Rupesh Parbhoo, ExxonMobil Papua New Guinea

STORAGE, LOADING AND MARINE ADAPTATIONS FOR PNG LNG RECOVERY EFFORTS

Author: Rupesh Parbhoo, P.E. Presenter: Benjamin Douglas Co-authors: D. DiMattia Ph.D., J. Jacobson, C. Sahuburua

ExxonMobil Production Company

Following a 7.5 magnitude earthquake in Papua New Guinea on 26th February

2018, the upstream gas conditioning facility, Hides Gas Conditioning Plant (HGCP), was shut down resulting in the shutdown of the Liquefied Natural Gas Plant (LNGP). The LNG in the storage tanks was used as fuel gas to power essential systems at LNGP and a portion of Port Moresby. Due to the unknown duration of the recovery, process facilities were adapted to prolong the use of this fuel gas supply to eliminate power disruptions and prevent a complex and lengthy restart for LNGP.

Three major facility adaptations were implemented:

i. Adjusted boil-off gas (BOG) compressor operation to meet fuel gas needs ii. Modified storage and loading facilities to receive LNG from a ship iii. Utilized ship’s onboard vaporizer to send gas to the plant inlet

Prior to the implementation of the facility adaptations, technical assessments were performed to ensure the feasibility of each change. Standard process simulation software was used to model the dynamic behavior of LNG (i.e. composition, temperature, density, BOG rate, weathering, stratification, rollover time).

Standard process simulation software, applied with an innovative technique, provided an accurate and efficient method of predicting dynamic LNG behavior, eliminating the need for time-consuming Computational Fluid Dynamic modeling or specific software.

Through the cross-functional efforts of operations, maintenance, marine and technical teams, LNGP was able to adapt the current facilities to ensure power availability and reduce restart time after a major earthquake affected production from the upstream facilities.

1.0 Introduction

1.1 Background

Papua New Guinea Liquefied Natural Gas Project (PNG LNG) is a joint venture with participation by ExxonMobil,

Oil Search Limited (OSL), Kumul Petroleum, Santos, JX Nippon Oil and Gas Exploration and Mineral Resources

Development Company. ExxonMobil is the operator. The $19 billion PNG LNG project in Papua New Guinea was

completed in 2014 and produced the first LNG into storage on 24th April 2014.

1.2 Facilities Description

The project infrastructure includes 5 well pads, a 22-inch full well stream pipeline and a gas conditioning plant,

Hides Gas Conditioning Plant (HGCP), located in Hela Province in the Highlands. A 700-kilometer natural gas

pipeline connects the HGCP to the Liquefied Natural Gas Plant (LNGP) with two trains located outside the capital

city of Port Moresby. Two oil production facilities, Kutubu and Gobe, operated by PNG LNG co-venture partner

OSL also provide associated gas to the natural gas pipeline for processing at LNGP. The LNGP comprises of two

identical trains and common facilities. It produces rich LNG, with a gross heating value (GHV) between 1060 and

1160 Btu/Scf, as well as plant naphtha. Both products are loaded on to tankers at the LNGP Marine Terminal. The

heavier hydrocarbon field condensate from HGCP is pumped via a 100-kilometer 8-inch pipeline to the OSL crude

oil stabilization facility at Kutubu, where it is blended with OSL produced crude oil and stored prior to shipment. The

condensate/crude oil blend is loaded on to tankers at the existing OSL Kumul Offshore terminal.

1.3 Earthquake

On 26th February 2018, at 03:44hrs (local time), a magnitude 7.5 earthquake struck Hela Province. The epicenter

was located 10 kilometers west of the town of Komo and 8 kilometers from the HGCP. The HGCP was

immediately shutdown to assess damages. The LNGP was shut down approximately 12 hours later.

1.4 Scope

This paper will discuss the major adaptations to the Storage, Loading and Marine facilities during the PNG LNG

recovery efforts to maintain power supply to Port Moresby and start-up readiness for LNGP.

The paper is split into 4 sections (i) Fuel Gas & LNG Optimization, (ii) LNG Tank Weathering Model, (iii) LNG Tank

Rollover Model, and (iv) Ship Vaporizer.

i. Fuel Gas & LNG Optimization section will discuss how operational parameters were adjusted to minimize

LNG usage to prolong the use of the fuel gas supply.

ii. LNG Tank Weathering Model section will discuss the methodology for estimating how long the fuel gas

supply would last. Standard Aspen HYSYS simulation software was used to develop a model to accurately

predict LNG weathering in the storage tanks.

iii. LNG Rollover Model section will discuss the methodology used to calculate the time to rollover. The tank

weathering model was enhanced to simulate stratified layers of LNG. Again, standard Aspen HYSYS

simulation software was used for the calculations instead of Computational Fluid Dynamic (CFD) analysis.

iv. Ship Vaporizer section will discuss how produced LNG was recycled to maintain LNGP operations while the

upstream facility required a shutdown.

