Commissioning. The EcoElectrica LNG Import Terminal. Penuelas, Puerto Rico. Jeffrey G. Steimer, Vice President, LNG/Aerospace Sales.

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1 Commissioning Of The EcoElectrica LNG Import Terminal At Penuelas, Puerto Rico By Jeffrey G. Steimer, Vice President, LNG/Aerospace Sales And Mark McGahey, Project Engineer Pitt-Des Moines, Inc. Presented at Gastec 2000 November 2000

2 Abstract The world s newest LNG import terminal was completed in July 2000, at Pe uelas, Puerto Rico. The EcoEl ctrica facility includes a 500-megawatt power generation station, fueled by natural gas provided by the import terminal. The power plant was completed in December of Propane was the initial primary fuel for the turbines, until completion of the LNG facilities. The first LNG ship arrived at Pe uelas in early July This paper discusses the start-up of the LNG terminal, with particular emphasis on integration of the LNG operations with the power plant. Design features of the terminal are reviewed, and startup is discussed, from final completion and pre-commissioning activities, through purge, cooldown, initial ship unloading, commissioning, switching from LPG to LNG at the power plant, and performance testing. Operating experience and an update on performance of the project is also provided. Introduction The EcoElectrica project has been completed, and is now in operation at Penuelas, Puerto Rico. Pe uelas is located on the southern shore of Puerto Rico, nine miles west of Ponce. The LNG import terminal is a key part of the EcoEl ctrica Project, which also includes a combined cycle natural gas fired power plant, and desalinated water plant. It is located on a peninsula known as Punta Guayanilla, on a former industrial site. EcoElectrica is a joint venture between Enron of Houston, Texas, and Edison Mission Energy, of Irvine, California. Pitt-Des Moines, Inc. (PDM) is the prime EPC contractor for the LNG terminal. The overall contractor for the project is Enron Engineering and Construction Company. The LNG import terminal includes a world class LNG tanker berth at the end of a piled concrete jetty, a 160,000 cubic meter double containment LNG tank, submerged in-tank sendout pumps, shell and tube vaporizers and superheaters for power plant fuel service, future open rack sea water vaporizers for pipeline gas service, centrifugal blowers and rotary screw compressors for boil-off gas service, and a dual LNG/LPG flare for emergency releases. The power plant includes two Westinghouse 501F combustion turbines nominally rated at 160 MW, ABB-Combustion Engineering heat recovery steam generators, and a Toshiba steam turbine nominally rated at 214 MW. The power plant waste heat is rejected to an induced draft salt water cooling tower. Thermal energy from the power plant in the form of low-pressure steam is used in a 2 million gallon per day desalinated water plant. Cold energy from the LNG vaporization process is used to chill inlet air to the combustion turbines by means of a circulating water/glycol cooling loop. The use of cold energy from the LNG substantially improves the thermal performance of the combustion turbines and reduces the cost of vaporizing LNG. The power plant operated initially on LPG, having been completed substantially before the LNG terminal. The existing ProCaribe LPG terminal, owned by Enron and located at Tallaboa Bay, four kilometers east of the EcoElectrica site, was refurbished for this purpose, including the addition of a Steimer 2

