An electrical Variable Frequency Drive (VFD) is a device that controls a motor by varying the frequency and voltage supplied to the motor. Frequency (or hertz) is directly related to the motor’s speed (RPMs). If an application does not require an electric motor to run at full speed, the VFD can be used to ramp down the frequency and voltage to meet the requirements of the electric motor’s load. As the application’s motor speed requirements change, the VFD can simply turn up or down the motor speed to meet the speed requirement which in turn controls the output of the connected equipment, in this case a pipeline pump (i.e. flow and pressure). This device is important in pipeline applications as it provides the operator with improved control over the critical parameters of the pump and in doing so increases pumping efficiency while reducing energy costs. Enbridge Liquids Pipelines has gradually introduced more VFD units on its mainline pumping systems since 1994. To date, 50% of the mainline pumps in the Enbridge Liquids Pipeline network operate under the control of a VFD. There is now sufficient historical operating data on those assets in order to quantify the benefits related to this particular system. This paper focuses on the operational reliability aspects of the VFDs and equipment controlled by the VFD. This includes failure probabilities and throughput performance over the life cycle of the system but excludes technical implications such as VFD selection, application, specification or design. From a pure maintenance perspective, VFDs contribute to a marked improvement on pumps in terms of failure reduction. For general pump failures including components such as mechanical seals, bearings, shaft, wear rings or couplings, it is demonstrated that the probability of failure is lower on pumps combined with VFDs compared to pumps without VFDs. In terms of mean time between repairs (MTBR), this equates to an increase of 65% relative to pumps with VFDs. All mainline pumps in Enbridge are driven by electric motors. With regards to drive motor failures, there is also a significant reduction in repairs; MTBR increases by approximately 25% on VFD driven electric motors. Another factor which can enhance the benefits associated with VFDs is the sparing options. In Enbridge Liquids Pipelines, there are two types of sparing options related to VFDs: • Dedicated VFDs (1 VFD controlling a single mainline pump) • Shared VFD (1 VFD shared between a set of mainline pumps) with back-up across the line starting. The throughput performance between the above mentioned existing options has been shown to differ substantially. On a specific pipeline built initially with shared VFDs then fitted with Dedicated VFDs, the number of pump failures decreased by 60% leading to a throughput loss reduction of 66%. However, while the VFD helps preserve the asset it runs in conjunction with, the VFD itself introduces a high frequency of failures in the overall pumping system. For the systems studied in Enbridge pipelines, adding a VFD increases the frequency of downtime events by 118%. However, these failures are short in duration which in the long term add up to less downtime (276% less) on a pumping system with VFD. Finally, VFD units have a high capital cost which can double the cost of ownership of a pumping system over the life cycle of the asset. However, this cost can be offset by the increase in availability provide by the VFD but this needs to be vetted through a Life Cycle Cost analysis.

A hydraulic transient occurs when there is a sudden change in the steady state condition of a fluid in a pipeline. The rapid change in velocity of a fluid causes a pressure wave to travel along the pipeline, potentially causing damage to the equipment and piping. Usually, different scenarios are studied depending on whether the fluid is being injected or delivered from the pipeline into a tank. The most commonly studied causes of sudden fluid velocity change in a pipeline are: closing of a fast acting valve (ESD or control valves which close within seconds) and stopping or starting of pumps. When a pipeline is delivering fluid into a tank, the closure of a valve can completely block the flow and create transient surge pressures that exceed acceptable pressure limits, and require mitigation. Although the closure of a fast acting valve is a commonly analyzed scenario, the closure of a motor operated valve (MOV), which is less commonly analyzed, can also create surge pressures which can put the pipeline at risk. There are three characteristics of an MOV that can significantly impact the surge pressures it creates when it is closed. These valve characteristics are: flow coefficient, valve curve and stroke time. Hydraulic simulations were performed to study the effect of these three valve characteristics on transient responses when delivering from pipelines into tanks. Simulation results show that a faster stroke time leads to higher pressure surges, as well as a valve with a quick closing or linear curve. However, the flow coefficient of the valves will have varying effects on transients depending on the piping system being analyzed. The purpose of this paper is to not only highlight the importance of valve characteristics when modeling transient surge events but also to provide key learnings that can be used to design safer delivery terminals.