2.0 Fuel Gas and LNG Optimization

2.1 Background

PNG LNG supplies up to 30% of the power supply to Port Moresby. Losing PNG LNG export power would result in

insufficient power for the city. After the earthquake, the HGCP restart timing was unknown; the primary focus of the

organization was individual’s safety. The HGCP shutdown and subsequent Liquefied Natural Gas Plant shutdown

meant that LNGP would be required to supply power to Port Moresby with the existing inventory of LNG in the

storage tanks. The remaining LNG in the storage tanks would be used as fuel to power the essential systems at the

LNGP in addition to the city of Port Moresby. The first task for the LNGP team was to understand the users of the

limited LNG in the tanks and minimize consumption where possible.

2.2 Facilities Description

The LNG Storage and Loading System is located downstream of the Liquefaction System of the two LNG

processing trains. The function of the system is to (i) store LNG produced by the two LNG processing Trains, (ii)

Load LNG product to LNG tankers for export, (iii) recover Boil-Off Gas (BOG) generated from the storage and

loading operations and send the BOG to the fuel gas system.

Figure 2.2.1 Storage and Loading Process Flow Diagram

The LNG Storage and Loading System is designed to store LNG with two single containment LNG Storage Tanks.

It can recover BOG, which is utilized for plant fuel gas.

The Loading and Circulation System is designed to operate in two different modes, Loading and Holding. Four

LNG Loading Pumps are installed in each LNG tank and one LNG Circulation Pump (smaller capacity) is installed

in one tank. During Holding Mode, the period between cargo transfers, the loading and circulation systems are

maintained cold by circulating LNG from one tank using a submerged cryogenic pump. Circulation also serves to

keep the LNG inventory homogeneous and prevent stratification (and subsequent rollover).

The flashed vapor from the production rundown and BOG by heat in-leak flows from the tanks to the BOG

compressor via the common BOG headers. Two parallel Boil-Off Gas Compressors compress the gas to supply

the fuel gas system.

Quench LNG is sent to the BOG Compressor Suction Drum to maintain the compressor suction temperature below

the maximum operating temperature. Quench LNG comes from the loading line.

2.3 LNG and BOG Flow

While LNGP was shutdown, boil off gas was generated in three ways:

i. Heat leak into the two LNG storage tanks, loading lines, and recirculation lines was dissipated through

natural weathering of the LNG. LNG was being circulated into the loading and recirculating lines to keep the

long length of pipe at cryogenic temperatures. If the loading lines warmed up, there would be a potential for

pipe movement and damage due to the thermal expansion. Additionally, there would be a 3 week increase

the plant start-up duration, due to the added requirement of cooling down the line.

ii. Energy input from the circulation and loading pumps. At least one pump was always on to maintain

circulation of LNG in the loading and recirculation lines and mix the LNG in the storage tanks to prevent

stratification (and subsequent rollover).

iii. Vaporization of quench LNG to maintain the BOG compressor operating temperature at cryogenic

temperatures.

While the LNGP was shutdown, there were two areas the BOG could flow:

i. Fuel gas system for LNGP internal power and export power to Port Moresby.

ii. Flare system. During normal operation, the excess BOG gas would flow to the Recycle Gas Compressor

which would send the gas to the inlet of the plant, with the inlet section of LNGP shutdown, the additional gas

was flared.

Initially, the focus was to reduce LNGP power users thus reducing the overall fuel gas consumption. However, the

team identified the amount of forward flow required (to prevent surge conditions) for a single compressor was

greater than the amount of fuel gas required. Therefore, the excess BOG discharge gas was being flared.

Reducing or optimizing the fuel gas needs for LNGP would result in the balance being flared; a purposeless

objective. The focus shifted to reducing the BOG forward flow to reduce the excess flaring.

