Joseph K. Lillard
Mafi-Trench Corp.
Santa Maria, Calif.
Gregor Nicol
Mobil North Sea Ltd.
Aberdeen
To expand the St. Fergus gas-reception terminal for the Scottish Area Gas Evacuation (SAGE) system, Mobil North Sea Ltd. is adding a second separation train and two treatment trains.
This project, Phase B, will bring the terminal's capacity up to 1. 15 bscfd from 500 MMscfd.
To meet pipeline-gas specifications over a wide range of flow rates and feedgas compositions, single-stage turboexpander chilling was selected over Joule-Thomson valve expansion.
Four turboexpanders (two per process train) will operate in parallel to achieve the required performance over the entire flow range of 90-575 MMscfd per process train.
Unusual operating conditions for the turboexpanders include dense-phase inlet gas, expansion near the cricondenbar, and high equilibrium liquid content at the exhaust (up to 50 wt %). The two turboexpanders in each train share common suction and discharge facilities as do their associated brake compressors.
Details of the more than 400 million Phase B discussed here include commissioning, start-up, and operation.
PARTNERS, FIELDS
SAGE system partners are Amerada Hess Ltd., Bow Valley Petroleum (UK) Ltd., British Borneo Oil & Gas Ltd., British Gas Exploration and Production, British Gas North Sea Holdings Ltd., British Petroleum Exploration Operating Co. Ltd., Enterprise Oil Plc, Kerr-McGee Oil (UK) Plc, LL&E (UK) Inc., Marathon Oil U.K. Ltd., Mobil North Sea Ltd., OMV (UK) Ltd., and Sovereign Oil & Gas Plc.
The SAGE pipeline system and gas terminal at St. Fergus were built and are being operated by Mobil North Sea to process gas from three North Sea producing fields: Beryl, operated by Mobil North Sea; Scott, operated by Amerada Hess Ltd.; and Brae, operated by Marathon Oil UK Ltd. (Fig. 1).
Construction of Phase A was completed in mid 1992 and has processed gas from Beryl since then and from the Scott field since November 1993. Current processing capacity is 500 MMscfd of sweet feed gas.
Upon completion of Phase B later this year, the plant will be capable of processing 1,150 MMscfd of sour gas following addition of a second separation train and two treatment trains, as stated.
Following gas-liquid separation and treatment, gas is exported into the British Gas Corp. distribution network via British Gas' terminal also at St. Fergus. Most gas is bought by British Gas to sell to its domestic and industrial customers, but a significant proportion is marketed by the SAGE partners directly to industrial consumers.
Associated NGLs move approximately 130 miles by pipeline to the Shell (U.K.) Exploration & Production (Shell Expro) NGL fractionation plant at Mossmorran via the Shell terminal at St. Fergus (OGJ, Mar. 8, 1993, p. 37).
Future facilities will include NGL export to the BP crude-oil pipeline coming ashore at Cruden Bay about 15 miles south of St. Fergus.
TWO-TRAIN PROCESS
The plant consists of two identical process trains (Fig. 2) with a design performance for producing sales gas to specification (Table 1). To avoid liquid drop out in the pipeline, the pressure is maintained at greater than the gas cricondenbar at between 120 and 165 bar gauge (barg).
The inlet knockout drum is provided not as a slug catcher but to drop-out such contaminants as lube oil and glycol from the offshore processing facilities.
Pressure into the dehydration unit is controlled at 114 barg at which the gas is dried to less than 1 ppm (v) before being chilled as part of the gas-liquid separation process.
The high integrity instrumentation-protection system's valves protect the plant against overpressurizing from the pipeline. They close when pressures immediately downstream of the letdown station or at the sales-gas metering reach preset values as measured from three discrete pressure transducers at each location.
A two-out-of-three voting system and regular maintenance ensure reliability to be ten times greater than for a relief-valve system; that is, probability of failure on demand is ten times less than a relief-valve system.
The significance of this is covered in a subsequent section.
The back pressure control valves downstream of the sales-gas metering allow the plant to operate at the British Gas pipeline pressure (valves fully open) when operating the plant on Joule-Thomson (JT) valve and to control back pressure to a higher value for expander operation.
For some feed-gas compositions, pipeline-gas specification can be met with JT-valve operation alone. Expander operation, however, allows lower temperature processing and greater NGL recovery which allows the plant greater flexibility to process different feeds.
GAS-LIQUID SEPARATION
It was necessary to design the plant to process a wide range of feed-gas compositions. Table 2 shows the design reservoir gas streams from which almost any mixture into the plant is possible.
