First LNG from North field overcomes feed, start-up problems

Qatargas North field Bravo offshore complex can produce 900 MMscfd from the Khuff K4 formation to supply the 4 million mty LNG plant.

• Qatargas LNG plant's first and second trains stand completed (Fig. 5). [18,691 bytes]
• Qatargas' LNG plant overview shows storage tanks (background), each of which can hold up to 85,000 cu m (Fig. 6). [15,934 bytes]
• A 3D model of the piping played an integral part in the overall plant design (Fig. 8). [9,816 bytes]

Qatar Gas LNG is the first LNG project in the gas-development program of the world's largest gas reservoir, North field. The plant ( Fig. 1 [130,162 bytes]) has been supplying LNG to Chubu Electric Power Co. Inc., Chubu, Japan, since January 1997. The LNG plant was completed within the budget and schedule. The project successfully dealt with:

• Location: First grassroots LNG project in Qatar, shallow shore, high ambient temperature
• Process: Resolution of gas treating difficulty of high mercaptan content; high N₂ content, and four Frame-5 applications
• Schedule: First two trains and offshore-production facilities; 1 month ahead of schedule for mechanical completion and high construction safety record
• Operation: Operator-training simulator, plant operation information system.

Milestones

Qatargas Co. was formed in November 1984 to develop the giant North field. The feasibility study was completed in January 1991. Front-end engineering design was undertaken by M.W. Kellogg Co. 1992-1993. In May 1993, an engineering, procurement, and construction (EPC) contract for the first and second trains (4 million metric tons/year; mty) and associated facilities with an option for the third LNG train was awarded to Chiyoda Corp., Yokohama. Following are project milestones from the EPC contract to LNG product export (CP = completion package number):

• Oct. 1, 1995: Site industrial buildings were completed. These facilities included laboratory, fire station, workshop, training center, and gate house which were handed over to Qatargas (CP-1).
• Jan. 28, 1996: Plant utilities systems, including fuel gas, power generation, fire protection, compressed air, effluent treatment, and seawater intake, were the first operational facilities handed over to Qatargas for start-up and operations (CP-2).
• May 29, 1996: Remaining utilities systems required for operation of the first LNG train, including desalination and steam generation systems, were completed and handed over (CP-3).
• Sept. 1, 1996: First LNG train was completed and handed over to Qatargas a month ahead of schedule. Early completion of this milestone allowed Qatargas to accelerate start-up (CP-4).
• Nov. 15, 1996: First LNG was produced, in advance of the first LNG shipment date.
• Dec.

  8, 1996: Construction of the second train was completed and handed over to Qatargas 3 weeks ahead of schedule (CP-5).

• Dec. 23, 1996: First LNG shipment, aboard the Al Zubarah, left Ras Laffan Port in Qatar.
• Jan. 10, 1997: Al Zubarah arrived at Kawagoe terminal, Nagoya, Japan, a distance of 12,000 km from Ras Laffan.
• Jan. 17, 1997: First LNG from second train produced.
• Jan. 23, 1997: Remaining associated facilities of first and second trains turned over (CP-6).
• Sept. 30, 1997: Methane Arctic left Ras Laffan port bound for Spain via Suez Canal, Qatargas' first European customer in Europe, after Qatargas signed a contract in May 1997 to sell 420,000 metric tons over a 13-month period to the Spanish natural-gas company Enagas.
• Mar. 31, 1998: The third train and associated facilities were completed 8 months ahead of schedule (CP-7).

LNG plant

The plant process system is supplied with feed gas from offshore production. Filtration and fiscal metering then takes place in the common reception facilities before the feed-gas flow is divided into three streams, one to each LNG process train. Each LNG process train consists of reception, acid-gas removal, dehydration and mercaptan/mercury removal, gas chilling and liquefaction systems, refrigeration, fractionation, nitrogen rejection, sulfur recovery, etc. ( Fig. 2 [91,495 bytes]). Following is more detail on the steps: Acid gas removal. In each train, Shell Sulfinol D process was selected to remove acid gases (CO ₂ and H ₂S), mercaptans, and other sulfur impurities from the feed gas. A two-stage flash scheme has been successfully applied to minimize the heavy hydrocarbon content in acid gas for optimal SuperClaus design ( Fig. 3 [56,695 bytes]). Liquefaction. The treated gas is then chilled and liquefied. This is done by propane precooled mixed refrigerant (MR) process of Air Products Chemicals Inc. (APCI), Allentown, Pa., using two refrigerant closed loops ( Fig. 4 [83,934 bytes]). The refrigerant cycle requires four GE Frame-5 gas turbines, one for propane and three for mixed refrigerant. To liquefy the gas, the stream is then introduced into the main cryogenic heat exchanger, where it is further liquefied by heat exchange with the mixed refrigerant. The refrigeration load balance between propane and mixed refrigerant shows slightly warmer refrigeration temperature for propane. A C ₃ booster compressor is used for hot summer periods to maintain production because of high seawater temperature. The reflux condenser duty of the scrub column is supplied by MR refrigerant via the warm bundle of main cryogenic heat exchanger. This exchanger consists of three bundles. Nitrogen is rejected from the stream by N ₂ stripper which contains around 4 mol % in order to meet the LNG specification. The SuperClaus process (licensed by Stork E & C, Amsterdam) was applied to the sulfur-recovery unit to recover sulfur from the acid gas. An overview of the trains is shown in Fig. 5.

