Graham W. Griffiths
SAST Ltd.
London
Denis J. Wills
Woodside Offshore Petroleum Pty. Ltd.
Karratha, Australia
Wouter J. Meiring
Koninklijke/Shell Laboratorium
Amsterdam
Based on a presention to OMAE 1993 (ASME), Galsgow, May 20 24, 1993.
A trunkline management system (TMS) utilizing dynamic pipeline and plant process simulation is scheduled to start up near the end of first quarter 1994 at Woodside Offshore Petroleum Pty. Ltd.'s North West Shelf gas project at Karratha, Western Australia.
The TMS is a real time, dynamic two phase model of the pipeline system and relevant portions of the onshore facilities (Fig. 1). Its budget was approximately $4 million (Australian).
This first part of a two-part series on the system describes the operating conditions that prompted its installation; the concluding article will describe the models it incorporates.
In the system, a dynamic model is continuously synchronized to actual plant data by use of reconciled measurement data. The model is used for rapid "look ahead" to examine control actions before they are implemented in the plant.
This is achieved by use of rigorous first principle modeling techniques to describe the two phase flow pipelines and associated process equipment. With dynamic mass and energy balances maintained throughout the model, composition tracking can be included.
Rigorous multicomponent thermodynamic and physical property calculations are also included throughout, enabling mass transfer between vapor and liquid phases along the pipeline to be predicted by means of flash calculations.
The TMS project is demonstrating that modeling technology, based upon advanced fluid mechanics, can now accurately predict the dynamic behavior of two-phase pipelines.
Additionally, parameter estimation and data reconciliation techniques can be used to make the "shadow-model" concept practical for providing inferential measurements.
The TMS project has involved close cooperation among three international organizations:Woodside project team, Karratha, W.A.; Koninklijke/Shell Laboratorium, Amsterdam (KSLA); and Special Analysis & Simulation Technology Ltd. (SAST), London.
The TMS project will start up in March 1994 after the following schedule: project award, April 1992; technology demonstration, July 1992; functional specification, November 1992; hardware testing, March 1993; MMI integration, May 1993; full system integration, September 1993; factory acceptance testing, November 1993,
WORLD SCALE LNG PLANT
The North West Shelf gas project is Australia's largest ever resource development (Fig. 1). Based on the huge North Rankin "A" (NRA) and Goodwyn "A" (GWA) gas fields, the project supplies pipeline quality gas to the domestic market in Western Australia and liquefied natural gas (LNG) for export to Japan.
The LNG plant is the world's tenth base load plant and consists of three parallel trains of 2.4 million metric tons/year (mty) each. The domestic gas plant consists of two parallel trains each with a capacity of 11.3 MMscm/day. Additionally, there are five condensate stabilization units, each capable of processing 2,800 metric tons/day of condensate.
Offshore, the facilities include the NRA gas production platform capable of producing 46.7 MMscm/day of gas and up to 6,320 cu m/day of condensate. The GWA gas production platform will begin production in early 1994 with a capacity of 25.4 million cu m/day of gas and 12,700 cu m/day of condensate.
Woodside Offshore Petroleum is the designated operator of these facilities on behalf of joint participants Woodside Petroleum Ltd., BHP Petroleum (North West Shelf) Pty. Ltd., Shell Development (Australia) Pty. Ltd., BP Developments Australia Ltd., Japan Australia LNG (MIMI) Pty. Ltd. (owned by Mitsubishi Corp. and Mitsui & Co. Ltd.), and Chevron Asiatic Ltd.
PIPELINES, TERMINAL
Early this year, two pipelines will have begun operation (Fig. 2):
- The 134 km (83.2 mile), 40 in. NRA to shore trunkline is
designed to operate at 13.2 MPa(g) and runs on a gradual
incline from 121 m water depth to shore.
- The 23 km (14.3 miles), 30 in. GWA to NRA is designed to
operate at 14.2 MPa(g) and runs on a gradual incline from
134 m water depth to 121 m at NRA.
Each pipeline operates in two phase with the predominant flow regimes being stratified wavy and annular dispersed. The exception is the GWA to NRA pipeline which in the early GWA production years operated in the dispersed bubble flow regime because GWA exports condensate with only a small amount of gas. Most of the gas produced was reinjected into the reservoir.
The slug catcher onshore has a nominal capacity of 5,200 cu m with a usable volume of 4,000. It consists of two halves with a total of fourteen 1,200 mm diameter bottles 350 m long, of which 8 are primary bottles (Fig. 1).
Sphere and pig receiving facilities are provided. Relief valves are provided on the slugcatcher with a capacity equivalent to the trunkline's.
Relief is provided because the slug catcher and associated piping have lower design pressures (8.27 MPa) than the NRA to shore trunkline design pressure (13.2 MPa).
Vapor from the slug catcher is fed under flow control to three parallel LNG trains and two domestic gas trains. Condensate from the slug catcher is directed under level control to three parallel flash tanks.
Vapor from these flash tanks is routed to the top section of the condensate stabilizers with the condensate to the liquid feed tray. Stabilizer overhead gas, which is rich in LPG, is directed to the domestic gas feed stream, Stabilized condensate produced is sent to storage.
A proportion of the LPG in the feed gas to the LNG trains is extracted in controlling the C5+ fraction in the gas before liquefaction. Also, LPG is extracted from the domestic gas feed stream during hydrocarbon dew point control.
These LPG rich streams are directed to two fractionation trains.
