Natural gas transmission systems have many sources of fugitive methane emissions that have been difficult to eliminate. This paper discusses an option for dealing with one such source for operations using turbo-compressor units fitted with dry gas seals. Dry seal leakage ultimately results in waste gas that is emitted to the atmosphere through the primary vent. A simple, cost effective, emission disposal mechanism for this application is to vent the seal leakage in to the gas turbine’s air intake. Explosion hazards are not created by the resultant ultra-lean fuel/air mixture, and once this mixture reaches the combustion chamber, where sufficient fuel is added to create a flammable mixture, significant oxidation of the seal vent gas is realized. In principle, this system is easily implemented with simple modifications to the existing vent piping. However, the inherent safety of ultra-lean fuel/air mixture applies only when the gas turbine is operating with gas turbine airflow overwhelming the seal leakage flow. A potential design solution for managing this emission avoidance mechanism including safe operation during gas turbine shutdown periods is detailed.

A surge control system for a natural gas centrifugal compressor station has been modified in order to reduce shutdowns caused by high discharge temperature and provide a more robust and stable operation. The process consists of a compressor driven by a 14 MW gas turbine and recycle piping, a 16” recycle valve, a PLC based surge control algorithm, a flow measurement element, and a compressor differential pressure transmitter. The control objective is to manipulate the recycle valve to maintain flow through the compressor to a setpoint determined from the differential pressure across the compressor. Field tests were conducted to measure the open loop process dynamics of the valve, piping, compressor and transmitters. From the test data, the relevant process dynamics were determined enabling the development of a first order plus dead time model of the system. The process dynamics are complex due to the gas dynamic effects of the station piping and tend to exhibit inverse and time delayed behavior. Large variations in process gain also create problems with obtaining a consistent flow response under different operating conditions. A stability analysis was completed and the control system was redesigned with several enhancements including derivative control, flow signal filtering, process linearization, and improved controller programming techniques. The results of the modifications are the compressor does not shut down when subjected to transients from other units, the compressor can be started against high head conditions, and the closed loop response time is ten times faster than the previous system. The new system has been in operation since May 1997.

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.

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.

A significant source of noise at pipeline facilities is piping radiated noise. Although the noise generation is due to the internal geometries and flow conditions of the rotating equipment or due to the orifices or valves, the acoustical radiator is the piping. Piping and compressor casings on numerous gas turbine driven turbocompressor packages as well as piping at meter stations and regulator stations have been treated using acoustical laggings, as a retrofit as well as during design. However very little information exists in the industry regarding the acoustical performance of site installed acoustical lagging systems. With the advent of innovative testing techniques, installed lagging system Insertion Losses have been obtained, and significant experience has been gained regarding material selection and system performance. As opposed to the massive panels typically used for acoustical enclosures on turbocompressor packages, acoustical laggings utilize lightweight and often removable materials. This paper discusses material properties that enhance the performance of acoustical lagging systems, considerations regarding corrosion prevention and removability, the importance of proper installation techniques, and field testing procedures to determine installed performance of acoustical lagging systems.

Hybrid PSOFC/GT cycles consisting of pressurized solid oxide fuel cells integrated into gas turbine cycles are emerging as a major new power generation concept. These hybrid cycles can potentially offer thermal efficiencies exceeding 70% along with significant reductions in greenhouse gas and NO X emissions. This paper considers the PSOFC/GT cycle in terms of electrical and mechanical power generation with particular focus on gas pipeline companies interested in diversifying their assets into distributed electric generation or lowering pollutant emissions while more efficiently transporting natural gas. By replacing the conventional GT combustion chamber with an internally reformed PSOFC, electrical power is generated as a by-product while hot gases exiting the fuel cell are diverted into the gas turbine for mechanical power. A simple one-dimensional thermodynamic model of a generic PSOFC/GT cycle has shown that overall thermal efficiencies of 65% are attainable, whilst almost tripling the specific work (i.e. energy per unit mass of air). The main finding of this paper is that the amount of electric power generated ranges from 60–80% of the total power available depending on factors such as the system pressure ratio and degree of supplementary firing before the gas turbine. Ultimately, the best cycle should be based on the “balance of plant”, which considers factors such as life cycle cost analysis, business and market focus, and environmental emission issues.

Since the early 1960’s, the use of aero-derivative and industrial gas turbines on TransCanada’s natural gas transmission system has been the norm, with a total of 245 units installed to date. In 1996 and 1997 the company installed six high-speed, 30.6 MW, variable speed, electric drive systems. In the same time period eight aero-derivative gas turbines of similar power, with Dry Low Emissions , were installed. After an elapse of three years running time we now have enough data to compare the performance of the two different compressor drivers. A comparison of the performance of the two prime movers is made in a number of different ways. Operation and maintenance costs of the two different systems are considered, including the fuel costs of the natural gas and electricity, from three different Canadian electric power utilities.

