Copyright 1983 by ASME TURBINE OR ELECTRIC MOTOR DRIVEN GAS COMPRESSORS ON PRODUCTION PLATFORMS

Transcription

1 THE AMERICAN SOCIETY OF MECHANICAL ENGINEERS 345 E. 47 St., New York, N.Y GT-114 The Society shall not be responsible for statements or opinions advanced In papers or in discussion at meetings of the Society or of Its Divisions or Sections, or printed in its publications. Discussion is printed only if the paper is published in an ASME Journal. Released for general publication upon presentation. Full credit should be given to ASME, the Technical Division, and the author(s). Papers are available from ASME for nine months after the meeting. Printed in USA. Copyright 1983 by ASME TURBINE OR ELECTRIC MOTOR DRIVEN GAS COMPRESSORS ON PRODUCTION PLATFORMS J.M. Overli Den norske stats oljeselskap a.s (Statoil) Trondheim, Norway and R. Magnusson Norwegian Petroleum Consultants a.s Oslo, Norway ABSTRACT This paper describes the results obtained from a study commissioned to ascertain the optimum drive arrangements for the gas compression machinery to be installed on an integrated platform in the North Sea. The study was restricted to two main drive type alternatives: - All compressor stages on one shaft driven by a variable speed aeroderivative gas turbine. - All compressor stages with separate, constant speed, electric motor drives The study took into account drive option and shafting arrangements with regard to flexibility of operation, weight, area, lay-out, foundation/alignment, waste heat recovery requirements, availability/reliability, safety, maintenance, fuel consumption, investment cost and operational experience. For the specific case studied, the overall conclusion was in favour of the gas turbine drive alternative. INTRODUCTION It is less than twenty years since the first small production platforms went on stream in the North Sea. Since then it has provided an expanding market for electric power and mechanical drive equipment. More than 1,5 million kw's of power are installed for mechanical drive on platforms offshore. Traditionally, the gas associated with crude oil production has been regarded as a product of secondary importance. However, since the energy crisis of 1973, the authorities have put more stringent restrictions on the flaring of gas. The price of gas today is almost equal to the price of oil for an equivalent energy quantity. This means that for a typical production facility in the North Sea the daily gas production may yield up to nearly 10% of the oil revenue. This is, however, dependent upon the gas-oil-ratio of the field. The aim, therefore, is to export the gas at suitable pressure to a point of distribution on land. This inevitably requires that a gas compression train is installed on the platform. At an early stage in the conceptual design of production facilities for an offshore platform, the drive arrangement for the recompression units have to be selected [1]. This paper discusses the design features of selecting either gas turbines or electric motors as prime movers for the gas compression machinery to be installed on a typical integrated platform in the North Sea. OIL AND GAS PRODUCTION ON PLATFORMS On a typical oil field platform, it is always necessary to separate the gas from the oil to stabilize the oil for transport purposes. For this reason separators and gas compressors are installed on the platform. For a typical gas field like Frigg, gas compressors are normally not installed for the initial production phase. However, when the reservoir pressure falls below a certain limit, compressors will have to be installed in order to provide the necessary transport pressure in the pipeline. Statfjord is a typical oil producing field yielding associated gas. A simplified flow diagram of the Statfjord A processing scheme is shown in Fig. 1 [2]. Four stages are used for the separation of oil and gas in two identical process trains. In order to have flexibility in operation, three parallel compression trains are installed. The design capacity of each compression train is 50% of the assumed total gas production, resulting in a stand-by capacity of 50%. Each centrifugal compression train is driven by an advanced aero-derivative gas turbine (LM 2500) through a speed increasing gearbox. Gas, oil and water flow from the reservoir into the first stage separator at an absolute pressure of 69 bar. In the three downstream separators the fluid pressure is gradually decreased and gas is flashed off. The operating pressures of these separators

