Systems, methods, and apparatus are provided for generating power in combined low emission turbine systems and capturing and recovering carbon dioxide from the exhaust. In one or more embodiments, the exhaust from multiple turbine systems is combined, cooled, compressed, and separated to yield a carbon dioxide-containing effluent stream and a nitrogen-containing product stream. Portions of the recycled exhaust streams and the product streams may be used as diluents to regulate combustion in each combustor of the turbine systems.

Systems and methods for carbon dioxide capture in low emission combined turbine systems

Systems, methods, and apparatus are provided for controlling the oxidant feed in low emission turbine systems to maintain stoichiometric or substantially stoichiometric combustion conditions. In one or more embodiments, such control is achieved by diverting a portion of the recirculating exhaust gas and combining it with the oxidant feed to maintain a constant oxygen level in the combined oxidant-exhaust stream fed to the combustion chamber.

Systems and Methods For Controlling Stoichiometric Combustion In Low Emission Turbine Systems

Systems and methods are provided for varying the exhaust gas recycle circuit of low emission gas turbines. In one or more embodiments, the systems and methods incorporate alternatives to the use of a direct contact cooler. In the same or other embodiments, the systems and methods incorporate alternatives intended to reduce or eliminate the erosion or corrosion of compressor blades due to the presence of acidic water droplets in the recycled gas stream.

Methods of varying low emission turbine gas recycle circuits and systems and apparatus related thereto

Methods and systems for CO2 separation in low emission power plants are provided. One system includes a gas turbine system that combusts a fuel and an oxidant in the presence of a compressed recycle stream to provide mechanical power and a gaseous exhaust. A purge stream is taken from the compressed recycle stream and directed to a CO2 separator configured to absorb CO2 from the purge stream using a potassium carbonate solvent. Volatiles are removed from the rich solvent by stripping or by flashing to an intermediate pressure before the rich solvent is regenerated and CO2 is removed.

Low emission power generation systems and methods incorporating carbon dioxide separation

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Experimental Characterization of High-Pressure Natural Gas Scrubbers

This paper presents the results of performance testing of a single-stage centrifugal compressor operating under wet gas conditions. The test was performed at an oil and gas operator’s test facility and was executed at full-load and full-pressure conditions using a mixture of hydrocarbon gas and hydrocarbon condensate. The effect of liquid was investigated by changing the gas-volume fraction between 1.0 and 0.97, which covers the range encountered by the operator during regular gas/condensate field production in the North Sea. Other parameters that were evaluated include the 111 PERFORMANCE EVALUATION OF A CENTRIFUGAL COMPRESSOR OPERATING UNDER WET GAS CONDITIONS by Lars Brenne Staff Engineer Tor Bjorge Staff Engineer Statoil ASA Trondheim, Norway Jose L. Gilarranz Senior Aero/Thermodynamics Engineer Jay M. Koch Staff Engineer, Aero/Thermodynamics and Harry Miller Product Manager, Marketing Dresser-Rand Company Olean, New York compressor test speed, the suction pressure, and two different liquid injection patterns. During the tests, the machine flowrate was varied from near surge to choke conditions; hence, the evaluation covered the entire operating range of the machine. Although the test was primarily intended to evaluate the effects of the wet gas on the thermodynamic performance of the machine, the mechanical performance was also investigated by measuring the machine vibration levels and noise signature during the baseline dry gas tests as well as during the tests with liquid injection. INTRODUCTION Centrifugal compressor packages utilized for upstream gas processing often must operate under wet gas conditions in which the fluid handled by the compression package contains a mixture of liquid and gaseous phases. Typically, the liquid components of the mixture are separated from the gas stream before they enter the compressor by the use of scrubbers and separators located upstream of the compressor inlet. These devices are very large and heavy, requiring a large “footprint” (amount of floor space) as compared to the gas compression package. A compressor with the ability to directly handle wet gas without the need for separation equipment is very attractive from an economic standpoint, as it would drastically reduce the size, weight, and cost of the gas compression package. For the case of future subsea compression systems, this capability is even more attractive because of the high costs of deploying a compressor train and all of its associated equipment under water. Wet gas compression (WGC) technology represents new opportunities for enhanced, cost-effective production from existing and future gas/condensate fields. Many oil and gas operators face future challenges in tail-end production, unmanned operation, and improved recovery from topside and subsea wells. This emphasizes the need to develop more robust compression systems, which can be designed for remote operation in unmanned topside installations, or could be designed for subsea operation for reinjection and/or transport boosting. The use of this technology for subsea boosting represents a new and exciting application for rotating equipment, which will allow new gas/condensate field production opportunities as well as enhanced recovery of existing gas/condensate fields and cost-effective production from marginal gas fields. As mentioned above, these wet gas compression systems could be based on the use of a liquid tolerant dry gas compressor, which could boost a coarsely separated (via a scrubber) well-stream, however, an even more attractive solution would be the development of compression systems that can boost the well-stream directly. Many research projects and product qualification programs are currently underway to develop such a system either by modifying existing multiphase pump technology or by the adaptation of currently available gas compression technologies (Scott, 2004). Regardless of the choice of concept, the compressor solution should be able to tolerate liquid ingestion for an extended time without failure. For the case of subsea applications, the high cost associated with the retrieval of the compressor from the sea floor accentuates the importance of a reliable design. The work presented herein served as an initial test to verify the multiphase boosting capabilities of a centrifugal compressor as well as to provide an oil and gas operator with data to compare the performance of this technology with other available wet gas compression concepts. It is important to state that the test compressor used for this investigation was not originally designed for wet gas boosting, nonetheless it provided an economically viable test bed for centrifugal compressor technology. DESCRIPTION OF TEST VEHICLE The test vehicle used for this work was a barrel-type, singlestage compressor, manufactured by the coauthors’ company. Said compressor was equipped with a high-head impeller, with a diameter of 0.384 m (1.26 ft), and a design flow coefficient of 0.02380. The compressor was originally designed to handle an inlet flow of 4332 Kg/min [2167 Am3/hr (76,526.88 ft3/hr)] of dry hydrocarbon gas (molecular weight of 18.49), with an inlet pressure of 130.2 bar (1888.4 psi)and a discharge pressure of 161.8 bar (2346.7 psi). Figure 1 shows a cross-section of the test compressor; the inlet and discharge nozzles are located at a 45 degree angle with respect to the top dead center of the machine. The original design of this machine, which dates to 1986, was not intended for wet gas service, and hence the internal geometry was not optimal. Nevertheless, in order to increase the reliability of the machine, the original rotor design was modified to accommodate an electron-beam welded and vacuum furnace brazed impeller with a shrink fit to the shaft. The rest of the machine remained the same (i.e., casing and stationary components). This compressor was equipped with a vaneless diffuser configuration. Figure 1. Cross-Section of the Test Compressor. The compressor was driven by a 2.8 MW synchronous electric motor, through a speed increasing gearbox, with a gear ratio of 6.607. A variable speed drive permitted the operation of the compressor within its speed range of 6000 to 13,000 rpm. The test compressor is utilized in the coauthor’s closed loop test facility, and was equipped to simulate the conditions expected for a centrifugal compressor operating under wet gas conditions. Figure 2 shows a schematic diagram of the test loop that was used for the evaluations. The major components of the test loop included a scrubber, the test compressor, a pump, a cooler, and a liquid injection module (mixer). The scrubber, here called guard separator, was used to separate the dry gas (saturated hydrocarbon mixture) from the liquid (hydrocarbon condensate) in order to permit accurate measurement of the massflow of each stream (liquid and gas). The liquid stream was measured with a Coriolis flowmeter while the gas stream was measured with a calibrated orifice plate. Figure 2. Schematic Diagram of the Wet Gas Test Loop. PROCEEDINGS OF THE THIRTY-FOURTH TURBOMACHINERY SYMPOSIUM • 2005 112 Variable Speed Electric Motor (MW) Gas Flow 2 Phase Flow Condensate

