Explosions in Gas Turbine Lube Oil Reservoir Result in Installation of Dry Gas Seal System

ES THE AMERICAN SOCIETY OF MECHANICAL ENGINEERS 345 E. 47 St., New York, N.Y. 10017 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. Papers are available ]^[ from ASME for fifteen months after the meeting. Printed in USA. Copyright 1989 by ASME 89-GT-222 Explosions in Gas Turbine Lube Oil Reservoir Result in Installation of Dry Gas Seal System LAWRENCE R. FERRILL, Mech. Eng. Phillips Petroleum Company Tananger, Norway N. DARYL RONSKY, P. Eng. Novacorp International Consulting Inc. Calgary, Alberta, Canada TIM A. HARRIS, P. Eng. Novacorp International Consulting Inc. Calgary, Alberta, Canada ABSTRACT Mechanical dry gas seal systems were retrofitted into two centrifugal natural gas compressors which are located offshore in the Norwegian sector of the North Sea. The project was initiated after a fire and several gas explosions had occurred in the gas turbine lube oil reservoir. These incidents were a result of gas leaking from the compressor's seal oil system and then migrating via the lube oil lines into the reservoir. The dry gas seal systems have eliminated gas leakage into the turbine lube oil reservoir, eliminating the hazard of gas explosion. The retrofits have also provided additional benefits including reductions in space and weight, reduced power usage, reduced maintenance, and elimination of seal oil consumption which had been up to 440 gal./day (2000 liters/day). INTRODUCTION Phillips Petroleum Co., Norway, is the operator of a number of oil and gas fields in the Norwegian sector of the North Sea, which are known collectively as the Greater Ekofisk Area. These fields are produced by 25 platforms located in approximately 325 ft. (100 meter) deep water. Oil and gas are produced and piped to Ekofisk Center via subsea pipelines. At Ekofisk Center, the oil and gas are separated, and then exported via its own subsea pipeline. The crude oil export line has a capacity of 1 million barrels/day (158,987 m 3 /day), and the gas export line 2.1 billion standard cubic feet/day (59,465 10 3m 3 /day). Equipment The Flash Gas Compressors are two Societe Rateau centrifugal compressors driven by General Electric gas turbines, Frame MS-3000, 13,500 HP (10,071 kw). The compressors operate at a speed of 11,675 rpm. The compressors have seven impellers in a back-to-back assembly, three in the low pressure section and four in the high pressure section. The compressors were equipped with Rateau's standard hydrodyne seal and seal oil system. Each compressor's lube and seal oil systems are common to its driving gas turbine's lube oil system. Process Crude oil and natural gas are pipelined from outlying platforms to a central processing platform called Ekofisk Center. There the crude either flows into a low pressure 100 psig (690 kpa), or intermediate pressure 265 psig (1827 kpa) oil-gas separator. The crude oil and natural gas are then separated and processed. The natural gas vapor in the low pressure 100 psig (690 kpa) crude oil production separator is compressed up to the pressure of the natural gas vapor in the intermediate stage crude oil production separator 265 psig (1827 kpa). This is done in the compressor's first section. Then, this gas stream is combined with the gas coming from the intermediate stage crude oil separator in the compressor's second section and is compressed to a pressure of 500 psig (3447 kpa). The gas is processed and compressed further into the sales gas pipeline system. Problem Several gas explosions and, on one occasion, a fire had occurred in one of the gas turbine's lube oil reservoirs. The explosions only occurred during times when the compressor was pressurized and a start-up or shutdown had been initiated. These incidents were a direct result of gas leaking from the Rateau compressor's seals and seal oil system, and then migrating through the seal oil drain lines into the turbine lube Presented at the Gas Turbine and Aeroengine Congress and Exposition June 4-8, 1989 Toronto, Ontario, Canada