2 FIG. 1 PROCESS FLOW FOR STATFJORD A are 22.7, 6.9 and 1,7 bar respectively. The export gas compressor raises the pressure to 218 bar. High speed single stage reciprocating compressors are used for reinjection of gas into the reservoir at a final pressure of 380 bar. MACHINERY ON PLATFORMS Compressors All of the oil producing installations have gas compression of some kind. The compressors used are usually of the radial flow, centrifugal type, driven by a gas turbine or an electric motor. Above a certain operating pressure the compressor casing consists of a vertically split forged steel barrel. However, for certain low flow and high head applications such as for gas reinjection, reciprocating compressors may be more suitable. In any offshore application a wide range of gas flow will always have to be considered, depending on the size of the oil or gas field and the number of wells in operation at any given time. The variation in flow can be accommodated by using multiple compression trains in parallel or by using the turndown capability of individual machines. It is believed that the selection of a centrifugal compressor should be made to meet four simultaneous objectives [3]: - cost - flexibility - performance - reliability The relative importance of these objectives is subject to discussion. For high pressure installations the most delicate aspect in the operation of these machines is the lateral behaviour of the rotor which can give rise to vibration. Another aspect of concern is axial thrust. Gas Turbines There are two basic types of gas turbines available on the market, the heavy-duty industrial gas turbine and the light-weight aero-derivative turbine. While the basic thermodynamic cycle is the same for both types of gas turbine, there are fundamental differences in the design concepts for the two types. The heavy industrial type is purposely built for its intended land-based role as compared with the aero-derivative type whose basic design has been optimized with emphasis on different criteria, such as: - Better power output to size and weight ratio - Substantially less maintenance time - Faster start-up in emergency - Superior peak load capability Fig. 2 illustrates the growing trend towards aero-derivative turbines for offshore use [4]. The advantage of reduced weight is illustrated by Fig. 3 [2]. Some of the gas turbines available today in the power range of 20 MW have almost the same efficiency as diesel engines. This is the case for the General Electric LM 2500 and the Rolls Royce RB 211 gas turbines. Smaller gas turbines in the 10 MW class have, however, efficiencies of approximately 70% of these. Table 1 shows some of the main data for the two specific gas generators with typical power turbines [5]. 2

3 The gas compressors normally run in the speed range r/min. In order to keep the step-up gear units as small as possible, electric motors with 2 poles and synchronous speed of 3600 r/min will often be preferred. On many installations motors running at 1800 r/min are selected for the following reasons: - higher mass moments of inertia can be handled - motor oscillations will be smaller - electric field oscillations are smaller FIG. 2 TREND TOWARDS AERO-DERIVATIVE GAS TURBINES Starting problems with electric motors have often been experienced on platforms. When motors are started, they draw a high inrush current that depresses line voltage. This in turn results in a reduction of motor starting torque by the square of the voltage drop. This reduction in available torque usually requires that the motor-driven compressors are started with inlet guide vanes or valves closed for a short period of time. A typical compressor speed-torque curve is shown on Fig. 4 [6]. A 2ND ERATION AERO-DERIVATIVE B 1ST ERATION AERO DERIVATIVE C HEAVY-DUTY INDUSTRIAL 02- O ENGINE POWER )MW) FIG. 4 TYPICAL COMPRESSOR SPEED-TORQUE CURVE FIG. 3 SHAFT POWER/WEIGHT FOR GAS TURBINE PACKAGES TABLE 1 BASIC DATA FOR AERO-DERIVATIVE TURBINES Gas turbines LM 2500 RB 211 Power output, ISO (kw) Pressure ratio Mass Flow (kg/s) Heat rate (kj/kwh) Power turbine speed (r/min) Electric Motors Both induction motors and synchronous motors are used for compressor drive. The synchronous motor is usually the primary choice for very large power ratings. Its higher efficiency and inherent ability to correct power factor can make the motor economically more attractive in spite of higher initial investment cost [6]. EXAMPLE OF COMPARISON OF DRIVE ALTERNATIVES Process Data The study is based on the requirements of an integrated (PDQ) platform with an assumed peak oil production of 245,000 barrels/day to be landed by offshore loading,- and a peak gas production of 3.5 million m 3 /day. The gas not consumed on the platform is either transported by pipeline to shore, or reinjected into the formation. Gas-oil separation occurs in two, threestage separation trains, each with a design capacity of 50% of the total flow. Flashed gas from these separators is compressed in one of two centrifugal compression trains consisting of four stages of compression. Each train will have 100% capacity for the flash gas produced. The basic design data, associated with the inlet and outlet conditions for each compressor stage necessary for selecting the proper compressor type and the appropriate performance characteristics are listed in Table 2. 3

