Mexico’s Energy Reform has opened up various interesting and unique opportunities for energy infrastructure. A CO 2 pipeline project that was recently completed in southern Mexico provides a perfect example of how to breathe new life to deteriorated pipeline infrastructure — infrastructure that would have typically been written off. By coupling a unique pipeline inspection method with a novel lining system, two 28-kilometer (17 mile) pipelines were rehabilitated in record time and in a cost-effective manner. The project consisted of two 12 and 18-inch (300 and 450 millimeters) CO 2 transport pipelines that had been out of service for 22 years and that are a central component for a high-profile fertilizer project. Replacing these deteriorated assets with a new transport pipeline was not an option due to time, environmental, permitting and budgetary constraints. The rehabilitated system had to offer a minimum 25-year service life required by the owner. To put this aging infrastructure back into service, it was essential to assess the condition of the pipelines with a high level of accuracy and precision which would allow for the rehabilitation of the pipeline and installation of an interactive liner to extend the system’s serviceable life for a minimum of 25 years. The challenge, however, was that these pipelines were non-piggable by traditional methods. By using a tethered MFL and Caliper ILI solution, the pipelines were each inspected in 13 separate sections with the level of detail necessary to assess the condition and suitability of the rehabilitation strategy selected for the project. Fast-track scheduling constraints required 24-hour data analysis turnaround of reports identifying and discriminating areas of modest and significant corrosion as well as deformations including areas of significant weld slag which could complicate the installation of the liners. Once high-quality data was available, pinpoint repairs were possible with a combination of carbon fiber reinforcement and steel pipe replacement. Afterwards, the pipelines were internally lined with a patented process that effectively provides a double containment system. A grooved liner and the host steel pipe create an annular space that is pressurized with air and remotely monitored. The system is able to detect even a small pressure drop in the annulus that would occur in case the integrity is breached, or a pinhole develops in the steel pipe. With the grooved liner, external repairs can be conducted while the line continues to operate without interrupting CO 2 service to the plant. By applying these novel solutions, the rehabilitated pipelines will transport carbon dioxide to a revitalized fertilizer plant in a safe and efficient manner for the next 25 years.

Flowline thermal insulation is essential for deepwater field development when long distance subsea tieback is required. Proper flowline insulation design can prevent hydrate and wax formation during production, as well as provide sufficient time, in the event of an unplanned well shut-in, for resuming production before the product temperature drops below the critical temperatures. Although many insulated flowline configurations, (i.e., insulated pipe-in-pipe and insulated multi-flowline bundle) have been installed, insulation designs are usually based on insulation material technical data obtained at standard conditions. Few publications are available on the effects of insulation material aging, operation temperature, and environmental pressure (in the case of a pressurized annulus of pipe-in-pipe or bundle) on the flowline insulation performance. In this paper, such effects on the thermal insulation properties of an insulated flowline, in both steady state and cool down conditions, are discussed. Insulation material thermal conductivity test data are presented at various pressures, temperatures, and aging effects (duration between manufacture and test). The test data are applied to typical flowline insulation designs and comparisons made with cases when these effects are neglected. Based on the test and analysis results, recommendations are made for insulated flowline designs.

The oil and gas pipelines are spread around the world in all nations as complex networks. The increased usage of gas is rapidly increasing this network. These networks are generally made from various diameters of pipes. The pipelines are serviced on as required basis, using pig launcher and receivers to suit the pipe diameter. Pigs of different types may be launched in different sequences, to clean the pipes and to obtain various data related to pipe condition and location. The pig launching and receiving process uses rapid pressure changes in the launcher and receiver and some magnitude of impact may be experienced by the unit. This process also requires frequent access to the launcher/receiver unit. To have an efficient and cost effective usage of the launcher/receiver unit, it is essential to have a door mechanism, which is safe, robust, capable of the above loading conditions, requires minimum service and is easy to use. PECO has recently developed & designed a door, which incorporates ail the above requirements. The door was put to high pressure testing and the test results were so encouraging that PECO named it SafeLock ® Closure. The design was developed with gas pipelines in mind. However it is equally applicable to vessels, exchangers and other metal openings where quick, frequent and easy access is required. Safety has been the prime concern through out the design and development process of this closure. Therefore the final product has resulted in a very safe closure. The initial design of the SafeLock ® door / closure used a spring load to make it easy in operation. This was removed in the later design. The segmental blocks, usually called C-ring segments, are operated to move in and out of the shell-sub annulus. The closure opening and closing is performed by the use of a single lever arm. This way only one person can operate (open and close) the door / closure. For opening and closing, the lever-arm needs to be rotated less than 40 degree angle. The rotation direction of the lever arm in closing is reverse of that in opening. The door / head can be fully retrieved from the shell-sub and rest by the side of the launcher/receiver to provide complete access to the opening. This door / closure provides quick access to launcher / receiver, pig traps, meter provers, filter vessel, scrubber, scraper, manway to pressure vessel, etc. This closure can be mounted in the vertical or horizontal position. During change of filter elements, launching a pig, quick access to container under pressure, this closure door is designed to provide a safe and fast service. The construction, operation, design details and application of the new closure door are included in this paper and explained with the help of the design diagrams and photographs.