Teikoku Oil Co. Ltd. (TOC) and NKK Corp. established a joint pilot project in 1994 in order to provide pipeline application and evaluation of NKK’s gas hydraulic simulation engine (GASTRAN) and to co-develop a Demand Forecasting Model (DFC). When the pilot project finished in March 1997, a commercial system, called Support Operation and Monitoring Application of Pipeline Simulator (SMAPS), was installed in TOC’s operation center. The DFC, which is based on an artificial neural network architecture, has several advantages for sales forecasting especially as several dozen delivery points that have different sales patterns are connected to the pipeline network. The results from DFC can be easily used for scenarios in off-line simulation to predict future pipeline situations when it is attached to the SMAPS system. It automatically assists the pipeline operator by reducing his workload and evaluating operation plans.

This paper discusses the merits of merging SCADA 1 and gas measurement from a technical and economical perspective. Because traditional SCADA is largely limited to control room data used only for day to day operational purposes, the real-time metering data is not often utilized in the external revenue-generation business systems of the organization. In many cases, entirely separate measurement systems are utilized in isolation which often have few, if any, ties to the SCADA system which is capable of collecting pertinent measurement information. Measurement data validation provides automatic data validation of flow measurement data upon retrieval from telemetered or non-telemetered data sources. Row measurement data can be supplied from field devices such as electronic flow computers or from other sources of flow measurement data such as manual operator entry, third party collection systems, chart integration sources, etc. Flow measurement data undergoes a series of automated validation tests including single-run limit checking, meter run comparisons (at a given metering station) and historical validation tests (such as searching for frozen values). The outcome of these tests determines the data quality code assigned to each flow measurement reading (indicating the results of validation tests). When combined with a real-time processing and data acquisition engine in a SCADA system that is capable of communicating with field devices via leased lines, VSAT, radio, dial-up, etc., many benefits can be realized.

In 1994, Teikoku Oil Co., Ltd. (TOC) and NKK Corp. established a joint pilot project to provide pipeline application and evaluation of NKK’s gas hydraulic simulation engine (GASTRAN), and to co-develop a Demand Forecasting Model (DFC). When the pilot project finished in March 1997, a commercial system, Support Operation and Monitoring Application of Pipeline Simulator (SMAPS), was installed in TOC’s operation center. SMAPS programs include a real time simulator, an off-line planning simulator, demand and supply database, SCADA interface program, and the DFC. The real-time simulator provides actual initial conditions to the off-line simulator. In addition, the demand and supply database facilitates inputting the data for each sales point and applying real time demand forecasts from DFC. SMAPS has been mainly used to evaluate pipeline operation and monitor pipeline situations. Future plans include expanding usage for pipeline construction and maintenance and improving employee training.

Gas transmission companies are sometimes disappointed with the results of efforts to control noise from reciprocating and centrifugal compressor packages, including new compressor station designs and retrofit programs. In an effort to begin to standardize noise control equipment specifications and performance testing procedures, the PRC I undertook a project to develop a series of “ Guidelines ” for implementing engineering noise control designs for compressor station equipment. The project was sponsored by the PRC I nternational (PRC I ). The project report consists of eleven stand-alone Guidelines that can be used by gas transmission companies to develop their own noise control specifications for major compressor station equipment. The intent of the Guidelines is to maintain traditional vendor/sub-vendor roles between compressor packagers and component manufacturers while maintaining the practice of vendor design - vendor guarantee. The noise control requirements can be verified by pre-establishing field performance testing methods. Specific field performance testing methods for various typical mechanical equipment are provided in each Guideline. The Guidelines are structured to draw a distinction between mechanical equipment components which are noise generators, sound attenuators or acoustic radiators, as each requires a different specification format. To fulfill this aspect, a high temperature microphone probe was researched, developed and tested. This piece of hardware, along with the developed measurement methodology, allows optional diagnostical testing of the engine exhaust noise component of compressor station noise. These diagnostics can assist in isolating the noise generated by the engine versus the attenuation provided by the exhaust silencer. The measurement procedures do not require silencer removal from the package or equipment shutdown to test, which thus reduces testing costs.

