The risk associated with third-party damage to transmission pipelines in areas of urban development is high. Distributed monitoring is a modern technique that uses fiber optic cables as sensors to continuously monitor pipeline parameters such as acoustics, vibration, strain and temperature. The fiber optic system notifies the operator in real-time of ongoing events allowing decisions to be made to prevent external interference or quickly address an incident that has already occurred. Traditional methods used to install distributed monitoring systems on pipelines have limitations and are not feasible for all transmission pipelines. For instance, it can be both challenging and expensive to trench in fiber optics in developed areas and other installation techniques require the pipeline to be temporarily taken out of service. SaskEnergy Incorporated’s transmission line subsidiary, TransGas Limited partnered with a Canadian pipeline monitoring service provider to install fiber optics inside of a natural gas transmission pipeline using a pig, steel capillary tubing and a pack-off hanger. A disengagement system was incorporated to release the fiber optics after the desired monitoring distance was reached. It was decided to perform the pilot project on a newly constructed NPS 6 natural gas transmission pipeline located in Humboldt, Saskatchewan. Nitrogen was used as a medium to simulate an in-service pipeline in order to reduce the risks associated with the first attempt of the project designs. The fiber optics were inserted into steel capillary tubing and connected to a disengagement system located at the back of a pig. A pack-off hanger was used to maintain pipeline pressure during and after the installation was completed. The spool holding the steel capillary tubing was stopped once the maximum monitoring distance was reached and the differential pressure activated the disengagement system located at the back of the pig. The pig continued to the receive location and the fiber optics remained in the pipeline for continuous monitoring. The deployment was successful and the fiber optics will remain in the pipeline for a one (1) year monitoring period. The primary limitation to this pilot project was the strength of the steel capillary tubing. The steel capillary tubing’s ultimate tensile strength would have to be higher to accommodate a pipeline with a larger outside diameter, multiple bends, large changes in wall thickness or large elevation changes. In addition, the steel capillary tubing must be removed from the pipeline in order to perform pigging activities.

Low temperature and high pressure conditions in deep water wells and sub-sea pipelines favour the formation of gas clathrate hydrates which is very undesirable during oil and gas industries operation. The management of hydrate formation and plugging risk is essential for the flow assurance in the oil and gas production. This study aims to show how the hydrate management in the deepwater gas well testing operations in the South China Sea can be optimized. As a result of the low temperature and the high pressure in the vertical 3860 meter-tubing, hydrate would form in the tubing during well testing operations. To prevent the formation or plugging of hydrate, three hydrate management strategies are investigated including thermodynamic inhibitor injection, hydrate slurry flow technology and thermodynamic inhibitor integrated with kinetic hydrate inhibitor. The first method, injecting considerable amount of thermodynamic inhibitor (Mono Ethylene Glycol, MEG) is also the most commonly used method to prevent hydrate formation. Thermodynamic hydrate inhibitor tracking is utilized to obtain the distribution of MEG along the pipeline. Optimal dosage of MEG is calculated through further analysis. The second method, hydrate slurry flow technology is applied to the gas well. Low dosage hydrate inhibitor of antiagglomerate is added into the flow system to prevent the aggregation of hydrate particles after hydrate formation. Pressure Drop Ratio (PDR) is defined to denote the hydrate blockage risk margin. The third method is a recently proposed hydrate risk management strategy which prevents the hydrate formation by addition of Poly-N-VinylCaprolactam (PVCap) as a kinetic hydrate inhibitor (KHI). The delayed effect of PVCap on the hydrate formation induction time ensures that hydrates do not form in the pipe. This method is effective in reducing the injection amount of inhibitor. The problems of the three hydrate management strategies which should be paid attention to in industrial application are analyzed. This work promotes the understanding of hydrate management strategy and provides guidance for hydrate management optimization in oil and gas industry.

Pressure transmitters (PT) are mounted on Diluted Bitumen (DilBiT) pipelines particularly in various locations around the pump stations. Conventional assembly of the PT includes short rigid tubing closely connected to the pipe. Due to fluid flow and equipment induced vibration of the main pipe, these tubing, being very short and close to the pipe, are vulnerable to break and hence becomes an integrity and reliability issue. For this reason, PT’s are often mounted at a longer distance away from the pipe (of the order of 2 meters) with the use of a flexible SS hose gaugeline to dampen vibration generated at the pipe/tubing connection. While this solves the problem of tube breaking, it creates an issue surrounding the effects of the long gaugeline on the dynamic response of the PT/gaugeline assembly to pressure variations, particularly in cold ambient temperature (e.g. −40°C). An experimental setup of a typical PT/flexible hose gaugeline assembly was placed in a cold chamber, and several tests were conducted on warm (10 to 20 °C) and cold temperatures (−40°C) to compare the difference in the dynamic response of the assembly. Several fluids filling the gaugeline were tested and compared. This paper present the test results and make a recommendation of the best fluid to use for the gaugeline to cope with −40°C ambient temperature. It was also found that no heat tracing would be required if this fluid is used.