For this reason, single-stage turboexpander chilling was selected over JT-valve operation.
To achieve the required performance over the entire flow range for each train (90-550 MMscfd), two expanders operating in parallel were installed, each capable of processing 300 MMscfd.
The plant is controlled by a distributed control system. Primary interlocking and emergency shutdown is performed by a separate PLC-based system although expander sequencing is controlled manually by the operators (PLC = programmable logic controller).
Manual sequencing has in fact proven beneficial as operating procedures have been modified following commissioning experience. A PLC-sequencing system would have been less flexible and more difficult to modify.
Fig. 3 gives a simplified view of the separation train's layout and control. Essentially, flow through the plant is manually controlled by the operator's varying expander guide-vane position or JT-valve opening or both.
Fig. 4 shows two views of a single installed unit.
Automatic pressure control is performed at three points: the pressure letdown station (Fig. 2), the back pressure control valves (Fig. 2), and the expander discharge drum (Fig. 3).
The last of these limits differential pressure across the expander to a pre-set value by opening the compressor recycle valve via a low-signal select within the distributed control system's anti-surge control system.
Gas from the expander discharge drum is warmed then mixed with gas off the stabilizer feed drum before flowing into the recompressors. Stabilizer feed-drum pressure is controlled at 1 bar less than expander discharge-drum pressure to maintain liquid flow.
The liquid pressure is dropped further before it enters the stabilizer columns and the off-gas from the stabilizers is compressed to mix with the gas from the recompressor.
TURBOEXPANDER SELECTION
In 1990, Mafi-Trench Corp. received the contract to provide the two parallel expanders for Phase A.
To reduce both initial cost and installation costs, the two turboexpander units were mounted on a single support skid with common lube oil, seal gas, instrumentation, and control systems.
All necessary valving and interlocks were provided to allow for operation of either machine individually or both together.
Process-piping design requirements were met by mounting the machines inline with 10 m between centers (Fig. 5).
The expander casing is designed for a pressure of 125 bar, while the compressor casing and bearing housing are designed for 88 bar.
Casings are cast from ASTM A351 Gr. CF3M stainless steel and are radiograph quality in accordance with Mobil Engineering Guides.
The variable-position inlet guide vanes provide high efficiency over the wide operating range required for this application. Special coatings are used to eliminate binding and galling.
The rotor including shaft, wheels, bearings, and seals is assembled within the bearing housing, forming a compact rotating assembly. A spare rotating assembly is kept at site to permit quick changeout if one of the operating units is damaged.
An automatic thrust equalizer is included in the design to maintain low thrust loads under the widely varying process conditions.
Separation of process gas and lube oil is maintained by buffered labyrinths between each bearing and wheel. Seal gas is supplied to each labyrinth through a filter-regulator system provided on the support skid.
The lube-oil reservoir and bearing housing drain are maintained at the compressor's suction pressure because the seal gas is vented through a filter system directly to the compressor's suction piping.
Typical turboexpander inlet conditions are supercritical at 110 bar and -1 C. (Fig. 7). The fluid expands through the two-phase envelope down to 60 bar and -27 C.
At the exhaust, equilibrium liquid content will be between 25 and 30 wt %, depending on inlet composition. High efficiency of up to 85 wt % is maintained even with the high liquid content. Design-point operating conditions are shown on Table 3.
Features of the turboexpander support system include: 316 stainless steel lube-oil reservoir, accumulators, and piping, full gauge board and annunciation panel on the skid and a remote control and monitoring panel; and "canned" sealless lube-oil pumps.
The entire instrumentation and electrical system was designed in accordance with Cenelec standards. Shop testing included PTC 10 Class III performance testing and API 617 mechanical testing.
A special full-pressure performance test of the lube oil and seal-gas system was performed to ensure operation at the 88-bar design pressure.
The first turboexpander system was delivered mid 1991. The second system (for Phase B) was delivered mid 1992.
COMMISSIONING, OPERATION
Early commissioning activities were dogged by problems with the quality of the start-up seal gas. As can be seen from Fig. 3, no further compression takes place between the expander's recompressor and British Gas' sales-gas pressure.
A source of lean seal gas is not readily available to maintain any differential pressure at start-up, although for normal running the seal gas can be fed from the recompressor discharge header (Fig. 3).
Start-up seal gas supply was taken from upstream of the expander feed exchanger (Fig. 3), dropped to a suitable feed pressure, and reheated to maintain a single-phase composition feed to the right of the cricondentherm.