This paper describes R&D efforts and trends and possible application of new technologies to improve on pipeline construction and operations. The paper also identifies possible solutions for some operating concerns related to pipeline integrity and safety. Safety is defined as protection for humans, the environment and materials/equipment. As in other industries, the oil & gas business too is driven by events; a typical example is the current interest on Stress Corrosion Cracking (SCC). Accordingly, there are technical concerns related to the influence of SCC and aging on pipeline integrity and the consequent financial concerns regarding possible pipeline upgrading, derating, abandonment and possible retrieval. Potential new solutions include a proposed flexible tube (currently under development) made out of fibre glass composites. This patented innovation could reduce pipeline construction and operating costs. This tube could also eliminate some problems typically associated with metal corrosion. Also included is the application of Fibre Optic Sensor (FOS) technology to the monitoring and evaluation of pipeline integrity. FOS technology may be utilized to study SCC because of its high resolution, and its insensitivity to electro-magnetic interference, and its real time availability. This cost effective technology is currently utilized in the monitoring and evaluation of a variety of structures such as airplanes, engines, generators, bridges and along highways. Optical fibres have the ability to detect a wide range of physical, mechanical, chemical and biological parameters, as: • frequency • temperature • pressure • strain-stress • residual-strain • vibration • damage • impact • displacement • deformation • acoustic-emission • wear • electric-fields • acceleration • rotation • voltage • chemical-species • refractive-index • chemical-reactions • load • liquidlevels • cracking If a fibre optic cable acting as a sensor can be applied to a pipeline system in a practical manner, it may be possible to monitor the performance and conditions of a pipeline over its operating life.

This paper presents how a major U.S. gas transmission and storage company restored gas storage peaking capacity by repowering obsolete gas turbine compressor units. Consumers Power Company’s Ray Field located in Macomb County, Michigan, USA, was developed as a 44 BCF working capacity gas storage field in 1966. Due to the high deliverability, the field is operated as a peaking reservoir, handling rates as high as 500 MMCFD on injection and 1,200 MMCFD on withdrawal. Ten (10) 2,750 horsepower gas turbine driven 4-stage centrifugal compressor units were installed in the mid to late 1960’s at the field. The compression is operated 2, 4 and 8 stage, as needed, to cover storage pressures of 450 to 1800 psig. Each centrifugal compressor is driven by a Pratt Whitney (PW) GG-12 Gas Generator firing into a Cooper-Bessemer (CB) RT-27 Power Turbine. By 1980 parts and maintenance services for the PW GG-12 Gas Generator became very expensive to non-existent. Aircraft use of the GG-12 (JT-12) had been phased out. Consumers Power, with 13 of these turbines on their system, was becoming the only remaining user. In the mid 1980’s four (4) of the Ray Field gas turbine compressor units were replaced with two (2) 6,000 horsepower reciprocating engine compressor units. These replacements maintained the deliverability of the field and provided salvageable engines and other parts to maintain the six (6) remaining turbines. However, by 1993 maintenance parts returned as a major problem as well as unit availability on the 6 remaining turbine units. In 1994 Consumers Power committed to a gas turbine unit repowering program as the preferred choice over unit replacement. Two (2) refurbished Solar Centaur T4500 Gas Turbine drives were purchased and installed to repower 2 of the obsolete turbine units. These installations have been very successful. Existing compressors, foundations, piping, coolers and auxiliary systems were re-used with only minor modification. The complete installed cost for repowering was about 33% of the cost experienced for replacement. Installation was completed within eight (8) months of project commitment. The low emission rates from the Solar SoLoNOx Combustors allowed short lead time (6 months) on air emissions permit. New sound attenuation enclosures met the new local noise ordinance and replaced equipment that had been a source of local complaint. PLC based controls improved reliability and flexibility of operation. The additional horsepower available from the T4500 Turbine (4,300 vs 2,750) allows for increased future capacity. Because of the success of the Ray Turbine Repowering Project, Consumers Power has committed to 2 more refurbished Solar Centaur T4500 Units to repower PW/CB Turbines at the St Clair Compressor Station. Solar is scheduled to delivery these 2 units by year-end 1995 for installation in 1996.

