures. These properties are also important for determining how water is removed from the cycle and for accurate modeling of the heat exchange within the recuperator. This paper presents a quantitative evaluation of ten different property methods that can be used for modeling direct sCO2 cycles in Aspen Plus®. Reference fluid thermodynamic and transport properties (REFPROP) is used as the de facto standard for analyzing high-purity indirect sCO2 systems, however, the addition of impurities due to the open nature of the direct sCO2 cycle introduces uncertainty to the REFPROP predictions as well as species that REFPROP cannot model. Consequently, a series of comparative analyses were performed to identify the best physical property method for use in Aspen Plus® for direct-fired sCO2 cycles. These property methods are assessed against several mixture property measurements and offer a relative comparison to the accuracy obtained with REFPROP. The Lee–Kessler–Plocker equation of state (EOS) is recommended if REFPROP cannot be used.

Effect of Hydrocarbons on the Internal Corrosion of Oil and Gas Pipelines

CORROSION ◽  
2007 ◽  
Vol 63 (7) ◽  
pp. 704-712 ◽  
Author(s):  
S. Papavinasam ◽  
A. Doiron ◽  
T. Panneerselvam ◽  
R. W. Revie
Keyword(s):  
Oil And Gas ◽  
Operating Conditions ◽  
Gas Pipelines ◽  
Internal Corrosion ◽  
Oil In Water ◽  
Oil And Gas Pipelines ◽  
Water Wettability

Abstract Under certain conditions, hydrocarbons may alter the internal corrosion conditions of oil and gas pipelines. In this paper, the effects of hydrocarbons on corrosion have been predicted based on the type of emulsion (i.e., water-in-oil or oil-in-water), wettability (oil-wet, water-wet, or mixed-wet), and corrosiveness of brine in the presence of hydrocarbons. Laboratory methodologies have been developed to determine wettability and to identify the type of emulsion under pipeline operating conditions. Using these methodologies, the wettability and the type of emulsion have been determined for 14 hydrocarbons obtained from operating pipelines. The corrosiveness of brine in the presence of hydrocarbons also has been determined using rotating cage experiments.

Best Practices for the Design and Installation of Bolted Joints

2004 ◽  
Author(s):  
Debra Tetteh-Wayoe
Keyword(s):  
Best Practices ◽  
Oil And Gas ◽  
Cost Effective ◽  
Field Testing ◽  
Oil And Gas Industry ◽  
Bolted Joints ◽  
Pipeline System ◽  
Technical Literature ◽  
Operational Life ◽  
Welded Pipe

The cost effective design and construction of liquid pipeline facilities traditionally necessitates the use of bolted joints as opposed to welds. Some of these bolted joints are frequently disassembled and reassembled as part of regular maintenance, while others are assembled at the time of construction and expected to retain a seal for the lifetime of the pipeline. Consequently, the design and installation practices employed for bolted connections are relied upon to produce the same operational life and integrity as welded pipe. In an effort to ensure that the bolted joints used on our pipeline system are as reliable as our welded joints, we investigated industry best practices for flange assembly and the root causes of joint failure. We have completed extensive research of technical literature, including the torquing procedures used in various industries, and performed field-testing on our own system. Generally we have found that: • Flange assembly failures and concerns about this issue are common in the oil and gas industry; • Practices for tightening flanges are inconsistent; and • To accomplish and retain an effective gasket seal, and thus minimize life cycle leaks, one has to consider many factors, including the amount of torque applied to nuts, the stud and nut friction, the type of gasket used, the size of the studs/nuts/flanges, the type of equipment used for tightening, the calibration of the torquing equipment, flange face alignment, and torquing sequence. Using the results of our investigation, we implemented several measures to enhance both the quality and the long-term integrity of our bolted flange connections. This paper describes the results of our investigations, as well as the practices implemented for flange assemblies required for maintenance and new construction activities.

