PROJECT ALTERNATIVES 1...QPRGG proposes to build Tema LNG Terminal of the coast of Ghana. The LNG...

CHAPTER 4

PROJECT ALTERNATIVES

Quantum Power Ghana Gas Limited 4-i Knight Piésold Consulting

Environmental and Social Impact Assessment

TABLE OF CONTENTS

4 CONSIDERATION OF PROJECT ALTERNATIVES ................................................................. 4-1

4.1 INTRODUCTION ........................................................................................................................ 4-1

4.2 BACKGROUND .......................................................................................................................... 4-1

4.3 ANALYSIS OF LOCATION ALTERNATIVES ............................................................................. 4-1

4.3.1 Methodology ............................................................................................................................... 4-2

4.3.2 Study Assumptions ..................................................................................................................... 4-3

4.3.3 Alternatives and Facilities Included in the Analysis .................................................................... 4-4

4.3.4 Comparing Location Alternatives ................................................................................................ 4-6

4.4 LNG TERMINALCONFIGURATION ALTERNATIVES ............................................................. 4-11

4.4.1 Option 1: FSRU on Soft Yoke Mooring ..................................................................................... 4-11

4.4.2 Option2: FSRU and LNGC on Double Berth Jetty.................................................................... 4-12

4.4.3 Option 3: FSRU on Spread Moor and LNGC on Single Berth Jetty ......................................... 4-13

4.5 OFFSHORE PIPELINE ROUTE ALTERNATIVES ................................................................... 4-14

4.5.1 Option 1 (Base Case) ............................................................................................................... 4-14

4.5.2 Option 2 .................................................................................................................................... 4-16

4.5.3 Option 3 .................................................................................................................................... 4-17

4.6 PIPELINE INSTALLATION METHOD ALTERNATIVES ........................................................... 4-20

4.6.1 Pull Pipeline Ashore from Pipelay Vessel (Preferred Case) ..................................................... 4-20

4.6.2 Pull Ashore Using Onshore Return Sheave ............................................................................. 4-20

4.6.3 Fabricated Pipeline Onshore .................................................................................................... 4-20

4.6.4 Directional Drilling ..................................................................................................................... 4-21

4.6.5 Tunnel and Shaft Construction (Microtunneling or Pipe Jacking) ............................................ 4-21

4.7 LNG VAPORISATION TECHNOLOGY ALTERNATIVES ........................................................ 4-26

4.7.1 Seawater (SW) Heating ............................................................................................................ 4-26

4.7.2 Fuel Gas (FG) Heating ............................................................................................................. 4-27

4.7.3 Ambient Air Heating .................................................................................................................. 4-28

4.7.4 Intermediate Fluid Heating ........................................................................................................ 4-30

4.7.5 Heat Integration with Power Plant ............................................................................................ 4-32

4.7.6 COMPARISON OF VAPORISER OPTIONS ............................................................................ 4-33

4.7.7 Rankings of LNG Vaporisation Technology Alternatives .......................................................... 4-37

Quantum Power Ghana Gas Limited 4-ii Knight Piésold Consulting


4.8 NO-GO ALTERNATIVE ............................................................................................................ 4-37

LIST OF TABLES

Table 4-1: Summary of Alternative Ratings ................................................................................ 4-8

Table 4-2: LNG Terminal Location Alternative Analysis ............................................................. 4-9

Table 4-3: Route Options (Pros and Cons) .............................................................................. 4-18

Table 4-4: Advantages and Disadvantages of Various Pipeline Installation Methods ............. 4-24

Table 4-5: Qualification Comparison for LNG Vaporisation Options ........................................ 4-34

Table 4-6: Vaporiser Rankings for Ambient above 18°C .......................................................... 4-36

LIST OF FIGURES

Figure 4-1: The proposed offshore localities of the mooring facilities ........................................ 4-5

Figure 4-2: FSRU on Soft Yoke Mooring .................................................................................. 4-12

Figure 4-3: FSRU and LNGC on Double Berth Jetty ................................................................ 4-13

Figure 4-4: FSRU on Spread Moor and LNGC on Single Berth Jetty ...................................... 4-14

Figure 4-5: Import Pipeline Route – Option 1 (Base Case) ...................................................... 4-15

Figure 4-6: Import Pipeline Route – Option 2 ........................................................................... 4-16

Figure 4-7: Import Pipeline Route – Option 3 ........................................................................... 4-17

Figure 4-8: TBM Located in Thrust Shaft ................................................................................. 4-23

Figure 4-9: Open Rack Vaporiser Flow Scheme ...................................................................... 4-27

Figure 4-10: Submerged Combustion Vaporiser ...................................................................... 4-28

Figure 4-11: Typical Ambient Air Vaporiser .............................................................................. 4-29

Figure 4-12: Glycol-water Intermediate Fluid Vaporiser Integration with Different Heat

Sources ..................................................................................................................................... 4-31

Figure 4-13: IFV LNG Vaporisers in Rankine Cycle ................................................................. 4-32

Figure 4-14: SCV Power Plant Integration ............................................................................... 4-33

Quantum Power Ghana Gas Limited 4-1 Knight Piésold Consulting


4 CONSIDERATION OF PROJECT ALTERNATIVES

4.1 INTRODUCTION

This section describes and analyses the most important features of the components of

alternatives that were evaluated to select the optimal project location, taking into account

environmental, social and economic variables. This analysis is aimed at comparing, based

on a set of previously established criteria, the best feasible alternatives in order to identify

the one causing the least impact and allowing to determine the optimal option for the Project

location. This analysis does not consider the unselected alternative as unviable, but only

presents it as the least favourable with respect to the other options.

Selection of criteria to qualify an alternative is important and specific for each case; thus, a

set of criteria generated for a specific Project cannot be applied to another without properly

studying the characteristics of each case. It should be clear that the criteria to be

established will depend on the project type and duration, as well as the environmental,

social and cultural conditions of the zone where it will be developed.

4.2 BACKGROUND

QPRGG proposes to build Tema LNG Terminal of the coast of Ghana. The LNG terminal

capacity is 250mm SCFD with the target uptime of 85% or greater.

QPRGG is developing an LNG import facility for Ghana as an alternative to light crude oil

(LCO) currently used for power generation. In December 2013, HR Wallingford was

commissioned by QPRGG to carry out review and advisory services in connection with the

project, including the review of an initial feasibility study carried out by Worley Parsons.

The terrestrial components associated to the Project, specifically land-based facilities are

considered as fixed (i.e. their location has already been established). The analysis of

alternatives was carried out only for location of marine components. Following is an

analysis of the Do-nothing, technology, installation method and Location (analysed in detail)

alternatives.

4.3 ANALYSIS OF LOCATION ALTERNATIVES

Project components include:

1. Offshore Mooring and Support for Floating Units (FSRU as well as LNG Supply

Vessels),

2. Floating Storage and Regasification Unit (FSRU),

3. Subsea Gas Pipelines and

4. Landing Facilities and Distribution, which will be located on land.

The analysis of the LNG Terminal location will not include evaluation of land-based facilities

since they will be a constant for every option to be analysed. Also, the analysis will include

a series of technical, environmental and social criteria; development of this procedure is

described below.



4.3.1 Methodology

This analysis comprises comparison of viable options from a technical viewpoint, so that

evaluated alternatives do comply with conditions required for location of infrastructure.

Based on this selection, the best alternative is chosen after a more detailed technical-

economic analysis considering environmental and socio-cultural aspects.