3 new 20,000 cubic meter LPG tank, refrigeration system, sendout pumps, and pipeline to the power plant. Fuel oil was utilized as the initial backup fuel source. With the LNG terminal operational, LPG serves as the primary backup fuel, while fuel oil will remain available. LNG Terminal Design Basis The LNG terminal design complies with the United States Federal LNG regulations as well as international standards for such facilities. Key codes and standards include: 49 CFR Liquefied Natural Gas Facilities 33 CFR Liquefied Natural Gas Waterfront Facilities NFPA 59A - Standard for the Production, Storage, and Handling of Liquefied Natural Gas NFPA 70 - National Electric Code API Design and Construction of Large, Welded, Low Pressure Storage Tanks ASME B Chemical Plant and Petroleum Refinery Piping Society of International Gas Tanker and Terminal Operators (SIGTTO), various standards relating to marine terminals Oil Companies International Marine Forum (OCIMF) - Design and Construction Specification for Marine Unloading Arms Local Codes Siting of the facility is in accordance with 49 CFR Part 193. The remote former industrial area is ideal for an LNG facility, with a relatively low population density in the immediate area, and limited industrial use of adjoining properties. However, the plant site itself is relatively small (98,000 square meters for the LNG facility, 176,000 square meters total). As a result, a double containment LNG tank and an on-shore spill impoundment with insulating concrete are utilized. The double containment design provides spill containment with a close in post-tensioned concrete dike surrounding the tank, substantially reducing thermal exclusion zones. Basic design criteria for the terminal include: Storage - 160,000 cubic meter Double Containment LNG Tank Ship Unloading - 9,000 cubic meters of LNG per hour, unload 125,000 cubic meter vessel in 18 hours Sendout 80 MT/hour at 45 bar (g) (100% spare capacity installed) Vapor Compression 27 MT/hour at 28.3 bar (g) during ship unloading LNG Storage Tank The LNG storage tank has a capacity of 160,000 cubic meters. accordance with Appendix Q of API 620 plus 49 CFR Part 193. It is designed and constructed in The basic design parameters for the LNG tank includes: Gross Capacity 160,000 Cubic Meters Steimer 3

4 Net Capacity 153,600 Cubic Meters Heel 1.22 Meters Internal Design Pressure 138 mbar (g) External Design Pressure 4.3 mbar (g) Design Roof Load 100 Kg per M2 Boil-off Rate 0.05% per day at 35 C Wind Speed 90 M/Sec OBE 0.20 G SSE 0.40 G The storage tank design is double containment. A close-in post-tensioned concrete dike surrounds the conventional double wall tank. A 9% nickel steel inner tank is utilized. The dike provides secondary containment in the unlikely event of liquid leaks in the primary container. The tank foundation is a continuous concrete slab, with conventional reinforcing. The foundation slab is installed at grade. A foundation is heating system is provided to prevent ground freezing and resultant frost heave. Soils improvement measures, including pre-consolidation and installation of stone columns, were implemented to mitigate the risk of soils liquefaction under seismic loading. Ship Unloading Facilities A marine terminal is provided to unload LNG tankers and transfer LNG to the storage tanks. The terminal can accommodate LNG tankers to a capacity of 135,000 cubic meters. The dock and dolphins for ship berthing are installed at the end of a concrete trestle, 530 meters from shore, which extends into Guayanilla Bay. The location of the dock was selected to allow world-class LNG tankers to berth without the need for dredging. The trestle extends the dock facilities out to the natural channel in the bay with sufficient water depth to permit this design approach. The trestle, dock, and dolphins are constructed of reinforced concrete, and are supported on driven concrete piles. Three 16-inch liquid unloading arms are provided to offload LNG ships. One 16-inch vapor arm is provided to return vapor to the ship from the LNG tank during unloading operations. A 3-inch nitrogen line is piggybacked onto the vapor line, for nitrogen supply to the ship. The arms are hydraulically operated articulated type, provided by FMC. Double ball valve Powered Emergency Release Connections (PERC) are provided for each arm. Disconnection is activated automatically by ship position, or manually. The unloading facilities are designed for a flow rate of 9,000 cubic meters per hour, and a discharge time of 18 hours maximum for a 125,000 cubic meter vessel. The maximum ship tank storage pressure is 1120 mbar (a), and the minimum ship pump discharge pressure is 3.6 bar (g). A single 32 insulated stainless steel liquid line directs LNG to the storage tank. Both bottom and top fill connections are provided at the tank. Steimer 4

