Levethian Project 07 - Chapter - C - Final

Leviathan Field Production EIA
Chapter C – Description of Actions Stemming from Performance

of the Application
3.0 CHAPTER C – DESCRIPTION OF ACTIONS STEMMING FROM

PERFORMANCE OF THE APPLICATION
3.1 General
Noble Energy and its Co-Venturers are developing the offshore Leviathan Field in the Levantine
Basin to provide gas to:
A. The Israeli domestic gas market by tie-in to the Israeli Natural Gas Lines (INGL)
infrastructure. Initial capacity for domestic supply will be 1,200 MMscfd; and
B. Regional gas users by (new) subsea pipelines to regional gas receivers. Capacity for
regional supply will be 900 MMscfd.
The total nameplate capacity of the Leviathan production system will be 2,100 MMscfd.
The Leviathan Field is located approximately 125 km off the coast of northern Israel in the I/15
Leviathan North and I / 14 Leviathan South leases. Leviathan is located to the west of the
producing Tamar Field which is being produced as a subsea tieback to a nearshore platform off
the coast of southern Israel. Water depths in the Leviathan area range from 1,540 to 1,800 meters.
The location of the Leviathan Field and the proposed infrastructure is provided in Figure 3-1 with
straight line distances included between points of interest / reference, these do not necessarily
reflect pipeline lengths. Note that only the Leviathan-5 well is shown in this figure as this is the
well which lies furthest from the Infield Gathering Manifold (detailed further below). The location
of the Tamar Field is included for reference.
This assessment is based on the Leviathan Field Development Plan (FDP) as it exists at the time
of preparation of this assessment. Specifics of the FDP may be updated as required as the project
progresses through Front End Engineering Design (FEED) and the subsequent Detailed Design
phase.
Client Doc. No: LPP-PM-NEM-EIA-PLN-0002

Confidential–Do Not Disclose Without Authorization © Copyright Genesis North America - All Rights Reserved
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Chapter C – Description of Actions Stemming from Performance of
the Application
Figure 3-1 Leviathan Field Location in the Eastern Mediterranean

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Chapter C – Description of Actions Stemming from Performance
of the Application
Development of the Leviathan Field is envisaged as a subsea tieback of approximately 117.5 km

to a dedicated LPP located within Israeli territorial waters.
Production wells will be arranged in clusters around a central Infield Gathering Manifold with all
initial production wells lying within a 10 km radius of the Infield Gathering Manifold. The LPP will
be a fixed platform (steel jacket) with all the necessary receiving, processing and export facilities
required to supply gas directly to both the Israeli domestic market, and regional gas importers.
The LPP will be approximately 10 km from the nearest Israeli coastline (Dor) and will export gas
to the Israeli domestic market by way of a subsea pipeline from the LPP to an onshore tie-in point
to the Israeli Natural Gas Line (INGL) system (at Dor). The tie-in point for connection to the INGL
system lies approximately 1.5 km from the shore crossing location, with up to 2 km of onshore
pipeline between the Coastal Valve Station (CVS) at the shore crossing, and the INGL tie-in point.
The subsea tieback concept has previously been proven through the development of the nearby
Tamar Field which features a 150 km multiphase production system tied-back to a fixed platform
off the coast of Ashdod. A schematic of the proposed development of the Leviathan Field is shown
in Figure 3-2.

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Chapter C – Description of Actions Stemming from Performance of the
Application
Figure 3-2 Leviathan Development Overview

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the Application
Production from the Leviathan Field will be through high-rate subsea wells into a subsea
production infrastructure that will transport the production fluids to the shallow water LPP where
the gas will be processed. Processed gas for the Israeli Natural Gas Lines (INGL) will be exported
by a 32” pipeline to an onshore tie-in valve station at Dor. Gas for regional export will be
compressed on the LPP and exported via dedicated pipelines which are yet to be defined.
Gas condensates (co-produced with Leviathan gas) will be stabilized on the LPP and exported
by a dedicated pipeline to shore which is the preferred route to market at this stage. Markets for
Leviathan condensate include the Bazan operated refinery in Haifa.
The Project will develop the Leviathan Field through parallel infrastructure for domestic supply
and regional export. Gas for domestic supply will be routed from the subsea wells via infield
flowlines to an Infield Gathering Manifold where it will be directed into two (2) 18” 117.5 km
production pipelines to the LPP in Israeli territorial waters. At the LPP gas for the domestic market
will be processed through the Domestic Supply Module (DSM) and ultimately exported to the
onshore INGL tie-in.
Gas for regional export will be produced through the same infield subsea infrastructure utilized
for domestic gas production, however at the Infield Gathering Manifold gas for regional export will
be routed through a single 117.5 km 20” production pipeline to the LPP. At the LPP, gas for
regional export will be processed through the Regional Export Module (REM) and ultimately
routed to regional consumers through dedicated subsea pipelines.
The LPP will be a manned facility with all processing and utility functions required to:
 Process the Leviathan gas to either domestic or regional supply specifications;
 Provide production chemicals and controls to the infield infrastructure; and
 Support a total crew of up to 140 Persons On Board (POB).
Cross connections will be in place on the LPP to enable gas processed through either of the
production modules to be routed to any available sales route.
The FDP calls for up to eight (8) production wells to be in place for first gas to supply gas to both
the Domestic Supply and Regional Export Modules. These initial wells will serve to further
increase understanding of the Leviathan reservoir and will guide the drilling and placement of
future infill wells to maximize ultimate recovery from the field. Current reservoir modelling
indicates that up to 29 wells [including the initial eight (8)] will be required to fully produce the field.
This document covers all infrastructure required to produce the initial eight (8) wells and route
production to the LPP. Consideration to future wells will be limited to briefly describing how they
may be tied into the production system at a later date.
The scope of this assessment is any infrastructure associated with the production of the Leviathan
Field that lies upstream of the LPP risers. This covers all infield and transmission infrastructure
up to, and including their tie-in points at the LPP riser bases. Note that drilling and tree installation
is not within the scope of this document and has previously been assessed in the Environmental

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the Application
Impact Report for Production Drilling, Production Tests and Completion on the Leviathan Field
(Noble Energy Mediterranean Ltd, 2016a).
The Leviathan Field development is planned for 30 years. Future facility modifications are beyond
the scope of this document.
The sections that follow will provide a detailed description of the infrastructure, which falls within
the scope of this assessment.
Project Schedule
The FDP for the Leviathan Field is targeting first gas for domestic supply at the end of 2019.
Regional export from the LPP is targeted to be available by July 2020. The overall development
schedule is shown in Figure 3-3 and indicates that installation of submarine infrastructure will
occur between Q1 2018 and Q3 2019.
Figure 3-3: Leviathan Development Schedule

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the Application
3.2 Description of the Application

This section considers all Leviathan Production facilities which exist in the Application area and
describes the development through its’ Project stages from installation to operations.
3.2.1 General
Development Wells, Wellheads and Xmas Trees
Due to the water depth at the Leviathan Field all wells will be drilled from dynamically positioned
drilling vessels and completed as subsea wells with wellheads and Xmas trees installed on the
seabed.
The plan for development calls for up to eight (8) wells at first gas, broadly arranged across the
Leviathan Field into two (2) clusters [one (1) north and one (1) south] with a satellite well
(Leviathan-5) located towards the northern limit of the field. The first eight (8) production wells on
the Leviathan Field are to be numbered as Leviathan-3 through to Leviathan-10, Leviathan-1 and
Leviathan-2 were exploration wells and will not be re-used for development. Details of the drilling
process and well design are available in the Leviathan Drilling EIA (Noble Energy Mediterranean
Ltd, 2016a).
The locations of Leviathan-3 through to Leviathan-10 are shown in Figure 3-4.
Figure 3-4: Map of Leviathan Production Wells for First Gas

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the Application
Following the initial production phase, additional development wells will be drilled into the
Leviathan Field to maintain production and optimize reserve recovery. The final requirement,
timing, and placement of future wells will be determined by the reservoir performance observed
during the initial production phase. Preliminary reservoir simulations indicate that up to 21
additional wells will be required.
Wellhead and Xmas Tree Installation

Installation of wellheads and trees form part of the drilling process and as such this activity is not
within the scope of this assessment. The reader is referred to the Leviathan Drilling EIA for further
information (Noble Energy Mediterranean Ltd, 2016a).
Commissioning of Xmas tree mounted valves is included under pre-commissioning and

commissioning activities of the infield controls system (Section 3.2.1.3).
Infield Facilities, Installation, Tie-in, Pre-Commissioning & Commissioning

The development of the Leviathan Field will utilize subsea infrastructure to produce and gather
reservoir fluids prior to their transmission to the shallow water LPP. Additional infield structures
and umbilicals will be required to provide services and controls to the production facilities.
The infield infrastructure required for development of the Leviathan Field through the initial
eight (8) wells includes the following elements:
 Infield production flowlines from wellheads to tie-in location;
 Infield tie-in jumpers;
 A single three header six (6) slot Infield Gathering Manifold;
 Infield SDU for distribution of MEG to the infield umbilicals; and
 Infield umbilicals, Umbilical Termination Assemblies (UTAs) and flying leads.
Note that the Subsea Distribution Unit associated with the primary umbilical from the LPP to the
field is included within the transmission facilities (Section 3.2.2).
The infield infrastructure to be in place for first gas is shown in Figure 3-5.