2.4 Boil Off Gas Compressor Operational Changes

Three strategies were employed to reduce the BOG compressor flow:

i. The anti-surge valves on the BOG compressor were clamped

open to allow gas from the discharge of the compressor to be

recycled to the suction of the compressor; during normal operation

these are closed unless there is not enough gas to run the

compressor.

ii. The inlet guide vanes were run in manual at a specified set-point

to maintain BOG flow through the compressor above the minimum

flow rate requirement to avoid surging.

iii. The BOG compressor suction temperature was increased to the

maximum allowable to minimize the vaporization of quench LNG.

2.5 LNG Storage Tank Mixing

To maintain a homogeneous layer of LNG, Operations pumped LNG from one tank through the loading lines back

into both tanks. To prevent the levels in the tanks from being too dissimilar, the pumps were switched from one

tank to the other. Two types of pumps were used for this operations (i) the LNG loading pumps and (ii) the LNG

circulating pump. The circulating pump has a smaller capacity, and this would generate less boil off gas when it

was in operation. Initially, the pumps were switched daily; to reduce excess boil off gas the team decided to

preferentially run the circulating LNG pump.

Figure 2.5.1 Loading Pump vs Circulation Pump Operation

Figure 2.4.1 Impact of Adjustments

3.0 LNG Tank Weathering Model

3.1 Background

While engineering and operations team were conserving LNG in the tanks, there was an inherent need to calculate

how long the LNG would last. Understanding the dynamic behavior of the LNG and BOG in the two storage tanks

was imperative to determining when it would run out. In-house expertise or tools on predicting the LNG weathering

were not available, as they are not required in production facilities. Additionally, a reliable estimate was required

urgently so that time would be available to work contingency plans should the fuel gas supply be exhausted.

3.2 LNG Weathering

Boil-Off Gas is evaporated LNG due to heat ingress into the liquid from (i) natural conduction and convection on the

surface area of liquid filled piping and equipment, (ii) heat transfer from pumps during operation, (iii) flashed vapor

from rundown and circulating LNG, and (iv) displacement in the storage tanks.

As LNG vaporizes, the lighter components (i.e. methane, nitrogen) preferentially vaporize resulting in the

concentration of the heavier components in the liquid (e.g. ethane, propane, etc.). The change of the thermo-

physical properties of the stored LNG through vaporization is known as weathering.

3.3 Model Methodology

The objective of developing the ‘Tank Weathering Model’ was to understand the following:

i. How long the LNG in the tanks would be able to supply vapor as fuel gas; once the LNG in the tanks reached

low level, the circulation and loading pumps would not be able to supply quench to the BOG compressor and

the fuel gas system would shut down.

ii. Temperature profile of the LNG in the tanks over time

iii. Composition of the vaporized fuel gas, to ensure the gas turbine generators could operate

The engineering team did not have the necessary tools to predict the required parameters based on the shutdown

conditions. For day-to-day process predictions and optimizations, the team uses Aspen HYSYS Process Simulation

Software. Instead of modeling a steady state process, a batch weathering process needed to be modeled.

The weathering batch process needed to be converted to a "steady state" process that Aspen Hysys could handle.

An innovative technique was hypothesized to perform the conversion:

i. The volume of the LNG in the tank was converted into a flow rate; e.g. if the tank had 60,000 m3 of LNG,

2500 m3/hr would be input in the HYSYS model (2,500 m

3/hr x 24hr = 60,000m

3).

ii. The LNG stream would enter a tank. An energy stream would be input to represent the heat ingress into the

LNG for the same period, in this case 24 hours.

iii. The vapor outlet of this unit operation would represent the Boil Off Gas generated during the day.

iv. The liquid outlet of this calculation block would represent the

properties (e.g. composition, temperature, density) at the end of

the first period (in this case a day).

v. The liquid outlet was then fed into another tank to represent the

heat pick up for the next day.

vi. This process was repeated to determine the properties of the

weathering tank over time.

In practice the weathering model was more complicated, and the model described did not work at accurately

predicting the weathering. The heat leak into the LNG was not isolated to only the tank. The heat sources into the

LNG were examined in more detail to refine the model and improve predictions. The main heat ingress locations

are as follows:

i. Heat ingress from the LNG storage tank bottom and sides (accounted for in the model above)

ii. Heat ingress from the LNG loading and recirculating line

iii. Heat ingress from running the LNG loading and circulation pump

iv. Heat ingress from BOG compressor operations; quench LNG was vaporized to maintain the proper operating

temperature of the compressor, the recycled gas mentioned in the previous section added heat to the

system

To more accurately represent the plant conditions, a small stream of LNG from the tank was sent to another flash

vessel and a heat input stream was added to that vessel. After this smaller amount of LNG was heated and

flashed, it was mixed with the rest of the LNG. These two process units were repeated to complete the model.