This paper will review the installation of the innovative MOPICO MOtor PIpeline COmpressor on a main transmission line segment of the Columbia Gas Transmission system in Harford County, Maryland. A review of the environmental and operational requirements for the construction process as well as for the operation of the station will be the foundation from which the various features of the station and the MOPICO technology will be discussed. The station consists of three (3) MOPICO motor compressors operating in series.

Increasingly stringent regulations by the EPA and state air quality agencies in the U.S., as well as new regulations by Environment Canada, are making the reduction of exhaust emissions from industrial engines and gas turbines ever more important far their operators. Not only are these regulations getting increasingly strict with time, but there will be both substantial fines and possible criminal penalties for non-compliance in the future. This presentation describes how harmful exhaust emissions are formed during the combustion process, what the current regulations are in various areas of North America and where they are probably headed in the foreseeable future. It then discusses possible emission reduction strategies in two broad categories, combustion modification and post-combustion treatment, using catalytic converters. The three types of catalyst substrates are discussed, with the advantages and disadvantages of each, as well as the relative advantages and disadvantages of the four possible catalyst locations.

Shaft torque and corresponding stresses in a motor driven - direct coupled - reciprocating compressor system, are significantly influenced by the system’s mass-elastic properties. Uncertainty in the system’s mass-elastic properties will therefore translate into uncertainty in the calculated system stresses. Three case studies provide the reader with an appreciation for the importance of defining uncertainty bands in the mass-elastic properties of a torsional system. The case studies are followed by a theoretical discussion section. The reader is introduced to the concept of torsional resonance, uncertainty in calculated system torsional natural frequencies is defined, and the relative influence that specific system mass-elastic properties have on the overall system is discussed. A full compliment of system mass-elastic uncertainties is presented.

Electric high-speed drives with magnetic bearings offer significant technical and economic advantages for gas compression and pipeline operation. Compressors with magnetic bearings and dry gas seals have been successfully used for more than a decade. These installations have demonstrated that the elimination of the compressor lube oil system results in increased availability and is economically viable. Nevertheless, as long as a lube oil system is still necessary for the drive or for a gearbox the benefits of oil-free operation such as increased safety and increased availability cannot be fully exploited. Electric high-speed drives do not require a gearbox. In combination with the use of magnetic bearings such drives allow the elimination of the entire lube oil system resulting in a dry rotor string. This results in increased efficiency and increased availability, and leads to reduced operation and maintenance cost. Furthermore, such electric high-speed drives can easily be adjusted to specific requirements, allow a wide operating range and thus the pipeline operation can be optimized. High efficiency, oil-free operation and no emissions make electric high-speed drives the most environmental friendly compressor drive. The main disadvantage so far has been that electric high-speed drives and especially magnetic bearings needed high engineering effort resulting in high cost. The concept developed by ABB overcomes these problems with a modular approach for the motor and the power converter as well as for the magnetic bearings. Thus, electric high-speed drives have become a cost competitive, attractive solution for gas industry.

When an energy industry facility must meet environmental noise regulations, the primary noise sources are the drivers (such as engines and motors), driven tools (such as compressors and pumps), air moving devices, and turbulent flow in valves and piping. The primary sound transmission path is the airborne radiation of noise, which is controlled by enclosures, lagging and silencers. The opportunity for sound energy to be transmitted through structural vibration and reradiated at another location is largely overlooked in typical acoustic impact analyses. Pipe support and skid structures often have large flat panels which are very efficient radiators of noise energy, where the sound energy generated by compressors can be emitted into the environment at some distance from the actual energy source. How a pipe is mounted on its supports, and the design of those supports, can have a significant effect on the noise emissions from its support structures.

This Paper presents the main design features and describes operating experience to date of a unique gas pipeline compression system marketed under the name MOPICO ( Mo tor Pi peline Co mpressor). MOPICO has been developed jointly by four companies in USA and Europe. A prototype unit was works tested in 1990 and subsequently installed as an extension to an existing gas booster station in Alabama, where it has been in industrial operation since 1991. The main elements of the motor/compressor design and the overall system performance capabilities are described briefly. Operational experience on a grass-roots station equipped with three units connected in series in a booster station in the US north east, and two single unit stations in the Province of Quebec are presented in detail.