5 LNG Sendout System The LNG sendout system is designed to provide a maximum continuous flow rate of 80 MT/hour to the gas turbines, at a pressure of 45 bar (g) and a temperature of 10 C at the battery limits. Two submerged in-tank LNG pumps are provided. Each pump has the capacity required for operation of the power plant gas turbines. Thus 100% spare pumping capacity is provided. Two additional pump columns are installed in the tank initially, anticipating future demand for off-site gas sales. Pump column diameter is 32 inches. The maximum sendout rate demand for turbine startup is 0 to 27.5 MT/hour in two minutes. The sendout system is designed to provide this rate. Instantaneous variations in the gas demands of the turbines can occur, and vary by as much as +/- 5%. The sendout system is designed to accommodate such fluctuations, acting in parallel with a gas accumulator system. This system includes the initial installation of pipeline for anticipated off-site sale of gas to other consumers, and when fully pressurized provides a volume of gas to act as a buffer when instantaneous increases in the power plant gas demand occur, until the sendout system can catch up. One pump is used to maintain a continuous flow of LNG to the unloading dock, via a 6 cooldown line, during periods when plant operators desire to keep the ship unloading piping systems cold, as well as during cooldown operations. A variable frequency high efficiency drive is provided for this purpose, for each LNG pump. Two LNG vaporizers will be provided, each with a capacity of 80 MT/hour, providing 100% spare capacity. The vaporizers are shell and tube types, heated by water glycol. The inlet air cooling system for the gas turbines in turn heats the water glycol solution. This unique integration of inlet air cooling and LNG vaporization substantially increases the efficiency of the power plant, while reducing both capital and operating costs for the LNG vaporization system. Water is heated by the inlet air heat exchangers. This heat is exchanged against the closed loop water/glycol system, which is pumped to the LNG vaporizers. Metering of vaporized gas, as well as boil-off gas, to the turbines is provided. Odorization is not required. Steimer 5

6 Vapor Handling Systems Single stage centrifugal blowers are installed to return vapor to the LNG tanker during unloading operations. Three blowers are provided each with a capacity of 13.5 MT/hour. Maximum ship pressure is assumed to be 1120 mbar (a). An air cooled vapor return recycle gas heat exchanger is provided to remove the heat of compression if the blowers are running with no flow to the ship. Variable frequency drives are provided for the compressor motors, to enhance efficiency. The vapor line from the tank to the ship is 16-inch diameter stainless steel. In addition to returning vapor to the ship, the centrifugal compressors also serve as the first stage of boil-off gas compression. Four rotary screw compressors provide the second stage. Each compressor is designed to boost 6.75 MT/hour of boil-off gas to a pressure of 28.3 mbar (g) at the LNG facility battery limits, for use as turbine fuel gas. A single compressor is required to accommodate normal holding conditions, including tank and piping heat leak, one LNG pump on recycle, and a falling barometric pressure rate of 1.72 mbar/hour. All four compressors are required for the maximum operating conditions during ship unloading, including tank and piping heat leak, falling barometric pressure, tank vapor displacement, ship pump heat, and ship boil-off. The compressors have slide valve capacity control, positioned according to storage tank pressure. Each compressor is furnished with a microprocessor for individual control and operation. A dual use flare is provided to safely accommodate plant upset conditions. The flare is designed t o dispose of the design flow rates of both LNG and LPG. Control and ESD Systems An integrated distributed control system is provided for the project, encompassing both the power plant and the LNG terminal. The various DCS system components are linked via fiber optic cable, with a backup redundant fiber. A single control room is utilized. DCS equipment dedicated to the LNG facility in the control room consists of two control consoles, two printers, and an optical disk storage device. This is the primary control location for the LNG facility. One of the consoles acts as a workstation for network hardware configuration and screen generation. A DCS processor, I/O, and control console are installed in the dock control building. This control station has the capability of operating the ship unloading facilities independently of the other areas of the LNG facility. A DCS processor, I/O, and control console are similarly installed in the motor control center building. This control station has the capability of operating the storage and vaporization areas independently. A control console is also installed in the administration building, for monitoring LNG facility operations. Steimer 6