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the Application
Figure 3-5: Infield Production Infrastructure Schematic
The anticipated installation, tie-in, pre-commissioning, and commissioning activities associated

with the infield subsea infrastructure are detailed in the subsequent sections.
Pre-Installation Survey
Geophysical and Hazard Surveys have previously been carried out at the Leviathan Field in order
to obtain site-specific engineering data on the infield area. Although this data was collected prior
to the selection of the nearshore LPP development concept, it covers the entirety of the Leviathan
Field.
The existing pre-installation survey consisted of a Bathymetric Survey, a Side Scan Sonar Survey
and sediment sampling across the field’s areal extent. The aim of the survey was to identify
geological conditions, seafloor and shallow hazards, existing pipelines and cables, and
bathymetric information, which could be used during the design and installation of subsea
infrastructure. Aside from that associated with the Leviathan Field exploration and appraisal wells,
the only infrastructure in the infield area is the MED NAUTILUS telecommunication cables.
The Leviathan Field is located in an area where seabed faulting and active draining channels are
present. Where possible infield flowlines will be routed to avoid crossing faults and channels,
however where this is not possible, engineered crossings will be designed as appropriate.

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3.2.1.1 Support Vessels

Finalized installation, tie-in and commissioning plans, and associated schedules will be developed
by the Engineering Procurement and Construction (EPC) contractor following contract award.
However, the activities associated with infield construction operations are anticipated to require
the following marine vessels:
 DP Pipelay Vessel (e.g., Allseas Solitaire);
 Pipe Supply Vessel - to transport pipe sections between the in-country storage site and
the Pipelay vessel;
 OCV (e.g. BOA Sub C) - to install subsea structures, umbilicals and tie-in jumpers;
 MSV with ROV capability (e.g. Siem Stingray) - to support pipeline and structure
installation, and perform commissioning activities; and
 Standby and Supply vessels.
In addition, weekly crew transfers for the pipelay vessel are expected to be performed by
helicopter, nominally a Sikorsky-61N.
Table 3-1 provides an estimate of vessel use during the infield installation, tie-in, pre-
commissioning and commissioning activities associated with the Leviathan Field development.
This is based on the installation campaign further in the following sections. Vessel fuel use is
estimated based on typical vessels available within each category and is assumed to be marine
diesel for vessels and Jet A for helicopters.
Assumptions relating to vessel durations and fuel use are provided in Appendix D.

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Table 3-1 Vessel Use for Infield Facilities Installation, Pre-Commissioning and
Commissioning
No of Working period Schedule Fuel Consumption Total Fuel

Vessel
vessels (days) Activity (Te / day) Use (Te)
DP Pipelay Vessel 1 18 1 130 2,340
Pipe Supply Vessel 1 18 1 15 270
Offshore Construction
1 60 2,3,4 51 3060
Vessel
Multipurpose Support
1 84 All 26 2184
Vessel with ROV
Standby vessel 1 84 All 2.4 201.6
Supply vessel Note 1 2 84 All 12 1008
Helicopter 1 5 hrs 1 0.40 Te / hr 2.0
Total 9065.6
Schedule Activity:
Activity 1: Flowline and Infield PLET Installation (18 Days)
Activity 2: Gathering Manifold and Pile Installation (3 Days)
Activity 3: Infield Umbilical and Controls Structure Installation (13 Days)
Activity 4: Flowline and Umbilical Tie-ins (44 Days)
Activity 5: Production System Pre-Commissioning and Commissioning (6 Days)
Activity 6: Controls Pre-Commissioning and Commissioning (Performed as part of overall controls commissioning)
Notes:
Note 1: Two (2) supply vessels are assumed based on there always being one (1) vessel in transit.
3.2.1.2 Infield Infrastructure and Installation
Infield Production Flowlines

Infield production flowlines will link the subsea wellheads to the Infield Gathering Manifold. For
the initial eight (8) production wells, flowlines will run directly from the subsea wellhead(s) to the
Infield Gathering Manifold. Future wells will be tied into the subsea production system by daisy
chaining new flowlines into the infrastructure in place for first gas, through spare tie-in points on
the infield flowline Pipeline End Terminations (PLETs – see below). This is required in order to
enable the tie in of up to 29 development wells into the single six (6) slot Infield Gathering
Manifold.
Flowlines will be of 14” diameter and of rigid construction. The total flowline length for the initial
eight (8) development wells will be 22.5 km, with the longest individual flowline measuring 9.8 km.

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the Application
Each flowline will feature a PLET at each end. PLETs will facilitate the installation of tie-in jumpers
to connect the flowline to the subsea wellhead(s) at one end, and the Infield Gathering Manifold
at the other.
All infield PLETs (upstream of the Infield Gathering Manifold) will be designed with a spare tie-in
slot to enable future flowlines/ wells to be tied into the initial infrastructure. Infield PLETS will be
relatively lightweight structures and as such will be installed on mudmat foundations.
The estimated land-take attributable to flowlines and infield PLETs is provided in Table 3-2, based
on the calculation provided in Appendix C.1.
Table 3-2: Infield Flowline and PLET Land Take
Description Location Wells Tied-in Land Take (m2)
Flowlines (22.5 km) Note 1 Distributed All 8,001
PLET - Single Infield Gathering Manifold Lev-3 90
PLET - Single Infield Gathering Manifold Lev-4 / Lev-8 90
PLET - Single Infield Gathering Manifold Lev-5 90
PLET - Single Lev-3 Lev-3 90
PLET - Single Lev-5 Lev-5 90
PLET - Twin Lev-4 / Lev-8 Lev-4 / Lev-8 120
PLET – Twin Lev-6 / Lev-7 Lev-6 / Lev-7 120
PLET - Twin Lev-9 / Lev-10 Lev-9 / Lev-10 120
Total 8,991
Notes: 1. Flowline land take is based on the full 14” diameter of flowlines giving a land take per unit of 0.36 m2 / m.
Infield flowline pipe will be fabricated in sections (typically 12 m) at an out of country fabrication
yard and shipped to in-country port facilities for storage until they are required at the infield
location. Flowline sections will be transported from the in-country storage location to the Pipelay
Vessel by supply vessels fitted with pedestal cranes.
Flowlines will be installed dry on the seabed by a Dynamically Positioned (DP) Pipelay Vessel
(discussed further under Section 3.2.2), which is expected to achieve an average lay rate of three
(3) km / day. Due to the water depth (>1,600 m) no trenching or burial of infield lines is required.
Further, the benign hydrodynamic conditions at the field will allow the flowlines and PLETs to rest
on the seabed due to weight alone, with no additional anchoring required.