This procedure proved unsuccessful because temperature drop in the feed pipework downstream of the seal-gas heater and in the seal areas themselves caused liquid drop-out within the shaft seal labyrinths.
The resulting fluid bearings in the labyrinth areas caused excessive rotor vibration that limited machine speed and operability.
This problem has been effectively remedied by heat tracing and insulating the seal-gas pipework and installing a knockout vessel upstream of the seal-gas heater to remove liquids from the feed stream (Fig. 8).
Although the resulting seal gas has a much reduced dew point, it is impossible totally to eliminate liquid formation within the expander shaft's seal labyrinth: seal gas flows to the expander wheel area where temperature and pressure are much less than seal gas dew point.
This causes labyrinth seal wear. It is therefore desirable to supply seal gas from the recompressor discharge immediately after the first expander is brought on line.
As seal gas to the machines comes from a common line, there was a tendency for one machine to starve the supply to the other. Control of this has been improved by replacing the self-acting regulating valves with pneumatic differential-pressure control valves.
The original regulating valves also suffered from explosive decompression of the diaphragm.
As previously described, lube oil and seal gas mix when returning to the reservoir. Gas dilutes the oil and reduces its effective viscosity. The extent of dilution can be observed on the reservoir's level gauge.
If start-up is with new oil, dilution with start-up seal gas raises the level, until reaching an equilibrium which is maintained until the normal lean seal gas is commissioned. This strips out some of the heavier hydrocarbons contaminating the lube oil until another equilibrium level is reached somewhere between the first and second.
The dilution caused problems initially with use of an ISO 32 viscosity grade (VG) oil which was unable to provide sufficient stiffness at the machine bearings.
The simple solution was to use a VG 68 oil. No further problems have been experienced, although regular lube-oil samples are taken to check for long-term degradation of the base oil.
It is impossible, however, to determine actual oil viscosity supplied to the bearings because when samples are taken for analysis, gas is flashed off.
For future installations, an in-line viscometer could be considered to measure viscosity under pressure and remove any doubt as to the oil's suitability.
INSPECTION
Following the first 6 months of operation, the units were both stripped for overhaul to solve the rotor-dynamic problem being intermittently experienced (described presently).
Inspection revealed slight erosion damage on the aluminum wheels due to corrosion product dust from the subsea pipeline. The exception was one expander wheel which had been anodized to provide a hard surface coatings
All future wheels will now be upgraded to provide this additional protection. Although quantities of dust are diminishing, it is impossible to predict how long the problem may last and the upgrade will extend the serviceable life of the units.
Both expander wheels had also been mechanically damaged by capscrews which had come loose from the machine's internals upstream of the inlet guide vanes.
The high differential pressure at start-up across an internal guide ring was overlooked during the design phase. Deflection of this part overstressed its bolting, which yielded and loosened after start-up.
All machines were fitted with higher tensile strength capscrews to guard against recurrence.
The common lube-oil system has resulted in complex isolation procedures. It is possible, however, to run either machine with the other down for maintenance and overhaul.
From an operability viewpoint, the oil system has functioned well. The main drawback of the arrangement is the cramped access to the skid.
START-UP: FIRST MACHINE
The most problematic starting point for running the expanders occurs when high flow is being produced through the plant on JT-valve operation.
The JT valve is sized to raise plant capacity without the aid of expanders. The relief system is not sized for JT operation in parallel with both expanders, however, and the JT valve's opening must be reduced each time an expander is brought on-line (to 49% and 13% for the first and second machines, respectively; interlocks ensure this is adhered to).
Change-over from JT to expander operation most often occurs with JT opening greater than 49%, which has the effect of reducing plant throughput before an expander can be started and upsetting the process steady state.
Following this first step, the operator must aim to maintain a steady flow through the plant to reduce process upsets. This is achieved over a period of 30 to 40 min by reduction of the JT valve opening and increase of the expander guide-vane position until the expander is at maximum flow and the JT valve is at 13% or less.
During this time, the operator must increase back pressure to the plant (to avoid machine overspeed) and increase feed temperature to the expanders using the bypass around the gas-gas exchanger (Fig. 3).
Before starting the second machine, the opportunity is taken to change over the seal-gas supply.
START-UP: SECOND MACHINE
The description of the first machine start-up is probably similar to many installations throughout the world. But having another machine in parallel has provided a few unique operational problems.
These problems are linked to anti-surge control and achieving forward flow through the recompressor of the second unit.
For the SAGE installation, it is normal to start the second unit with 20 bar pressure across the recompressor. One of the units experienced surge at start-up (identified on vibration-monitoring equipment) during early commissioning activities.