Once criteria have been established and depending on the decision making logic, the

analysis of alternatives may be completed in this case using a semi-quantitative process,

which selects the best option by weighting of criteria.

The initial stage of this process usually consists of selecting preliminary alternatives as well

as applying criteria in order to reduce the number of these alternatives. The final stages

comprise comparison of alternatives, selecting among them the best one from the technical-

economic, environmental and social viewpoints.

After determining the set of criteria to be used in the alternative analysis process, it is

necessary to establish the analysis method to be applied. This study has used a modified

version of the Multiple Count Matrix (MCM) process (Kerr et. al., 2003). The methodology

considers a series of main criteria or counts (technical-economic, environmental and

socioeconomic aspects), each of which has a weighting value. Since each count may be

influenced by factors, it is in turn divided into sub-criteria or sub-counts (e.g. considerations

for the construction, operation, closure stages, among others). Each sub-count also has a

weighting value and includes indicators of determining factors specific for the components

(e.g. operation ease, positions and perceptions, among others), each of which also has a

weighting value. The reason for dividing and sub-dividing each count is to define a base for

the analysis of alternatives that will allow following the logic of the MCM analysis authors.

The weighting of each count, sub-count and indicator in the analysis of alternatives takes

into consideration that some factors become more important than others. It should be noted

that, even with the incorporation of quantitative values, this is a subjective process since

weightings and counts are determined based on the evaluator’s experience and professional

judgment. However, it allows for a systematic procedure that can be replicated by different

interested parties. The weighting scale must be defined by the evaluator considering the

possible values that each indicator may take. Scales used in the present MCM are as

follows:

For the count and sub-count levels:

0.2 = low value

0.4 = moderately low value

0.6 = moderate value

0.8 = moderately high value

1.0 = high value

For the indicator level:

1 = low value



2 = mid-low value

3 = mid value

4 = mid-high value

5 = high value

After indicators have been established and their weighting values have been determined, a

value is assigned to each option. This Multiple Count Matrix considers a value scale that

weights positive and negative effects for different alternatives.

The scale is as follows:

3 = positive option

2 = moderately positive option

1 = slightly positive option

0 = neutral option

-1 = slightly negative option

-2 = moderately negative option

-3 = negative option

After establishing values for counts, sub-counts and indicators, count values are multiplied

by weightings in order to obtain a total value.

To prevent bias associated to with the use of different numbers of sub-counts and indicators

per considered aspect, the total value obtained for each aspect (technical, environmental

and social) was divided by the number of sub-counts. This operation allowed standardizing

or placing under the same conditions each one of the considered aspects.

Weighted values for each indicator are subsequently added up. The resulting higher value

is considered to be the best alternative.

A text description is included for each indicator and its corresponding value in order to

provide a value basis.

4.3.2 Study Assumptions

It is very important to identify the starting assumptions in each analysis of alternatives. This

allows putting in perspective the analysis limitations according to its relevance. The analysis

cannot be considered valid if after it has been completed, the project objectives change or if

there are significant changes in the project development. The assumptions included in the

analysis of alternatives for this study are as follows:

The economic model parameters, such as fuel and consumables prices will not change

to the extent that a radical change in the Project design and requirements would be

required.



Design of facilities as presented corresponds to the Project design to be used. Should

there be any design changes, they shall not significantly impact the project

requirements.

There are no conflicts in the use of marine areas between QPRGG, the government

and the communities located in the vicinity of Tema.

This evaluation does not disqualify some of the alternatives proposed for the

establishment of infrastructure since it is only a relative comparison of areas under

technical, economic, environmental and socio-cultural criteria based on the LNG

Terminal specific requirements.

The environmental and social conditions for this study are representative of the area

and, therefore, they have been considered as the basis for the analysis of alternatives.

4.3.3 Alternatives and Facilities Included in the Analysis

Determination of the location of the LNG Terminal will take into account the components

within the maritime area which were mentioned in Section 4.3 including: i) FSRU,

ii) Offshore mooring and support for floating units, and iii) Subsea gas pipeline. As

previously mentioned, location of the land facilities will not be evaluated.

As a result, the scope of the alternative assessment will involve the determination of the

optimal location of the FSRU and mooring, including the configuration of the gas pipeline.

Location of this infrastructure was evaluated in the following zones:

Alternative 1: Point 1 (up to 20 m deep).

Alternative 2: Point 3 (up to 40 m deep).

Figure 4-1 shows the location of Alternatives 1 and 2.



Figure 4-1: The proposed offshore localities of the mooring facilities

Below is the analysis of the technical, environmental, and socio-cultural implications of the

infrastructure location presented in these two alternatives, including a brief description of

their main characteristics.

4.3.3.1 Alternative 1: P1 (~ 20 m deep)

Location: The referential location proposed in Alternative 1 corresponds to the coordinates

165 088m E and 618 839m N (UTM 31N WGS84), at a distance of approximately 4.2 km

from the coast of the Gulf of Guinea. The zone reaches a depth of approximately 20 m.

Additionally, the distance between P1 and the port of Tema is approximately 4.8 km.

Technical Aspects: The subsea gas pipeline will require approximately 5 km piping of 24-

inch over the seabed for the transport of regasified LNG from the offshore facility (FSRU) to

the coast, close to Tema city.

Environmental Aspects: As previously mentioned, Alternative 1 is located in the marine

area. For this reason, the environmental aspects of greater importance are those associated

with oceanographic conditions including the wind behaviour, which is prioritized in the wind

and wave analysis. Winds in the zone are predominately in the southwest direction.

Approximately, 1.9% of waves have a height exceeding 2.5 m. Peak wave periods longer

than 12 s occur approximately 38% of the time. Waves with heights greater than 2 m with

periods longer than 12 s occur approximately 4.8% of the time.

Social Aspects: The communities that could be affected in the land area are the following:

the Tema Metropolis District, the Kpone Katamanso District, and the Ningo Prampram



District. Of these, the District of Tema, specifically the capital city of Tema, would be

considered the main area of influence.

The local economy of Tema is comprised of agriculture, industry, and commerce/services.

However, the industrial and service sectors constitute the backbone of the local economy,

as they employ the majority of the workforce. Additionally, a part of the population works in

agriculture and fishing. Furthermore, Tema has commercial and fishing ports; the latter is

the larger of the two seaports in Ghana.

The area of direct influence of the project includes the maritime area of the project

infrastructure location, including the gas pipeline. It is probable that the project

implementation will involve interaction with the maritime activities that are developed in the

area. It is important to emphasize that the distance between P1 and the port is 4.8 km.

4.3.3.2 Alternative 2: P3 (~ 40 m deep)

Location: The location proposed by Alternative 2 corresponds to the following coordinates:

P3 174 247 m E and 622 816 m (UTM 31N WGS84), at a distance of approximately 5.45 km

from Alternative 1 (SE direction) and 9.2 km from the coast. In addition, the distance

between P3 and the Tema port is approximately 9.5 km.

Technical Aspects: The subsea gas pipeline will require 10 km piping of 24-inch over the

seabed for the transport of regasified LNG from the offshore facility (FSRU) to the coast,

close to Tema.

Environmental Aspects: Similar to Alternative 1, Alternative 2 is also located in the marine

area. The winds in the zone are predominately in the southwest direction. Approximately

1.3% of waves have a height exceeding 2.5 m. Peak wave periods longer than 12 s occur

approximately 33% of the time. Waves with heights greater than 2 m with periods longer

than 12 s occur approximately 2.2% of the time.