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Pipelay may be by either the J-lay or the S-lay method subject to EPC contractor selection;
selection of either method is not expected to significantly alter the environmental impact of flowline
installation operations.
Infield Tie-in Jumpers

Infield tie-in jumpers (here in referred to as jumpers) will connect the subsea production structures
(subsea wellheads and Infield Gathering Manifold) to their respective PLETs on the infield
flowlines. All jumpers will be of rigid steel pipe construction.
Due to the project water depth all jumpers will be designed for diverless connection with ROV
support. During installation, jumpers will be allowed to free flood with seawater. Following
installation, the jumpers will be flushed with MEG to displace seawater and protect the internal
surfaces from seawater corrosion and biogenic growth. MEG discharge during flushing operations
is discussed further below.
An OCV will be used for jumper installation. An example of an OCV being considered for this
project is the BOA Sub C. Installation will be supported by the use of ROVs and an associated
support vessel, which is expected to be of an MSV design, equipped for ROV deployment and
recovery. An example of such a vessel is the Siem Stingray as shown in Figure 3-6.
Figure 3-6: Siem Stingray – ROV / Multipurpose Support Vessel

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the Application
Jumpers will be fabricated at a location within Israel and subsequently transported to the infield
location by either cargo barge, supply vessel or on the deck space of the OCV used to install
them.
Due to the project water depth and benign seabed conditions, jumper protection (in the form of
concrete mattresses) or mid-point anchoring is not required and as such will not be used.
Infield Gathering Manifold

The Infield Gathering Manifold will be a six (6) slot manifold with three (3) production headers of
16” nominal diameter. Actuated valves on the manifold will allow any of the six (6) slots to be
routed to any production header, thus allowing the operations team to alter the distribution of gas
routed to the domestic supply and regional export production pipelines without the need for ROV
intervention.
The Infield Gathering Manifold will have approximate dimensions of 10 m by 20 m (W x L) with a

total area in the region of 200 m2. The dry weight of the complete structure is expected to be in
the region of 350 Te and will thus necessitate a piled foundation. It is intended to install the Infield
Gathering Manifold on a single six (6) m diameter suction pile; suction piling is preferred at this
water depth due to ease of installation when compared to driven piles. The use of a single suction
pile has the added benefit of reducing the total land take associated with the gathering manifold,
as the manifold itself will not sit on the seabed. As such the land take attributable to the Infield
Gathering Manifold is limited to that of the six (6) m diameter suction pile (28 m2).
The Infield Gathering Manifold and associated suction pile will be installed from an OCV using
the main crane facilities. Due to the manifold weight, installation is expected to require multiple
offshore lifts to ensure total lift weight does not exceed crane capacity. A total of three (3) lifts are
considered in this assessment based on:
 Lift 1: Suction Pile Installation;
 Lift 2: Manifold Support Structure Installation; and
 Lift 3: Manifold Installation.
It is possible that fewer lifts will be required however this will be determined following installation
contractor selection.
The Infield Gathering Manifold will be fabricated at an out of country fabrication yard and shipped
to in-country port facilities for storage. It is expected that it will be transported to site on the deck
of the OCV from which it will ultimately be installed from. In addition to the OCV, ROVs and
associated supports vessel will be required during the installation.
An alternative to transport to site on the OCV is transportation by towed cargo barge. This decision
will be made during the EPC Engineering phase but is not considered to materially impact the
environmental impact of the project.

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Infield Subsea Distribution Unit – MEG

An infield SDU will be installed local to the Infield Gathering Manifold for the purpose of receiving
and distributing MEG from the 6” MEG supply lines (two (2) of) to the infield umbilicals.
The SDU will be installed onto a mudmat foundation and secured in place by its submerged weight
with no piling required. The land take associated with the SDU and its mudmat foundation is
estimated at 97 m2. Installation will be from an OCV that will already be in the field for the purpose
of umbilical and structures installation. Operational support will be required from ROVs and an
MSV.
Infield Umbilicals and Flying Leads

Hydraulic and electrical flying leads will transmit controls signals, MEG, and chemicals from the
SDUs (one (1) by MEG SDU and one (1) by controls SDU) located close to the Infield Gathering
Manifold to the infield UTAs. From the UTAs these will be further routed to the subsea wellheads
via the Infield Umbilicals. This will enable hydraulic actuation of Xmas tree mounted valves and
chemical injection into the production fluids.
Additional hydraulic and electrical flying leads will connect the Infield Gathering Manifold to the
SDUs to enable control and monitoring of manifold mounted valves.
Infield umbilicals will be multi-cored electrohydraulic systems with a total of six (6) electrical power
cores and 14 super-duplex stainless steel tubes for conveying hydraulic fluids and chemicals. All
cores and tubes will be bundled into a single infield umbilical with a high density polyethylene
protective outer coating giving an approximate outer diameter of 7.2” (180 mm). A detailed list of
infield umbilical cores is provided in Table 3-3.
Table 3-3: Infield Umbilical Cores

Core No Service Size (ID) Notes1
1-6 6x Power Supply 6x 6 mm2 Shielded
7-10 4x Hydraulics 4x ½” Installed HW540P filled
11 Scale Inhibitor ½” Installed SST5007 filled
12-15 Auxiliary, Annulus and Methanol 4x 1” Installed SST5007 filled
16-18 3x MEG + (CI) supply 3x1¼” Installed SST5007 filled
19 Spare 1 1¼” Installed SST5007 filled
20 Spare 2 1” Installed SST5007 filled
Notes: 1. Where reference is made to cores being installed either HW540P or SST5007 filled, this refers to the specific chemicals
“Macdermid Oceanic HW540P” and “MacDermid Oceanic SST5007” respectively. Final chemical selection will be made by
the EPC contractor.
All infield umbilicals will feature UTAs at each end to enable tie-in (by flying leads) to the relevant
structures. A total of 10 UTAs will be installed infield, with each one installed on a 21.7 m2 mudmat
foundation with no requirement for additional anchoring in the form of piles. This gives a total land
take for infield UTAs of 217 m2.

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the Application
The total length of infield umbilicals required for the initial eight (8) production wells is
approximately 22.8 km. Based on a 180 mm diameter the total land take for the infield umbilicals
is estimated at 4,152 m2. When considered with the UTA land take, this gives a total land take
attributable to infield umbilicals of 4,369 m2.
All infield umbilicals will be laid directly onto the seabed from an OCV equipped for flexible lay
operations. Prior to installation all hydraulic fluid lines will be filled with MacDermid Oceanic
HW540P which is the selected hydraulic fluid for the Leviathan development. This will act to
protect hydraulic cores during installation and minimizes pre-commissioning activities associated
with these cores. Further, all chemical and service cores will be filled with MacDermid Oceanic
SST5007 prior to installation to a) protect them during installation, b) prevent microbial infection,
and c) provide a test fluid for future pre-commissioning activities. Both MacDermid Oceanic
HW540P and MacDermid Oceanic SST5007 are water based fluids.
The Material Safety Data Sheet (MSDS) for MacDermid Oceanic HW540P and MacDermid
Oceanic SST5007are provided in Appendix C.2.
Infield umbilical installation operations will be supported by ROVs and an associated MSV. Future
infill wells will require additional infield umbilicals and UTAs of a similar design to those discussed
above.
Pre-Commissioning and Commissioning

Following installation, the infield infrastructure will require pre-commissioning and commissioning
prior to first gas. It should be noted that all infield infrastructure (excluding wells) will be
commissioned after the transmission facilities (see Section 3.2.2) and as such nitrogen for
commissioning of the infield flowlines will be available from the packed production pipelines.
Pre-commissioning and commissioning activities typically include:

 Pre-commissioning: Flooding, Cleaning, Gauging and Hydrotesting; and
 Commissioning: Dewatering and Drying.
Pre-commissioning and commissioning activities specifically required for the Leviathan Field
development will be determined during detailed design.
The project schedule provided in Figure 3-3 indicates that subsea facilities will require pre-
commissioning and commissioning during H2 2019. This is reliant on the project progressing as
currently expected and is subject to change depending on project progress. Further definition of
anticipated pre-commissioning and commissioning dates will be determined during the detailed
engineering phase of the project.
Preliminary estimates of pre-commissioning and commissioning durations associated with the

infield facilities are presented in Section 3.2.1.1.
Production System
The commissioning philosophy for the infield production system is as follows:

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 Pre-commission infield flowlines prior to jumper installation by way of subsea pumping,

and subsea pig launch and receive at the infield PLETs;
 Following jumper installation, subsea connectors will be leak tested and the jumpers
flushed with MEG to displace free flood seawater. This action will complete infield pre-
commissioning as all jumpers will be cleaned and hydro-tested prior to installation; and
 Commission (dewater and nitrogen purge) the entire infield production system by routing
nitrogen from the nitrogen packed production pipelines through the Infield Gathering
Manifold and into the infield flowlines and jumpers.
Pre-commissioning flooding will utilize filtered and chemically treated seawater. Indicative
chemicals to be used for this purpose are:
 Roemex RX5227: Combined oxygen scavenger, corrosion inhibitor and biocide – typically
dosed at 1,000 ppm; and
 Roemex RX9025: Leak tracer dye – typically dosed at 50 ppm.
Both of these chemicals are classified as Gold chemicals under the OCNS which indicates that
they present a relatively low hazard to the environment, final chemical selection will be made
during the detailed design phase of the project. For the purpose of this assessment the Roemex
chemicals stated above are considered throughout this chapter as typical examples of chemicals
that may be used.
As part of the pre-commissioning procedure the infield flowlines will be cleaned through the use
of pigs. This will drive various construction and welding residue/ debris from the flowlines and into
the subsea pig receivers. This will not be released to the environment, but retrieved to the surface
in the pig receivers; this will subsequently be transported to shore and disposed of as appropriate.
Pre-commissioning of the tie-in jumpers will necessitate MEG discharge to the environment to
ensure seawater is adequately displaced. The total MEG discharge per jumper is estimated at
10 m3. This discharge will occur local to the jumper.
During dewatering and drying of the infield production system the chemically treated seawater
used for pre-commissioning activities will be discharged to the marine environment at the
wellhead ends of the flowlines. Low volumes of MEG will also be discharged in this operation.
Table 3-4 provides an estimate of the infield releases during pre-commissioning and
commissioning operations associated with the tie-in of the initial eight (8) development wells.
Future well tie-ins and flowline commissioning will result in incremental discharges of similar
fluids.

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Table 3-4: Infield Pre-commissioning and Commissioning Releases

Pre-commissioning
Volume
Location Discharge Notes
(m3)
MEG discharge associated with
infield jumper displacement. A total
Gathering Manifold MEG 50
of 5jumpers will be displaced at this
location.
MEG Discharge associated with
80
jumper displacement. One (1)
Wellheads MEG (10 at each
jumper to be displaced at each
Wellhead)
well-head.
Commissioning
Volume
(m3)
Chemically Treated
Leviathan 3 440
Seawater
Displaced hydrotest water
Chemically Treated
Leviathan 4 / 8 360 containing a cocktail of:
Seawater
a) RX5227 (or equiv.) at 1,000 ppm
Chemically Treated
Leviathan 5 940 b) RX9025 (or equiv.) at 50 ppm
Seawater
c) Low volumes of MEG.
Chemically Treated
Leviathan 6 / 7 200 Final chemical use is subject to
Seawater
confirmation during detailed design.
Chemically Treated
Leviathan 9 / 10 220
Seawater
Pre-commissioning and commissioning activities on the infield production system will be

supported by ROVs launched and controlled from a surface based MSV.
3.2.1.3 Controls Distribution System

Pre-commissioning and commissioning activities for the infield controls system will involve
pressure testing of all equipment, displacement of storage fluid and functionality checking. This
will be performed in conjunction with the pre-commissioning and commissioning of the primary
umbilical that will run from the LPP to the Controls SDU (see section 3.2.2).
Pressure testing will be performed from an MSV or dedicated commissioning vessel located at
the LPP end of the primary umbilical. Pressure testing will be performed as per standard hydrotest
procedures, however the test fluid will be that present during umbilical installation, either
MacDermid Oceanic HW540P or MacDermid Oceanic SST5007, both of which are water based.
Storage fluid displacement and function checking of the infield controls system for the initial eight
(8) development wells will be performed as part of the wider controls system commissioning
process to be performed from the LPP. During storage fluid displacement, the umbilical storage
fluid will be displaced from all non-hydraulic cores other than the two (2) spare cores. Details of
the infield umbilical cores to be displaced are provided in Table 3-5.

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the Application
Table 3-5: Infield Umbilical Cores for Pre-Commissioning Operations

Size
Core No Service Notes1
(ID)
12 Auxiliary 1” Installed SST5007 filled
13 Annulus Service Line 1” Installed SST5007 filled
14 Methanol 1 1” Installed SST5007 filled
15 Methanol 2 1” Installed SST5007 filled
16 MEG + CI 1 1¼” Installed SST5007 filled
19 / 20 Spare cores that will be left SST5007 filled until required

Notes: 1. Where reference is made to cores being installed SST5007 filled, this refers to the specific chemical
“MacDermid Oceanic SST5007”. Final chemical selection will be made by the EPC contractor.
Storage fluid from the infield umbilicals will be discharged at the wellhead end of the infield
umbilical. An alternative method of storage fluid displacement is to route the fluid into the flowlines
and production pipelines for displacement back to the LPP. A decision on the preferred routing of
displaced fluid will be made in future phases of design
For the initial eight (8) development wells there will be MacDermid Oceanic SST5007 discharge
at each of the following locations:
 Leviathan-3;
 Leviathan-4 / 8;
 Leviathan-5;
 Leviathan-6 / 7; and
 Leviathan-9 / 10.
Approximate discharge volumes of MacDermid Oceanic SST5007 based on core diameter and
infield umbilical length are provided in Table 3-6.
Following storage chemical displacement of the entire controls system (for displacement of the
primary umbilical see Section 3.2.2.2) the system will be function tested by hydraulically
energizing all actuated valves in the subsea infrastructure. Due to the open-loop nature of the
Leviathan controls system this will result in low volume discharges of hydraulic fluid (MacDermid
Oceanic HW540P) at all valve locations.
Actuated subsea control valves to be energized during commissioning operations include:

 Wellhead / Xmas tree mounted valves; and
 Infield Gathering Manifold mounted valves.

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Hydraulic fluid discharge from commissioning all valves on a single Xmas tree is estimated at 18
liters. For the initial eight (8) development wells this corresponds to a total discharge of 288 liters
of MacDermid Oceanic HW540P.
Hydraulic fluid discharge from commissioning all valves on the Infield Gathering Manifold is
estimated at 117 liters.
Beyond the discharges associated with wellhead and manifold valve commissioning there are no
further discharges of MacDermid Oceanic HW540P hydraulic fluid associated with infield umbilical
commissioning activities.
All discharges associated with pre-commissioning and commissioning activities of the infield
umbilicals are estimated in Table 3-6 and will be subjected to gaining the necessary approvals
from the authorities.
Any infill wells (future) that are subsequently tied into the Leviathan production infrastructure will
be subject to similar pre-commissioning and commissioning procedures to those discussed
above. As such future wells will result in incremental discharges.

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Table 3-6: Discharge Sites and Volumes for Infield Umbilical Pre-Commissioning and
Commissioning
Pre-commissioning
Discharge Volume
Discharge Location Chemical
(Liters)
Lev-3 3600
Lev-4 / 8 2900
MacDermid
Lev-5 7600
Oceanic SST5007
Lev-6 / 7 1800
Lev-9 / 10 1800
Commissioning
Gathering Manifold 117
Lev-3 18
Lev-4 / 8 36
MacDermid
Oceanic HW540P
Lev-5 18
Lev-6 / 7 36
Lev-9 / 10 36
The MSDSs for MacDermid Oceanic HW540P and MacDermid Oceanic SST5007are provided in
Appendix C.2.
3.2.2 Transmission Facilities Installation, Tie-in and Commissioning

In order to transport Leviathan production from the Infield Gathering Manifold to the LPP located
in Israeli territorial waters transmission pipelines shall be installed. The development will utilize
the following production infrastructure:
 Two (2) by 18” 117.5 km rigid steel production pipelines for production to the DSM;
 Two (2) by 18” Pipeline End Terminals (PLETs) located at the infield end of the DSM
production pipelines;
 Two (2) by 18” Sub-Sea Isolation Valves (SSIVs) and structures at the LPP end of the
DSM production pipelines;
 One (1) by 20” 117.5 km rigid steel production pipeline for production to the REM;

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 One (1) by 20” PLET located at the infield end of the REM production pipeline; and
 One (1) by 20” SSIV and structure at the LPP end of the REM production pipeline.
In addition to the production infrastructure, additional subsea infrastructure will be required to
supply services and controls from the LPP to the infield infrastructure and SSIVs. This will
primarily consist of:
 Two (2) by 6” 117.5 km rigid steel MEG supply lines, installed either as standalone lines,
or piggybacked onto the 18” DSM production pipelines;
 Two (2) by 6” PLETs at the infield end of the MEG supply lines;
 One (1) by 117.5 km primary umbilical of electrohydraulic design – Installed as two (2)
lengths of umbilical (one (1) by 60 km and one (1) by 57.5 km) joined with UTAs and flying
leads at the mid-point;
 One (1) by Controls SDU at the infield end of the primary umbilical;
 One (1) by independent umbilical to provide electrohydraulic connection between the LPP
and the SSIVs; and
 One (1) by UTA local to the SSIVs to facilitate controls tie-ins.
All transmission pipelines (production and MEG supply) and umbilicals shall be laid into a single
transmission corridor from the LPP to the Leviathan Field. This transmission corridor will be up to
600 m wide. The selected corridor routing is shown in Figure 3-7. The total corridor length from
the LPP to the Infield Gathering Manifold is approximately 117.5 km.
It should be noted that the planned installation of the transmission lines (production pipelines,
MEG supply lines and primary umbilical) will occur prior to the installation of the infield facilities.
This will enable commissioning activities on the infield facilities to be completed either; from the
LPP, or from a vessel located in close proximity to the LPP.