After some trial and error on splitting the LNG streams, the model was able to accurately predict the desired

parameters.

Figure 3.3.2 Weathering Model – Single and Repeating Unit

Figure 3.3.1 Model Philosophy

3.4 Results

After using a week of data to tune to model it converged with real life observations; further adjustment was not

required. Revisiting the model objectives of (i) Fuel gas supply (ii) tank temperature (iii) fuel gas composition:

Figure 3.4.1 Predicted LNG Supply

Figure 3.4.2 LNG Tank Temperature

Figure 3.4.3 Fuel Gas Composition

-162

-160

-158

-156

0 10 20 30 40

LN

G T

em

pera

ture

[°C

]

Days since Earthquake

Actual Predicted

Tank LNG Temperature

-0.50

-0.25

0.00

0.25

0.50

0 10 20 30 40

Actu

al vs P

redic

tio

n [°C

]

Days since Earthquake

Temperature Prediction vs Actual

Temperature < ±0.25°C difference from prediction

The model calculated a faster boil off rate of nitrogen than compared to the actual composition in the tank. The

nitrogen stayed in solution much longer than predicted from the model.

4.0 LNG Tank Rollover Model

4.1 Background

Using the ‘LNG Tank Weathering Model’ and updates from the upstream facility damage assessment, the team

determined that fuel gas would run out before the upstream facilities were available for re-start. Multiple options to

maintain power supply were considered and pursued simultaneously to maximize flexibility. The options included:

i. Install additional diesel generators to power LNGP, no power would be exported to Port Moresby

ii. Use associated gas from Kutubu, if the facilities were ready for start-up before HGCP

iii. Draw down the remaining gas inventory in the 700km pipeline from HGCP to LNGP

iv. Purchase a cargo of LNG and off-load it into the tanks

The optimal solution was to off-load LNG into the tanks. The additional LNG would enable LNGP to (i) supply

power to Port Moresby for an additional 3 months, (ii) maintain the storage and loading system at cryogenic

temperature (iii) cool down the liquefaction facilities to accelerate start-up, and (iv) dilute the heavy weathered LNG

in the tanks resulting in on-specification product.

4.2 Hazard & Operability Screening

A detailed hazard and operability screening was conducted to determine (i) if a cargo could be purchased in time,

(ii) the optimum reverse flow path, and (iii) the safety and environmental risks associated with the offload.

Numerous flow paths were proposed, and each was evaluated based on the following characteristics:

i. Safety systems in place to prevent loss of containment or equipment damage

ii. Maximum flowrate the path would allow to minimize the duration the ship was at berth

iii. Minimum facility modifications, due to the limited available time and resources on site

The flow path selected required the product to be top loaded in the tank. The incoming LNG was going to be much

lighter than the existing LNG in the tanks. At the time the new LNG would be loaded into the tanks, the existing

LNG had weathered for over a month. The density of the product in the tank was relatively heavy compared to that

of the purchased product.

Due to the known difference in density of the weathered LNG in the storage tanks versus the purchased cargo, and

the requirement for top loading, the team identified LNG stratification and subsequent rollover as the major risk for

the operation. An LNG ‘Tank Rollover Model’ was developed to understand the behavior of the light and heavy

LNG layers in the storage tanks.

4.3 Rollover

Heat leak into the LNG storage tank comes from the surfaces in contact with the liquid phase. The heat ingress

warms the LNG in contact with the floor and sides of the tank, causing the density to decrease and the liquid to

rise. At the liquid surface the lighter components (methane and nitrogen) evaporate cooling the liquid due to the

loss of latent heat and increasing the density (weathering as discussed in the prior section). A natural convective

current is created in the tank, as the warm LNG rises and the cooler denser LNG falls, resulting in natural mixing.

If a lighter density of LNG is loaded on top of a heavier LNG, discrete

layers of LNG are likely to form and natural convective mixing

ceases. The hydrostatic pressure of the upper layer on the lower

layer of LNG prevents evaporation (or heat release) in the lower

layer. Over time, the density of the upper layer increases (as a result

of weathering) and the density of the lower layer decreases (due to

heat ingress and the layers inability to release the heat through

vaporization). Eventually, the density difference between the two

layers decreases enough to break the interface between the lighter

and heavier LNG, resulting in spontaneous rapid mixing of the two

layers.