7 Operator stations consist of Pentium processors, 21 monitors, and QWERTY type and Mylar membrane keyboards. The software package utilizes a graphically oriented objects based approach to process control. Emergency shutdown systems (ESDs) are provided for the unloading area and the LNG storage/sendout area. The ESD systems are functionally independent of the DCS system. They are interconnected to the DCS via fiber optic cable. The DCS is capable of monitoring and initiating ESD. The unloading ESD is connected to the ship ESD via flexible cable, and is hardwired to the LNG storage/sendout ESD. The LNG storage/sendout ESD incorporates subsystem ESDs for the storage tank, vaporizers, and boil-off compressors/vapor blowers. All ESDs and subsystems are capable of initiation automatically by process point trip or hazard detection, and manually by hardwired push button. Uninterruptible power supplies are furnished, at the unloading dock control building and the power distribution building, for control, emergency shutdown, and communications systems Buildings The LNG facility shares the control room, administration building, and maintenance buildings with the power plant. Separate buildings dedicated to the LNG facility include: Boil-off compressor/vapor blower shed Air compressor building Motor control center building Unloading dock control building Fire Protection and Safety Systems A firewater loop is installed around the LNG facility area, on the trestle, and at the dock. The firewater is supplied from the power plant. Firewater monitors are installed on the unloading dock, along the trestle, and in the LNG facility area, plus a connection is provided at the dock for supplying firewater to the LNG tanker. Monitors are manually operated only. Fire extinguishing systems are provided. A combination of fixed, wheeled, and hand-held dry chemical units and hand-held carbon dioxide units are utilized. High expansion foam systems are installed at the process area impoundment to mitigate thermal radiation from LNG pool fires. A fire suppression system is provided for the motor control room. One remotely operated dry chemical system is provided at the unloading dock, controlled from a tower located on the trestle near the dock. Hazard detection instrumentation is provided, including flame, high temperature, low temperature, smoke, and combustible gas detectors. All detectors are wired to the control room, for alarm and emergency shutdown. A separate DCS display panel indicates the locations and status of each detector. Three separate and independent communications systems are provided. The primary system is a telephone communications system, linking the primary control stations at the unloading dock Steimer 7

8 building, power plant control room, and administration building. This system will also be connected to the LNG ship via a flexible cable. An emergency telephone communications system is provided, linking the primary control stations and the local control stations at the top of the LNG storage tank, vaporizer area, unloading platform, boil-off compressor shed, power distribution building, and locations along the pier. Security communications is provided by two-way radio. Public address speakers and intercoms are provided at each telephone location. A security monitoring system is provided. Television cameras are installed on the top of the LNG storage tank, at grade level in the LNG process area, on the pier, and on the unloading dock. Cameras have pan, tilt, and zoom capability. Television monitors are located in the power plant control room and the unloading dock area. Emergency lighting is provided for all operating areas in the LNG facility, including the buildings, process area, LNG storage tank top platform, the trestle, and the dock. Pre-Commissioning of Major Mechanical Equipment Construction of the LNG facility began in June of By early 2000, major mechanical components were in place. Pre-commissioning of this equipment began in April of The four rotary screw boiloff compressors were factory tested by running on air, prior to arrival at the jobsite. Prior to coupling with the compressors at the jobsite, the 2,500 horsepower compressor motors were tested. This included a one-hour run for each motor, checking for vibration and proper alignment. The eight 20 horsepower boiloff gas cooler fans were also run with belts disconnected to check for vibration. After the compressors were aligned with the motors and leveled on their foundations in the compressor building, air was again utilized to check out and confirm proper operation. During the initial cooldown of the LNG tank, nitrogen vapors were utilized to further confirm operation. The three centrifugal compressors were also tested at the factory, utilizing cold nitrogen vapors, and the variable frequency drives which were to be installed in the motor control center for these compressors. The 300 horsepower motors were run in the field for one hour prior to alignment with the compressors, checking for vibration and alignment. Similar to the boiloff compressors, the centrifugal compressors were also field tested with air initially, and then run on cold nitrogen vapors during cooldown of the LNG tank. The in-tank LNG pumps were factory tested by the vendor. LNG was utilized for the test. curves were confirmed during testing. Pump The LNG sampling system skids were factory tested, utilizing liquid nitrogen. sampling system vaporizers and confirmation of sampling rates were confirmed. Operation of the Motors for remaining equipment were also bumped prior to start up of the LNG terminal, including: Steimer 8