A team forms to address the challenge of low cost, low maintenance gas compression that can be quickly ramped up to meet peak demands. The Natural Gas Industry recognizes the importance of efficient, flexible compression equipment for the transmission of gas. In the early 1900s the Gas Industry met its compression objectives with many small reciprocating compressor units. As competition increased, Gas Companies began employing more cost effective larger units 3.7 MW (5,000 bhp) and eventually gas turbines 11+ MW (15,000 + bhp) became the prime mover of choice. While gas fired engine driven compressors are convenient for gas companies; they are becoming increasingly difficult to install. Environmental restrictions have tightened making permitting difficult. The larger gas turbine units seemed a solution because they were the low capital cost prime mover and clean burning. However, gas turbines have not yet achieved the high degree of flexibility and fuel efficiency gas transporters hoped. Flexibility has become an increasingly important issue because of the new “Peaking Power Plants” that are coming online. Gas companies are trying to solve the problem of low cost, low maintenance compression that can be quickly ramped up to meet peak demands. The idea of using electric motors to drive compressors to minimize the environmental, regulatory, and maintenance issues is not new. The idea of installing an electrically powered, highly flexible, efficient, low maintenance compressor unit directly into the pipeline feeding the load, possibly underground where it won’t be seen or heard, is a new and viable way for the gas and electric industries to do business together. This paper examines the application of totally enclosed, variable speed electric motor driven gas compressors to applications requiring completely automated, low maintenance, quick response gas pressure boosters. In this paper we will describe how a natural gas transporter, compressor manufacturer, motor manufacturer, and power company have teamed up to design the world’s first gas compressor that can be installed directly in the pipeline. We will discuss methodologies for installing the proposed compressor, the environmental benefits — no emissions, a small footprint, minimal noise — and the benefit of being able to install compression exactly where it is needed to meet the peaking requirements of today’s new loads.

During 1997–1999 an energy company based in Calgary, Alberta, Canada added approximately 17.5 megawatts of electrical generating capacity to its oil production facility in Ecuador. Reservoir pressure was insufficient to permit free flow into the transportation pipeline. Therefore, a series of motor driven, bottom hole pumps had been installed. As is typical with many remote well sites, an electricity source was not available to achieve reliable operation of the bottom hole pumps. Therefore, a decision was made to install seven (7) refurbished on-site turbo-generator sets. The turbo-generators are based on the Rolls-Royce 501K gas generator, were commissioned during the first half of 2000, and today provide electricity for the facility. This paper discusses the refurbishment of the turbo-generator sets. The refurbishment is a noteworthy achievement given the fact that the units sat idle for many years within the unprotected environment of the Venezuelan rain forest. The refurbishment methods and technologies are discussed. Factory test data are also presented.

Variable frequency drives are now frequently used to power large horsepower pipeline pumps to eliminate power costs wasted by throttling, to reduce inrush current on motor start, and to provide greater operating flexibility. This variable speed operation, however, can cause vibration problems in the pump and motor bearings, and in the couplings that are not normally experienced with fixed speed pumps. Enbridge Pipe Line has installed a number of variable frequency drives on units ranging from 2500 to 5000 hp in size and discovered unexpected torsional and lateral resonance vibration in the equipment at certain operating speeds. This presentation discusses the tests that were conducted to determine the source of the vibration, the theoretical analysis of the vibration modes and equipment responses, and the solutions that were implemented to reduce or eliminate the vibration. Recommendations are given for design principles that could be incorporated into the initial pump station design in order to avoid vibration problems with variable speed operation.