The corroding conditions of a cased carrier pipe segment are difficult to measure in the field. It is hard to know whether or how well the cased pipe segment is cathodically protected. The pipeline industry needs a tool that can predict the in-situ corrosion potential of the carrier pipe in the casing annulus in order to determine the level of cathodic protection (CP). This work reports on a large-scale, three-dimensional computer model developed to make such a prediction. The casing wall may be treated as bare or coated on both or either of the external and internal surfaces. The carrier pipe is coated, and the coating quality inside the annulus may or may not be the same as the outside of the casing segment. The casing annulus is full of electrolytes. The model is used to investigate the effect of several factors on the level of CP imposed on the carrier pipe in the annulus, including the coating quality on the carrier pipe, the casing wall native potentials (both external and internal), the presence of a coating on a casing wall surface, and a metallic contact (between the casing and the carrier pipe) with the contact resistance being a variable. The effect of the voltage variation inside the pipe metal wall is also investigated.

For more than half a century, cased crossings have been used to support oil and gas steel pipes for crossing highways, railways, or rivers. Leaks or ruptures of cased crossings have occurred that resulted in casualties and property damage. Unlike uncased pipes buried in soils, which can be assessed for external corrosion directly and indirectly, the presence of a steel casing wall makes it challenging, even if possible, to conduct these assessments. The effect of the casing wall on the external corrosion of the carrier pipe inside the annulus is not well understood; it is unclear what tools can be used to effectively inspect the cased pipes. Empirical experience from the pipeline industry has shown that a few tools can be used to detect the contact status between a casing and the carrier pipe, which can help assess the severity of the carrier pipe external corrosion. Unfortunately, the criteria used to detect a contact status vary by user for the same tool and thus, the effectiveness of these criteria is uncertain. This paper reports results from a recent study aimed at evaluating the effectiveness of AC current attenuation, AC voltage gradient, and close interval (potential) survey as tools for detecting the contact status between a casing and the carrier pipe.

Full encirclement repair sleeves with fillet-welded ends are used as a permanent repair on pipelines to reinforce areas with defects such as cracks or corrosion which may penetrate the pipe wall subsequent to the installation of the repair. CSA standards require that these sleeves be tapped to relieve the stress field surrounding the defect unless an engineering assessment indicates that the defect will not extend beyond the ends of the sleeve during future operation of the pipeline. This paper describes an engineering assessment recently completed to establish the relative performance of a sleeved pipe with and without a pressurized annulus. Finite element analysis (FEA) was used to relate changes in stresses in the weld region to internal pressure fluctuations. The FEA included an estimate of the effects of circumferential fillet weld shrinkage on local stiffness due to residual stress fields. Relationships between stress and internal pressure were used to convert the line pressure history to local weld stress fluctuations. This stress history was then used to assess the potential for fatigue crack propagation of possible circumferentially-oriented weld flaws using a fatigue crack growth algorithm. The results showed that the highest stresses were developed in the weld toe and root regions. The operating conditions of the line, as well as the pipe and sleeve dimensions, were considered when making recommendations concerning sleeve tapping.