Social Aspects: The coastal area of influence for Alternative 2 (P3) is the same as

Alternative 1. The city of Tema is the main area within the zone.

Similarly, the area of direct influence of the project corresponds to the maritime area of the

project infrastructure location, including the gas pipeline. It should be emphasised that the

distance between P3 and the port is 9.5 km.

4.3.4 Comparing Location Alternatives

The following is a comparison of the technical, economic, environmental, and socio-cultural

aspects of Alternatives 1 & 2.

4.3.4.1 Technical-Economic Aspects

With regard to technical aspects, Alternative 1 was more optimal mainly due to the shallower

zone depth which provides greater advantages regarding the infrastructure location. It also

requires less piping and, therefore, a shorter construction, installation and work time. By

contrast, Alternative 2 has a more profound depth and requires a larger number of works

due to the greater length of piping.



The distance to the port of Tema also involves advantages with respect to the transportation

of personnel, materials, and inputs. As such, Alternative 1 (located at an approximate

distance of 4.8 km) is more beneficial than Alternative 2, which requires greater time and

transport distances (P3 is found at an approximate distance of 9.3 km from the port).

On the other hand, a greater depth facilitates the manoeuvring of oceangoing vessels. For

that reason, Alternative 2 would be more beneficial due to its greater depth.

In general terms, these results allow for reaching a preliminary conclusion that technically,

Alternative 1 has more advantages in relative terms when compared to Alternative 2.

However, Alternative 2 also presents conditions that could be advantageous. Finally, if an

economic comparison is performed, Alternative 2 would require greater investment than

Alternative 1.

4.3.4.2 Environmental Aspects

In regards to environmental aspects, both alternative 1 and alternative 2 have similar

climatic ratings.

In relation to waves, Alternative 2 could be more beneficial as there is a lesser frequency of

waves with a height greater than 2 and 2.5 m, which facilitates the manoeuvring for

operations as well as transportation and construction. It would also support construction and

engineering works, and better wave conditions would result in fewer environmental risks (for

example, spills).

Consequently, Alternative 2 presents fewer complications in terms of environmental

management due to the nature of the site.

4.3.4.3 Social Aspects

With regard to social aspects, Alternative 1 presents fewer advantages due to its proximity

to the commercial and fishing ports, involving potential interference with fishing and

commercial vessels which could generate, among other issues, expectations in the

fishermen population or the risk of interference with fishing and commercial vessel routes.

From the perspective of the landscape, Alternative 1 is visually accessible so its impact

would be greater in comparison to Alternative 2, taking into account that the distance of

Alternative 1 to the coast is around 4.2 km. Alternative 2 represents the less complex option

for managing social impacts due to its remoteness from the coast and port.

4.3.4.4 Final Balance

Table 4-2 presents the alternative analysis matrix for the location of the LNG Terminal. The

two proposed alternatives were compared based on the results of the analysis of the

technical-economic, environmental, and social aspects under consideration. Table 4-1

presents a summary of the results obtained, based on the calculation of the assigned values

and weights presented in Section 4.3.1.



Table 4-1: Summary of Alternative Ratings

Considerations Alternative 1 Alternative 2

P1 P3

Technical – Economic Aspects 4.5 3.8

Environmental Aspects 4.0 6.0

Social Aspects 8.0 12

Accumulative Total 16.5 21.8

According to these results, Alternative 2 is the best choice for the LNG Terminal location, as

it has a relatively higher score than Alternative 1. This analysis consisted of a process in

which the two areas were relatively compared according to technical, environmental and

social criteria.



Table 4-2: LNG Terminal Location Alternative Analysis

Considerations Alternative 1

P1 Alternative 2

P3

Counting Counting Weighting

Sub-counting Indicator Indicator

Weighting Value Description Value Description

Technical & Economic Aspects

0.8

Closeness to Solid Ground

Distance to coastline 3 3 Distance: 4.2 km

approx. 2

Distance: 9.2 km approx.

Sub-counting Value

9

6

Closeness to Tema port

Distance to port 4 3 Distance: 4.8 km

approx. 2

Distance: 9.5 km approx.

Sub-counting Value

12

8

Underwater Pipeline

Requirement

Pipe Length: 24’’ 4 4 Length: 5 km

approx.. 2

Length: 12km approx.

Sub-counting Value

16

8

Vessel Manoeuvrabil

ity

Depth of the alternative 4 2 20 m 4 40 m

Sub-counting Value

8

16

Counting Value

45

38

Weighted Counting

4.5

3.8



Considerations Alternative 1

P1 Alternative 2

P3

Counting Counting Weighting

Sub-counting Indicator Indicator

Weighting Value Description Value Description

Environmental Aspects

1

Wave Condition

Frequency of waves higher than 2 and 2.5 m

4 2 Higher frequency 3 Lower frequency

Sub-counting Value

8

12

Counting Value

8

12

Weighted Counting

4

6

Social Aspects

1

Interference with Small-

Scale Fishing Activities &

Minor Vessel Traffic

Distance to the small-scale fishing Tema port

4 2

Distance: 4.8 km approx., which increases interference potential

3

Distance: 9.5 km approx., with a lower interference potential

Sub-counting Value 8

12

Interference with

Commercial port activities

Distance to the small-scale fishing Tema port

4 2

Distance: 4.8 km approx., which increases interference potential

3 Distance: 9.5 km approx., with a lower interference potential

Sub-counting Value

8

12

Counting Value 16 24

Weighted Counting 8 12

Cumulative Total 16.5

21.8



4.4 LNG TERMINALCONFIGURATION ALTERNATIVES

An uptime assessment was undertaken to consider three options for the LNG terminal

configuration.Three mooring types were then analysed with regard to uptime (average annual %

time that facility could be operational, undisturbed by ocean conditions and there is gas demand

and gas is exported) for each of the remaining localities. These include;

Option 1: FSRU on soft yoke mooring.

Option 2: FSRU and LNGC on double berth jetty.

Option 3: FSRU on spread moor and LNGC on single berth jetty.

4.4.1 Option 1: FSRU on Soft Yoke Mooring

This configuration is based on an FSRU with a soft yoke mooring system. The system is used in

shallow water and the soft yoke provides softness in the mooring system – this reduces the

loads on the mooring tower from wave action on the FSRU. A typical mooring layout is shown in

Figure 4-2. The soft yoke mooring system comprises the following components:

A soft yoke structure attached to the FSRU which provides restoring forces to “move” the

FSRU back to its equilibrium position.

A mooring tower connected to the soft yoke structure on the FSRU. The mooring tower

essentially holds the FSRU on site and allows the FSRU to weathervane to the prevailing

weather conditions (compliant system), in particular the wind conditions.

The interface between the mooring tower and soft yoke structure comprises of swivel bearings

and high pressure gas swivels. The vaporised natural gas travels from the FSRU through gas

piping, high pressure gas swivels, piping on the mooring tower towards the subsea pipeline to

shore.

The soft yoke mooring system permanently moors the FSRU on site and is not designed to be

disconnected on a regular basis. The LNG is transferred onto the FSRU using side-by-side

offloading; in this scenario, the LNGC berths alongside the FSRU and LNG transfer is carried

out using loading arms on the FSRU. The pros for this option are:

Higher gas availability due to permanently moored FSRU and gas export equipment as a

part of the soft yoke mooring tower.

Cost and schedule effective mooring system, no mooring dolphins or piles.

Weathervaning (compliant) mooring system.