9 Three 75 horsepower and one 10 horsepower process area spill impoundment sump pumps. Four 75 horsepower and four 10 horsepower LNG tank spill containment sump pumps. Two 30 horsepower instrument air compressors. One 50 horsepower flare blower. Two 2 horsepower centrifugal compressor recycle gas cooler fans. Input/output and operation of the power distribution equipment was checked out at the factory prior to shipment. The variable frequency drives for the 4,160 volt 750 horsepower LNG pumps and the 480 volt 300 horsepower centrifugal compressors were checked out shortly after installation in the field, before start-up of the pumps and compressors. This included diagnostic checks, input/output checks, and frequency output checks. Equipment vendor technicians assisted with pre-commissioning and start-up of the following major components: LNG and vapor arms at the dock Boiloff gas compressors LNG pumps LNG vaporizers Centrifugal compressors Variable frequency drives LNG sampling systems Motor control center Foam system Remote operated dry chemical system Motor control center fire suppression system Control System PDM designed the distributed control system for the LNG terminal. The system hardware, software, and programming were provided by Enron, as part of the order for the power plant control system. As previously discussed, these systems are integrated for optimal performance. Enron subjected the DCS equipment to a Factory Acceptance Test prior to shipment. Steimer 9

10 The DCS for the LNG terminal includes two stations in the field, at the motor control center building and the dock building. Both of these are Engineering Stations, configured so that control loops can be checked out at each location, independent of power block operations, and each other. Several major equipment items have skid-mounted local control systems. These include the boiloff gas compressors, centrifugal compressors, variable frequency drives, and motor control center. These systems allowed functional checkout of this equipment both at the factory and in the field, prior to integration with the DCS system. After checkout of each individual control station, and its associated equipment and field-mounted devices, the LNG control system was integrated into the overall power plant system during a shutdown period at the power plant. This allowed for a seamless startup and integration of the systems. The control system architecture, with functional independence, proved very convenient for operator training. The independent stations allowed operator training to proceed separately at each location, while other activities could be performed at other locations. This also contributed to the ease of control loop checkout and functional checks of equipment operation. The LNG facility has approximately 2,500 control loops, excluding the packaged local control systems for skid-mounted equipment. Control loop checkouts were performed over a three-month period, from April to June The loop checks were performed on a twenty-four hour a day, seven days per week schedule, to allow completion and operation of the LNG facility in accordance with contract requirements. Two crews were utilized for loop checks, each working twelve hour shifts. Each crew was comprised of six individuals, including an operator stationed at each control consol, two field instrumentation technicians, and two field engineers. Both loop checks and functional checks were performed by these teams. Control loop checks were performed by plant system. These systems included: Instrument Air Nitrogen Potable water Firewater Flare Foam Water/glycol Wastewater Steimer 10

11 High Voltage Low Voltage Ship Unloading LNG Tank Sampling Boiloff Gas Oily Water Sendout The above list also indicates the sequence of the checkout operation, and turnover to Enron Engineering for evaluation and punch list development. The safety systems were also carefully checked out and prepared for plant operation. systems include: These key Firewater Foam Dry Chemical MCC Building Fire Suppression System Hazard Detection Systems, including gas, fire, smoke, oxygen, low temperature, and high temperature detectors Emergency Shutdown Systems These systems were loop checked and functionally checked like all other systems. In addition, EcoEl ctrica, Enron Engineering and Construction, the Coast Guard, the local Fire Marshall, and other government agencies participated in this process. Valve, equipment shutdown, alarm, and horn operation were all witnessed by EcoEl ctrica, EECC, the Coast Guard, and, in some instances, the local Fire Marshall. The foam system, motor control building fire suppression system, and remote operated dry chemical system at the dock were all checked out and functionally tested by vendor technicians. This process expedited approval of these key safety systems by government agencies. The hazard detection, safety, and emergency shutdown systems consumed over half of the total checkout time for the LNG terminal. Steimer 11