Value of Reliability, Availability and Maintainability (RAM) Simulation Models in Pipeline Systems

2016 ◽  
Author(s):  
Bradley M. Jones ◽  
André-Michel Ferrari
Keyword(s):  
Oil And Gas ◽  
Block Diagram ◽  
Discrete Event ◽  
Simulation Models ◽  
Cost Effective ◽  
Business Environment ◽  
Pipeline System ◽  
Throughput Optimization ◽  
Design Standards ◽  
Cost Avoidance

Reliability, Availability and Maintainability (RAM) models were first developed in Enbridge Liquids Pipelines in 2006 and in the last 3 years have contributed over $200 Million in capital cost avoidance while maintaining or improving the reliable design and operation of the pipeline system. These models constitute a very effective, factual and dependable tool to assess the throughput performance of a pipeline system over its entire life cycle or a specified time of interest. In addition, the RAM model cost is a small fraction of the overall monetary benefit, in the order of 1%, hence making RAM models a highly leveraged activity. The concept of a RAM model stems from Reliability Block Diagram methods (also known as Dependent Diagrams). Interaction of large, complex and multi layered systems can then be analyzed using the Monte Carlo simulation methods (or Stochastic Discrete Event Simulation) hence quantifying the output of the entire system with greater accuracy than other estimating tools or methods. Over 10 years, Enbridge Liquids Pipelines has developed its own failure database for equipment and operational events consequently almost all model inputs are based on in-house data rather than industry generic data, making the model output more robust, accurate and appropriate for internal use. Initially, in Enbridge Liquids Pipelines, RAM models were mainly built to assess and confirm the design capabilities of future pipelines designs and assist in the optimal selection of specific design options. Because of the effectiveness of the tool combined with the current cost constrained business environment, the company is moving towards building RAM models for assets already in operation in order to optimize their performance. This is proving to be an extremely cost effective addition to internal decision making processes. The approach has been used in risk based budgeting, asset maintenance, design modifications and throughput optimization initiatives. In various industries including Oil and Gas, RAM models have proven their worth over time as an effective cost avoidance tool. This approach has now been successfully deployed in the Pipeline Industry at Enbridge. As an example, a RAM model conducted during the design phase of a pipeline project saved $28 million in capital by proving that an additional storage tank and significant new infrastructure was not required. Another benefit of RAM models has been their ability to confirm or counter stated assumptions by internal stakeholders. Equipment upgrades and equipment sparing decisions are often seriously debated and costly decisions may not always be based on complete economical foundations but rather on avoiding past negative experiences or by following basic guidelines that are less than optimal. When a project or operational team needs to find an alternative, a RAM model is a tool of choice to evaluate, and justify the best option. Because of its proven value, RAM models are now an integral part of Enbridge Liquids Pipelines Design Standards and are used on all large projects. Models recently built for operational pipelines delivered similar value so in the near future the work will be expanded to encompass the entire existing network of integrated pipelines to improve on performance and operational costs.

Production Tubing Leak Repair Using Reinforced Thermoplastic Pipe

2021 ◽  
Author(s):  
Olalere Sunday Oloruntobi ◽  
Prasanna Kumar Chandran ◽  
M Azuan Abu Bakar ◽  
Nurul Nazmin Zulkarnain ◽  
Hasrizal A Rahman ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Cost Savings ◽  
Cost Effective ◽  
Internal Diameter ◽  
Hydrocarbon Recovery ◽  
Coiled Tubing ◽  
Well Integrity ◽  
Cost Effective Method ◽  
Integrity Management ◽  
Corrosive Environments

Abstract Operators are faced with never-ending well integrity issues relating to tubing leaks. This situation is particularly important in oil and gas wells that are producing in corrosive environments. When a well can no longer be safely produced due to well integrity issues relating to tubing leaks, an expensive workover is often performed to restore the tubing integrity. To improve the economics of a well intervention involving tubing leak repairs, a new cost-effective method is being proposed. The novel technology involves the installation of reinforced thermoplastic pipe (RTP) inside the existing tubing to isolate multiple leaks using a coiled tubing unit or an E-line. The RTP is engineered for downhole applications with custom designed connectors and accessories. It is designed to handle corrosive fluids (CO2 and H2S) and prevent downhole erosion caused by sand production. The RTP can be used to eliminate tubing – annulus communication in both producers and injectors with full compliance to well integrity management system. The results of the field trial in a gas injector well in Malaysia basin show that the RTP can provide a reliable means of restoring and enhancing the production of oil and gas with considerable cost savings (up to 80% cost reduction when compared to a conventional workover). In most cases, the high cost associated with a conventional workover can make it uneconomical when compared to the expected hydrocarbon recovery from the well, resulting in production deferment (well shut-in). The RTP can significantly increase the viability of repairing a larger percentage of the wells that are shut-in due to the loss of tubing integrity when the hydrocarbon recovery from the well is insufficient to justify a full workover. The significant cost savings provided by the RTP would dramatically improve economics and would likely result in more reserves recovered. The RTP also has a smoother surface that contributes to minimum friction and reduces the risk of scales formation when compared to the steel tubing of the same internal diameter.