“Rollover refers to the rapid release of LNG vapor that can occur as a result of spontaneous mixing of layers of

different densities of LNG in a storage or cargo tank. A pre-condition for rollover is that stratification has occurred,

i.e. the existence in the tank of two separate layers of LNG of different density,” (SIGTTO).

4.4 Model Methodology

The methodology used to create the LNG Tank Weathering model was extended to create the LNG Tank Rollover

model. The following assumptions were used to develop the basis of the model:

i. No mass transfer between the stratified layers of LNG; the assumption enabled the model to treat each layer,

the light and heavy, independently

ii. Heat ingress into each layer was estimated based on the percentage of wetted surface area; the LNG Tank

Weathering model could be simplified because the additional was no longer required.

To model the upper (light) layer, the heat leak was calculated based on the percent of the wall in contact with the

liquid phase. As a simplifying assumption the tank roof and side walls not wetted by liquid LNG were ignored. For

the pressure, the normal operating tank pressure was used.

To model the lower (heavy) layer, the heat leak was calculated based on the percent of the side wall in contact with

the LNG and the surface area of the storage tank floor. The pressure was calculated by adding the pressure in the

tank to the hydrostatic pressure that the upper layer exerted on the lower layer.

Figure 4.3.1 Rollover Diagram

4.5 Model Sensitivities

Three factors were varied to estimate the time to rollover (i) amount of heat ingress into the tanks from the tank

side wall and floor, (ii) amount of heavy LNG in the tanks and amount of light LNG loaded on top, and (iii) amount

of heat transfer between the two layers.

i. Heat Ingress into the tanks from the environment

a. 400kW - based on the initial project study

b. 2000kW – 5 times case one

c. 3600 kW – 9 times case one, roughly represented the amount of heat leak of the entire storage and

loading system during the tank weathering phase; used as an extreme case

ii. Tank Loading Conditions

a. Heavy layer split equally in each tank and full light LNG cargo loaded split equally into both tanks;

19,000m3 and 80,000m

3 per tank respectively

b. Minimum volume of heavy layer, maximum volume of light layer loaded into one tank; 10,000m3 and

150,000m3, respectively

c. Heavy layer split equally between both tanks and partial light LNG cargo loaded into both tanks;

19,000m3 and 32,000m

3 per tank respectively

iii. Heat Transfer between the Light and Heavy Layer

a. 0% heat transfer between the interface; temperature of the layers is not affected by each other, i.e.

the heavy LNG is not cooled by the incoming new LNG

b. 50% heat transfer between the interface

c. 100% heat transfer between the interface; temperature between the light and heavy LNG come to

equilibrium on Day 1

4.6 Model Insights

The key insights from the modeling study are summarized below:

i. The time to rollover occurred when the heavy layer reached its bubble point, breaking the interface.

ii. Increasing the heat leak into the tank reduced the time to rollover (i.e. when the heavy layer reaching its

bubble point); if the heat leak into the system was doubled, the time to rollover was halved.

iii. Reducing the volume of the heavy layer decreased the time to rollover. Most of the heat leak into the heavier

layer is from the tank floor. Decreasing the volume of the heavy layer, deceases the mass of LNG that the

heat can be distributed, causing it to heat up faster. Paradoxically, if the rollover were to occur, a thinner

heavier layer would have less boil off gas generation than a thick layer.

iv. Increasing the heat transfer between the two layers extended the time to rollover. The cooler light layer

removed heat from the heavy layer moving the fluid away from the bubble point of the heavy layer.

Based on the learnings from the sensitivity analysis performed, the optimum loading and surveillance plan was

developed. The heavy LNG would be split evenly between both tanks and the light product would be loaded into

each tank. The temperature and pressure of the heavy layer would be tracked to ensure the fluid did not reach

the bubble point (and break the interface between the light and heavy layer).

Figure 4.6.1 Key Rollover Model Insights

4.7 Results

In early April, the Kumul ship arrived at the LNGP Marine Terminal to off-load approximately 160,000 m3 of LNG.

After the necessary safety checks and loading arm cooldown, the LNG offload commenced. The loading rate

started at 400m3/hr and increased to the planned loading rate of 2500m

3/hr over a 4-hour period. After three days

of off-loading at 2000 - 2500 m3/hr the loading was complete. During the entire period of the load and several days

afterward, the density and temperature of the tank was monitored and compared to the predictions from the model.

The LNG behavior in the heavy layer was consistent with the model estimates. As predicted, the temperature

increased, and the density decreased linearly with time. From an operational safety perspective, this was ideal; the

timing of the heavy layer reaching the bubble point was easily estimated.