In producing offshore oil and gas fields there is a need for maintaining flow assurance in the associated pipelines. Restricted and plugged pipelines result in loss of production which is loss of revenue. It is common for these pipelines to exceed the length that can be reached by conventional coiled tubing when cleaning obstructions becomes necessary. Paraffin, asphaltine’s, hydrates and sand are a few of the contaminants that can obstruct flow and cause plugging. Historically, pipeline intervention has been limited to conventional coiled tubing with a reach of only +/−5,000’. A typical maintenance practice involved “pigging” the pipeline with a poly foam pig to remove any obstruction. Under severe conditions multiple pigs with graduated ODs were used. The problem with the poly foam pig is that the flexibility allows it to be forced through a smaller ID, leaving the restriction in place. CoilTAC ® (Coil Thrust and Carry), developed by Superior Energy Services, was designed specifically to extend the reach of conventional coiled tubing for pipeline intervention while negotiating a minimum 5D bend. The Thruster was designed for line sizes with internal diameters from 2.900” up. This Thruster system eliminates the compression force on the coiled tubing and has been proven to 14,800’, and it has the ability to exceed 50,000’. The Thruster utilizes a “mechanical intelligence” which is present into the thruster with takes into consideration applied force parameters prior to the cleanout procedure. The key factors are: working pressure of the pipeline, length of the pipeline and the length and size of the coiled tubing to be carried by the thruster. The forward motion of the thruster is initiated by annular pressure applied between the coiled tubing and the inside diameter of the pipeline. The pressure energizes the cups and moves the thruster forward. At a preset pressure, a check value opens inside the thruster allowing fluid to pass to the front of the tool and exit through a series of ports. This causes a washing/jetting action in front of the thruster as it moves down the pipeline. The debris that is removed from the pipeline is returned through the center of the thruster. Retrieving the thruster is accomplished by pumping down the center of the coiled tubing which applies pressure to the front of the tool to reverse the Thruster out of the pipeline. The returns during reverse thrusting are then taken on the coiled tubing/pipeline annulus. Pump pressure moves the thruster in and out of the pipeline not the coiled tubing injector, thus eliminating the helical buckling forces and extending the reach of the coiled tubing. Historically, paraffin-laden pipelines had to be abandoned and new lines laid at great expense to the operator — it was difficult to abandon subsea pipelines without complete removal. Now there is an option with the CoilTAC ® system.

Full encirclement repair sleeves with fillet-welded ends are often used as permanent repairs on pipelines to reinforce areas with defects, such as cracks or corrosion. In-service failures have occurred at reinforcing sleeves as a result of defects associated with the sleeve welds, such as hydrogen-induced cracks and undercut at the fillet welds, inadequate weld size, and sleeve longitudinal seam ruptures. This work was undertaken to support the development of tools for sleeve design and for conducting an engineering assessment to determine the tolerable dimensions of flaw indications at full encirclement repair sleeves. In particular, the project was intended to validate the stresses estimated using finite element analysis (FEA) models against actual in-service loading conditions experienced at reinforcing sleeves. The experimental work focused on the collection of full-scale experimental data describing pipe and sleeve strains for the following field and laboratory conditions: • Strains induced by sleeve welding, • Strains induced by pressurization of the sleeved pipe, • Strains induced by pressurization of the sleeved pipe and the annulus between the pipe and sleeve. Finite element models of the field and laboratory sleeved pipe segments were developed and subjected to the same applied loading conditions as the full-scale sleeved pipe segments. Comparisons of the measured strains against those estimated using FEA were completed to determine the ability of the models to predict the behaviour of the sleeved pipe segments. Comparisons were made to illustrate the relative strain levels and deformation trends, the accuracies of the strain predictions and trends in changes with pressure, the differences in behaviours between tight and loose fitting sleeves, and the effects of pressurizing the annulus between the pipe wall and sleeve. The analysis of the field data and FEA modeling predictions led to several conclusions regarding to use of numerical models for predicting sleeved pipe behaviour and weld flaw acceptance: • FEA results demonstrated behaviours that were consistent with full scale data, • Trends in the FEA predicted strains agreed with the full-scale data, • FEA models describing the effects of gaps between the pipe and sleeve and annulus pressurization agreed with field experience and engineering judgment, • Evaluation of the significance of root and toe flaws can be completed by extending the models validated in this work.

The work described in this paper was completed to assess the expected performance of various repair sleeve configurations on an NPS 30, Grade X70 pipeline. A total of ten sleeve variations were studied, and these included sleeve-on-pipe, sleeve-over-collar, and sleeve-over-double collar configurations. The comparisons were based on the stress results of axisymmetric finite element modeling of the sleeve geometries, and included examining sleeves with different thickness, models with and without a gap between the sleeve and the pipe, and cases in which the annulus between the sleeves and pipe were either pressurized or not pressurized. Complementary tasks involved with this work included the specification of recommended epoxy materials and steel grades for reinforcing sleeves. The results of the analyses are presented in terms of contour plots of stress at the maximum operating pressure of the pipe, showing the general stress distribution and indicating areas of stress concentration. This study demonstrates how the loads vary amongst the different sleeve types, and shows how variations in geometry and loading conditions between models affect the operating stresses.