Needs to be in around 18m to 40m water depth (works for both considered site locations)

The cons for this option are:

Requires side-by-side offloading operations to transfer LNG from LNGCs to FSRU.



Soft yoke mooring tower needs careful design to avoid mooring tower overrun and is

typically limited to around Hs=5m 100 year return condition and around 30 m/s wind and

2knots of current.

Figure 4-2: FSRU on Soft Yoke Mooring

4.4.2 Option2: FSRU and LNGC on Double Berth Jetty

The double berth jetty mooring system is oriented to be aligned with the predominant swell

direction (i.e. N to S orientation) with the FSRU/LNGC bows towards the South. FSRU is

berthed on the west side of the Jetty and the LNGC is berthed on the east side. This mooring

layout is shown in Figure 4-3. The jetty includes mooring/fendering structures to moor the FSRU

and LNGC, loading arms for LNG transfers from the LNGC to the FSRU. High pressure loading

arm(s), also on the jetty, transfer natural gas from the regasification unit on the FSRU to the

jetty; the gas then flows in a riser down the jetty substructure to a subsea PLEM, and via

subsea pipeline to shore.

LNG is transferred from the LNGC to the FSRU via low pressure loading arms and piping on the

platform. A separate set of high pressure loading arms and piping then transfers the vaporised

gas from the FSRU to the jetty, and into a subsea pipeline to shore.

The jetty mooring system is a disconnectable mooring system. The FSRU will need to

disconnect and sail to safety during extreme weather events.

The pros for this option are:

Utilises standard jetty for LNGC berthing and offloading and therefore allows any LNG

supplier to use the terminal.


Lower gas availability due to disconnectable FSRU.

Not cost and schedule effective mooring system; requires mooring dolphins and piles.

Needs to be in 15m to 20m water depth.



Figure 4-3: FSRU and LNGC on Double Berth Jetty

4.4.3 Option 3: FSRU on Spread Moor and LNGC on Single Berth Jetty

After initial consideration, it was decided to add a third option to the previous two. This option

consists of a FSRU permanently moored with a spread mooring system in the close proximity

and parallel to the single berth jetty where LNGC is berthed to perform LNG offloading. Both the

single berth jetty and the spread mooring systems are oriented to be aligned with the swell (i.e.

N to S orientation) with the FSRU/LNGC bows towards the South. The FSRU on spread moor is

positioned west of the single berth jetty. This mooring layout is shown in Figure 4-4.

LNG is transferred from LNGC to jetty via loading arms and from jetty to FSRU via LNG aerial

hoses (as proposed by Hoegh and Excellerate for a Canadian FLNG terminal).

High Pressure (HP) gas is transferred from FSRU to jetty via HP hoses, then down the jetty

substructure to a subsea PLEM, and via subsea pipeline to shore, as used for the West Java

FSRU.

The pros for this option are:

Higher gas availability than double berth jetty due to permanently moored FSRU.

Utilizes standard jetty for LNGC berthing and offloading and therefore allows any LNG

supplier to use the terminal.

Cost and schedule effective mooring system, by minimising mooring dolphins and piles.


Only works in highly directional met-ocean condition as encountered offshore Ghana and

Nigeria, etc.

Needs to be in around 21m to 28m or better 40m water depth (i.e. long piles for jetty) to

avoid clashing of spread mooring lines with moored LNGC and during berthing of LNGC.



Requires LNG and HP hose transfer via aerial hoses to span approximately 30m to a jetty

platform, the latter all technologies are available and have been used in similar conditions.

However, in a permanently moored application, lifecycle costing requires assessment due

to frequent replacement of LNG hoses.

A spread mooring in close vicinity of a platform requires careful design and analysis to

avoid clashing with infrastructure and is limited to around Hs=5m 100 year return condition

and around1.5knot of current.

Figure 4-4: FSRU on Spread Moor and LNGC on Single Berth Jetty

Based on the LNG Terminal Configuration Assessment, Option 3: FSRU on spread moor and

LNGC on single Berth Jetty was selected as the base case for the Tema LNG project.

4.5 OFFSHORE PIPELINE ROUTE ALTERNATIVES

Pipeline route alternatives were identified and evaluated to determine whether or not alternative

alignments could avoid or reduce the impacts identified. The Pipeline Route Alternatives are

based on specific design data and routing restrictions mentioned in Chapter 2 (Project

Description). Three route options were discussed with Option 1 selected as the base case for

the FEED stage. The various options are described in the sections below, with their pros and

cons presented in Table 4-3.

4.5.1 Option 1 (Base Case)

This option considers the FSRU to be located inside the exclusion zone on the east side of the

WAGP pipeline as illustrated in Figure 4-5. PLEM is located on the eastside of the FSRU; a tie-

in spool approximately 100m in length connects the PLEM to the import pipeline.

From the spool tie-in (KP 0) the import pipeline routes north towards the corridor of exclusion

zone. The FSRU mooring anchors are located near the exclusion zone having a minimum of

50m exclusion zone at each anchor location. To avoid crossing the exclusion zone around

anchors the import pipeline is routed outside the fishing and anchoring exclusion zone before



routing back inside the corridor. A pipeline lay radius of 800m is considered while routing which

will allow minimum pipeline outside the exclusion zone. A total of 525m length of import pipeline

falls outside the exclusion zone and extends out of exclusion zone by 43m.

The import pipeline once inside the exclusion zone routes north-west towards the WAGP

pipeline. At approximately KP 5.6 it curves around the existing SPM exclusion zone to align for

landfall tie-in point. The pipeline route maintains a minimum 50m separation between WAGP

pipeline from approximately KP 10 to landfall tie-in section which is required to be trenched and

backfilled.

Figure 4-5: Import Pipeline Route – Option 1 (Base Case)



4.5.2 Option 2

This option considers the FSRU to be located inside the exclusion zone on the east side of the

WAGP pipeline. PLEM is located on the eastside of the FSRU on seabed, a tie-in spool

approximately 100m in length connects the PLEM to the import pipeline.

From the spool tie-in (KP 0) the import pipeline routes under the FSRU and runs north-west

towards the WAGP pipeline. Around the existing SPM exclusion zone the pipeline curves to

align for landfall tie-in point as shown in Figure 4-6.

Figure 4-6: Import Pipeline Route – Option 2



4.5.3 Option 3

This option considers the FSRU to be located inside the exclusion zone on the west side of the

WAGP pipeline. PLEM is located on the eastside of the FSRU on seabed; a tie-in spool

approximately 100m in length connects the PLEM to the import pipeline.

From the spool tie-in (KP 0) the import pipeline routes north east and crosses the WAGP

pipeline. The import pipeline then curves 90 degree and aligns to reach the landfall tie-in

location as a straight route (see Figure 4-7).

Figure 4-7: Import Pipeline Route – Option 3



Table 4-3: Route Options (Pros and Cons)

ROUTE OPTIONS PROS CONS

Option 1 (Base Case)

FSRU moored bow to south on the east side of

WAGP with riser hang offs on right side.

Preferred arrangement for LNG offloading

Pipeline not entirely within WAGP exclusion zone

No crossing of WAGP pipeline Additional pipeline protection [outside WAGP

exclusion zone required]

Route Option 2

FSRU moored bow to south on the east side of

WAGP with riser hang offs on right side. And the

pipeline is routed under the FSRU to route it on

seabed on other side of FSRU. PLEM is located

on right side of FSRU.

Offshore import pipeline routing is simple and

straight route almost parallel to existing WAGP

pipeline.