The LNG behavior in the light layer was complex yet

understandable. The top level of the light layer was the coldest

temperature because the heat of this layer was being release

through vaporization. During the first day, the density

decreased as more LNG was loaded. After a few days of

loading, the density of the fluid throughout the layer was

uniform at 447kg/m3 and didn’t change relative to the heavy

layer, as predicted.

Figure 4.7.1 Tank Profile during Load

Figure 4.7.1 Heavy Layer Temperature and Density

Figure 4.7.2 Light Layer Temperature and Density

Industry literature usually describe rollover as the density of two stratified layers of LNG converging resulting in

spontaneous mixing and rapid vapor release. In this scenario, the two layers had a density difference of over

60kg/m3. The densities of the two fluids would never converge to cause rollover in the time frame concerned. For

this scenario, when the heavy layer reached its bubble point, the vapor generation would break the interface

resulting in the rapid vapor generation from the mixing.

5.0 Ship Vaporizer

5.1 Background

In early April, the HGCP was partially restarted, supplying enough feed gas to maintain one LNG train at reduced

rates. About a week later, one train of LNGP successfully produced the first drop of LNG into the storage tanks.

Soon after start-up of both plants, the team identified maintenance work that would impact the feed gas to LNGP.

Starting the liquefied natural gas plant in any condition is complex and time consuming. Starting up the plant from

ambient temperature conditions, as was the case after the earthquake, required the entire system to be water free

(i.e. defrosted) and cooled from ambient temperature to -160°C at a controlled rate of change to prevent thermal

strain. The LNGP team was challenged to determine creative way to maintain one train operation at reduced rates

for a period.

5.2 Facilities Description

During normal operation the LNG plant recycles excess boil off gas (above the fuel gas requirements) to the inlet of

the plant using the Fuel Gas Recycle Compressor. This represents inefficiency in the process; energy is wasted

re-liquefying molecules that have boiled off from the LNG, instead of liquefying fresh feed from the pipeline.

On each LNG ship there is an LNG vaporizer, which is intended to produce vapor to maintain pressure in the ship

tanks during discharge. Simply put, the liquid volume of LNG leaving the ship is displaced by vaporized LNG to

prevent a vacuum in the ship tanks. On the ship there is also a gas compressor to send gas to shore if the

pressure in the ship tanks gets high.

Figure 5.2.1 Ship Vaporizer Process Flow Diagram

5.3 Method

A team of Marine advisors, engineers, and operations analyzed the ability to use the vaporizer to recycle LNG to

the inlet of the plant, reducing the need for feed gas. The plan was to load a small amount of LNG on the ship; then

use the ship vaporizer, to generate gas. The gas would then flow from the ship (using free flow or the ship

compressors) through the normal vapor return line to the BOG compressor. The BOG compressor would

compress the gas and send it to the Fuel Gas Recycle Compressor to be sent to the inlet of the plant.

The cross functional team analyzed the heat duty of the ship vaporizer, the pressure drop between the ship and the

2km vapor return line and the capacity of the BOG and Fuel Gas Recycle Compressor.

5.4 Results

Vaporized LNG was successfully recycled during the period of using the ship vaporizer.

6.0 Conclusion

In late April, the upstream plant was able to achieve full rates, the second LNG train started (after a similar defrost

and cooldown period), and LNGP loaded its first produced cargo after the earthquake. The plant returned to normal

operations.

During the almost 60 days of plant disruption after the earthquake, the LNGP team collaborated to execute a

tremendous amount of work, many of the adaptations were performed for the first time. The team manually

operated the BOG compressors to reduce flaring. The engineering team developed an innovative and accurate

method for predicting LNG behavior in storage tanks (without special software of CFD). The Marine team

purchased an LNG cargo in 4 weeks; a process that is usually planned months in advance. After detailed

operational risk assessments, Engineering, Operations, Maintenance and Marine turned the production facility into

a receiving terminal in less than 4 weeks. The Operations team safety loaded the cargo and managed stratified

layers of LNG with no prior experience. The success of the LNG off-load enabled the team to work creatively with

the ship captains to recycle LNG from the ship to the front end of the plant to maintain stable operations when the

feed gas to the plant was disrupted; another first for PNG LNG. Importantly, the plant was able to provide

uninterrupted power supply to the people of Port Moresby after a devastating earthquake in the Highlands region.

Figure 6.0.1 Team Pictures during Earthquake Recovery and Ship Load

References

SIGTTO (2012). Guidance for Prevention of Rollover in Ships