oil reservoir. The subsequent investigation after each incident revealed the following: 1) It was suspected that the unearthed Dresser pipe coupling on the oil drain line of the gas turbine's number 4 bearing was acting as an electrical capacitor and was releasing an electrical charge from the coupling sleeve. This was not established with 100 percent certainty. 2) The explosions only occurred during start-up or shutdown of the compressor. The gas was able to accumulate in the lube oil reservoir and drain lines and reach explosive levels when there was either a small amount of air, or no air, sweeping through the reservoir, such as during shutdown or start-up. During normal operation, the lube oil reservoir atmosphere is changed out approximately every three minutes by the turbine bearing bleed-air. This air leaking into the reservoir prevents the accumulation of gas. To prevent accumulation of gas during start-up and shutdown, a purge air was connected to the reservoir providing purge air of approximately 10 SCFM (280 L/min.) to sweep out any natural gas. Purging was automatically started by the Speedtronic Control System logic. In addition to an existing 8-inch (219 mm) vent mounted on the side of the reservoir, a 6-inch (168 mm) vent was installed on top of the turbine's lube oil drain line where the compressor's lube oil drain line connects to it. (Near No. 4 turbine bearing.) 3) The degassing tank was not constructed to API specifications. The inside construction did not prevent gas within the tank from flowing with the return oil back into the turbine lube oil reservoir. Novacorp International, Calgary, Canada, had published an ASME paper presenting their successful retrofitting of the John Crane T-28 mechanical dry gas seals into their pipeline compressors. During a visit to two of NOVA's pipeline compressor stations, the dry gas seals and systems were operationally demonstrated to us. Measurements to check for the presence of gas in the lube oil reservoir and compressor bearing chambers during start-up, normal operation and shutdown indicated that no gas was present, thus leading to the decision to proceed with the retrofit project. MECHANICAL DRY SEAL SYSTEM DESIGN Design Requirements The fundamental premise for the retrofit was that the system must provide a barrier to prevent the escape of process gas to the bearing chamber of the compressor. The presence of any natural gas leakage into the bearing chamber was unacceptable. The operating conditions for this retrofit were: Discharge Pressure - 500 psig (3,500 kpa) Suction Pressure - 90 psig (620 kpa) Maximum Operating Temperature - 330 F (165 C) Shaft Size - 5.108 in. (129.74 mm) Operating Speed - 11,675 rpm Gas Sealed - Sweet Natural Gas Mechanical Gas Seal The mechanical seal was designed in a tandem configuration as illustrated in Figure 1. The primary seal achieves 100 percent of the sealing during normal operation. The secondary seal is a backup in case of primary seal failure. The seal cartridge was designed to allow easy installation and removal while retaining the PRIMARY - -PRIMARY SECONDARY SUPPLYLEAKAGE II LEAKAGE ^ 1Ij I 4) The sour oil drain traps were leaking gas into the degassing tank as a result of worn seats on the float valves. The problem was corrected by installing new, larger traps to increase oil residence time and to separate entrained gas from the oil. PROCESS GAS BARRIER SUPPLY DRY GAS SEAL SOLUTION FIRST STAGE ---^ I I- SECOND STAGE MATING RING JPRIMARY RING FIRST STAGE SECOND STAGE PRIMARY As a result of past unsatisfactory seal RING MATING RING oil system operation, it was decided that dry gas seals should be retrofitted into the Rateau compressors to solve the problem of gas leaking into the turbine lube oil reservoir. FIGURE 1 MECHANICAL DRY SEAL ARRANGEMENT 2

same shaft-to-seal and seal-to-housing locking and bolting assemblies as the hydrodyne seal. This meant little change in existing installation procedures. Purge Barrier The secondary seal leakage is extremely low. To prevent this minimal leakage migrating into the compressor bearing chambers, a purge air barrier labyrinth is built into the bearing end of the seal. This purge air barrier prevents lubricating oil and secondary gas leakage from ingressing and contaminating the secondary seal. Rotor Dynamics The rotor dynamic behavior of the compressor was recalculated with the new dry gas seals. The changes in rotor dynamic behavior were negligible. Figure 2 illustrates the critical speed map for both before and after the dry seal retrofit. 