12 Purge and Cooldown Operations Nitrogen for purge and cooldown was supplied from two local air separation plants. Purging of the LNG facility began on June 14, at 5:00 PM. Purging of the LNG tank utilized a liquid nitrogen pumping unit and a diesel-fueled vaporizer. The nitrogen injection point was at liquid nitrogen piping running from the liquid nitrogen storage tank to LNG storage, via a temporary connection. The flow rate during tank purge averaged 115,000 scf per hour. During the tank purge operation, the overpressure and uplift tests required by API 620 Appendix Q were performed. Nitrogen flow was directed to a purge header at the bottom of the inner tank. A piston effect was established, such that the nitrogen accumulated at the bottom of the tank first, and slowly progressed upward, so that the purge could be accomplished utilizing the least amount of nitrogen. During purging of the inner tank and annular space, air was removed from the tank through a purge header installed at the bottom of the annular space. During purging of the roof dome space, air was removed by utilizing a temporary valve installed at the top of the tank roof. The 32-inch LNG fill line was purged at the same time as the LNG tank. Other process piping was purged utilizing the permanent liquid nitrogen tank and vaporizer installed at the LNG facility. The LNG tank was purged to an oxygen level of 7% or less. The piping systems were purged to a level of 1% oxygen or less, to assure dryness. There was no dew point criteria for purge. Purge operations were completed on June 19, 2000, at 6:00 AM. A total of 10,890,000 scf of nitrogen was required. Cooldown of the LNG tank utilizing liquid nitrogen began on July 2, 2000, at 7:00 AM. A liquid nitrogen pumping unit was again utilized. The unit was connected to the 32 inch unloading line via a drain line. At the tank, nitrogen flow was directed to a cooldown header and spray nozzles, installed below the suspended insulation deck at the middle of the inner tank, via a four-inch cooldown line. The nitrogen pumping rate varied between 50 and 100 gallons per minute. A system of thermocouples was installed at the base of the tank, around the tank circumference, to monitor tank temperatures during the cooldown operation. The rate of cooldown was maintained at 5 F degrees per hour or less. The temperature differential between any two adjacent thermocouples was maintained at 50 F degrees or less. The temperature differential between any two thermocouples in the tank was maintained at 100 F degrees or less. Cooldown was considered to be achieved when all tank thermocouples read -240 degrees F or less. This was achieved on July 7, 2000, at 10:00 AM. A total of 490,000 gallons of liquid nitrogen was required. Tank cooldown was maintained until July 10 at 12:00 PM, utilizing additional liquid nitrogen. This required an additional 165,000 gallons of liquid nitrogen, at an average flow rate of 40 gpm. The LNG unloading line and vapor line were cooled down to 175 degrees F utilizing cold nitrogen vapor, the desuperheater located at the dock, and the centrifugal compressors. Cold nitrogen vapor from the LNG tank was directed to the dock via the 16-inch vapor line utilizing the centrifugal Steimer 12