Support facilities associated with the LNG trains include fuel gas distribution, NGL extraction, refrigerant make-up, and NGL return; flare system and liquid burn pit; process-effluent water treatment, electric-power generation, steam generation, cooling water, water desalination, fire fighting water distribution, air compression, nitrogen generation, etc.

Sulfur loading. Sulfur is solidified and trucked to the port for shipping. The sulfur export system at the port consists of a solid-sulfur storage silo and a traveling ship-loader. The silo has a capacity of 20,000 metric tons.

Electric-power generation. Electric power is generated by five GE Frame-6 gas turbines, each of 28-mw site rating, with a sixth machine being added for the third LNG train. With this design, at least one machine is always available as spinning reserve or as standby for maintenance.

Steam generation. Steam is generated at a pressure of 10 barg by three boilers, each rated at 146 metric tons/hr. A fourth boiler is being added for the third LNG train.

Cooling water. The seawater cooling system includes the intake facilities located in the port with two seawater pumps per LNG train, the supply distribution and return systems, and outfall channel discharging to the open sea.

Maximum water temperature differential from intake to outfall is 10° C. A fifth pump (seventh after three LNG trains) acts as a common spare on the connecting manifold, from which the LNG trains are supplied. All the pumps are of vertical shaft; each has a capacity is 17,300 cu m/hr. An 84-in. seawater supply line is dedicated for each train.

LNG storage, loading

LNG produced in the two trains is stored in three identical full containment, double-wall, metal inner and concrete outer shell storage tanks for maximum safety. Each tank has a nominal working capacity of 85,000 cu m (Fig. 6) and is equipped with four top-entry, column-mounted loading pumps, each having a capacity of 1,300 cu m/hr and one circulation pump with a capacity of 250 cu m/hr. The tanks are located at the northeast corner of the plant area, and the loading lines are routed along the main breakwater of the port to LNG Berth No. 1. A fourth LNG tank and a third boil-off gas compressor are being added for the third LNG train. LNG is loaded into carriers through three articulated loading arms, each having pipes of 16-in. OD and capacity of 3,400 cu m/hr. This leads to an overall nominal loading rate of 10,000 cu m/hr, which means that an LNG carrier spends less than 24 hr in the port at Ras Laffan. A fourth arm is used to receive the vapor generated in the ship during loading; the vapor is directed to a discharge flare outside the breakwater.

EPC contract

The plant project used a single overall EPC contract for the first and second train, 4 million metric ton/year plant and associated facilities, with an option for the third LNG train. Chiyoda was assigned responsibility for three long lead items:

• LNG tanks: to a consortium of SN Technigaz & Bouygues of France and Mecon & Midmac of Qatar
• Cryogenic heat exchangers: to APCI of the U.S.
• Compressors: to Nuovo Pignone of Italy.

In addition, a few small contracts were awarded and administered directly by Qatargas for such activities as site surveys, site preparation, and Qatargas head office building, completed in second quarter 1997. All these contracts were competitively bid and awarded on a lump-sum basis. Completion packages were divided to facilitate handover during a phased period, with penalties assigned for late completion. A Qatargas LNG project task force was established in Chiyoda's Yokohama office to facilitate rapid decision making and approvals for matters of direct concern to Qatargas. Engineering optimization studies were started during bidding, followed by the engineering work at Chiyoda's Yokohama office. The engineering optimization study was the key to establish the mercaptan-removal scheme which was modified after front-end engineering design. The engineering work has been done mainly in Chiyoda's Yokohama office.

