gl1z plant operation enhancement and overall …...the lng plant gl1z of sonatrach at arzew...

© Gastech 2005

The 21st International Conference & Exhibition on LNG, LPG and Natural Gas

(Gastech 2005) Bilbao, Spain, 14-17 March 2005

GL1Z PLANT OPERATION ENHANCEMENT AND OVERALL RELIABILITY IMPROVEMENT

By Abdelouahab Madouri

Adda Missoum Process engineers

Technical department GL1Z plant/Sonatrach

Algeria

© Gastech 2005 Madouri 2

ABSTRACT

The LNG plant GL1Z of Sonatrach at Arzew (Algeria) started production in february 1978. It uses the APCI C3-MCR process to liquefy the natural gas. The nameplate production capacity of this plant is 105 billion thermies of HHV/year.

During the initial twelve years of operation, the LNG production level was approximately 60% of the plant

capacity. This was mainly due to difficulties inherent to the operation and reliability of the major refrigeration compressor turbine drives, the associated process boilers and the main cryogenic heat exchangers. In addition, extended trains' start up time and excess gas flaring were major concerns for the plant.

To increase the plant LNG production and improve overall reliability, Sonatrach has implemented a revamp project. Ensuring compliance with current safety legislation was also the aim of that project.

During this project, the LNG production capacity has been first restored to the design capacity then, increased to

110% after solving some bottlenecks. Furthermore, some process changes and addition have been introduced to improve the LNG trains operation, thereby reducing start up time and consequently minimising annual auto-consumption. Some process modifications have resulted in some troubles, which have been subsequently resolved.

This paper will first highlight the limiting bottlenecks, the weak equipment reliability and the operating difficulties, experienced during the initial twelve years of operation. Then, it will present the main process modifications carried out during the revamp project. Finally, it will cover the actual LNG production levels, the equipment reliability and the plant availability. 1- INTRODUCTION

The LNG plant GL1Z of Sonatrach at Arzew (Algeria) started operation in February 1978. It consists of six identical process trains, using the APCI propane pre-cooled-MCR process to liquefy the natural gas. The plant is designed to produce 105 billion thermies per year of high heating value (HHV) in equivalent LNG.

From 1980 to 1983, the plant operation was reduced due to commercial reasons. When the commercial conditions were re-established in 1989, and the production resumed, some maintenance problems had been experienced, which subsequently affected plant operation. In addition, extended trains start up time due to leaner feedstock and excess gas flaring were the major concerns for the plant.

To overcome these problems, a revamp project has been initiated in 1993. The aim of this project was to improve the plant reliability flexibility and safety and further increase LNG production. The project activities had been undertaken within less than four (04) years, without interrupting totally the LNG production of the plant and with no lost time incident.

To continue operating efficiently and reliably, GL1Z plant made many efforts by solving main factors, which had an impact on plant operation and LNG production. The loss of production report was the main tool used to establish problem priorities, thus helping management to deal with the essentials.

In order to perfectly assess revamp benefits, it was thought necessary to consider the plant performance during a period as long as five years after project completion. 2- PREVIOUS OPERATING PROBLEMS 2.1- LNG production limitation

Analysis of the loss of production from plant start up to 1992 highlighted some serious problems, which affected significantly the LNG production. Nineteen problem areas were identified, five of which account for over 50 % of the production loss. These five areas are:

- Liquefaction: The main cryogenic heat exchangers

- Compression: The refrigeration compressor turbines LNG trains related causes - Steam generation system: Process boilers - Seawater system: Main pumps and exchangers Utilities related causes

- Electrical power generation: Turbo generators


- Main cryogenic heat exchangers

The main cryogenic heat exchangers (MCHE) had experienced many repairs due to the hot bundle tube leaks. In fact, tube damage due to combined thermal and mechanical shocks during train trips was identified to be the main cause. Thus, the frequent need for inspection and repair affected the availability of the MCHE, resulting in LNG production losses. Furthermore, the availability of the MCHE was affected by mercury attack, which was due to non-existence of a mercury removal system within the process trains. - Refrigeration compressor turbines

The second major problem causing the loss of production was identified to be the poor reliability of refrigeration compressor turbine drives. Corrosion of the steam path with associated blade failures, as well as coupling failures due to high vibration levels and axial displacements were experienced. Investigations on the various failed turbines revealed the main following causes:

- The poor quality of steam: Seawater salts, such as sodium and calcium chlorides entering the steam system via leaking surface condenser tubes and accumulating in the turbine.