10000 CRITICAL SPEED MAP FOR MODIFIED ROTOR REVOLUTIONS PER MINUTE The active and standby filters are monitored by a differential pressure gauge and a warning switch. The filters have a double block and bleed system to allow on-line changing of the filter elements. The primary leakage is monitored to determine if the primary supply is working properly and if the primary seal is functioning correctly. A low pressure and a high pressure alarm switch, and a high pressure shutdown switch are included in the primary leakage line. The supply gas must be present in order for the vent pressure to be high enough to actuate the low pressure switch. If the primary seal leakage becomes excessive, the high pressure alarm, and then the high pressure shutdown switches, will be activated. The primary leakage is vented to atmosphere. A relief valve provides extra capacity to vent should a massive primary seal failure occur. The purge barrier air is supplied by a clean dry source of instrument air. A pressure switch annunciates an alarm should the supply of air be stopped. The purge barrier air mixes with the secondary leakage and is vented to the atmosphere. The secondary leakage is not monitored. The gas leakage approximately.005 SCFM (.14 L/min.) is mixed with purge barrier air and is simply vented to the atmosphere. On the vent line is an oil drainer trap, which removes any lube oil. Figure 3 illustrates the dry seal system instrumentation. fa 1000 +- 10000 100000 1000000 BEARING STIFFNESS (LBS/IN) FIGURE 2 CRITICAL SPEED MAP BEFORE AND AFTER DRY SEAL RETROFIT Control System The control system consists of six alarms and two shutdown devices. All switches, filters, and valves are mounted in a 4.9 ft. x 6.6 ft. (1.5 m x 2.0 m) stainless steel panel located near the compressor. The flow of gas through the seal, purge barrier, and the associated control systems can be divided into four areas: 4'MCSPH ERE CRAIN Primary Seal Gas Supply Primary Leakage Purge Barrier Gas Supply Secondary Leakage Filtered primary seal gas is provided to the primary seal faces to prolong their life and prevent contamination of the primary ring. The source for the seal gas is a clean, dry, pipeline quality gas with a pressure of 400 psig (2758 kpa). (Compressor discharge gas was not used because there is a slight amount of NGL entrained in the gas stream.) Some of the supply gas flows through the seal and out the primary vent. The majority flows back into the compressor to suction. ORIFICE LEGEND El - FLOW INDICATOR FIGURE 3 MECHANICAL DRY SEAL SYSTEM INSTRUMENTATION PSI -PRESSURE SWITCH LOW PSM - PRESSURE SWITCH HIGH PSMM - PRESSURE SWITCH WISH-RICH PT -PRESSURE TRANSMITTER D11511 - DIFFERDS IAL PRESSURE E WCM HIGH Annunciation The existing General Electric Speedtronic panel had no extra annunciation capacity, so a custom annunciation panel was manufactured and installed. This panel graphically illustrates 3

the alarm and shutdown features of the control system. Figure 4 illustrates the Custom Annunciation Panel. MECHANICAL ONT SEAL ANNUNCIATION PANEL DYNAMIC TEST RESULTS WITH AIR LEAKAGE (L/M) 80 80 60 60 40 40 l_ l IN 3 20 20 LI 0 J L14 L1 0 200 400 600 800 1000 1200 PRESSURE (PSIG) anu i"'o.. ws ^'o" I VALUES ARE AN AVERAGE OF THE INBOARD AND OUTBOARD SEAL LEAKAGES 6250 RPM -- 12 450 RPM FIGURE 4 CUSTOM ANNUNCIATION PANEL SEAL TESTING FIGURE 5 SEAL TEST RESULTS INSTALLATION The six seal cartridges for this retrofit (four operational and two spare) were shop tested by the manufacturer. The testing was performed with air as the test medium. The test procedures included: 1) Static testing to maximum operating pressure 1200 psig (8274 kpa). 2) Dynamic testing at half operating speed with seal pressure increasing in steps from minimum pressure to operating pressure. 3) Dynamic testing at full operating speed with seal pressure increasing in steps from minimum pressure to maximum operating pressure. 4) Dynamic testing for two hours at operating speed and pressure. 5) Dynamic testing at 105 percent overspeed for five minutes. 