Routing the pipeline under FSRU would have

highest risk to safety of FSRU in an event of

pipeline damage.

Not preferred by FSRU Operator.

Pipeline lengths would be reduced.

Supply vessels will be operating directly above

the pipeline route.

No need to extend the existing WAGP exclusion

zone.

Independent HAZID and HAZOP will need to be

carried out to assess the risks associated before

this option could be confirmed as acceptable.

-

Additional protection of the pipeline under FSRU

would be required.

- Pipeline must be installed before FSRU on station



Route Option 3

FSRU to be located on the west side of the

WAGP pipeline at about 40m WD contour.

May be able to route the pipeline inside the

exclusion zone.

Import pipeline will need to cross over existing

WAGP pipeline.

- Longer length of pipeline.

-

Supply vessels will need to ferry on top of the

WAGP pipeline.



Option 2 has a direct safety risk to FSRU and hence is not considered viable. Option 3 will need

to cross over existing WAGP pipeline and will also have supply vessels ferrying over both

WAGP and import pipeline routes subsea, and hence is not carried forward at this stage.

Option 1 has the benefit of being away from all existing subsea assets. It also allows favourable

mooring of delivery vessels to FSRU. From the above assertions, Option 1 is selected as a

base case at the FEED stage. But a further review of the exclusion zone co-ordinates and as-

built position of the existing WAGP pipeline should be carried out to confirm the Option 1 route.

4.6 PIPELINE INSTALLATION METHOD ALTERNATIVES

The Tema LNG project design considers five basic methods to install the landfall pipeline, with

option 1 as the preferred case. These installation methods with their advantages and

disadvantages are also presented in Table 4-4.

1. Fabricate pipeline on lay vessel stationed offshore and pull the pipeline ashore using

winches installed at beach head;

2. Pipelay vessel stationed offshore with return sheath anchored at beach head; pipeline

fabrication on lay vessel and winched ashore by return pull-in wire using A&R or anchor

winch located on the pipelay vessel;

3. Fabricate pipeline onshore either in strings or as a single length and pull offshore using

winches installed on a pulling barge; and

4. Directional horizontal drilling (HDD)

5. Tunnel and Shaft (Microtunneling or Pipe Jacking).

4.6.1 Pull Pipeline Ashore from Pipelay Vessel (Preferred Case)

An onshore pull method requires the installation of an onshore winch spread to facilitate pulling

a pipe-string to the beach from a pipelay vessel which would be positioned offshore.

This is the proposed method for the successful installation of the Quantum gas pipeline and is

discussed in more detail in Section 2.5.5 (Proposed landfall construction & pipe installation

method).

4.6.2 Pull Ashore Using Onshore Return Sheave

This method is similar to the above installation except the pulling winch setup is located on the

pipelay vessel with a sheave block anchored onshore. Once the lay vessel is in position

offshore the pull wire will be run from the lay vessel and passed around the onshore return

sheave and then run back to the lay vessel for attachment to the pulling head of the pipeline.

The vessel will then commence a conventional pipelay installation with winch pulling the pipe off

the lay vessel as the welding of each pipe section is completed.

The sheave block should be capable of sustaining double the load of the beach anchor.

4.6.3 Fabricated Pipeline Onshore

This scheme requires the pipeline to be fabricated onshore either as a continuous pipe-string or

as a number of short pipe-strings and a pulling vessel/lay barge will be setup offshore.



The continuous pipe-string method may only be used if the construction site is sufficiently long

so that the pipe-string maybe fabricated in one length on level ground and supported on rollers.

A pipe launch ramp along the route of the pipeline would be constructed down to the shoreline.

A winch will be located at the rear of the pipe-string in line with the launch ramp to act as a

control brake during pulling operations. Once the pulling vessel is in position offshore a pull wire

will be run from the vessel to shore where it will be attached to the pull head of the pipeline. The

vessel mounted winch will pull the pipe-string offshore to a defined point and leave it on the

seabed with a marker buoy attached to the pullhead. After the pulling vessel has been de-

mobilised, a pipelay vessel will retrieve the pullhead from the seabed and pipe layaway

operations shall commence.

Alternatively, a short pipe-string method can be used; it is very similar to the method described

above except in this case the pulling sequence is carried out multiple times depending on

workspace for string lengths.

4.6.4 Directional Drilling

The method uses a drill rig that drills a hole at a very shallow angle to the horizontal. A pilot hole

is drilled in the first instance with a rig situated on either land or a vessel. More common is to

have the rig on land and to punch out of the seabed reducing vessel costs. The formation is

then typically reamed with a hole opener to achieve the size hole required. For small diameter

pipelines reaming is often not required and the required size can be achieved with the pilot drill.

The formation is stabilized during drilling operations with bentonite clay slurry, which is pumped

down the hole from the rig site.

The pipeline may then be pulled back through the hole from an offshore barge or pushed

through by feeding the pipe string into the formation. A pipelay vessel will retrieve the end of the

pipeline from the seabed and pipe layaway operations commence.

Installation requires pipelines to be coated with a durable anti-corrosion coating such as

polypropylene or similar to avoid damage during pull back as there is no requirement for

concrete weight coating.

For a directional drilling operation, a detailed ground investigation will be required to ensure that

the ground conditions are suitable in order that the drill hole will remain open and the ground

has sufficient strength to prevent a bentonite blow-out. The ground conditions best suited to the

technique are clean clays and alluvial deposits (e.g. silty sand). The presence of gravel, cobbles

or boulders within clay creates difficulties whilst gravel or cobble strata render the technique

unfeasible. Drilling fluid is not really suited for the stabilisation of large cohesionless materials

due to loss of fluid pressure.

4.6.5 Tunnel and Shaft Construction (Microtunneling or Pipe Jacking)

Microtunneling is an underground method of constructing pipelines using a sophisticated,

remotely controlled, laser guided, steerable boring machine. It utilizes remotely controlled

equipment that does not require personnel to work underground.

Pipe jacking involves installing a pipeline by pushing pipe sections through the ground with

hydraulic jacks assembled in a jacking frame located in a shaft excavation called the jacking pit.



Pipe jacking also involves the machine operator and other personnel to perform much of the

work at the tunnel heading and inside the pipe string.

Excavation is carried out using a microtunneling machine in front of the lead pipe section as the

pipeline is pushed forward from the jacking pit. After pushing a full pipe section into the ground,

a new pipe section is lowered into the jacking pit with a crane and connected to the previous

pipe section and the process is repeated until the machine reaches the receiving pit.

4.6.5.1 Shaft Construction

The shaft can be installed as a caisson or built in-situ by under pinning, or by other methods.

The top of the shaft can be located a safe distance back from the top of the cliff to allow for its

construction and for any projected future erosion of the cliff. The shaft diameter should be of

sufficient diameter to provide access for construction of the horizontal tunnel out to the beach

and constructing the pipeline. Typically, a shaft diameter of 5m is necessary for access of

personnel and equipment. All spoil will be placed in a stockpile within the working area.

Stockpiled material will be subsequently removed on a regular basis to minimise on-site storage

areas. If material is suitable then it may be dumped on the foreshore, but any spoil that maybe

contaminated due to construction works will be disposed of at approved disposal sites.

Upon completion of the shaft construction a reinforced concrete base slab will be cast in-situ to

seal the bottom of the shaft to prevent the ingress of water.