Self Directed Integrity Assessment of Non-Piggable Pipelines

2015 ◽  
Author(s):  
Ashish Khera ◽  
Rajesh Uprety ◽  
Bidyut B. Baniah
Keyword(s):  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Management Plan ◽  
Gas Industry ◽  
Internal Corrosion ◽  
Integrity Assessment ◽  
Regulatory Standards ◽  
The Us ◽  
Integrity Management ◽  
External Corrosion

The responsibility for managing an asset safely, efficiently and to optimize productivity lies solely with the pipeline operators. To achieve these objectives, operators are implementing comprehensive pipeline integrity management programs. These programs may be driven by a country’s pipeline regulator or in many cases may be “self-directed” by the pipeline operator especially in countries where pipeline regulators do not exist. A critical aspect of an operator’s Integrity Management Plan (IMP) is to evaluate the history, limitations and the key threats for each pipeline and accordingly select the most appropriate integrity tool. The guidelines for assessing piggable lines has been well documented but until recently there was not much awareness for assessment of non-piggable pipelines. A lot of these non-piggable pipelines transverse through high consequence areas and usually minimal historic records are available for these lines. To add to the risk factor, usually these lines also lack any baseline assessment. The US regulators, that is Office of Pipeline Safety had recognized the need for establishment of codes and standards for integrity assessment of all pipelines more than a decade ago. This led to comprehensive mandatory rules, standards and codes for the US pipeline operators to follow regardless of the line being piggable or non-piggable. In India the story has been a bit different. In the past few years, our governing body for development of self-regulatory standards for the Indian oil and gas industry that is Oil Industry Safety Directorate (OISD) recognized a need for development of a standard specifically for integrity assessment of non-piggable pipelines. The standard was formalized and accepted by the Indian Ministry of Petroleum in September 2013 as OISD 233. OISD 233 standard is based on assessing the time dependent threats of External Corrosion (EC) and Internal Corrosion (IC) through applying the non-intrusive techniques of “Direct Assessment”. The four-step, iterative DA (ECDA, ICDA and SCCDA) process requires the integration of data from available line histories, multiple indirect field surveys, direct examination and the subsequent post assessment of the documented results. This paper presents the case study where the Indian pipeline operators took a self-initiative and implemented DA programs for prioritizing the integrity assessment of their most critical non-piggable pipelines even before the OISD 233 standard was established. The paper also looks into the relevance of the standard to the events and other case studies following the release of OISD 233.

Predicting Corrosion Rates for Onshore Oil and Gas Pipelines

2006 ◽  
Author(s):  
J. M. Race ◽  
S. J. Dawson ◽  
L. Stanley ◽  
S. Kariyawasam
Keyword(s):  
Corrosion Rate ◽  
Growth Rates ◽  
Oil And Gas ◽  
Cost Effective ◽  
Management Plan ◽  
Assessment Method ◽  
Internal Corrosion ◽  
Corrosion Rates ◽  
External Corrosion ◽  
Comparison Of The Results

One of the requirements of a comprehensive pipeline Integrity Management Plan (IMP) is the establishment of safe and cost effective re-assessment intervals for the chosen assessment method, either Direct Assessment (DA), In-Line Inspection (ILI) or hydrotesting. For pipelines where the major threat is external or internal corrosion, the determination of an appropriate re-inspection interval requires the estimation of realistic corrosion growth rates. The Office of Pipeline Safety (OPS 2005) estimate that the ability to accurately estimate corrosion rates may save pipeline companies more than $100M/year through reduced maintenance and accident avoidance costs. Unlike internal corrosion, which occurs in a closed system, the rate of the external corrosion reaction is influenced by a number of factors including the water content of the soil, the soluble salts present, the pH of the corrosion environment and the degree of oxygenation. Therefore the prediction of external rates is complex and there is currently no method for estimating corrosion rates using either empirical or mechanistic equations. This paper describes a scoring model that has been developed to estimate external corrosion growth rates for pipelines where rates cannot be estimated using more conventional methods i.e., from repeat in-line inspection data. The model considers the effect of the different variables that contribute to external corrosion and ranks them according to their effect on corrosion growth rate to produce a corrosion rate score. The resulting score is then linked to a corrosion rate database to obtain an estimated corrosion rate. The methodology has been validated by linking the calculated corrosion rate scores to known corrosion rate distributions that have been measured by comparison of the results from multiple in-line inspection runs. The paper goes on to illustrate how the estimated corrosion rates can be used for the establishment of reassessment intervals for DA, ILI and hydrotesting, comparing the benefits of this approach with current industry recommended practice and guidance.

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