There, propane and butane produced are spiked into the LNG and domestic-gas products as necessary to meet product specification. Condensate produced as the debutanizer bottom product is sent to condensate storage.
The extent of the process covered by the TMS is shown in Fig. 3.
It is to be noted that the modeling does not cover the fractionation trains, although extraction of LPG from the LNG and domestic-gas feed streams is included, as well as the spiking of LPG into these products to meet specifications.
SLUG-CATCHER CAPACITY, TRIPS
The slug catcher can accommodate liquid transients generated by normal rate changes. There are, however, several transient scenarios for which the slugcatcher's capacity and the processing capacity of the stabilization units are insufficient, and flooding would occur.
One such scenario is during the early years of GWA production when it is exporting only condensate with produced gas being reinjected.
In such a case, the liquid hold up of the GWA to-NRA pipeline is approximately 9,000 cu m and that of the NRA to shore trunkline 12,000 cu m.
Should the GWA compressor trip and reinjected gas be directed to the pipeline, a significant change in the hold up of these two pipelines will result.
Eventually (after approximately 8 10 hr), this change in hold up is seen as a liquid surge or transient into the slug catcher. This liquid surge exceeds the slugcatcher's capacity and associated stabilization capacity by some 4,500 cu m.
With such scenarios, the potential exists for massive liquid entrainment into downstream processing facilities (the LNG plant, for example) or at worst flooding of these facilities should the high level trip on the slug catcher fail.
Either situation would lead to prolonged plant shutdowns.
Because of the steep pressure gradient in the NRA to-shore trunkline (11.3 MPa offshore to 6.0 MPa ashore), it is possible under certain conditions (shutdown of two or more LNG trains, for example) to have a pressure rise ashore which could lead to a slug catcher high pressure trip or, if this failed, relief of hydrocarbons through a vent system to the atmosphere.
From an operational point of view, being aware that a high slug catcher pressure will occur and knowing its value and time of occurrence enable better management of the situation and optimization of production by lowering the risk of a shut in of the slug catcher.
BALANCES
With certain mixes from GWA and NRA, it is possible to have excess LPG greater than what can be disposed of in the products (LNG, domestic gas, and condensate).
Also, excess LPG can be produced as a result of an increased stabilization load because of a liquid transient. (That is, the ratio of liquid to gas increases by a factor of 3 compared to the steady state ratio at which there was an LPG balance.)
Although excess LPG can be sent to a 1,000 cu m storage sphere, situations can be envisioned whereby flaring may become necessary. On both environmental and commercial grounds, even occasional flaring is to be avoided. lt is apparent that a means of managing the shore LPG balance under both steady state and, particularly, transient conditions is important.
The supply of gas to the onshore facility depends on a single pipeline whose integrity is critical in meeting contractual gas sales (domestic gas and LNG). No less important is the integrity of the GWA to NRA pipeline.
Because of upsets in these systems, internal corrosion could be a major problem, even though gas is dehydrated offshore and condensate is de watered.
Knowing the percentage water saturation along the pipeline system and having this information updated regularly (every 10 min, for example) are useful operationally in monitoring and maintaining pipeline system integrity and highlighting the need for corrective action offshore.
PROJECT JUSTIFICATION, AIMS
In 1990, the North West Shelf gas project decided no to install additional condensate handling facilities to accommodate major liquid transients.
The proposed facilities at the time consisted of two storage spheres with a total capacity of 5,000 cu m. This would have effectively increased the storage capacity of the trunkline terminal onshore to 9,000 cu m (4,000 cu m slug catcher + 5,000 cu m spheres).
The cost saving to the project was approximately $40 million (Australian).
A safety and operational review showed it was feasible to manage major transients with the existing slug catcher by imposing strict operating procedures covering potential transient situations.
Nevertheless, it was considered that such procedures could not cover all possible events and would not allow optimum operation of the pipeline system by minimizing disruption to the gas supply onshore.
It was also recognized that the potential always existed for an incident which could cause a prolonged shutdown of the onshore facilities through flooding or contamination of the process trains with condensate.
Such an incident could arise if operators are unaware of what was happening in the pipeline system as a result of its complex behavior or have insufficient information about a possible liquid transient on which to formulate corrective actions.
Such an incident has the potential to be very costly.
Additionally, there was seen to be the need to manage the pipeline system and facilities onshore within the other operational constraints described in earlier:
- Avoidance of slug catcher high pressure trips or venting
- No excess LPG onshore
- Maintenance of an acceptable percentage of water
saturation.
Out of these requirements was born the trunkline management system (TMS). Following are its primary objectives:
- Upset prediction. To advise operators up to 12 hr ahead of
the event that a transient condition is present in the
pipeline system which could lead to an upset in the plant
onshore, for example too high slug catcher level or
pressure.
- Control strategy formulation. To provide the operators
with the necessary tool to allow corrective actions to be
formulated and taken to avoid an upset at the plant
onshore from a transient, thus avoiding a loss of
production.
- Optimization. To advise on the best method for operating
the pipeline system and shore facility within their
operating constraints (for example, avoiding excess LPG).
Among the several secondary objectives for the trunkline management system are the following:
- It must be compatible with existing land and offshore
process control systems. For land and NRA, this is a
Honeywell TDC 3000; for GWA, a Bailey system.
- The man machine interface (MMI) must be easy to use and
understand.
- The structure must allow for easy expansion and
development.
- It must have high availability (ideally, 98% or better).
Copyright 1994 Oil & Gas Journal. All Rights Reserved.