4.6.5.2 Tunnel Construction

At the base of the shaft a thrust pit will be established and the tunnels pipe-jacked towards the

beach. As the tunnel face is excavated the tunnel lining rings will be installed at the shaft base

and jacked forward on the required alignment. The tunnels will be driven towards the beach and

any groundwater will be pumped to the top of the shaft for disposal. The water shall be

disposed by filtering it through a soak away; however, if the water is contaminated then it will be

collected and transported to a licensed disposal site.

The disposal of spoil from the tunnels shall be treated in the same manner as per the spoil from

the shaft.

At the beach, the tunnels will be driven into the tunnel reception pit / cofferdam.



Figure 4-8: TBM Located in Thrust Shaft



Table 4-4: Advantages and Disadvantages of Various Pipeline Installation Methods

METHOD TYPE

SCHEME ADVANTAGES DISADVANTAGES

1 Pull Pipeline Ashore From Pipelay Vessel

Most common construction method using pull

winch(s).

Winch set-up onshore

Pipe joints transported directly to lay vessel

Small land-take for construction

Short pull length

Pipeline layaway operations would commence once

pipeline has been landed ashore and made secure

Pulling operation requires several days window

due to the welding of pipe joints on lay vessel.

Risk of weather deterioration can also delay

operations.

Large pull force may result in complicated winch

set up onshore.

Addition and removal of buoyancy aids, if used

Reduced on-bottom stability of pipeline for

period of installation.

Volume of dredging to accommodate pipelay

vessel access can be a problem

2 Pull Ashore Using Onshore Return Sheave

Winch set-up on pipelay vessel

Pipe joints transported directly to lay vessel

Simple set up of sheaved anchor onshore

Pull operation controlled on lay vessel

Pipeline layaway operations would commence once

pipeline has been landed ashore and made secure

Same as method 1 above

3 Fabricated Pipeline Onshore

Fabrication of pipe-string can be completed before

arrival of lay vessel

Pre-test fabricated pipe-strings.

Once pipeline has been installed pipeline layaway

Pipe joints have to be transported to onshore

construction site

Delay in pulling operation due to phased

addition of pipe-spool wielding to form pipe



METHOD TYPE

SCHEME ADVANTAGES DISADVANTAGES

operations would commence string

Onshore temporary works

Open trench has to remain open for long period

Tow operation can be a risk

Buoyancy and control aids required for tow

operation

Detailed survey of tow route required

Finding suitable site for fabrication of pipe-

spools

4 Directional Horizontal Drilling

Limited disturbance to surface and nearby

infrastructure

Concrete weight coating not required

Inshore trenching not required

Drill paths can be constructed with a wide fanned

arrangement from beach

If the ground is not self-supporting a drift hole

may collapse

Risk of frac out / bentonite break out

Presence of large cobble/rock may make this

option unfeasible

Drilling normally suited to clay soils.

5 Tunneling

Concrete weight coating not required

Inshore trenching not required

Buoyancy and control aids not required

May not be cost effective



4.7 LNG VAPORISATION TECHNOLOGY ALTERNATIVES

As described in Section 2, LNG must be warmed from a liquid to a gaseous state (vaporised)

before it can be transported as natural gas in the send-out pipeline. A number of technologies

for vaporising LNG were evaluated. The focus on conceptual selection was on using seawater

or air as the “cold sinks” rather than combustion gases as these technologies have proven to be

more simple and can be applied to both floating and fixed storage and re-gasification systems.

The analysis for various vaporisation technologies were based on studies conducted by Patel et

al., 2013,regarding LNG vaporiser selection at locations where site ambient conditions are

warmer (i.e. above 18 oC).

Typical types of vaporisers that have been used worldwide for LNG regasification are:

Open Rack Vaporisers (ORV)

Submerged Combustion Vaporisers (SCV)

Ambient Air Vaporisers (AAV)

Intermediate Fluid Vaporisers (IFV)

Open rack vaporisers (ORV) and submerged combustion vaporisers (SCV) are the most

common vaporisation methods in existing regasification terminals, which have generally been

located in the subequatorial region. Recent LNG receiving terminal activities have been shifting

to the tropical/equatorial region where the weather is warmer, and the use of intermediate fluid

vaporisers (IFV) is found to be attractive. Important factors that should be considered in the

LNG vapouriser selection process are:

Site conditions and plant location

Availability and reliability of the heat source

Customer demand fluctuation

Emission permit limits

Regulatory restrictions with respect to the use of seawater

Vaporiser capacity and operating parameters

Safety in design

Operating flexibility and reliability

Capital and the operating cost.

4.7.1 Seawater (SW) Heating

LNG receiving terminals are generally located close to the open sea for ease of access to LNG

carriers. Seawater is generally available in large quantities at low cost as compared to other

sources of heat, and is the preferred heat source. The opposition is mainly from the



environmental sensitive regions for the concerns on the negative impacts on marine life due to

the cold seawater discharge and the residual chemical contents.

Open Rack Vaporiser (ORV)

An Open Rack Vaporiser (ORV) is a heat exchanger that uses seawater as the source of heat.

ORVs are well proven technology and have been widely used in Japan, Korea and Europe LNG

terminals. The preferred seawater temperature for ORV operation is above 5°C.

ORV units are generally constructed of aluminum alloy for mechanical strength suitable to

operate at the cryogenic temperature. The material has high thermal conductivity which is

effective for heat transfer equipment. The tubes are arranged in panels, connected through the

LNG inlet and the regasified product outlet piping manifolds and hung from a rack (Figure 4-9).

ORVs require regular maintenance to keep the finned tube surface clean.

The panel arrangement feature provides ease of access for maintenance. Depending on the

design of the units, it is also possible to isolate sections of the panels and vary the load on the

units. The unit can be turned down to accommodate fluctuations in gas demand, gas outlet

temperature and seawater temperature.

Figure 4-9: Open Rack Vaporiser Flow Scheme

4.7.2 Fuel Gas (FG) Heating

LNG vaporisation using fuel gas for heating typically consumes approximately 1.5 % of the

vaporised LNG as fuel, which reduces the plant output and the revenue of the terminal.

Because of the high price of LNG, SCVs are sometimes used during winter months to

supplement ORV, when seawater temperature cannot meet the regasification requirement.

They can also be used to provide the flexibility in meeting peaking demands during cold

seasons. The SCV burners can be designed to burn low pressure boil-off gas as well as

letdown send-out gas.

Submerged Combustion Vaporisers (SCV)



A typical SCV system is shown in Figure 4-10. LNG flows through a stainless steel tube coil that

is submerged in a water bath which is heated by direct contact with hot flue gases from a

submerged gas burner.

Since the water bath is always maintained at a constant temperature and has high thermal

capacity, the system copes very well with sudden load changes and can be quickly started up

and shutdown.

The bath water is acidic as the combustion gas products (CO2) are condensed in the water.

Caustic chemical such as sodium carbonate and sodium bicarbonate can be added to the bath

water to control the pH value and to protect the tubes against corrosion. The excess

combustion water must be neutralized before being discharged to the open water.

To minimize the NOx emissions, low NOx burners can be used to meet the 40 ppm NOx limit.

The NOx level can be further reduced by using a Selective Catalytic Reduction (SCR) system to

meet the 5 ppm specification if more stringent emission requirements are needed, at a

significant cost impact.

SCV units are proven equipment and are very reliable and have very good safety records.

Leakage of gas can be quickly detected by hydrocarbon detectors which will result in a plant

shutdown. There is no danger of explosion, due to the fact that the temperature of the water

bath always stays below the ignition point of natural gas.