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Figure 3-7: Gathering Facilities Route
3.2.2.1 Installation of Submarine Production Infrastructure

This section describes activities and methodologies associated with the installation and
commissioning of the submarine infrastructure required for the transmission of production fluids,
chemicals and controls between the infield facilities and the LPP (i.e. pipelines, umbilicals and
isolation systems). It further describes the supply and support services required during the
installation phase of development.
Pipeline Route and Pre-installation Survey

Since the discovery of commercial quantities of gas in the Tamar and Leviathan Fields a number
of potential pipeline corridors have been surveyed to assess suitability for piping gas from the
fields to northern Israel. Figure 3-8 shows the pipeline corridors that have been surveyed to date,
with the selected route for the Leviathan development overlaid for reference. This shows that the
majority of the route for transmission lines from the Infield Gathering Manifold to the northern
TAMA block has previously been surveyed. There is a short length of the route, where the corridor
jumps from the previously surveyed Leviathan corridor to the previously surveyed (but unused)
Tamar corridor, that has not been extensively surveyed.
Although not shown in Figure 3-8, the infield area, and the area directly to the east of it has
previously been subject to preliminary surveying (identifying location of channels etc.), however
some additional survey work may be required along the finalized transmission corridor. Additional
surveying of this area is expected to be completed in conjunction with any other survey work
required along the transmission route.

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Figure 3-8: Surveyed Pipeline Routes
The surveys performed on the previously proposed pipeline routes have been Geophysical and
Hazard Surveys to obtain site-specific engineering data of the seafloor conditions along the
proposed corridors. The aim of these surveys is to identify geological conditions, seafloor and
shallow hazards, existing pipelines and cables and bathymetry information, all of which is used to
help determine the design and installation of subsea infrastructure.
In order to confirm the findings of the previous surveys and to fill in any un-surveyed areas,
additional survey work is planned for summer 2016. This will primarily consist of a Bathymetric
Survey and a Side Scan Sonar Survey performed from an Autonomous Underwater Vessel
(AUV).
The Leviathan pipeline corridor is located in an area where faulting is present. Where possible
transmission pipelines have been routed to avoid major channel / fault crossings, however where
this is not possible, engineered crossings will be developed as required.
Water depths along the transmission pipeline corridor range from 1,660 m at the Infield Gathering
Manifold, to approximately 600 m at territorial waters, and down to 86 m immediately adjacent to
the LPP. Due to the water depth, and large diameter thick walled production pipelines, no pipeline
burial, trenching or armoring will be utilized. Umbilicals, and standalone MEG supply lines (if
required) will also not be subject to trenching or burial.

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All SSIVs and pipeline tie-ins at the LPP end of the transmission pipelines will lie within the 500 m
platform exclusion zone and as such will not require protection from external actions unrelated to
platform operations. A dropped object study to be performed during detailed design will determine
any requirement for protection from dropped objects originating from platform operations.
Pipeline / Umbilical Installation and Tie-In
Production Pipelines
The production pipelines [two (2) by 18” and one (1) by 20”] will each be approximately 117.5 km
long and will link the Infield Gathering Manifold to the LPP in Israeli territorial waters.
The production pipelines will be of rigid construction and will be installed directly onto the seabed
with no trenching or burial required at any location along the pipeline route. Each pipeline will
feature a PLET at the infield location and a valved diver assisted tie-in point at the LPP end to
enable tie-in to the SSIV structure.
Each PLET will be installed onto a dedicated mudmat foundation with an estimated land take per
PLET of 110 m2. The valved diver assisted tie-in points will sit directly on the seabed with no
additional foundations (mudmat or piles).
Tie-in jumpers will be required to make the connections between the deepwater PLETs and the
Infield Gathering Manifold. Connections local to the LPP will be made with tie-in spools.
Each production pipeline will require one (1) set of tie-in jumpers / spools. All jumpers and spools
will be of rigid construction and will match the nominal diameter of the production pipeline they
are associated with. Wall thickness of jumpers and spools will be as per that determined by
design. Deepwater jumpers will feature diverless connections, while spools around the LPP will
utilize diver assisted connections.
Estimated land take associated with the production pipelines is provided in Table 3-7. The land
take associated with pipelines is calculated based on the full pipeline diameter.
Table 3-7: Production Pipeline and PLET Land Take

Land Take
Item
(m2)
2x DSM 18” Pipelines (117.5 km each) 107,442
2x DSM 18” PLETs 220
1x REM 20” Pipelines (117.5 km) 59,690
1x REM 20” PLET 110
Total 167,462
The production pipelines will be fabricated in 12 m sections at an out of country fabrication yard
and shipped to in-country port facilities for storage until they are required onsite for installation.
Pipeline sections will be transported from the in-country storage location to the pipelay vessel by
a pipelay supply vessel fitted with a pedestal crane.

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Production pipelines will be installed dry on the seabed, with no anchoring required along the
route. Pipelay may be by either the S-lay or J-lay method which differ primarily in the way that the
pipeline is allowed to flex during installation. Final selection of the lay method will be made by the
EPC contractor following contract award. For the purpose of this document S-lay is assumed,
however the incremental impact of reverting to J-lay are not considered significant.
It is anticipated that the same DP Pipelay Vessel that will be used for flowline installation will be
used for the production pipelines. The Allseas Solitaire is considered a representative vessel at
this stage as the large diameter, thick walled production pipelines, combined with the project water
depth will drive the selection of a high specification vessel. Final vessel selection will not be made
until the EPC contract is awarded, however an average lay rate of three (3) km / day is anticipated
with an additional two (2) days allowed per pipeline for start-up and lay down.
A typical DP S-lay vessel features a tunnel structure or ‘firing line’, on its main deck which allows
for pipe handling, welding & non-destructive testing (NDT), grit blasting and coating (as
appropriate) as well as the maintenance of tension on the pipeline. These vessels are capable of
offshore pipe loading from supply vessels while simultaneous pipelay continues. The 300 m long
Allseas Solitaire is shown in Figure 3-9 performing simultaneous pipe loading and pipelay.
Figure 3-9: Allseas Solitaire – Dynamically Positioned Pipelay Vessel
For the purpose of this assessment it is assumed that all tie-in jumpers / spools associated with
the production pipelines will be installed from an OCV. This operation will require ROV / diver
support (depending on water depth) and the associated support vessels. The option of installing
jumpers / spools from an MSV may be reviewed by the EPC contractor following contract award.