13 compressors, further cooled by spraying liquid nitrogen into the desuperheater vessel, and directed back to the LNG tank via the 32 inch line. LNG Ship Unloading The first shipload of LNG was delivered from Trinidad by the Matthew, a 125,000 cubic meter capacity carrier. The Matthew arrived at Guayanilla Bay on July 9, It remained at anchor offshore until the morning of July 10. The Matthew docked and was tied off by 10:00 AM. US Customs and Immigration officials were the first to board the vessel, followed by the US Coast Guard and EcoEl ctrica representatives. The LNG liquid and vapor arms were connected to the Matthew for the first time, and purged, by 1:00 PM. Ship unloading began at 3:00 PM. Cooldown of the LNG arms was accomplished by utilizing a stripping pump aboard the ship. This pump was also utilized to further cooldown the 32 inch unloading line to 250 degrees F. The main cargo pumps were then brought online, and the flow rate to the LNG tank increased slowly until full flow at 45,000 gpm was achieved at 10:30 PM. Unloading proceeded at this rate for eight hours. No vapor was returned to the ship during this initial unloading operation, nor was vapor recovered by the boiloff gas system. All vapor required due to cargo displacement was generated by a vaporizer on board the Matthew. The nitrogen-rich vapor generated in the LNG tank during ship unloading was either sent to the flare or vented from the tank relief valves. The Matthew unloaded a total of 89,000 cubic meters of LNG. The ship unloading performance test was conducted during this operation, and successfully demonstrated that contractual performance criteria were achieved. Unloading operations were completed on July 11, 2000, at 1:00 PM. There was one emergency shutdown during ship unloading, due to hazardous vapor detection at the top of the LNG tank during venting operations. The ESD shutdown sequence functioned as designed, the issue was resolved, and ship unloading proceeded to completion. Sendout System Commissioning The LNG pumps were initially run on recirculation on July 12, beginning at 4:00 PM. The variable frequency drives were utilized, running at _ speed, 45 Hz. The water glycol supply system to the vaporizers was pre-commissioned in June by first flushing the system with potable water, passivating the piping, then adding ethylene glycol until a 50%/50% mixture was achieved, by weight. With the water/glycol solution circulating in a closed loop, heat for initial LNG vaporization was supplied by the trim heater. The trim heater in turn is supplied with heat from the power plant closed water cooling system. When LNG operations commenced, the power plant was running on LPG. In order to begin natural gas operation, the turbines were switched to fuel oil. One turbine was then shut down, while the other continued to operate. One LNG pump was started up, and flow directed to the vaporizer. The natural gas line to the power plant was previously purged with nitrogen. This line was pressurized by Steimer 13

14 natural gas from the vaporizer. When the required pressure was achieved, the natural gas was directed to the turbine, and operation on natural gas commenced. This first occurred on July 17, By August 1, both turbines were running continuously on natural gas. With both turbines in operation, the inlet air cooling system could be utilized to vaporize LNG. With this system in operation, the trim heating system automatically backs off, until all the inlet air cooling system is providing all heat required for LNG vaporization, and the LNG vaporization system in turn supplies cooling to the inlet air system. This operation was achieved, and the sendout system performance testing was successfully completed on August 4, With the power plant in operation on natural gas, the boiloff system could be utilized to direct LNG tank boiloff to the power plant. There was some initial concern that with the purge operations only recently completed, the nitrogen-rich boiloff gas could cause disruptions to the power plant operation. In fact, there were no problems of this nature, and operation of the boiloff gas system and power plant proceeded smoothly. Performance Testing The prime contract for the EcoElectrica facility, as well as the contract for the LNG terminal, both required that certain performance tests be successfully completed prior to achieving substantial completion. All such tests were completed successfully, and on time, in accordance with these requirements. The LNG facility had to demonstrate the Ship Unloading Guarantee, defined as successfully unloading a 125,000 cubic meter LNG ship in eighteen hours or less, at specified ship conditions. The intention of the contract was that this test would be performed when the second LNG tanker was unloaded, allowing for the inherent uncertainties when a facility of this nature is first put into operation. In fact, operation of the unloading of the first ship went so smoothly that the test was conducted at that time. The design flow rate required to achieve unloading in the stipulated time as specified, 9,000 cubic meters per hour, was exceeded for several hours, and both EcoEl ctrica and EECC accepted these results, waiving any further testing on arrival of the second LNG ship. Actual flow rates were in excess of 10,000 cubic meters per hour. Each pump and vaporizer had to demonstrate the Vaporization Rate Guarantee, which included the capability to deliver the design sendout rate of 93 mmscfd, for a test duration of one hour. Actual flows during the test were mmscfd and 91.3 mmscfd, at a temperature of 46 degrees F. These values were the gas demands that were placed on the LNG sendout system by the power plant. Correcting for the gas design temperature of 40 degrees F, and the actual composition of the gas, which varied from the design composition, it was demonstrated that the sendout system meets the Vaporization Rate Guarantee. Acting together with the power plant, the LNG sendout system had to demonstrate the LNG Terminal Availability Guarantee. This required continuous operation of the power plant and LNG sendout system for a period of seventy-two hours, at full power plant demand, not to exceed a sendout rate of 93 mmscfd. Fluctuations in power plant fuel demand must be accommodated by the sendout system during this test. Both the power plant and LNG sendout system met the Availability Guarantee easily, without incidence. Steimer 14