SCVs are compact and do not require much plot area when compared to the other vapouriser

options.

Figure 4-10: Submerged Combustion Vaporiser

4.7.3 Ambient Air Heating

Air is another source of "free" heat and would avoid the use of fuel gas and the generation of

greenhouse gas from SCVs. In the environmental sensitive parts of the world, the use of sea

water may not be allowed and could also be difficult to permit. In this case, the use of ambient

air heat is the next best choice.



Ambient Air Vaporisers (AAV)

Direct ambient air vaporisers are used in cryogenic services, such as in air separation plants.

They are vertical heat exchanger and are designed for icing on the tube side and require

defrosting. Automatic switching valves are installed to allow automatic defrosting using timers.

When compared to other vapouriser options, they require more vapouriser units and more real

estate.

A typical AAV design configuration is shown in Figure 4-11. AAV consists of direct contact, long,

vertical heat exchange tubes that facilitate downward air draft. This is due to the warmer less

dense air at the top being lighter than the cold denser air at the bottom. Water condensation

and melting ice can also be collected and used as a source of service/potable water.

To avoid dense ice buildup on the surface of the heat exchanger tubes, deicing or defrosting

with a 4-8 hour cycle is typically required. Defrosting requires the exchanger to be placed on a

standby mode, and can be completed by natural draft convection or force draft air fans.

Fog around the vapouriser areas can pose a visibility problem, which is generated by

condensation of the moist air outside. The extent of fog formation depends on many factors,

such as the separation distances among units, wind conditions, relative humidity and ambient

temperatures.

Ambient air heater is advantageous in hot climate equatorial regions where ambient

temperature is high all year round. In the cooler subequatorial areas, where winter temperature

is lower, supplementary heating may be required to meet the sales gas temperature.

Figure 4-11: Typical Ambient Air Vaporiser



4.7.4 Intermediate Fluid Heating

This LNG vaporising via intermediate fluid utilizes Heat Transfer Fluid (HTF) in a closed loop to

transfer heat to vapourise LNG. Three types of Heat Transfer Fluids are typically utilised for

LNG vapourisation:

Glycol-Water

Hydrocarbon Based HTF (Propane, Butane or Mixed Refrigerant)

Hot Water

Glycol-water Intermediate Fluid Vaporiser (IFV)

This system typically uses glycol-water as an intermediate heat transfer fluid. Ethylene glycol or

propylene glycol or other low freezing heat transfer fluids are suitable for this application. Heat

transfer for LNG vaporisation occurs in a shell and tube exchanger. Warm glycol-water flows

through the intermediate fluid vaporisers where it rejects heat to vapourise LNG.

A simplified process sketch of these various heating options is shown in Figure 4-12.

Currently, glycol-water intermediate fluid LNG vaporisers account for a small fraction (around

5%) of total LNG regasification markets worldwide. Some of the operating plants utilize air

heater and reverse cooling tower as the source of heat.

There are several options to warm the glycol-water solution prior to recycling it back into the

shell and tube LNG vaporisers, such as:

Air heater

Reverse cooling tower

Seawater heater

Waste heat recovery system or fired heater.

Using air for heating will generate water condensate, especially in the equatorial regions. The

water condensate is of rain water quality which can be collected and purified for in-plant water

usage and/or export as fresh raw water. Similarly, the reverse cooling tower design, which

extracts ambient heat by direct contact with cooling water via sensible heat and water

condensation, would require an intermediate fluid. The heat of the cooling water can be

transferred to the intermediate fluid by a heat exchange coil.

Seawater may be also be used. However, the use of seawater is more prone to exchanger

fouling, and the exchanger (plate and frame type) need to be cleaned periodically. The plate

and frame exchangers are very compact and low cost. Typically, spare seawater exchangers

are provided for this option.

Fired heater may be used at the costs of fuel expense. For environmental compliance related to

CO and NOx emissions, a selective Catalytic Reduction System can be fitted into the flue gas

duct of the fired heater.



Figure 4-12: Glycol-water Intermediate Fluid Vaporiser Integration with Different Heat

Sources

Intermediate Fluid (Hydrocarbon) in Rankine Cycle

This system uses propane, butane or other hydrocarbon refrigerant as an intermediate heat

transfer fluid (HTF). The use of a hydrocarbon avoids the potential freezing problems

encountered with seawater. This vapouriser arrangement allows the use of cold seawater as

low as 1°C to minimize fuel consumption in the downstream trim heater.

LNG heating is achieved using two heat exchangers operating in series: a first evaporator

exchanger that uses the latent heat of propane condensation to partially heat LNG, and a

second heat exchanger using seawater to further heat the LNG to the final temperature. The

second exchanger is also used to vapourise propane that is recycled to the first exchanger.

Since the heating by seawater only occurs in the second exchanger, it avoids direct contact with

cryogenic LNG, and hence freezing of seawater can be avoided. For this reason, seawater

close to freezing can be used in this configuration. The basic flow arrangement is illustrated in

Figure 4-13.

Propane or butane can also be used as a working fluid for power production with the addition of

a propane gas expander. The expanded gas is cooled which needs to be reheated with

seawater to meet the pipeline temperature.



For a typical LNG terminal, the power generated by the Rankine cycle and gas expansion can

be used to reduce or even eliminate power import. The power can be generated without any

fuel input or emissions which are very attractive for most terminals.

Figure 4-13: IFV LNG Vaporisers in Rankine Cycle

4.7.5 Heat Integration with Power Plant

Where the regasification facility is located close to a power plant, a hybrid type system using the

waste heat from the power plant and SCVs for trim heating can increase the thermal efficiency

and improve the economics of the regasification process.

The conceptual heat integration scheme is shown in Figure 4-14. The hot exhaust gases from

the gas turbine in the power plant pass through a direct contact heating tower with the exhaust

heat to increase the temperature of a closed hot water circuit. This hot water is then circulated

and injected to the water bath of the SCVs transferring the heat to the LNG.

The returned chilled water from the SCVs can be recycled back to pick the heat in the heating

tower or can also be used to lower the gas turbine inlet temperature. A lower gas turbine inlet

temperature can significantly increase the power output from the turbine. Typically, for each

degree centigrade drop in air temperature, power output can be increased by about 1%. Aero-

derivative turbine is more sensitive to change in air temperatures.

Depending on the available waste heat from the power plant, the fuel gas consumption in the

SCVs can be reduced or even eliminated. In addition to energy savings, there is also reduction

in CO and NOx emissions from the facility.

This SCV hybrid configuration offers flexibility in operation. It can be operated as a standalone

submerged combustion unit, or it can use the warm water from the power plant for LNG

regasification, without the submerged burner operating.



Figure 4-14: SCV Power Plant Integration

4.7.6 COMPARISON OF VAPORISER OPTIONS

The optimum choice of an LNG vaporisation system is determined by the terminal’s site

selection, the environmental conditions, regulatory limitations and operability considerations. It

has to comply with the LNG industry’s requirements for minimizing life cycle costs. The

selection should be based on an economic analysis in maximizing the net present value while

meeting the local emissions and effluent requirements.

Table 4-5 and Table 4-6 compare the six vapouriser options in term of their applications,

operation and maintenance, utility and chemical requirements, environmental impacts and

relative plot sizes.

The six options considered in this analysis are:

Option 1 uses ORV as in existing regasification terminals

Option 2 uses propane as the intermediate fluid with seawater as the heat source.

Option 3 uses glycol water as the intermediate fluid with air as the heat source.