Deepwater pipelines and high pressure casing and tubing are prone to buckling and unstable collapse under compressive loading and external pressure. The most important parameters governing the unstable collapse behaviour of perfectly round pipes and tubes are the circumferential yield stress of the material, the Young’s modulus and the ratio of diameter over thickness (D/t). Initial imperfections in the geometric shape of the pipe, like wall thickness variations or ovality, can have a pronounced influence on the collapse resistance of a pipe. Local dents can reduce the collapse pressure significantly, and trigger propagating buckles along the line. In this paper, buckling and unstable collapse of seamless pipes and tubes are studied. First, collapse pressure experiments for High Collapse Casing grades L80HC and P110HC are presented, showing that the seamless pipe production at ArcelorMittal Tubular Products in Ostrava (Czech Republic) is under tight quality control and complies with the API standards. Then, the critical collapse pressure is calculated for different scenarios. Depending on the ratio of diameter to wall thickness, four regimes are identified: yielding collapse, followed by plastic collapse, a transition range, and finally elastic collapse. For each condition, closed form expressions are derived for the critical collapse pressures. In addition, simplified design equations are reviewed to quickly estimate the collapse pressure. Then, the influence of initial imperfections on the collapse resistance is studied. Both the effects of geometric imperfections (ovality and wall thickness eccentricity) and material properties (especially yield stress and residual stresses) are addressed. In the end, an enhanced design equation is proposed to predict the critical collapse pressure of dented seamless pipes. This equation is validated by collapse experiments, can account for different initial imperfections, and is valid for a wide range of D/t ratios.

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.

Many methods of flame detection are available. Unfortunately, few offer remote, non-line-of-sight, detection. In cases where flammable mixtures are transported within tubing (such as flare lines, storage tank vents, air drilling, and improperly designed purging operations) there is often no means by which combustion can be detected. This is a significant deficiency in some applications. If the mixture were to ignite, the results could be catastrophic. To address this problem, combustion noise is being investigated at the University of Calgary as a possible means of detecting flames within tubing. An experimental study has been completed that shows that combustion noise can be distinguished from other sources of noise by its inverse power law relationship with frequency. A robust algorithm has been developed that, when combined with high-speed pressure measurements, provides early detection of flames. When combined with other filters, the algorithm can automatically separate combustion noise from other sources of noise. In this paper, a stop band filter was used to remove the noise created by a fluttering check valve.

Modern high strength steels need accurate control of microstructure in order to meet the steadily increasing requirements on mechanical properties, toughness or corrosion resistance. An appropriate steel making with inclusion control and a sophisticated thermo-mechanical controlled processing are the key factors, but we have to recognize that the process parameters have to be refined continuously to meet the targets. The present paper is going to demonstrate this progress using the examples of two recent development activities at Arcelor. At the same time it is shown that the development is often accompanied by the installation of new testing equipment for a more accurate and target-oriented material characterization. The first example deals with the development of an X70 for a 36” OD spiral welded pipe with 20.6mm wall thickness, a challenge for a hot strip mill when a good toughness is required at this thickness. We will briefly describe the sheet and pipe production and compare the mechanical properties on sheet and on pipe. The toughness performance of the new steel has been characterized in different orientations with respect to the rolling direction. In an attempt to quantify the crack growth propagation during the Batelle test, we equipped the existing testing device with a load cell so that we are now capable to document the energy absorption during crack propagation. The second example concerns the development of a coiled tubing grade 90 with HIC resistance for downhole application in corrosive environment. The challenging combination of high strength level, excellent low cycle fatigue (LCF) performance and corrosion resistance gave rise to the launch of a metallurgical study with the aim to develop a new steel grade. For a more complete material characterization we took advantage of this opportunity to install new CO 2 corrosion test facilities (atmospheric pressure and high pressure). The LCF performance of the steel sheets has been characterized under constant strain amplitude conditions.

Distributed fiber optic sensing presents unique features that have no match in conventional sensing techniques. The ability to measure temperatures and strain at thousands of points along a single fiber is particularly interesting for the monitoring of elongated structures such as pipelines, flow lines, oil wells and coiled tubing. Sensing systems based on Brillouin and Raman scattering are used for example to detect pipeline leakages, verify pipeline operational parameters, prevent failure of pipelines installed in landslide areas, optimize oil production from wells and detect hot-spots in high-power cables. Recent developments in distributed fiber sensing technology allow the monitoring of 60 km of pipeline from a single instrument and of up to 300 km with the use of optical amplifiers. New application opportunities have demonstrated that the design and production of sensing cables is a critical element for the success of any distributed sensing instrumentation project. Although some telecommunication cables can be effectively used for sensing ordinary temperatures, monitoring high and low temperatures or distributed strain present unique challenges that require specific cable designs. This contribution presents advances in long-range distributed sensing and in novel sensing cable designs for distributed temperature and strain sensing. The paper also reports a number of significant field application examples of this technology, including leakage detection on brine and gas pipelines, strain monitoring on gas pipelines and combined strain and temperature monitoring on composite flow lines and composite coiled-tubing pipes.