15 The LNG vaporization system was required to return water/glycol to the inlet air cooling system at a temperature at least 27 degrees F colder than the water/glycol supplied to the LNG vaporizers from the inlet air cooling system, at a sendout rate of 82.5 mmscfd. The test was performed with a sendout rate of for one pump/vaporizer set, and mmscfd for the other set, and a gas delivery temperature of 46 degrees F. The data gathered during the test was input into a computer model to determine the product of the heat transfer coefficient and area available in the vaporizer. This model was then used to simulate the vaporization of 82.5 mmscfd of Design Basis Composition LNG. The fluid temperatures calculated demonstrated that the water/glycol temperature decrease through the vaporizers would exceed the specified minimum requirement of 27 degrees F at the design conditions. The Operating Point Guarantee was therefore successfully demonstrated. The Auxiliary Load Guarantee required that the electrical consumption of the terminal, exclusive of ship unloading operations, flare heater, flare blower, sump pumps, LNG pump in service for piping cooldown, boiloff compressors, centrifugal compressors, and LNG tank annular space lighting should not exceed 1,000 kw. All of these loads were considered intermittent, and would not contribute significantly to total power used by the LNG facility over the normal course of time and facility operation. The total auxiliary load measured during the test, including sendout to the power plant, was 788 kw, significantly lower than the contract requirement. A tank boiloff test was not required. The contract did require, however, that tank boiloff shall not exceed the specified rate as demonstrated by calculations in accordance with generally accepted methodology in the LNG industry. The calculated boiloff rate at design conditions is 0.046% per day of tank contents, versus the design rate of 0.05%. This performance point was therefore successfully demonstrated. All performance tests were successfully completed by August 4, 2000, in accordance with contract schedule requirements. Current Plant Operations As of the date of writing of this paper (September 1, 2000), the second LNG ship was successfully unloaded at EcoEl ctrica. Both gas turbines continue in operation successfully on natural gas. The LNG terminal has been acknowledged as Substantially Complete by EcoEl ctrica, and continues to function as specified under the control of EcoEl ctrica. Punchlist items are being completed by PDM, and Final Completion will be achieved shortly, with their completion. Provisions for Future Expansion A second tank and a second set of vaporizers will be required when justified by off-site sales. Several provisions are made in the design of the LNG facility to accommodate the additional facilities as simply and economically as possible, while minimizing current capital expenditures. The facility is designed, sited, and permitted for two LNG tanks. Soils improvement, including preconsolidation and stone column installation, has been completed at the second tank site. Construction of the second tank foundation can therefore begin immediately after release. Two spare pump columns are installed in the LNG tank, including foot valves, extensions to the platforms, spill collection system, and pump removal system. Various other measures are Steimer 15

16 incorporated into the facility piping design to allow expansion with little or no disruption to ongoing plant operations, including: LNG sendout piping from the tank manifold to the vaporizers is designed for a flow rate of 320 MT/hour. Space is provided in the LNG facility layout for the addition of seawater vaporizers. Thermal exclusion and vapor dispersion zones are calculated based on the second tank, plus the additional vaporization equipment. Space is provided on pipe racks for the addition of piping and electrical service for the additions. Space is provided in the power distribution building for additional equipment as required. The original four boil-off compressors and three vapor blowers are adequate for the additions. Tie-in points are provided for the installation of additional vaporizers and a truck loading station. Schedule The EcoElectrica Project was conceived in 1992, in response to a request from PREPA (Puerto Rico Electric Power Authority) for proposals for furnishing the first independent power plant in Puerto Rico, under PURPA. The EcoEl ctrica Project was selected by PREPA in Permitting, financing, and contract finalization were completed in late Enron Engineering and Construction then issued a Notice to Proceed to Pitt-Des Moines, Inc., for the LNG facility in December of 1997, at the same time that work on the power plant commenced. The power plant went on line in December of The LNG facility was completed and operational in July of Performance testing was completed on August 4, All contractual schedule milestones were met. Steimer 16