The Environmental Protection Agency (EPA) publishes emissions factors for gas turbines in its Compilation of Air Pollutant Emission Factors, “ Volume I Stationary Point and Area Sources, Publication No. AP-42 ”. This document uses an emissions factor (EF) which is a representative value that attempts to relate the quantity of a pollutant released to the atmosphere with an activity associated with the release of that pollutant. For natural gas-fired gas turbines, EPA NO x (nitrogen oxides) emissions factors are usually expressed as the weight of pollutant per unit fuel volume burned or its equivalent heating value (e.g. kg/m 3 or kg/GJ). In most cases, these factors are simply averages of available data, and are generally assumed to be representative of long-term averages for all facilities in the source category. Additionally, AP-42 specifies two EFs depending on the engine load being above or below 80% of rated power. In this paper, NO x emissions tests were conducted on four gas turbines. The first two were non dry low emissions (non-DLE) General Electric engines (LM1600), one in Alberta and the other in Ontario, with significant elevation difference. The other two were Rolls-Royce (R-R) engines; one DLE (RB211-24G) while the other is a non-DLE (RB211-24C), both in Alberta at the same elevation. These tests were conducted at different ambient temperatures varying from −7°C to +28°C using Continuous Emissions Monitoring (CEM) emissions samples based on EPA Method 7E standard. Predictive Emission Monitoring (PEM) systems were also developed based on these and previous testing, and predictions are compared to measured data. The difference between NO x emissions from these four engines at different loads (minimum to maximum) and different ambient conditions are presented and compared. A comparison with AP-42 emissions factors is presented and discussed. It was found that the elevation difference between the two LM1600 engines makes a significant difference in NO x emissions. Additionally, the emissions from the DLE engine when it is operating out of the DLE mode (at low loads) emits higher NO x than a non-DLE engine at the same load and ambient conditions.

Gas Turbine (GT), like other prime movers, undergoes wear and tear over time which results in performance drop as far as available power and efficiency are concerned. In addition to routine wear and tear, the engine also undergoes corrosion, fouling etc. due to the impurities it breathes in. It is standard procedure to ‘wash’ the engine from time to time to revive it. However, it is important to establish a correct schedule for the wash to ensure optimal maintenance procedure. This calls for accurate prediction of the performance degradation of the engine over time. In this paper, an error-in-variables based methodology is applied to evaluate the performance degradation of two GT engines between soak washes. These engines are LM2500+ (single spool) and RB211-24G (twin spool). The engine-air-compressor isentropic efficiency and air inlet flow rate as well as the engine heat rate and specific work are analyzed for both engines. For both engines, the compressor isentropic efficiency is found to degrade over time, while the engine heat rate correspondingly increases. The compressor air inlet flow rate and engine specific work remain mostly constant. Through a comparison between the time-history of the engine health parameters, it is found that the LM2500+ degrades at a much faster rate than the RB211-24G. However, the degradation of the LM2500+ is found to be fully recoverable by offline washes, while the degradation of the RB211-24G is only slightly recovered by offline washes. The RB211-24G engine is found to be running near its maximum efficiency at all times, which is likely the cause for the observed non-recoverable degradation that the engine experiences. The engine’s site location is also found to contribute to the degradation that the engine experiences.

Motor and pump units can start either directly across the line (utility) or through a VFD. If the power system is weak (high impedance and relatively low available MVA), the result will be limitations on the maximum size of motor that may be started directly across the line. Currently some available power systems are not capable of starting large motors across the line and therefore VFD systems are required. A VFD can be used for starting purposes or to operate a motor/pump unit (unit) continuously. Liquids pipelines have been using VFDs for unit starting purposes and for pressure control while either one of the units connected to the VFD or while there is a dedicated VFD per unit. One VFD can be used to operate all the units. The VFD starts the motor, ramps it up, and synchronizes it with the utility to switch the motor from VFD operation to utility operation. The VFD follows the same sequence with the next unit. The VFD also switches the motor from utility operation to VFD operation. With pumps in series, one unit can remain connected to the VFD for pressure control in liquids pipelines. Each unit can also be controlled by a dedicated VFD, allowing independent control of each unit for start-up and speed control. Both single VFD or dedicated VFD per unit offer advantages. Benefits of using a single VFD for all units are cost savings for some applications, a backup start across the line when allowed by the power system, and station pressure control. The benefits of a dedicated VFD per unit application include more flexibility in flow and pressure control, ease of expansion without interrupting existing operations for an extended period, energy efficiency, and redundancy. Motor protection schemes for the above two VFD applications are discussed and compared in this paper. In order to maintain a safe and reliable pipeline system, comprehensive motor protection functions are provided to the pump unit. Although the principles are the same, there are some differences between the two motor protection applications. For a dedicated VFD per unit application, the VFD protection/control circuitry normally provides motor protection because the motor is always connected to the VFD. RTDs over-temperature protection is not typically a standard feature of VFDs, however, it can be provided by proper PLC programming or the VFD incoming feeder protection relay.