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Subsea Isolation Valves (SSIVs)

SSIVs will be installed on each of the large diameter production pipelines in order to enable the
LPP to be rapidly isolated from the hydrocarbon inventory of the pipelines in the event of an
emergency event on the LPP. SSIV location is subject to a dropped object study, but it is
anticipated that all SSIVs [total of three (3)] will be located within 100 m of the LPP and will thus
lie within the LPP’s exclusion zone (500 m).
Each SSIV will feature an integrated protection structure which will also house the SSIV tie-in
points to enable diver assisted tie-ins. The structures will be installed onto the seabed with
mudmat foundations which are estimated at eight (8) m by eight (8) m, giving a total footprint per
SSIV of 64 m2. Total land take attributable to all three SSIVs is therefore 192 m2.
For the purpose of this assessment SSIVs are assumed to be installed from an OCV with diver
assistance during positioning and touchdown. Each SSIV will be installed in a single lift.
Installation operations will necessitate the usual support vessels in the form of an MSV (for
supporting diver operations), and supply and standby vessels.
MEG Supply Lines

Two (2) 6” MEG supply lines will be required in order to supply MEG from the LPP to the infield
SDU from where it will be routed to the wells via the infield umbilicals. The infield MEG SDU has
previously been discussed in Section 3.2.1.3.Each MEG supply line will feature a PLET at the
infield location and a valved diver assisted tie-in point at the LPP end to enable tie-in to the LPP
riser.
The MEG supply lines will be installed either as:

 Standalone lines laid onto the seabed within the transmission corridor; or
 As piggyback lines on the two (2) 18” DSM production pipelines.
Estimated land-take associated with standalone MEG supply pipelines is provided in Table 3-8
based on the standard outer diameter for 6” nominal bore pipe of 6.625”. There will be no land
take associated with the MEG supply lines (excluding PLETs) if they are installed in a piggyback
configuration on the DSM production pipelines.
Table 3-8: Incremental Land Take for Standalone MEG Supply Pipelines
Item Land Take (m2)
2x 6” Standalone MEG supply pipelines (117.5 km each) 39,545
Irrespective of the configuration selected, MEG supply lines will be installed from a DP Pipelay
Vessel (assumed to be the same as that used for production pipeline installation) in either an S-
lay or J-lay method. Final vessel selection and lay method will be decided following EPC
contractor award. If a piggyback configuration is selected then the MEG supply lines will be laid
simultaneously with the DSM production pipelines, thus reducing the overall installation duration.
Conversely if standalone MEG supply lines are selected, then it is assumed that pipelay will

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proceed at an average lay rate of three (3) km / day with an additional two (2) days allowed per
pipeline for start-up and lay down
Line pipe for the MEG supply lines will be fabricated in 12 m (or similar) sections at an out of
country fabrication yard and shipped to in-country port facilities for storage until they are required
onsite for installation. Pipeline sections will be transported from the in-country storage location to
the pipelay vessel by a pipelay supply vessel fitted with a pedestal crane.
MEG supply lines will be installed dry, with no anchoring required along the route. For the purpose
of this assessment, S-lay is assumed, however the incremental impacts of reverting to J-lay (either
as standalone or piggybacked) are not considered significant.
PLETs will be installed onto dedicated mudmat foundations while the valved diver assisted tie-in
points will sit directly on the seabed with no additional foundations (mudmat or piles).Each MEG
supply PLET [two (2) off total] will demand an estimated subsea land take of 36 m2.
Tie-in jumpers will be required at the deepwater end to make the connections between the
deepwater PLETs and the MEG SDU. Connections around the LPP will be made with tie-in
spools.
Each MEG supply line will require one (1) set of tie-in jumpers / spools. The deepwater MEG
jumpers will be of flexible construction with diver-less connections while the shallow water tie-in
spools will be of rigid construction with diver assisted connections. Wall thickness of jumpers and
spools will be as per that determined by design.
For the purpose of this assessment, jumpers are assumed to be installed from an OCV; however,
it is possible that an MSV may have the required crane capacity (this will be confirmed by the
EPC contractor following contact award). Should an MSV be used in place of an OCV, this will
reduce vessel presence and emissions arising from this activity. Deepwater jumper installation
will require ROV support, while shallow water spools will necessitate diver assistance. Support
vessels in the form of an MSV (to support ROV / diver operations), a supply and a standby vessel
will be required.
Primary Umbilical
The primary umbilical from the LPP to the infield controls distribution unit will be of an
electrohydraulic design. This will run parallel to the transmission pipelines, and like the pipelines
will not be trenched or buried.
The primary umbilical will be constructed at an out of country location in two (2) lengths. These
are; a 60 km section from the LPP to an intermediate UTA, and a 57.5 km section from a second
intermediate UTA to the infield Controls SDU. UTAs will be installed on mudmat foundations with
a seabed take of approximately 22 m2 each. The two (2) intermediate UTAs will be joined with
hydraulic and electrical flying leads. The Controls SDU will be installed in close proximity to the
MEG SDU and will utilize a mudmat foundation, thus resulting in an estimated land take of 97 m2.

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The umbilical will consist of a number of elements for the purpose of conveying control fluid and
chemicals, transmitting electrical currents, and protection from impacts and corrosion. The total
diameter of the umbilical is expected to be approximately 160 mm giving a total land take over
the length of the umbilical (117.5 km) of approximately 19,041 m2, increasing to 19,182 m2 when
the UTAs and SDU are considered.
The primary umbilical will be installed onto the seabed by reel lay from an OCV; such a vessel
will also be capable of installing the UTAs and SDU from on-deck cranes as required. An example
OCV that may be used for this work is the BOA Sub C as shown in Figure 3-10.
Figure 3-10: BOA Sub C – Offshore Construction Vessel
An average lay speed of 9.6 km / day is considered feasible for this type of flexible lay operation.
During installation all steel tubes will be liquid filled (either with MacDermid OceanicHW540P or
MacDermid Oceanic SST5007) to prevent seawater ingress and damage due to installation
stresses. The planned umbilical has a total of 17 cores as detailed in Table 3-9.

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Table 3-9: Primary Umbilical Cores
Core No Service Size (ID) Notes1
1-4 4x Power Supply 25 mm2 (each) No Shield / Armor
5-6 3x Fiber Optics Cable 16 way (each) Armored
8-9 2x LP Hydraulic 1” (each) Installed HW540P filled
10-11 2x HP Hydraulic ½” (each) Installed HW540P filled
13 Auxiliary 1” Installed SST5007 filled
14-15 2x Methanol 1” (each) Installed SST5007 filled
16-17 2x Spare 1” (each) Installed SST5007 filled

“MacDermid Oceanic HW540P” and “MacDermid Oceanic SST5007” respectively. Final chemical selection will be made by
the EPC contractor.
SSIV Umbilical and UTA

A short length (approx. 100 m) of umbilical will run from the LPP to a dedicated SSIV UTA in order
to provide hydraulics and services to the SSIVs on the production pipelines. The UTA will lie within
the LPPs marine exclusion zone.
The SSIV umbilical will feature a combination of ½” ID tubes, electrical conductors and 8-way
fiber optic cables. The ½” ID tubes will be configured so as to allow a closed loop controls system
to be implemented on the SSIVs whereby any hydraulic fluid discharged from the valve actuators
will be routed back to the LPP topsides as opposed to vented to the surrounding marine
environment. A closed loop system is feasible for this section of infrastructure due to the proximity
to the LPP, relatively shallow water depth at the SSIVs, and limited function of the SSIV umbilical.
Preliminary calculations indicate an external diameter of approximately six (6) inches (152 mm)
for the SSIV umbilical.
The land take associated with the SSIV UTA is estimated at 21.7 m2 (as per all other UTAs). The
land take directly associated with the length of umbilical is conservatively estimated at
15.2 m2based on an umbilical length of 100 m.
The SSIV umbilical and its associated UTA is anticipated to be installed from the same OCV to
be used to lay the primary umbilical running from the LPP to the infield facilities. Installation will
be completed with diver assistance, supported by an MSV and the same Supply and Standby
vessels anticipated for all construction operations. Installation of tie-in flying leads (from the SSIV
UTA to the SSIVs) is expected to utilize the same marine spread, with the exception of the OCV
which will not be required for this work.

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3.2.2.2 Pre-Commissioning and Commissioning Methodology

Transmission facilities will undergo various pre-commissioning and commissioning activities
depending on their function. These are detailed in the following sections based on typical pre-
commissioning and commissioning activities, these will be finalized during future detailed design.
The project schedule (provided in Figure 3-3) indicates that all subsea facilities will require pre-
commissioning and commissioning during H2 2019. This is reliant on the project progressing as
currently expected and is subject to change depending on project progress. Further definition of
anticipated pre-commissioning and commissioning dates will be determined during the detailed
engineering phase of the project.
Preliminary estimates of pre-commissioning and commissioning durations associated with the

transmission facilities are presented in Table 3-12.
Pipelines
Typically, rigid pipelines (production and MEG) require cleaning, gauging, hydrotesting, and
dewatering to prepare them for operational service. Additionally production pipelines are typically
dried to remove any remaining water. Cleaning, gauging and hydrotesting are pre-commissioning
activities, while dewatering and drying are considered commissioning activities.
The general pipeline pre-commissioning and commissioning philosophy to be applied to the rigid
transmission pipelines is:
 Pre-commission all pipelines prior to tie-in jumper / spool installation by:
o Free flooding all rigid pipelines with treated seawater from the deepwater PLET to the
LPP end; and,
o Cleaning, gauging and hydrotesting all rigid pipelines from the LPP end (subsea pig
launch) to the deepwater PLET (subsea pig receive).
 Commission production pipelines prior to jumper installation by:
o Dewatering and drying the lines with a dewatering pig train (launched subsea at the
LPP end and received subsea at the deepwater PLET) driven by compressed
nitrogen; and
o Purge and pack the production lines with nitrogen. Packed nitrogen will be used for
later commissioning activities of jumpers, manifolds and infield flowlines.
 Install production pipeline jumpers / spools and leak test connections. Dewater and purge
jumpers with nitrogen from the pipelines; and
 Commission the MEG pipelines following jumper installation by circulating MEG from the
LPP topsides (with the assistance of a commissioning vessel) down one pipeline, through
a crossover connection at the deepwater end and back to the LPP. MEG supply lines will
be left MEG filled ready for start-up.