4 H TABLE 2 COMPRESSOR DESIGN DATA COMPR. PRESSURE TEMP. MOL. VOLUME FLOW STAGE INLET OUTLET INLET WEIGHT INLET (bar) (oc) (m3/s) POWER STATION COMPRESSOR STATION 1 X L_ L Identification of Alternatives Although several options exist, the operating oil companies have, to date, limited the compressor drive options to gas turbines and electric motors. The optimum choice of prime movers for the compressors in any given situation can only be arrived at by thoroughly analysing such variables as [7]: - fuel consumption/efficiency - process data (flow, temperature, pressure, molecular weight) - availability/reliability - area and weight - investment cost - operational flexibility - operation and maintenance cost - simplicity in construction and lay-out - easy maintainability - noise - safety The optimum solution would obviously be that choice which maximises the benefits while minimising the costs. In the search for the optimum selection, it is necessary to identify and investigate all compressor arrangements, using either gas turbines, or electric motors, or a combination of gas turbines and electric motors. Additionally, it is possible to drive one or more compressors on a common shaft with either a gas turbine or an electric motor. To facilitate comparison, the number of alternatives was reduced to two. Electric Drive Alternative: A simplified lay-out arrangement is shown in Fig. 5. The compressors are all driven by constant speed electric motors. Essentially, two process trains exist. However, it must be noted that each of the compressors on stages I, II and III are all designed for 100% production capacity, while the three compressors on stage IV are all designed for 50% production capacity. Consequently, regardless of which train is in operation, two of the compressors in stage IV will be operating in order to handle 100% capacity in the final compression stage. Additionally, it was decided that the compressors for stages I and II should be on a common shaft. FIG. 5 ELECTRIC DRIVE ALTERNATIVE Gas Turbine Drive Alternative: A simplified compressor lay-out arrangement is shown in Fig. 6. This arrangement consists of two 100% capacity process trains, each driven by a gas turbine. The compressors, stage I through IV are all assumed to be on a common shaft, with the gas turbine connected at the end of the largest compressor. The type of gas turbine was restricted to the General Electric LM 2500 and the Rolls Royce RB 211. POWERSTATMN COMPRESSOR STATION T L FIG. 6 GAS TURBINE DRIVE ALTERNATIVE COMPARISON OF THE TWO OPTIONS Availability/Reliability A Fault Tree Analysis (FTA) was employed to compute and compare the total availability for the two alternatives under consideration. The fault tree for the gas turbine case is shown in Fig. 7. The analysis was based upon statistical values for failure rates, mean repair times and mean overhaul times for all the individual components. Data for start and stand-by failures were also included in the study. As an example, these failure rates (per 10 6 hours) were applied: - electric motor gas turbine gear generator 24 - compressor 117 4

5 C,0114,ESSOR G - HIGH- SPEED GEAR GT- GAS TURBINE Gen - ERATOR FIG. 7 FAULT TREE ANALYSIS OF GAS TURBINE DRIVE ALTERNATIVE The evaluation concluded that there was no significant difference between the two alternatives. The computed availability of the complete systems comprising power station and compression units, appeared to be in the range 91-93%. Sensitivity analysis were also carried out by changing the availability values of the different components in the FTA-system. No significant tendency was found favouring one system over the other. However, in this study the influence of false alarms and trips from external sources was not included. Operating Flexibility The duty on the compression train will be particularly arduous because of the variation in types of reservoir fluid to be processed. Overall gas-oil-ratio will vary and thus any compressor selected must have the flexibility to accomodate turndown as a normal mode of operation, particularly in the pre- and postplateau production phases. Also, different gas rates and molecular weights resulting from changes in the reservoir fluid type have to be considered in the design. In the electric drive alternative it is possible to change operation from one compressor in one train to the corresponding compressor in the other train, with minimum interruption in operation. This increases the flexibility of operation during maintenance and repairs. The equivalent possibility does not exist in the gas turbine drive option. The fixed speed motors have less flexibility to accomodate off-design operation without starting the actual stand-by compressors. On part load and at design molecular weight, stable operation is ensured by suction throttling and recycling. The use of inlet guide vanes was considered impractical due to the mechanical complexity of operation. A lower than design molecular weight will require a larger compressor, and a higher than design molecular weight will require a larger motor. In fact, if variations in molecular weight are expected, the compressor must be designed for the lowest molecular weight and the motor for the highest. If the molecular weight turns out to be as designed for this situation, then severe throttling and recycling must be made in order to obtain design discharge pressure, resulting in increased fuel consumption. Changing the gear ratio between the motor and the compressor to accommodate different molecular weight gases is possible in principle, but it is costly and the delivery time is long. A better solution may be to install a dummy stage in the compressor, in which an additional wheel may be installed later to provide the same effect. However, in any case, the electric motors must have a power rating well above that required for on-design operation. Due to the wide pressure and volume changes between suction and final discharge flows, the design of a fixed speed compressor train presents some problems. Ideally the machine requires large diameter low speed wheels at the low pressure end with smaller diameter high speed wheels at the high pressure end. Constraining the machine to run at fixed speed imposes limitations on controllability and operational flexibility. In order to assess the overall system capability to recover from a process disturbance, it is recommended that a dynamic simulation study is performed. The study should make use of a simulation model in which the predicted compressor performance is incorporated together with models representing the behaviour of process equipment, vessels and control systems. Dimensionless compressor performance 5