To avoid repeating this, the plant depends on following operating procedure and on a reliable, well-calibrated anti-surge control system.
Fig. 3 shows there is no recycle cooler. There are, therefore, three requirements to limit overheating on start-up:
- The unit is brought on-line with the anti-surge control on "automatic" to ensure minimum recycle at all times.
- The vent valve to flare, upstream of the anti-surge valve, must be opened on start-up to draw cool gas into the machine from the suction header.
- The second machine's speed must be increased rapidly (5 min) to ensure the recompressor overcomes its discharge check valve before the recycled gas becomes too warm to achieve forward flow. The last of these requirements causes the biggest problem. Although the guide-vane position of the first machine is reduced as the second is increased in speed, it is impossible to maintain steady flow through the plant.
Process upsets are inevitable. Fortunately this operation is not routine and the operators have learned by experience to prepare for the upset by, for example, reducing expander discharge-drum liquid level before start-up to accommodate the additional inventory.
Requirements 1 and 3 are undesirable from a machinery viewpoint, and observations from recent testing indicate the second unit may reach the onset of surge on start-up when the vent valve is only slightly open.
Checks performed on the anti-surge valve indicate it to be adequately sized and the problems may be linked to the power-flow characteristics of the expander-compressor combination.
Sudden increase in speed, resulting from increased expander flow, instantaneously increases power available to the Compressor. Compressor flow increase is delayed, sending its operating point towards surge.
This does not become unstable but flow reversal is a distinct possibility during machine trips as the anti-surge valve cannot open instantaneously. In either case, resulting transient conditions can create short periods of high vibration which by experience can severely damage seal areas.
To reduce the problems, the vent valve is fully opened during start-up and the shutdown logic ensures most machine-trip signals delay closure of the expander inlet's trip valve for 1 sec to allow the anti-surge valve to open.
PARALLEL OPERATION
Early concerns of achieving matching machine flows during parallel operation proved unfounded.
When the second unit is brought on-line, the operator reduces flow through the first machine and increases the second until guide-vane positions and expander speeds equalize. Guide-vane positions are then manually adjusted simultaneously until the desired total flow is achieved.
Manual operation is maintained and speed match between the two machines is usually within 200-300 rpm at machine speeds of about 16,500 rpm.
Small differences in compressor performance and anti-surge valve sizes result in different values of compressor-suction flow and suction temperature (usually within 2 C.).
If this temperature difference is allowed to increase before guide-vane positions are matched, one unit may find its temperature increasing because of the power mismatch until the compressor can no longer achieve forward flow and the machine trips on high compressor-discharge temperature.
This is unusual and little operator intervention is required during steady-state conditions.
OFF-DESIGN OPERATION, PROCESS UPSETS
For any process plant, it is desirable to maintain forward flow following an upset. The high integrity instrumentation-protection system's valves at the front end of the plant will shut off flow completely to protect a inst overpressurization.
If both expanders trip simultaneously, overpressurization is impossible to avoid. But it has proven possible to maintain flow through the plant when one machine has tripped. This pressure control at the letdown station downstream of the instrumentation-protection system's valves.
During such instances, the unit that remains on line has experienced minimal upset enabling the plant to be returned to steady-state conditions quickly.
The expanders have proven themselves operable in a unique range but with some initial problems. High inlet pressure (and therefore high inlet density) coupled with a large pressure drop across the expander (55 barg) have resulted in large external forces acting on the expander wheel and causing excessive vibration.
The vibration spectra indicate a large proportion of this to be a subsynchronous component, and machine bearings have been modified effectively to damp this out.
Under certain off-design process conditions, however, low-level subsynchronous vibration still appears. These occasions correspond with high volumetric liquid-vapor ratios in the expander discharge, but it is still unclear whether the rotor is being excited by fluid effects creating secondary bearings within the machine or by liquid build up in the discharge pipework.
Attempts to match these operating points to unstable flow regimes on two-phase flow charts have so far proven inconclusive.
Although undesirable, the levels of subsynchronous vibration are operationally acceptable and are not giving undue concern because they are experienced infrequently.
To ensure long-term operability under different feedgas compositions, additional internal machine modifications will be fitted to reduce the tendency for the rotor to exhibit subsynchronous vibration caused by the formation of fluid bearings within the expander wheel seal areas.
What Mobil North Sea has learned during this installation for Phase B of its SAGE gas terminal appears in an accompanying box.
Copyright 1994 Oil & Gas Journal. All Rights Reserved.