Due to its robust design, the General Electric Frame 3 MS3002 gas turbine is highly reliable and has reasonably good maintenance qualities, which explains why it is so widely used all over the world. At present, there are nearly 1000 units in this series, the bulk thereof are operated as gas-pumping units (GPU) to drive natural gas compressors.

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.

Performance guarantees are an integral part of the purchase of turbo-compressor equipment. Traditionally the testing is done at the equipment supplier’s factory in accordance with the appropriate test code. This paper puts forward technical and economic arguments for basing the final acceptance of the equipment on site tests. The equipment considered is in the 5 MW to 30 MW range. The main emphasis of the paper is on making the site tests conform as closely as possible to the factory tests so that the results are acceptable to the manufacturer. The paper also includes discussions on the differences between shop test and site test procedures and results, comparative costs, site test specifications, instrumentation selection, and data analysis techniques.

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.

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.

Compression systems employed in gas pipeline transmission systems and gas processing plants provide a vital function to the overall operation of both systems, and therefore must be vigilantly monitored in order to ensure a high level of operational reliability. The majority of these compression systems employ centrifugal compressors, driven by either gas turbines or electric motors with/without gearboxes. These systems are designed and operated in a manner to eliminate or minimize the potential for surge, which is a dynamic instability detrimental to the integrity of the unit. Surge can occur when compressors are subjected to rapid transients such as one following an emergency shutdown (ESD) or power failure. To prevent this, compressor stations are designed with recycle systems and special types of recycle valves required to open upon ESD. This paper describes the dynamics surrounding an ESD operation of a compression system composed of two units in series and two independent recycle systems, one for each unit. The conventional sizing of the recycle system applied to a single unit operation needs to be evaluated carefully when there are two units operating in series, and in particular sizing of the recycle system surrounding the higher pressure unit, i.e. the downstream unit. This paper provides an insight into the salient parameters that impact the operation of such system via several dynamic simulations of an ESD event. Different ‘what-if’ design scenarios are analyzed and results presented. The data was obtained from an actual station operation on TransCanada’s Alberta gas transmission system in Canada. This station also employs two large gas volume capacitance aerial coolers which are also involved in the dynamics of the system during ESD.

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 is 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, a methodology is presented to predict the performance degradation in a GE LM2500 Gas Turbine engine used at one of TransCanada’s pipeline system, Canada. Emphasis is laid on analyzing the degradation of the air compressor side of the engine since it is most prone to fouling and degradation. Although the results presented are for a specific engine type, the general framework of the model could be used for other engines as well to quantify degradation over time of other components within the GT engine. The present model combines Gas Path Analysis (GPA) to evaluate the thermodynamic parameters over the engine cycle followed by parameter estimation to filter the data of possible noise due to instrumentation errors. The model helps quantify the degradation in the engine performance over time and also indicates the effectiveness of each engine wash. The analysis will lead to better scheduling of the engine wash thereby optimizing operational costs as well as engine overhaul time.

Gas turbine (GT) engines employed in natural gas compressor stations operate in different modes depending on the power, turbine inlet temperature and shaft speeds. These modes apply different sequencing of bleed valve opening on the air compressor side of the engine. Improper selection of the GT and the driven booster compressor operating conditions can lead to larger bleed losses due to wider bleed valve openings. The bleed loss inevitably manifests itself in the form of higher overall heat rate of the GT and greater engine emission. It is therefore imperative to determine and understand the engine and process conditions that drive the GT to operate in these different modes. The ultimate objective is to operate the engine away from the inefficient modes by adjusting the driven booster compressor parameter as well as the overall station operating conditions (i.e. load sharing, control set points, etc.). This paper describes a methodology to couple the operating conditions of the booster compressor to the modes of GT bleed valve opening (and the subsequent air bleed rates) leading to identification of the operating parameters for optimal performance (i.e., best overall efficiency and minimum CO 2e emission). A predictive tool is developed to quantify the overall efficiency loss as a result of the different bleed opening modes, and map out the condition on the gas compressor characteristics. One year’s worth of operating data taken from an existing compressor station on TransCanada Pipelines’ Alberta system was used to demonstrate the methodology. This station employs GE-LM1600 gas turbine driving a Cooper Rolls-RFBB-30 centrifugal compressor. The results from the analysis conclusively indicate that there are operating regions on the gas compressor map where losses due to bleed valves are reduced and hence lower CO 2 emissions, which presents an opportunity for operation optimization.