6 curves for the gas turbine drive alternative are plotted in Fig. 8. The electric alternative requires about 20% more area than the gas turbine alternative. The study revealed that the electric drive option is approximately 20% heavier than the gas turbine option. These figures have been based on the assumption that in the gas turbine drive alternative 4 gas turbines are installed on the platform, and in the electric drive option only 3 turbines are installed. Investment Cost Even with one gas turbine less installed on the platform in the electric drive alternative, the initial investment cost of the necessary equipment is expected to be almost 15% higher. In this analysis the cost for bulk materials and labour is based upon actual Statfjord cost. FIG. 8 DIMENSIONLESS COMPRESSOR PERFORMANCE CURVES AT 100% SPEED Fuel Consumption A comparison of fuel cost for driving the compressors was made at full load and part load conditions. No attempt was made to accumulate the fuel cost over the productive life of the plant. The gas turbine drive alternative will give the lowest fuel consumption, i.e. approximately 7% less fuel consumption at full load. At part load the fuel cost differences is higher. In addition, a simplified fuel cost analysis was performed, taking into account the main power consumers on the platform including the compressor drive. The total fuel consumption is approximately 3% in favour of the gas turbine drive alternative at both peak and at half production. At 30% production rate, the fuel cost is 6% lower in the electric drive alternative. In this case only two generator turbines are assumed operating in the power station. This conclusion is specific to the case studied. For another case, where smaller and less efficient gas turbines are employed, fuel consumption may favour the electric drive alternative. Area and Weight The space requirement for both alternatives was minimised by providing only sufficient space around the machinery for maintenance purposes and necessary escape. This implies that piping to and from the compressors was run vertically through the deck. Areas for control equipment and various auxiliary systems were also taken into account. Maintenance A proper periodic inspection, repair and replacement of equipment is required to achieve optimum availability for both options. A preventative maintenance program on electric motors and generators is estimated to be less costly than that required for gas turbines. Turbines operating on a platform will normally experience salt and drilling mud dust build-up. Filtration of the intake air must be applied to provide protection against erosion, fouling and corrosion. In spite of the filtration the gas turbines have to be shut down periodically for a waterwash. This will apply to both compressor drive turbines and generator turbines. Furthermore, in the gas turbine drive option the compressor drive turbines will have to be placed in a different location from the generator turbines on the platform. This is not regarded beneficial from a maintenance point of view. Consequently, the electric drive alternative may be preferred for reasons of maintenance. Costwise, the difference is estimated to be negligible. Foundation/Alignment Any steel or concrete structure will give a static deflection when subjected to a heavy load. Secondly the deck suffers dynamic deflection due to wind and waves. Vibration induced by rotating equipment and piping on the platform might also create a problem. After all the equipment is in place, the static deflections can be coped with by various alignment procedures. It is important to keep the misalignment of the flexible coupling within the deflection tolerances. A common shaft system with a very long compression train may create lateral vibrations and whirling. Nevertheless there is some proven experience of four compressors in three casings in offshore use. With respect to vibrations and alignment the conclusion is in favour of a short electric motor shaft arrangement. 6