Alternative mercaptan-removal

The design feed gas indicated around 350-ppm mercaptan content, although current operation shows lower mercaptan content. No LNG plant has ever encountered such high mercaptan content. Front-end engineering design applied for the following acid-gas removal scheme: chemical absorption amine+13x molecular sieve + physical absorption + Claus. During bidding, Chiyoda proposed an alternate after an engineering optimization study: Sulfinol + 5A molecular sieve + SuperClaus. After the EPC contract, Qatargas selected the alternate scheme based on the following considerations:

• Simple process flow; two-step adsorption/absorption (molecular sieve and physical absorption) to a single-step absorption of mercaptan (Sulfinol), and eliminating regeneration gas recycle
• Easy environment control. In the original scheme, the dryer, 13x molecular-sieve regeneration desorbs the unrecoverable sulfur compound in a high-concentration peak for every cycle time.
• Higher sulfur recovery. The SuperClaus application was proposed to reduce the SOx emissions in deference to worldwide ecology concerns. For Claus reaction, the recovery rate of sulfur is limited by the equilibrium of the partial pressure of H₂S and SO₂ which becomes low for this case as a result of the inert compounds such as H₂O, CO₂, and N₂.

For flame stability, fuel gas co-firing has been considered in a reaction furnace. The fuel-gas introduction increases the inert gas such as N ₂ with the increased combustion air and CO ₂ in the combusted gas. Consequently, the partial pressure of H ₂S and SO ₂ will decrease, and 95% sulfur recovery will become difficult. To maintain the sulfur-recovery rate, the SuperClaus process was applied, which enables the high sulfur recovery, regardless of the low partial pressure of H ₂S and SO ₂. The SuperClaus process, developed by Stork E&C, forms sulfur by a partial oxidation reaction instead of the Claus reaction which is an equilibrium reaction. Claus reaction: 2H ₂S + SO ₂ = 3S + 2H ₂O SuperClaus reaction:

H₂S + 1/2O₂ S + H₂O The mercaptan content in the acid-gas feed to the sulfur-recovery unit will increase the sulfur-recovery rate which will reduce the SOx emission to the atmosphere to two thirds of the original design.

Eventually, the design modification caused new drawings of two thirds of piping and instrumentation diagrams (P&ID) of the process units, but the joint effort of Qatargas and Chiyoda minimized the impact to the project schedule.

Layout modification; simulation

Safety considerations against toxic gas, especially hydrogen sulfide, necessitated a layout modification. The hydrogen sulfide-rich section, that is, the Sulfinol regenerator and sulfur-recovery unit, was separated from the other process units. The welded plate frame exchanger (a Compabloc heat exchanger of Vicarb) was used for the Sulfinol lean-rich solution exchanger. The application reduced the plot area and cost as a result of its compactness. The welded type promised safety from toxic gas. Seven heat exchangers plus one spare were installed in parallel as a result of its counter-current heat exchange. The equal solution distribution was carefully designed to obtain proper performance of the heat exchanger. On-line cleaning can be done with the spare heat exchanger, if required. Subcontractor Special Analysis & Simulation Technology (SAST), Brentford, U.K., carried out dynamic simulation for various operations of the refrigeration cycle. The simulation revealed that the propane compressor and mixed refrigerant compressors will experience surging during emergency shut down. The surging was caused by low inertia of the power turbine of Frame-5 connected to the compressor as load and the large discharge volume of the compressor. To avoid the surging, modifications were made to provide a hot by-pass valve from the compressor discharge to the suction drum.

Information, control

Plant operations information system (POIS) has been introduced to this LNG plant. Recent advances in computer technology have led to the application of total plant-wide information systems in LNG plant operations. In this application, POIS provided a crucial link between the process-control system and the business-information system. Functionally, the process-control system provides for daily plant operation and is used by the process-operation personnel, while the business-information system provides for corporate-level information relating to such activities as accounting, financial management, and business and facility planning. The main users of POIS are plant managers, operation managers, and engineers. POIS enables users to generate LNG-production schedules, operator guidelines, summary and shift reports, and provides information on the LNG plant, such as equipment performance, product quality, safety, and environmental monitoring. In general, advanced process control (APC) consists of increased production throughput, improved product quality, and/or reduced energy costs. LNG plants are usually required to operate at maximum load. In this LNG project, model-based predictive control algorithms are applied to achieve the following objectives:

• Maximize LNG production at main heat exchanger.
• Control the quality at the fractionation section to maximize valuable product and minimize utilities.

Recent advances in computer and simulation technology have enabled Chiyoda to provide a high-fidelity dynamic simulator containing rigorous dynamic equations of the process.