- The operating conditions did not provide the isolation and nitrogen conservation of the turbine rotors during long

period of turbine shutdown. In fact, oxygen ingress in the turbine, during shutdown, was also the cause of a severe corrosion.

- Failures of the turbo-compressor couplings were due mainly to frequent tripping of LNG trains and inadequate

lubrication system. - Steam generation system

The efficiency of the steam generation system was affected by the following: - The steam requirements for a full load operation were not satisfied. A deficit of steam was estimated to be about 15%. This was due to the following:

• Boiler shutdowns due to maintenance requirements and repairs in general. • Impossibility to operate the boilers at their design capacity (100%).

- Limited reliability of steam system: an average availability not exceeding 70% was noticed in the steam system. This lack of reliability in the steam system is featured by:

• Hot spots on the boilers. • Leaking and/or bursting tubes. • Difficulties in controlling the steam system. • Low reliability of the mechanical equipment (forced draft fans, feed pumps and vents).

- Seawater system Six submerged pumps supply the cooling seawater required for liquefaction process. An average availability not exceeding 60% was recorded for these equipments, which thus constituted an important cause of loss of production. The following problems were encountered on these equipment:

- Corrosion on the pump body resulting from inadequate coating. - Shears in coupling sleeves. - Break down of driving motor stator coil. This problem was due to prolonged shutdowns resulting in accumulation

of seawater humidity in the motor thus shortening the life of the stator insulation. The other problem affecting LNG production in this system is the seawater exchangers and steam condensers, which had experienced a number of tube failures. Tube leaks were mainly due to inadequate tube materials and high seawater flow velocity. Tube materials were not resistant to high flow velocity and erosion effect. Severe fouling leading to under-deposit corrosion was also experienced. In addition, the existing chlorination system had been shutdown for safety reasons. Lack of effective chlorination gave rise to marine organism growth in the seawater intake, pipes and seawater exchangers, leading to extensive tube fouling. A substantial loss of heat exchange had been noticed in the main seawater exchangers.


- Electrical power generation The turbo-generators were operating with low efficiency. In fact, the total power generation was limited, due mainly to steam path deterioration and high vibration levels. 2.2- Operating difficulties Extended start up time

Originally, the plant started with a heavy feed natural gas. But currently and since the start up of the new LPG plant, the quality of the feed natural gas has become leaner in heavy hydrocarbons. This has consequently led to long start up times to stabilise the scrub tower operation, with a considerable amount of gas flaring which was a major concern for the plant.

The required propane and butane to be recycled to the scrub tower was increasingly difficult to obtain. So, the time taken to reach stable LNG production was such that a considerable amount of off-specification feed gas to the cryogenic heat exchanger has to be flared. Consequently, a significant number of days of production were lost, and thus flaring overhead scrub tower gas for up to four days contributed to increase plant auto-consumption. The longer start-up times from feed in to the scrub tower until the required overhead specification was obtained, were because:

- The scrub tower and fractionation unit took around 4 days to build up a sufficient inventory of propane and butane in order to meet a scrub tower overhead pentane specification.

- Liquid propane from the fractionation unit was insufficient to build up the necessary initial inventory and continuous makeup for the propane loop. This plant, therefore, imported liquid propane for start-up.

High autoconsumption rate

During the initial twelve years of plant operation, the plant autoconsumption rate has been high. The average autoconsumption rate was about 25 %, exceeding the guarantee value. The high plant autoconsumption rate was mainly due to the extended process trains start up times and continuous import of ethane and propane for refrigeration. Other contributing factors were:

- Plant and LNG trains trips and shutdowns. - Main cryogenic heat exchanger tube leaks and refrigerant losses. - High deriming frequency. - Inadequate LNG boil-off recovery. - Depressurisation to flare the dryer to be reactivated.

2.3- Weak plant availability

Based on LNG production data, the average plant availability from 1988 to 1990 was estimated to be about 58 % only. Availability of the LNG process trains was mainly restricted by the upsets related to the operation of the refrigeration compressor turbines and the main cryogenic heat exchangers. Other major downtime was related to fouling and tube leaks in the main seawater exchangers.

The other factor significantly affecting the plant availability was the poor coordination between maintenance and operation. Delays in qualified manpower and spare parts unavailability affected the total downtimes for both scheduled and unscheduled maintenance and had an impact on overall plant availability.