Option 4 uses glycol water as the intermediate fluid with seawater as the heat source.

Option 5 uses SCV using fuel gas and waste heat from cogeneration plant

Option 6 uses ambient air vaporiser (AAV).



Table 4-5: Qualification Comparison for LNG Vaporisation Options

OPTIONS 1 2 3 4 5 6

HEATING MEDIUM Seawater (SW) Propane (C3) /

Seawater (SW)

Glycol-water (GW) /

Air

Glycol-water (GW) /

Seawater

Hot Water (HW)

Fuel Gas (FG))

/Waste Heat (WH)

Air

FEATURE Direct LNG

vaporisation using

sea water

Indirect LNG

vaporisation by

condensing propane

which is heated by

seawater

Indirect LNG

vaporisation by

glycol which is

heated by air fin

exchanger

Indirect LNG

vaporisation by

glycol which is

heated by seawater

Indirect LNG

vaporisation by hot

water which is

heated by waste

heat and SCV

Direct LNG

vaporisation using

air

MAJOR

APPLICATION

70% base load

plants use ORV

Cold climate

application and

avoid freezing of

seawater

For warm climate

application. IFV

makes up 5 % of

base load plants

Similar to Option 3

except seawater is

used as the source

of heating

For energy

conservation with

use of waste heat.

SCV is used in 25%

of base load plants

For warm climate

application, peak

shavers and where

real estate is not a

constraint.

OPERATION &

MAINTENACE

Seawater pumps

and filtration system

Maintenance of

vaporisers and

cleaning of

exchangers

Similar to Option 1

with addition of a

glycol loop and

propane system

Similar to Option 2

with a glycol loop

and use of air as the

source of heat

More complex,

requiring

coordination with

power plant.

More complex

control. Need to

balance waste heat

and fuel gas to

SCVs. Require

coordination with

power plant

operation

Cyclic operation,

requiring adjustment

of the defrosting

cycle according to

ambient changes

UTILITIES Seawater and Seawater and Electrical power only Seawater and Fuel gas and Electrical power only



OPTIONS 1 2 3 4 5 6

HEATING MEDIUM Seawater (SW) Propane (C3) /

Seawater (SW)

Glycol-water (GW) /

Air

Glycol-water (GW) /

Seawater

Hot Water (HW)

Fuel Gas (FG))

/Waste Heat (WH)

Air

REQUIRED electrical power electrical power electrical power electrical power

CHEMICALS Chlorination for

seawater treatment.

Similar to Option 1

but lower

chlorination

None Similar to option 1

but lower

chlorination

Neutralization

required for pH

control and NOx

reduction by SCR

None

EMISSION &

EFFLUENTS

Impacts on marine

life from cold

seawater and

residual chloride

content

Impacts on marine

life from cold

seawater and

residual chloride

content

No significant impact

on environment

except dense fog

Impacts on marine

life from cold

seawater and

residual chloride

content

Flue gas (NOx, CO2)

emissions and acid

water condensate

discharge

No significant impact

on environment

except dense fog

SAFETY Leakage of HC from

ORV to atmosphere

at ground level

Leakage of HC to

atmosphere at

ground level.

Operating a propane

liquid system is

additional safety

hazard

Leakage of HC to

glycol system which

can be vented to

safe location via

surge vessel

Leakage of HC to

glycol system which

can be vented to

safe location via

surge vessel

Leakage of HC to

water system which

can be vented to

safe location via the

SCV stack and

surge vessel

Leakage of HC from

AAV to atmosphere

at ground level

PLOT PLAN Medium Size Medium Size Large Size Medium Size Small Size Large Size



Table 4-6: Vaporiser Rankings for Ambient above 18°C

Option Vaporiser / Heat Transfer

Fluid

Environmental Operability Maintainability Total Rank

1 ORV (SW) 4 3 3 10 3rd

2 IFV (C3/SW) 5 5 5 15 5th

3 IFV (GW/Air) 2 1 1 4 1st

4 IFV (GW/SW) 3 4 4 11 4th

5 SCV (HW (FG) /WH) 6 6 6 18 6th

6 AAV (Air) 1 2 2 5 2nd



4.7.7 Rankings of LNG Vaporisation Technology Alternatives

In warm ambient locations, as that of the Tema LNG project, where site ambient temperature

stays above 18°C, the ambient air vaporisers or the air heated intermediate fluid type vaporiser

units can provide the full LNG vaporisation duty without trim heating. In addition, there is

potential revenue to be gained by collecting and marketing the water condensate from the air.

The 6 options in Table 4-6 are ranked for their performance in terms of environmental impacts,

system operability and maintenance requirement. The ranking system is based on a score of 1

to 6, with 1 being the most desirable and 6 the least desirable. These scores are summed and

the one with the lowest score is considered the most desirable option. The rankings are divided

into two regions.

For the hot climate zone, the environmental score for air heating is the top two most desirable

(option 3 and 6) followed by seawater options (1 and 4). Option 5 uses fuel gas for heating in

the SCV generating emissions and hence the least desirable. The use of propane as an

intermediate fluid (Option 2) requires an additional propane system which is not required in a

warm climate region and is also ranked low in the rating.

For operability and maintainability, air heating (option 3 and 6) is the simplest to operate and

maintain. Option 3 using an intermediate fluid with the air heater, which eliminates the cyclic

defrosting operation required for AAV and is ranked the most desirable. For this reason, option

3, the use of glycol and air heating is considered the most desirable. However, the score is only

marginally higher than the AAV option. The final selection depends on other factors, such as

plot space requirement, capital and operating costs.

Open-loop water-based systems are typically used as the heating medium where warm water is

available in sufficient amounts throughout the year. In the case of the Tema LNG Project,

seawater is available in unlimited quantities compared to other sources of heat, and is therefore

the preferred heat source. Detailed description of the preferred regasification process is

presented in Chapter 2 (Project Description).

4.8 NO-GO ALTERNATIVE

The No-Go alternative considers non-construction of Project, which would entail gas supply

deficiencies for independent power providers (“IPP”) and industrial consumers in the area of

Tema and surroundings.

While the Tema local economy comprises agriculture, industry and commerce/services, the

industrial and services sectors employ the majority of labour force. Therefore, the project non-

construction would lead to the slowing down of the economic growth in the area as well as

energy supply deficiencies in some sectors.

If the proposed LNG Regasification Project is not developed, the predicted energy shortfall in

Ghana is likely to be accounted for by the increased reliance on LCO. The cost associated with

LCO is much greater than LNG1. Emissions from LCO combustion can contribute to

1 Energizing Economic Growth in Ghana: Making the Power and Petroleum Sectors Rise to the Challenge, World Bank, 2013



deterioration of air quality in Tema and Takoradi. Natural gas is a less carbon-intensive fuel

(meaning less CO2 is emitted per unit of energy production) than the LCO fuels currently burnt

for electricity production from thermal plants2. Not only is the project less carbon intensive than

industrial processes reliant on LCO, but it will also assist in alleviating the emissions of key air

pollutants such as oxides of sulphur, particulate matter and oxides of nitrogen in the region.

The proposed LNG re-gasification Project therefore provides a more sustainable solution to

meet the expected increase in energy demand than the ‘do-nothing’ option.

2 Guide to Natural Gas Development in Ghana by the Resource Centre for Energy Economics and Regulation, University of Ghana, 2006

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PROJECT ALTERNATIVES 1...QPRGG proposes to build Tema LNG Terminal of the coast of Ghana. The LNG...

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