Training

Operator training simulator (OTS) is an efficient training tool both for new and for experienced operators to refresh their skills. The OTS can provide practice (skill learning and development) in start-up, shut-down, normal operations, and special or emergency operations. OTS in this LNG project will be one of the first high-fidelity training simulators in LNG plants in the world. It is expected to be a key component for training because the plant is a grassroots facility and training of a pool of new operators was required initially. The model for each unit operation has already been developed by OTS subcontractor Honeywell Hi-Spec Solutions, excluding the main cryogenic heat exchanger, which is a specialty heat exchanger. The model of the main cryogenic heat exchanger was newly developed by the joint effort among Qatargas, Chiyoda, and Honeywell Hi-Spec Solutions which took 1 year. The actual OTS model was the combination of a model based on the actual configuration of the plant. OTS was delivered in February 1996 well before the plant start-up to enable operator training. It was equipped with an exact replica of the distributed control system (DCS) operator consoles to enable operators to become familiar with DCS. Also, the high-fidelity simulation of process models in OTS allows for process-operation training. In the future, the potential exists for the high-fidelity process models to be further developed to serve as useful engineering tools.

Data management system

Design of the Qatargas plant was performed entirely by the most advanced computers available. A plant design system by Intergraph Corp., Huntsville, Ala., was employed within a three dimensional CAD format. Chiyoda's global information network connects headquarters in Yokohama with offices in the U.S., England, Italy, and Singapore through international leased lines. Chiyoda headquarters were linked with the site in Qatar by Intelsat digital communication, which enabled video conferencing, fax, telephone, and complete data-transmission capability using e-mail. The transmission route from Chiyoda's Yokohama office to Ras Laffan through Intelsat ( Fig. 7 [110,068 bytes]) is as follows:

• TDM (time-divided multiplexer) Chiyoda's Yokohama office - DSU (digital service unit) - NTT communication line - KDD Shinjuku - KDD, Yamaguchi - Intelsat
• Intelsat - CPES (customer-premised earth station) owned by Q-TEL-TDM, Ras Laffan site.

Communication between Japan and Qatar was further enhanced by a communications system with internal exchanges for the speedy exchange of voice, fax, and e-mail. Engineering and construction drawings including vendor drawings have been successfully sent electronically over the computer networks. Some 700,000 pages ranging in size from A0 to A4 were sent and received. Engineers of Qatargas and Chiyoda opened these diagrams with their own personal computers to enhance efficiency. This two-way communication network was also supported by Qatargas, with both parties making use of data to keep the project moving. At each office, internal LAN (local area network) and other communication networks facilitated the quick exchange of information for greater efficiency in engineering work, equipment procurement, transport, and project management. As-built drawings/documents, operation manuals, and project procedures, including vendor prints are electronically stored in form of AutoCAD (*.

dwg) file, Intergraph (*.dgn), Microsoft Office files, compressed image data (*.tiff), etc.

At the completion of Trains 1 and 2, the stored data amounted to 60 CD-ROM disks. Oracle-based software has been successfully developed to retrieve information from and view such a large data base.

3D module

A 3D PDS (piping-design system) module, from Intergraph Corp., was used for the piping design of the process plant (Fig. 8). The 3D module data base includes structure data, equipment data, piping data, raceway data, HVAC data, etc. The module greatly reduces the engineering man-hours by automatic generation of:

• Material take-off, crash check, and piping general arrangement drawing
• Isometric drawings and material data for construction for each line

The 3D module generated 160 piping general arrangement drawings and 6,000 isometric drawings for the process plant.

Start-up, operation

First gas from North field Qatargas upstream facilities arrived via the 32-in. pipeline in July 1996. A minimum gas flow had to be maintained through the pipeline to prevent excessive slug formation in the slug catcher. The minimum flow had been predicted during engineering through extensive simulation using two-phase flow modeling and design of a dynamic simulator that will predict liquid hold up and slug formation. To date, the upstream facilities have been able to meet the LNG plant demand and provide 240 MMscfd of gas to QGPC through an existing 34-in. pipeline to Messaied industrial area. The utility plant successfully started operation at the beginning of 1996, which supplied not only the first train but also the upstream facilities. The Phase 1 pipeline gas was utilized for this start-up. After several months of first-train operation, it needed to reduce the capacity because of Sulfinol-unit foaming. The feed gas from upstream contains heavy hydrocarbons in addition to breakthrough of fine carbon from damaged filter elements. which might have caused the Sulfinol foaming. Several actions were taken:

• Oil was skimmed from the unit.
• Steam rate to the Sulfinol regenerator was controlled.
• The most suitable antifoam agent (self-emulsified and modified silicone type) was selected by foaming tests on site among several antifoam agents.
• The durable filter element of the mercury-removal effluent filter upstream of the Sulfinol unit was replaced, preventing sulfur-impregnated activated carbon leaks.