Electric generator turbine drives have also been a reason for the unavailability of the process trains. 3- DEBOTTLENECKING PROGRAM

To overcome these problems, a full debottlenecking program has been implemented from June 1993 to March 1997. The aim of this project was:

- Reestablishment of the plant operation at the nameplate capacity. - Increase of the plant production to 110 % of the nameplate capacity. - Improvement of the overall plant reliability. - Reduction of the autoconsumption of the LNG trains. - Ensuring compliance with current safety legislation.


This project involved refurbishment, replacement and design changes to the plant equipment and systems to ensure that the facilities can be restored to a condition, which is equivalent to a new plant. Work activities had been carried out on two trains simultaneously while the four other trains remained in full production to maintain delivery commitments. 3.1- Operation Enhancement Bottlenecks identification

To increase the plant LNG output, the performance of the process trains had been evaluated at various throughputs of up to 130% of the original design capacity, calculated on a net production basis. To do this, a performance test of fifteen (15) days period had been conducted on train 600 in September 1990.

The test results confirmed that the process train has some inherent overcapacity of approximately 10% of the original design throughput. This overcapacity was achieved for the duration of the test but would be difficult to maintain on a continuous basis without minimal modifications being made. The limiting bottlenecks were:

- The propane refrigerant system was found to be the main limiting factor on production during the test and a

power limitation was imposed on the turbine drive. The maximum plant capacity was reached when the propane compressor steam turbine reached a power limit imposed by the turbines supplier. This was lower than the rated power, due to deterioration in the mechanical condition of the turbine.

- The test results indicated that, with the plant operating at 100 % capacity and a seawater temperature of 19 °C, a reduction in cooling flow of about 12.5 % is possible. Thus, this data confirmed that the surface condensers are limiting at 110 % capacity.

- The LNG product pumps had insufficient design margin to allow operation at 110% without operation of the

standby pump, which is undesirable for continuous operation.

- The propane drums level control valves were identified as potential bottlenecks during the performance test and parallel valves were installed to achieve the performance test.

- The condensate pumps were undersized for operation at capacities of 100 % throughput. To enable satisfactory

operation at 110%, these pumps should be replaced. LNG output increase

In addition to reestablishment of the plant operation at the nameplate capacity, by resolving some operating problems, the plant LNG output has been increased to 110 % of the plant capacity. This was successfully completed with a full debottlenecking operation of the plant. The increase of capacity was obtained by mainly improving the refrigeration power (Propane and MCR refrigeration systems). More powerful new machines rated at 30 MW have replaced the existing steam turbines driving the propane and MCR compressors. In addition, to improve efficiency, operability, maintainability and reliability of the refrigeration system, the new turbines were designed to the latest available technology. Other improvements such as monitoring, lubrication, isolation, draining, turbine conservation etc were also introduced.

To obtain increased LNG output, the hydraulic capacities of the surface condensers have been increased. New surface condensers with a capacity of 69 MW each have been installed on trains 200 to 600 replacing the existing propane and MCR condensers. This increases the performance of the surface condensers

The surface condensers of train 100 have not been replaced. Since the LNG output of this train is limited at 105% of design capacity due to a serious loss of effective area of the MCHE, capacity increase of surface condensers was therefore not needed. The other systems upgraded for increased plant capacity, were: - Process steam generation: The steam generation capacity has been increased by installing four new process boilers of a capacity of 400 tonnes/hour each. This to further improve reliability of the steam system and, to meet the additional requirements resulting from the extended LNG capacity. Improvement of the boiler and steam control system was also included. - Seawater cooling system: The other change necessary to achieve this output was the increase of the seawater cooling capacity. To provide sufficient cooling water for the 110 % LNG production, the existing seawater pumps and motors have been replaced by new equipment of higher flow rate.