Multi-objective optimizations were conducted for a compressor station comprising two dissimilar compressor units driven by two dissimilar gas turbines, two coolers of different size, and two parallel pipeline sections to the next station. Genetic Algorithms were used in this optimization along with detailed models of the performance characteristics of gas turbines, compressors, aerial coolers, and downstream pipeline section. Essential in these models is the heat transfer between the gas and soil as it affects the pressure drop along the pipeline, and hence relates back to the coolers and compressor flow/pressure settings. Further investigative techniques were developed to refine the methodology as well as to minimize the downstream gas temperature at the suction of the next station. Current operating conditions at the station were compared to the optimized settings, showing that there is room for improving the efficiency of operation (i.e. lower energy consumption) with minimum effort on the station control strategy. Two threshold throughput conditions were determined in so far as single vs. multi-unit operations due to the dissimilarity in the compressor units and associated gas turbine drivers. The results showed that savings in the energy consumption in the order of 5–6% is achievable with slight adjustment to unit load sharing and coolers by-pass/fan speed selections. It appears that most of the savings (around 70–75%) are derived from optimizing the load sharing between the two parallel compressors, while the balance of the savings is realized from optimizing the aerial coolers settings. In particular, operating the aerial coolers at 50% fan speed (if permitted) could lead to substantial savings in electric energy consumption in some cases.

A Predictive Emission Monitoring (PEM) model has been developed for a non-DLE GE LM2500 gas turbine used on a natural gas compressor station on the TransCanada Pipeline System in Alberta. The PEM model is based on an optimized Neural Network (NN) architecture which takes four fundamental engine parameters as input variables. The model predicts NOx emission in ppmv-dry-O2 corrected and in kg/hr as NO 2 . The NN was trained using Continuous Emission Monitoring (CEM) measurements comprising two sets of actual emission data collected over two different dates in 2009, when the ambient ambient temperatures were vastly different (∼1° C and 24 °C), respectively. These training data were supplemented by other emission data generated by GE ‘Cycle-Deck’ tool to generate emission data at different ambient temperatures ranging from −30 to +30 °C. The outcome is a total of 1872 emission data of engine emissions at different operating conditions covering the range of the engine operating parameters (402 data points from CEM and 1470 data points from GE Cycle-Deck). The PEM model comprises a simple single hidden layer perceptron type NN with only two neurons in it. The performance of the NN-based model showed a correlation coefficient greater than 0.99, and error standard deviation of 4.5 ppmv of NOx and 1.4 kg/hr as NO 2 . Uncertainty analysis was conducted to assess the effects of uncertainties in the engine parameters on the NOx predictions by PEM. It was shown that for uncertainty in the ambient temperature of ±1 °C, the uncertainty in the NOx prediction is ± 0.9 to ±3.5%. Uncertainties of the order of ±1% in the other three input parameters results in uncertainties in NOx predictions by ±2.5 to ±6%. Finally, the PEM model was implemented in the station CEHM (Compressor Equipment Health Monitoring) system and NOx prediction were reported online on a minutely basis. These data are presented here over the first three months since implementation.

Noise is generated at gas turbine-based compressor stations from a number of sources, including turbomachinery (gas turbines and compressors), airflow through inlet ducts and scrubbers, exhaust stacks, aerial coolers, and auxiliary systems. Understanding these noise sources is necessary to ensure that the working conditions on site are safe and that the audible noise at neighbouring properties is acceptable. Each noise source has different frequency content, and the overall sound pressure level (OSPL) at any location in the station yard or inside the compressor building is the result of a superposition of these noise sources. This paper presents results of multiple-point spectral noise measurements at three of TransCanada’s compressor stations on the Alberta System. A method is described to determine the overall noise map of the station yard using Delaunay Triangulation and Natural-Neighbour Interpolation techniques. The results are presented in OSPL maps, as well as animated pictures of the sound pressure level (SPL) in frequency domain which will be shown on a video at the conference. The latter will be useful in future work to determine the culprit sources and the respective dominant frequency range that contributes the most to the OSPL.

Government policies currently in place or in development will require the reduction of greenhouse gas emissions from industry, including gas transmission systems. Most of the natural gas transmission systems are powered by gas turbines of sizes up to 30 MW per unit. A typical gas turbine of this size can emit 6 ktonnes of CO 2 per MW-year, equivalent to about 180 ktonnes per year. Reduction in greenhouse gas emissions can be accomplished through post-combustion systems (separation of CO 2 from flue gases through chemical absorption, physical adsorption, membrane or cryogenic systems) or through oxy-fuel combustion, where fuel is combusted in pure O 2 leading to sequestration of CO 2 by compression and dehydration of the exhaust gases. The purpose of the current work is to explore the application of the latter concept, simplify and enhance the cycle, and to provide an economic valuation of the cost per tonne of CO 2 abated. Innovations explored for enhancement include elimination of excess power production, simplification of capital equipment requirements, and optimization of the power to the booster produced from the gas turbine and steam turbine. The paper presents various innovation options arrived at, detailed thermodynamic parameters, and a cost and economic evaluation of these options. Particular emphasis was placed on the application of this technology to a typical compressor station on a natural gas transmission system as this application is vastly different than a typical power plant contemplating or employing carbon capture and storage (CCS) systems, most notably from the small power size, the remote location, and the self-containment perspectives.

Theoretical and experimental study of compressor and gas turbine performance with wet compression has been carried out on S1A-02 industrial gas turbine to reveal its effects on gas turbines, compressors. Experiment results show that wet compression has significantly effects on performances of gas turbines and compressors; under situations of high ambient temperature, wet compression can be used to restore engine power output.