6) Seal disassembly and inspection of faces and secondary sealing elements. During seal inspection, evidence of explosive decompression was observed in secondary seals. This was attributed to an error in testing procedures and, once corrected, testing proceeded smoothly. The results of dynamic testing are presented graphically in Figure 5. The installation proceeded in two phases. Flash Gas Unit 2 was retrofitted in January of 1988, with Flash Gas Unit 1 completed in April, 1988. In advance of the system installation offshore, a spare compressor rotor was modified to accommodate the gas seals. The modifications required grinding down two shaft steps in the hydrodyne seal area at both ends of the rotor. The installation itself involved the following steps: 1) isolate the operational compressor; 2) drill the purge air passages in the compressor end heads; 3) modify the existing inboard seal-oil labyrinths next to the seals; 4) remove the complete seal-oil system. [This proved to be a major job with the seal-oil console distributed between two decks. The entire console encompassed a 13.1 ft. x 6.6 ft. x 6.6 ft. (4 m x 2 m x 2 m) area, and weighed approximately 3500 lbs. (1590 kg)]; 5) install the dry seal instrumentation panel and connect it to the compressor; 6) install the annunciation panel and connect its instrumentation into the G.E. Speedtronic Controls logic; 7) connect the primary vent leakage pressure transmitter into the condition monitoring system. The retrofit project went smoothly from the beginning of installation through commissioning. 4

The only technical problem was experienced on the first retrofit when a slight amount of lube oil leaked into the secondary seal cavity. The oil was leaking inwardly through the seal's sleeve lock nut threads. There is a.157-inch (4 mm) gap between the inboard side of the journal bearing and the seal's sleeve locking nut. Lube oil leakage toward the seal was reduced by minimizing the oil flow into the journal bearings and installing a special oil seal in the inboard side of the journal bearings. Additionally, silicone sealant was applied to the lock nut threads. These measures eliminated the problem. Computerized Condition Monitoring System The gas leakage from the primary seal is monitored and trended by an "on-line" rotating equipment condition monitoring system (CMS). In 1985-86, an on-line monitoring system was installed offshore on four G.E. Frame 5002B gas turbines and Dresser-Rand pipeline compressors. The system provides an up-to-date (real-time) analysis of the mechanical characteristics of the turbines and compressors, such as vibration frequency analysis, bearing temperatures and wear rates, as well as thermodynamic data such as polytropic head and thermal efficiency. The system captures data and produces trend curves to aid maintenance planning. Even though the CMS was not dedicated to the Rateau compressors, there was extra space within it to permit connection of the primary gas leakage lines' pressure transmitters. Figure 6 illustrates gas leakage for a six-month period of time. PUg 10 20 P0-304, FLASHGAS 2 INBOARD LEAKAGE 0, -. 'v'";1 " CONCLUSION The retrofit project was premised on improving operating safety of the Rateau compressors by elimination of natural gas leakage into the compressor bearing chambers and the turbine's lube oil reservoir, which it has done. Additional benefits were: - simplification of the seal system controls; - reduction of space and weight (important on offshore platform); - elimination of seal-oil leakage into the compressors (the leakage before the retrofit had been as high as 440 gal./day (2000 liters) of oil per machine); - power reduction of approximately 135 HP (100 kw); - reduced maintenance; - increased reliability and availability of compressors. The seal system has operated faultlessly since installation. REFERENCES 1. Hesje, R.C., and Peterson, R.A., "Mechanical Dry Seal Applied to Pipeline (Natural Gas) Centrifugal Compressors." ASME 84-GT-3, (1984). 2. Pennink, H., "The Gas Lubricated Spiral Grooved Face Seal in the Process Industry", from proceedings of the Fourteenth Turbomachinery Symposium, Texas A & M University, (1985) p. 59-64. 3. Gabriel, P.G., "Fundamentals of Spiral Groove Noncontacting Face Seals", ASLE 78-AM-3D-1, (1978). 4. Sedy, J., "A New Self Aligning Mechanism for Spiral Groove Gas Seal Stability", ASLE 79-LC-3B-3, (1979). P,ip 10 20 P6-305 FLASNGAS 2 OUTBOARD LEAKAGE 20 PR - 6288 FLASHGAS I OUTBOARD LEAKAGE P g 10 1 20PX-6287' FLASHGAS INBOARD LEAKAGE P g 10 0 40 80 120 160 200 240 280 320 360 Dot's FIGURE 6 DRY GAS SEAL LEAKAGE FROM FLASH GAS UNITS OVER A 360-DAY PERIOD 5