3.2- Process modifications and benefits

During plant revamping, some process changes and additions have been introduced to the process to improve LNG trains operation and reliability. The main process modifications were: Monoethanolamine (MEA) flash drum

A flash drum has been installed downstream of the carbon dioxide (CO2) absorber. The rich MEA solution leaving the absorber flows into this new vessel before passing to the rich/lean MEA exchanger. This new equipment flashes off hydrocarbon vapors from the rich MEA solution before entering the MEA. It also separates any hydrocarbon liquid, which may be contaminating the MEA stream. Since then, the corrosion/erosion problem of the rich amine letdown valve upstream the regenerator, due to released carbon dioxide has not been even more. Dryers reactivation system

The initial gas dryers reactivation system used the fuel gas at a pressure of 5.5 bara, which required depressurising to flare the dryer to be reactivated. This caused disturbances of the fuel gas system during sequencing and contributed to increased autoconsumption of the plant. To overcome these problems, the gas dryers reactivation system has been switched from low pressure to high pressure. The high-pressure system uses natural gas at normal operating pressure. This avoids the need to depressurise the driers to flare and, disturbances to the pressure and the heating value of the fuel gas system are no longer caused. Thereby plant autoconsumption is reduced. Mercury removal system

To avoid mercury-induced corrosion in the cryogenic equipment, especially the main cryogenic heat exchanger, a mercury removal system comprising an adsorbent vessel and outlet dust filters, has been installed in each train, downstream of the dehydration unit.

Scrub tower overhead system

A plate heat exchanger using multi-component refrigerant (MCR) as a cooling medium was installed at the scrub tower overhead circuit, downstream of the propane condenser. This modification helps increase LPG extraction to reduce start-up time and meet LNG product specification. This exchanger can eliminate the need for propane and butane recycle during normal operations. Vapors leaving the scrub tower overhead condenser pass through the LPG-recovery heat exchanger, where they are cooled to –50 °C. for the lean feed case and –43 °C. for the rich feed case. The MCR refrigerant flows, from the high-pressure MCR separator and returns to the MCR first-stage suction drum. The cold scrub-tower overhead then flows to the scrub-tower separator where LPG liquids are separated and returned to the scrub tower as reflux. Process gas leaving the separator passes back through the LPG-recovery exchanger to minimize the consumption of MCR refrigeration before flowing to the main cryogenic heat exchanger.

Benefits of the LPG-recovery heat exchanger on the scrub tower overhead circuit include: - A considerably shorter start-up time with a resultant decrease in gas flaring due to more stable operation of the

scrub tower. The trains’ start-ups are currently accomplished with a small amount of flaring and less production losses.

- No propane and butane recycle needed during normal operations. Because sufficient reflux is created in the LPG-recovery heat exchanger, the butane recycle to the scrub tower is not required to achieve the overhead product pentane specification. Propane and butane imports were discontinued.

Electro chlorination unit

Seawater chlorination was improved to reduce marine fouling, which have caused partial blockage of tubes. The existing chlorination unit has been replaced by an electro chlorination unit. This unit consists in producing continuously sodium hypochlorite, which is injected either in the seawater intake and the main pumps suctions.


Distributed control system

To enable safer and better control of plant facilities, the existing control systems pneumatically based was replaced by a distributed control system (DCS). Pneumatic controllers and transmitters have been replaced with electronic equivalents, including smart transmitters. The revamp project incorporated also an emergency shutdown system (ESD) and a modern vibration analyser system. Digital communication was established between the ESD system and the DCS, primarily for better alarm management. Revamp benefits are:

- Enhancement of plant efficiency by accurately monitoring process data and responding to process changes. - Regulation of steam supply to the process trains by operating the boilers with maximum flexibility to the best

advantage. - Ability to perform the desired data logging. - More diagnostics are available to the operator and the technical and maintenance personnel. - Improvement of main compressors anti-surge control system. - Enhancement of plant safety

Safety system

To improve personnel and facilities safety, a new system has been implemented. This system consists of: - Fire and gas detection: The existing fire and gas systems have been renovated and modified. New fire and gas detectors have been installed around the different areas of the plant so that personnel of operation and safety departments can be alarmed in case of fire or gas leakage. In addition, this system shuts down automatically the process train, and its three associated boilers, in case of a fire detected by at least one detector or a gas leakage detected by at least three detectors. - Emergency isolation and depressurisation system: In case of fire or hydrocarbon leakage, the affected zone is isolated at its boundaries by the emergency shutdown valves before proceeding to depressurisation. Depressurisation is the rapid reduction of process equipment pressure by relieving its inventory to flare. This is manually activated from either the main control room or the local control room in case of fire, potentially dangerous upsets or hydrocarbon leakages.

- Emergency shutdown monitoring: Shutdown parameters of the main rotating equipment, and emergency alarms are recorded in this system. This allows technical, maintenance and safety personnel to analyse any deviations, avoiding any hazardous event. 3.3- Reliability period

At the end of the debottlenecking project, in accordance with project contract, the contractor has performed a reliability guarantee period from December 1997 to December 1998. The objective of this test was to verify that the plant production capacity is 105 billion thermies high heating value, measured in the LNG storage tank, over a period of 330 days per year.