7 Heat Recovery The recovery of heat from gas turbine exhausts is widely used on landbased installations, primarily as part of a gas turbine/- steam turbine combined power generation cycle. Offshore, the use of waste heat recovery units is limited to the use in a closed circuit process. The primary effect of the installation of waste heat recovery units in the flue gas ducting of the gas turbine generators is to increase the back pressure imposed upon the power turbines. This increase in back pressure results in a lower pressure ratio across the turbine and a corresponding reduction in power output at a given gas generator throughput. It is estimated that about 18 MW can theoretically be recovered per set from a 20 MW aeroderivative gas turbine, cooling the flue gas temperature at the heat exchanger outlet to approximately 200 C. This temperature is well above that corresponding to the sulphuric acid dewpoint. In the study case, if 36 MW is sufficient to serve the process, there is no difference between the two options. For the gas turbine option, if more heat is required, alternative heat sources must be installed on the platform. One option would be to employ waste heat recovery units in the compressor gas turbine exhaust. This would necessitate the installation of heat recovery units in two different locations on the platform. There is, as yet, limited experience for such an arrangement. Therefore, the electric drive alternative may provide a better solution. Main Power Station At the peak of oil and gas production of the field, the total power requirement will be more than 50 MW. Almost 20 MW is used for gas compression. The remaining is used for oil production, water injection, light, heat, safety equipment, drilling and maintenance of wells. The electrical load conditions on the platform are estimated to be as follows: Normal drilling 3.8 MW Water injection 14.2 MW Production 10.2 MW Normal life support and emergency power 7.6 MW Subtotal 35.8 MW Gas compression (electric drive) 18.2 MW Total 54.0 MW The number of generators to be used in the main power station is a function of the production profile and the type of drivers chosen for the compressors. In the first year of platform operations, and also after peak production has been reached, the power requirement is reduced. The duration of peak production compared to the total lifetime of the field is also essential for the lay-out of the main power station. In the actual situation the use of electric drive for the compressors will increase the generator stand-by capacity in the main power station. At 30% production rate only two of three available generators need to be in operation. In the case where the compressors are driven by electric motors, the power requirements for each motor will be approximately 2-8 MW. The voltage drop created by starting such machines is influenced by the capacity and the number of generators in operation in the main power station. On production platforms normally 20% voltage drop is permissible. The worst case when starting a motor will be with only one generator in operation. In this situation electric motors larger than 5 MW will cause severe voltage drop in the power system. Safety The turbine room may be classified as a safe area provided that the room is adequately ventilated with an overpressure and the fuel gas pipe to each turbine hood has no more than one pair of flanges inside the room. The compressors constitute a secondary source of hazard and the compressor module will be classified as such. The routing of fuel gas pipelines for turbines to different parts of the platform will increase the potential sources of gas leakages due to increased number of flanges and valves. With the electric drive alternative all the motors must be pressurized and cooled. The four gas turbines, in two different locations for the gas turbine drive, may be considered to constitue an additional element of hazard. From a safety point of view, the all electric approach" may have some advantage. Field Experience In selecting equipment for offshore application it is of paramount importance that the equipment has proven experience in similar service and environment. Fig. 9 gives an indication of the relative magnitude in shaft power of gas turbine driven compressors versus electric motor driven compressors installed in the North Sea. A review of the individual curves provide no conclusive evidence that there is a trend towards the application of electric motors as prime movers for the compressors. It appears that the use of gas turbines is on a continual rise, while the use of electric motors is more sporadic. The following platforms account for the majority for the so-called "all electric" installations: - Brae - Brent - Magnus - Ninian - Thistle The total installed compressor power is approximately 150,000 kw of which the Brent platform alone accounts for about 90,000 kw. 7

8 sors, Lecture no. 1, Stavanger, Bardsley, K. W., Prosser, N. J., "Gas Turbine Experience in the North Sea Environment", The Institution of Mechanical Engineers, C 237/81, 1981, pp "Nominal Performance Specifications for Users and Consultants", Gas Turbine World, Moore, J. C., "Electric Motor Drivers for Centrifugal Compressors", Hydrocarbon Processing, May 1975, pp Magnusson, R., "Drift av kompressorer pa produksjonsplattformer", NIF-kurs i Roterende maskineri i off shoreindustrien, Fagernes, FIG. 9 ACCUMULATED COMPRESSOR POWER IN THE NORTH SEA CONCLUSION For the two drive alternatives under consideration it may be concluded that with respect to: Area and weight requirements, investment cost and fuel consumption, the conclusion is in favour of the gas turbine alternative. Molecular weight changes and especially for molecular weights lower than design, the gas turbine drive alternative can meet such variations better. Flexibility of lay-out, mounting/alignment and safety the conclusion is in favour of the electric drive alternative. The ability of accomodating day-to-day deviations from design flow, the two alternatives can be regarded as practically equal. Availability/reliability and maintenance, these factors do not particularly favour one alternative over the other. Past experience and future trends there is no distinct tendency towards electric motors as prime movers for gas compression applications. The overall conclusion is in favour of the gas turbine drive alternative. REFERENCES 1 Viani, R. E., The All Electric Approach to Offshore Oil Production Facilities", Gas Turbine Reference Library, GER-3109, Hancock, W. P., "The Development of Reliable Gas Re-injection Operation for the North Sea's Largest Capacity Production Platform - Statfjord A", Society of Petroleum Engineers of AIME, 57th Annual Fall Technical Conference, New Orleans, Overli, J. M., "Gas Turbines and Centrifugal compressors offshore", Short Course in Gas Turbine Technology and Turbocompres- 8