Performance Evaluation Of A Centrifugal Compressor Operating Under Wet Gas Conditions.

A fluid compression system (100) is disclosed having a hermetically-sealed housing (110) with at least a motor (102) and a compressor (104) arranged therein. The motor may drive both the compressor and a blower device (128) coupled to the housing or otherwise arranged within the housing and configured to circulate a cooling gas throughout the housing and thereby cool the motor and accompanying radial bearings (120). The blower device circulates the cooling gas through a closed-loop circuit which may include a heat exchanger (156) and gas conditioning skid (157). Carbon ring seals (146) may be used to seal the shaft (108) on both sides of the compressor so as to prevent the migration of liquid and solid contaminants into the closed-loop cooling circuit.

Method and system for cooling a motor-compressor with a closed-loop cooling circuit

A fluid compression system is disclosed having a hermetically-sealed housing with at least two motors and a compressor arranged therein. The motors may be arranged either on both sides of the compressor or in a tandem configuration on one side of the compressor. The motors may be adapted to drive both the compressor and at least one blower device coupled to a free end of shaft that extends through the housing, the blower device being configured to circulate a cooling fluid throughout the housing and thereby cool the motors and any accompanying radial/axial bearings.

Multiple motor drivers for a hermetically-sealed motor-compressor system

This paper addresses the use of 5-hole probes in the testing of industrial centrifugal compressors. The 5-hole probes utilized for this work are of the conical-tip type and were used in a non-nulling configuration (i.e. the probes do not need to be rotated or moved in any way during the tests). These 5-hole probes proved to be fairly robust, making them practical for a non-laboratory setting such as an industrial multistage compressor test stand. A discussion of 5-hole probes and how they function is provided, including an overview of the mathematical formulations and calibrations required to translate the pressure data gathered from the 5 holes into static and total pressures, velocities and flow angles. A method to transform these variables from a probe-based coordinate system to a machine-based coordinate system is also presented and schematics of this process are provided to aid the reader’s understanding. The testing performed on a prototype multistage centrifugal compressor using 5-hole probes is also discussed showing that the probes provided valuable insight into the flowfield exiting the impellers and at the return bend. The hub-to-shroud velocity profile exiting an impeller was found to be more skewed than expected and was contributing to poor performance in the downstream stationary components. The measured flowfield from one of the tests is also compared against 3-D CFD results and comments are offered regarding the agreement between the analytical and measured results. Advantages and disadvantages of 5-hole probes as compared to more conventional instrumentation are presented. Finally, conclusions are drawn regarding the value of 5-hole probe data in the development and/or troubleshooting of high performance turbomachinery and in the validation / calibration of design and analysis tools.Copyright © 2004 by ASME

On the Use of Five-Hole Probes in the Testing of Industrial Centrifugal Compressors

This paper describes a full-scale, flexible test vehicle designed and built by the original equipment manufacturer (OEM) to validate the aerodynamic and mechanical performance of large compressors for a variety of applications. This paper provides a description of the test vehicle as well as mechanical and aerodynamic performance data gathered during testing of the vehicle.

Jose L. Gilarranz

Papers

Performance Evaluation Of A Centrifugal Compressor Operating Under Wet Gas Conditions.

Method and system for cooling a motor-compressor with a closed-loop cooling circuit

Multiple motor drivers for a hermetically-sealed motor-compressor system

On the Use of Five-Hole Probes in the Testing of Industrial Centrifugal Compressors

Full-Scale Aerodynamic And Rotordynamic Testing For Large Centrifugal Compressors.