The total produced LNG during this reliability period was 17,33 million m3. Prorated to 330 days, as per the contract, gave a total adjusted production of 107,42 billion thermies which is equivalent to 102.30 % of the nameplate capacity. 4- IMPROVEMENTS 4.1- LNG production level

The main indicator, used by GL1Z plant to assess LNG production is the loss of production. The loss of LNG production is calculated per train on a basis of the design-installed capacity, which is defined as follows:

Production loss (in m3/day) = Design (installed capacity) LNG production - actual LNG production

This indicator is used to quantify and categorise LNG production losses and helps establishing problem priorities and bringing management to deal with the essentials.

The production level is defined as: Design single train daily LNG production (in thermies HHV) X Number of trains (6) X 330 days


After plant debottlenecking, the LNG production was significantly increased and maintained at acceptable levels, as shown in table 1.

Table 1: LNG production history

1978-1990 Reliability period 1999 to 2003 Average Production level

(%) 60.00 102.30 92.51

During these five years (1999-2003), the main factors contributing to the loss of LNG production are as follows:

External causes

The loss of production related to external influences represented around 53 % of the total LNG losses. Including these approved external losses would increase the average LNG production level to 103.5 % of the nameplate capacity.

The main external influence experienced during the last five years is the LNG loading. During adverse weather, ships movement was restricted, resulting in level built-up in the LNG storage tanks. Consequently, LNG production was reduced or one or more trains were shut down. This cause represented 94.8 % of the external losses.

Seawater temperature is another factor influencing the LNG production. Seawater temperatures as high as 28°C,

has been reached in hot period (summer). These temperatures exceed the equipment design value, which is 23.9°C.

Plant related causes The top problem areas and categories were:

- Scheduled shutdown - Compression - Dehydration - Liquefaction The plant’s significant progress in focusing close attention to plant related losses resulted in a sustainable production

level. Moreover, these continuous efforts permitted GL1Z plant to move forward in the period of 2002 to 2004 with significant progress, as shown in table 2. In fact, a production level of 100.7 % of the plant capacity has been reached during the year of 2004, while minimising plant autoconsumption. Table 2: Plant performance improvement

2002 2003 2004 LNG production level (%) 93.95 96.10 100.70

Loss of production (%) 17.42 15.24 9.13

LNG shipping (106 m3) 16.55 16.79 17.68

Autoconsumption rate (%) 12.78 13.11 12.71


The LNG production level of GL1Z plant was increased by 6.75 % from 2002 to 2004. Figure 1 above shows the apparent increase of the LNG production level during the last three years. 4.2- Equipment reliability

The reliability improvement of the two following systems resulted in a reduction of the LNG trains trips by more than 70 % from 1999 to 2003.

Refrigerant compressors:

During the reliability period, frequent trips of refrigerant (propane and MCR) compressors were experienced. These trips were mainly due to the main lube oil turbine trip. In the event of main lube oil turbine trip, the auxiliary pump will start automatically. However, even the instantaneous start up of the auxiliary pump, the lube oil pressure at the compressors drops below the trip value ending up in a train trip. To eliminate this problem, two oil accumulators containing pressurized nitrogen bladder, have been installed in the oil circuit. These equipment supply sufficient oil at a pre-set pressure for a few seconds to give the auxiliary pump sufficient time to built up the required head. Seawater cooling system:

After the plant project completion, repetitive trains trips due to drop of seawater cooling pressure have been recorded. Six main pumps are available for supplying cooling seawater to the six trains. To be able to run all trains there must be at least 5 pumps running to maintain enough pressure to feed the LNG trains. In case of the trip of one or more pumps, the seawater cooling system pressure dropped. To avoid trips of all trains, closing down the water supply to some trains according to a mass balance, was performed. This manual operation induced a sharp drop of the seawater system pressure, promoting trains trips more than selected ones. To avoid this, a logic load-shedding program has been implemented on the DCS system. In case of pump trip, this program closes instantaneously the feeding valves of the selected trains. Therefore, the cooling system pressure is maintained, avoiding the needless trips of the other trains. 4.3- Plant availability

The availability of each system or process was determined by calculating the equivalent downtime (unavailability) and subtracting this from 100%.