As a result of these countermeasures, the plant has been operating with no load change caused by foaming since August 1997. Another situation arose when, during construction, gas from a new producing well became available. The new feedstock has lower H ₂S and higher CO ₂ together with large amounts of heavy hydrocarbons. As a result of the physical and chemical absorption process, a large amount of heavy hydrocarbons is entrained in the feed acid gas to the SRU. The new feedstock had to be incorporated in one of the operation cases with the same process performances as the design feedstock. The treatment of a large amount (1 vol %) of heavy hydrocarbons in the low H ₂S feed acid gas of 10 vol %, is believed impossible, resulting in soot formation, deactivation of the catalyst, and lower process performances. For the treatment of this type of feed acid, an enrichment process or hydrocarbon removal by activated carbon is normally applied. In order to achieve this, thermodynamic models and experiments were used to study combustion of heavy hydrocarbons in substoichiometric conditions. It was ensured that the soot was formed at the stoichiometric amounts of air, that is, less than 60% of the combustible components in the feed acid gas. Then more air was required to prevent soot formation; consequently, the sulfur-recovery rate was decreased significantly. The fine combustion air control, the higher flame temperature, the sufficient residence time in the reaction furnace, and the excellent high-intensity main burner are the key factors for the stable operation with the high process performances, free of trouble related to the soot formation. Before initial start-up of the SRU, the control system of the combustion-air supply was specially optimized for this feed-acid gas.

Since the initial start-up operation, the task of achieving the high sulfur-recovery rate to meet the environment regulation with the production of the good quality and salable sulfur is fulfilled.

The actual feed-gas specification is now not as lean in H₂S content, but contains more heavy hydrocarbons. Because of the well-designed advanced control system, this task is achieved in the ordinary operation manner of the SRU.

Performance test

Performance testing of the first liquefaction train was successfully conducted beginning on Sept. 28, 1997, for 72 hr with minor problems:

• Insufficient propane purity
• Entrainment from low-pressure propane chiller.

Insufficient propane purity is mainly caused by the feed-gas deviation from the design feed-gas composition. The propane purity was achieved by reducing the de-ethanizer operating pressure. Entrainment from the low-pressure propane chiller caused a high-level trip of the propane compressor suction drum by improper level transmitter span of the chiller. Performance testing of the first sulfur-recovery train began Oct. 5, 1997, and ran for 72 hr without any problems. Performance testing of the second liquefaction train began Nov. 3, 1997, and went for 72 hr with minor outstanding problems such as entrainment from the low-pressure propane chiller. A 72-hr performance test of the second sulfur-recovery train began Nov. 7, 1997. This resulted in a color-test failure. All test results are shown in Table. 1 [114,226 bytes]. The 72-hr auto-consumption, self fuel-consumption rate test was successfully performed, beginning Oct. 21, 1997, feed backing the de-ethanizer operating pressure from the first-train performance test. The auto-consumption of the plant is calculated as 4.09 terajoules/hr against the guarantee value of 4.86 terajoules/hr, while the LNG production rates are at 309.3 metric tons/hr for the first train and 315 metric tons/hr for the second train. The auto-consumption figure is adjusted for cooling-water temperature, although the adjustment for the ambient temperature was not made since it was unnecessary: ambient, 30.37° C. (avg.) test, 29° C. design; cooling-water, 31° C. test, 35° C. design.

Plant availability

Design life of the plant is 30 years, and appropriate consideration has been made for the hot, salt-laden atmosphere at the remote coastal site. The sparing and monitoring philosophy is based on obtaining an annual availability, excluding scheduled shutdowns, of 95% for each LNG train. Two types of scheduled shutdowns are planned. A major shutdown shall be scheduled every 3 years for each process train after some adjustment during the first 1-4 years to enable a regular pattern to develop. This schedule for major train shutdowns satisfies the requirement that only one process train is to have a major shutdown in any single year, while catering for the planned expansion to three LNG trains. A minor shutdown of each process train will take place annually unless the train is due for its major shutdown. The process-train major shutdown is to be completed in 30 days and shall permit major overhaul of all four compressor gas turbines and cleaning of seawater exchangers. The minor shutdown is to be achieved in 5 days and shall include combustion-chamber inspection of the gas turbines and change-out of the complete inventory of molecular-sieve material or mercury-removal bed (if required). Based on two minor and one major shutdowns in a 3-year period, the average scheduled downtime is therefore 13.3 days/year. In addition to the scheduled shutdowns, each LNG train can experience unscheduled downtime. The annual average unscheduled downtime for an LNG train is not to exceed 5%.

Acknowledgment

Information provided by Qatar Liquefied Gas Co. and process licensors is hereby acknowledged.

The Authors