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All water used for either flooding or hydrotesting of pipelines will be filtered and chemically treated
prior to use to protect the pipeline materials in the event of a commissioning delay. Indicative
chemicals to be used for this purpose are:
 Roemex RX5227: Combined oxygen scavenger, corrosion inhibitor and biocide – typically
dosed at 1,000 ppm; and
 Roemex RX9025: Leak tracer dye – typically dosed at 50 ppm.
Both of these chemicals are classified as Gold chemicals under the OCNS which indicates that
they present a relatively low hazard to the environment.
Pipeline cleaning and gauging will result in the discharge of the initial fill of flooding water and its
associated chemicals. Residual oils and soluble material on the internal pipeline surfaces will be
discharged with the chemically treated flooding water during the cleaning operation.
Dewatering and drying of the production pipelines will result in the discharge of chemically treated
seawater (used for hydrotesting) at the deepwater PLET. Additionally, small volumes of MEG will
likely be discharged during this operation.
Dewatering of the MEG pipelines will be performed as a round trip operation and as such
chemically treated hydrotest water will be produced at the LPP location. This water will be
discharged locally at the LPP, subject to obtaining the necessary permits and approvals.
In addition to those discharges associated with cleaning, gauging, and drying, there will be small
volume discharges of MEG immediately following jumper installation. This is associated with the
flushing of jumpers to prevent seawater corrosion or biogenic growth. The discharge of MEG is
estimated at 10 m3 per jumper.
Table 3-10 provides details of the environmental releases during pre-commissioning and
commissioning operations associated with the transmission pipelines (production and MEG).

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Table 3-10: Infield Pre-commissioning and Commissioning Releases
Pre-commissioning
Volume
(m3)
MEG Discharge associated with jumper
Deepwater MEG PLETs MEG 20
flushing for two (2) MEG supply jumpers.
Displaced flood water containing a cocktail of:
Chemically Treated
Deepwater MEG PLETs 4,150 a) RX5227 (or equiv.) at 1000 ppm;
Seawater (Flooding)
b) RX9025 (or equiv.) at 50 ppm.
MEG Discharge associated with jumper
Deepwater Production PLETs MEG 30
flushing for three (3) production jumpers.
Displaced flood water containing a cocktail of:
Chemically Treated
Deepwater Production PLETs 60,450 a) RX5227 (or equiv.) at 1000 ppm;
Seawater (Flooding)
b) RX9025 (or equiv.) at 50 ppm.
Commissioning
Volume
(m3)
Chemically Treated
Displaced hydrotest water containing a
Deepwater Production PLETs Seawater 60,450
cocktail of:
(Hydrotest)
a) RX5227 (or equiv.) at 1,000 ppm;
Chemically Treated b) RX9025 (or equiv.) at 50 ppm;
LPP
Seawater 4,150
(from MEG pipelines) c) Low volumes of MEG.
(Hydrotest)
Pre-commissioning and commissioning activities on the transmission pipeline system will be

supported by ROVs launched and controlled from a surface based MSV.
In order to minimize the environmental impact of hydrotest discharge the discharge ports on
PLETs will be designed to direct discharges vertically upwards to prevent seabed disturbance or
scouring.
Disposal of the hydrotest water to the marine environment will be subject to discussions with
MoEP and obtaining the appropriate permits and approvals.
Primary Umbilical
Pre-commissioning and commissioning activities for the primary umbilical will involve pressure
testing, displacement of storage fluid and functionality checking. All of these activities will be
performed in conjunction with analogous commissioning activities on the infield umbilicals.
Pressure testing will be performed from an MSV or dedicated commissioning vessel located
adjacent to the LPP. Pressure testing will be performed as per standard hydrotest procedures,
however the test fluid will be that present from umbilical installation (either MacDermid Oceanic
HW540P or MacDermid Oceanic SST5007) which is water based.

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Following pressure testing all cores filled with storage fluid (MacDermid Oceanic SST5007) will
be displaced with the relevant service chemical. This will be performed from the LPP with MSV
or commissioning vessel support as required. During this operation the inventory of storage fluid
will be discharged from all non-hydraulic control cores, with the exception of the two (2) spare
cores which will be left under storage conditions. Details of the primary umbilical cores to be
displaced are provided in Table 3-11.
Table 3-11: Infield Umbilical Cores for Pre-Commissioning Operations

Size Inventory
Core No Service Notes1
(ID) (m3)
12 Scale Inhibitor ½” Installed SST5007 filled 14
13 Auxiliary 1” Installed SST5007 filled 58
14 Methanol 1 1” Installed SST5007 filled 58
15 Methanol 2 1” Installed SST5007 filled 58
Total 188
“MacDermid Oceanic HW540P” and “MacDermid Oceanic SST5007” respectively. Final chemical selection will be made by
the EPC contractor.
The intention is that umbilical storage fluid from the primary umbilical will be discharged at the
infield Controls SDU. Subsequent to displacement of the primary umbilical cores the infield
umbilical cores will be displaced to the wellheads as per Section 3.2.1.3. An alternative method
of storage fluid displacement is to route this fluid into the flowlines and production pipelines for
displacement back to the LPP. A decision on the preferred routing of displaced fluid will be made
in future phases of design.
The total discharge of MacDermid Oceanic SST5007 at the infield SDU is estimated at 188 m3.
This operation will be subject to obtaining dedicated permits from MoEP.
Following pressure testing and storage fluid displacement, the primary umbilical will be function
tested in conjunction with the infield umbilicals to complete commissioning activities. During
function testing there will be low volume discharges of hydraulic fluid at multiple infield locations
(See Section 3.2.1.3); however there will be no discharges from the primary umbilical.
SSIV Umbilical and Controls

The SSIVs and associated controls infrastructure will be designed based on a closed loop controls
system. As such, during commissioning all fluids displaced from the umbilical will be received on
the LPP where they will be processed, re-used or discharged in a manner which is appropriate to
their environmental toxicity.
Pre-commissioning and commissioning of the SSIV umbilical will follow the same procedure as
that for the primary umbilical, but with no discharges at the subsea infrastructure. No incremental

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vessel time is considered in relation to pre-commissioning and commissioning of the SSIV

umbilical as this is expected to occur simultaneously to that of the primary umbilical.
3.2.2.3 Support Vessels for Pipeline Installation, Tie-in and Commissioning

The transmission facilities installation, tie-in and commissioning activities will require support from
a variety of vessels including:
 DP Pipelay Vessel (e.g. Allseas Solitaire);
 Pipe Supply Vessel - to transport pipe sections between the in-country storage site and
the Pipelay Vessel;
 OCV (e.g. BOA Sub C) - to install subsea structures, umbilicals and tie-in jumpers;
 ROV / MSV (e.g. Siem Stingray) - to support pipeline and structure installation, and
perform commissioning activities. Where diver assisted operations are to be used the MSV
is assumed to act as the dive support vessel for this work; and
 Standby and Supply Vessels.
In addition, weekly crew changes for the pipelay vessel are expected to be performed by
helicopter, nominally a Sikorsky-61N.
Table 3-12provides an estimate of the vessel use based on the installation campaign described
above and assumes that the MEG supply lines are installed as per the piggyback configuration
being considered. Table 3-13 provides the incremental vessel use associated with installing the
MEG supply lines as standalone lines.
Fuel use figures are estimated based on typical vessels available within each category. Fuel used
is assumed to be marine diesel for water based vessels and Jet A for helicopter use.
Appendix D details the assumptions made when calculating fuel use.