Equivalent downtime (day) = LNG production loss (m3) / Plant production (m3/day)

Availability (%) = 100- (downtime / number of days) X 100

The plant availability calculated from the LNG production losses of the past five years of operation is about 91.2 %. Compared to the expected overall plant availability of 90-94 %, this actual value is considered to be satisfactory, as indicated in table 2.

Figure 1: LNG production increase - period of 2002 to 2004

100.70

96.10

93.95

90

92

94

96

98

100

102

2002 2003 2004Years

Pro

duct

ion

leve

l (%

)


Table 3: Plant availability

1978-1990 1999-2003 Expected

Overall plant availability (%) 57.50 91.23 90-94

The most important element affecting the overall plant availability is the total plant shutdowns performed during

1999 and 2001, for respectively outstanding revamp project items and implementing some maintenance work. Unplanned shutdowns for corrective measures and LNG trains trips due to processing upsets were also contributing factors. 4.4- Plant autoconsumption rate

As a result of the plant revamping, the annual plant autoconsumption rate was reduced by about 37 %. This was mainly due to the following:

- A considerably shorter train start-up time with a resultant decrease in gas flaring due to more stable operation of the scrub tower. This has been accomplished by modifying the scrub tower overhead system. Also, import of propane and butane during start-up and normal operation is no more needed.

- Avoiding the need to depressurise the gas dryers to flare to be reactivated, by modifying the Dryers’ reactivation system.

Continuous improvements of the net autoconsumption and flaring gas have been carried out during the past five years of plant operation. In fact, the net autoconsumption and flaring gas have been reduced respectively by about 12.6 % and 58,8 %. As can be seen in figure 2 below, the plant autoconsumption rate is reduced below the guarantee value of 14.75 % during the period of 2000-2003. This figure shows also the significant reduction of gas flaring. Main improving factors were:

- Reduction of refrigeration compressors trips - Reduction of LNG trains trips due to utilities systems - Stable LNG trains operation - Improvement of LNG tanks boil off recovery - Improvement of fuel gas high heating value.

4.5- Environment

On the environmental aspect, GL1Z plant is making a major contribution to the reduction of gas flaring. Reduction in the autoconsumption and flaring gas resulted in significant environmental improvement. The carbon dioxide (CO2) emissions were reduced, from 1999 to 2003, by about 24 % for the same production rate.

GL1Z is moving towards ISO certification of its quality (ISO 9001:2000) and environmental management systems (ISO 14001) to register its success for a better environmental management.

Figure 2: Plant autoconsumption & flare gas rates

13.1112.79

14.32

16.29

14.38

1.011.231.661.45

2.45

02468

1012141618

1999 2000 2001 2002 2003

Year

Au

toco

nsu

ptio

n (

%)

0

2

4

6

8

10

Flar

e ga

s ra

te (

%)

Autoconsumption guarantee value: 14,75 %


5- CONCLUSION

Benefits of the plant debottlenecking are significant. Through this project, GL1Z plant has been able to achieve its assigned goals. This achievement was followed by other successful results. LNG production and plant availability are maintained at acceptable levels by focusing attention on process systems and equipment which caused large LNG losses and taking the corrective measures.

It should be noted that LNG production losses were not necessarily affected by plant related causes, but external influences were very often the real source of substantial losses. In general, plant related causes are problems that can be solved by the plant, compared to external influences.

The use of the loss of production reports as a management tool and a continuous reference has helped finding

the limiting parameters, establishing problems priorities, and allowing management to deal with the essentials. In addition, starting up the trains, which was a major concern for the plant, is currently accomplished in a

relatively short time with little flaring. This decreases production losses and minimizes plant autoconsumption.

As a result of the plant operation efficiency, both the net autoconsumption and the flaring gas have been considerably reduced, resulting consequently in a reduction of the carbon dioxide (CO2) emissions.

Furthermore, the plant strives to ensure continuous improvements of the plant efficiency, reliability and safety as well as that of its environmental performance. References cited “Bechtel engineering audit report N°2: Reliability”, GL1Z renovation project, February 1991. “Bechtel engineering audit report N°18: LNG capacity increase”, GL1Z renovation project, February 1991. Production loss (Manque à produire) reports, GL1Z documents. Plant annuel reports, GL1Z documents.

gl1z plant operation enhancement and overall …...the lng plant gl1z of sonatrach at arzew...

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