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Table 3-12 Vessel Use for Pipeline Installation, Pre-Commissioning and Commissioning
Fuel
Working Schedule Total Fuel
Vessel No of vessels Consumption
period (days) Activity Use (Te)
(Te / day)
DP Pipelay Vessel 1 123 1,2 130 15,990
Pipe Supply Vessel 1 123 1,2 15 1,845
1 50 3,4 51 2,550
Vessel
1 242 All 26 6,292
Vessel with ROV
Standby Vessel 1 242 All 2.4 580.8
Supply Vessel Note 1 2 242 All 12 2,904
Helicopter 1 35 hrs 1,2 0.4 Te / hr 14.0
Total 30,175
Schedule Activity:
Activity 1: DSM Pipelines (inc. piggy backed MEG lines) and PLET Installation (82 Days)
Activity 2: REM Pipeline and PLET Installation (41 days)
Activity 3: Primary and SSIV Umbilical and Structures Installation (19 days)
Activity 4: SSIV Installation, Pipeline and Umbilical Tie-ins (31 Days)
Activity 5: Production System Pre-Commissioning and Commissioning (30 Days)
Activity 6: MEG System Pre-Commissioning and Commissioning (16 Days)
Activity 7: Controls System Pre-Commissioning and Commissioning (23 Days)
Notes:

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Table 3-13: Incremental Vessel Use for Standalone MEG Pipeline Installation, Pre-
Commissioning and Commissioning
Fuel
Working Total Fuel Use
Vessel No of vessels Consumption
period (days) (Te)
(Te / day)
DP Pipelay Vessel 1 82 130 10,660
Pipe Supply Vessel 1 82 15 1,230
1 0 51 0
Vessel
1 82 26 2,132
Vessel with ROV
Standby Vessel 1 82 2.4 197
Supply Vessel Note 1 2 82 12 984
Helicopter 1 23 hrs 0.4 Te / hr 9.2
Total 15,212
Notes:
3.2.3 Other Infrastructures

Aside from those facilities detailed in Sections 3.2.1 and 3.2.2 for infield and transmission
purposes, there will be no additional production or controls infrastructure installed upstream of
the LPP. However, in order to facilitate pipeline / umbilical crossings of seabed features the
following will be developed:
 Channel crossings; and
 Pipeline / Cable crossings.
The above are considered in the following sections.
3.2.3.1 Channel Crossings

There are three (3) substantial seabed channels that must be crossed by the transmission
pipelines in order to connect the Infield Gathering Manifold to the LPP. The channels identified lie
between the Infield Gathering Manifold in the west, and the Tamar production system in the east
and are shown in Figure 3-11.The three (3) channels referred to above are:
 Channel D;
 Channel E; and
 The Tamar Channel.

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In addition, the transmission pipelines will cross the poorly defined channel F which lies between
channel E and the Tamar channel. Further channels that have not been identified at this stage
may also require crossing by the transmission pipelines.
Figure 3-11: Seabed Channels for Pipeline Crossings
Based on the three (3) channels identified above, there will be a total of 18 channel crossings if
the MEG supply lines are installed as standalone lines, or 12 crossings if they are installed as
piggyback lines on the 18” DSM production pipelines.
Crossing of channels requires dedicated engineered solutions in order to minimize pipeline

stresses as a result of free-spans and their associated hydrodynamic affects.
A range of concepts are being considered to enable channel crossing, these are outlined below:
Increased Wall Thickness

The simplest option for mitigating stresses arising from free-spans is to increase the pipeline wall
thickness around these areas to increase the maximum stress capacity of the line pipe. The
effectiveness of this option may be limited to shorter free-spans where spanning loads (either

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static or dynamic) are not so great. Implementation of this option will not pose any incremental
environmental impacts.
Increased Pipelay Tension

Where static or dynamic loads arising from free-spans lead to unacceptable pipeline strain
(deformation) this may be effectively mitigated by increasing the tension on the pipeline during
the pipelay operation. Utilizing increased lay tension ensures the pipeline is pulled tight across
the free-span, thus minimizing the deflection in the unsupported section. Where this option is
suitable, it will not pose any incremental environmental impact.
Pipeline Buoyancy and Strakes

Where a free-span cannot be avoided, and the resultant pipeline stresses lead to unacceptable
pipeline deformation, distributed buoyancy modules may be installed directly onto the pipeline at
the span to reduce static stresses and resultant strains. Further, where vortex induced dynamic
stresses are present, additional vortex shedding features (strakes) may be installed to reduce the
impact of these dynamic loads.
Should this option be implemented there is no perceived incremental environmental impact.
Seabed Dredging
Where none of the options identified above are either sufficient to mitigate pipeline stresses, or
attractive from a project stand-point, pre-lay excavation and dredging may be implemented to
alter the seabed bathymetry at the channel crossing location. This option consists of physically
moving seabed sediment to create a dredged installation corridor at the channel crossing location.
This will allow the pipelines to cross the channel while minimizing, or removing entirely, the
number and length of free-spans.
Dredging and excavation will be performed in advance of pipelay and it will be up to the DP
Pipelay Vessel to ensure pipelines are laid into the dredged corridor(s) where they cross the
identified seabed channels.
A portion of the excavated material may be used to infill low-points around the crossing, while the
majority will be disposed of at a designated area offshore. Implementation of a deepwater
dredging solution will result in:
 Increased water turbidity local to the excavation and disposal sites;
 Deposition of fine sediments local to the excavation and disposal sites;
 Seabed coverage at the disposal site due to volume of material to be relocated; and
 Modification to the seabed bathymetry and local hydrodynamics.

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The aspects identified above are expected to be of a relatively concentrated nature without a
substantial area of impact. As such only the environment local to the dredging, and disposal sites
may be expected to be impacted.
3.2.3.2 Pipeline Crossings

The selected corridor routing for the transmission pipelines and the primary umbilical requires the
aforementioned infrastructure to cross the existing Tamar production system and the IC1
Segment 8 cable system. The Tamar production system crossing lies approximately 45 km from
the Infield Gathering Manifold, and 15 km south-east of the Tamar production manifold, while the
IC1 Segment 8 cable runs approximately 2 km west of the LPP. The approximate locations of
these existing infrastructures, and their planned crossings, are shown in Figure 3-12.
Figure 3-12: Existing Infrastructure and Crossing Locations
The existing Tamar infrastructure that must be crossed consists of:

 Two (2) by 16” production pipelines running between the Tamar Manifold and the Tamar
Platform;
 Two (2) by 4.5” MEG supply lines running between the Tamar Platform and the infield
infrastructure, these were installed as piggyback lines on the 16” production pipelines; and

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 Two (2) primary umbilicals running between the Tamar Platform and the infield
infrastructure.
All of the above lie in a single corridor which is approximately 150 m wide. The IC1 Segment 8
cable system is single cable bundle which may be crossed by each pipeline in a single span.
Crossing of the above infrastructure will be by way of engineered crossings consisting of support
structures located either side of the infrastructure to be crossed. The Leviathan infrastructure will
be subsequently laid over the support structures to allow it to free-span over the crossed
infrastructure without contact. This concept has previously been applied on the Tamar project to
enable crossing of subsea cables.
The process for infrastructure crossing will be as follows:

1. Locate existing infrastructure using ROV visual or tone monitoring, existing as-built
schematics and admiralty charts. Subsequently mark with buoys from the ROV;
2. Place crossing structures either side of infrastructure and secure as determined by seabed
conditions;
3. Install Leviathan infrastructure across structures and existing infrastructure while maintaining
continuous visual contact with an ROV to ensure no contact is made between infrastructures
during installation;
4. Secure Leviathan infrastructure to the crossing structures; and
5. Perform an as built survey and document condition for future reference.
In order to maintain separation, each Leviathan transmission pipeline will require a dedicated set
of crossing structures. Where a crossing is developed to support the Leviathan umbilical, this will
be designed so as to provide sufficient support to ensure clearance of the crossed infrastructure.
The total number of pipeline crossings is dependent on the final installation method selected for
the 6” MEG pipelines. If these pipelines are installed as standalone pipelines within the Leviathan
transmission corridor, then the total number of crossings will be 24 (four (4) per line). However, if
a piggybacked configuration is selected, the MEG pipelines will be piggybacked onto the 18” DSM
production pipelines, and the number of crossings will be reduced to 16.
The crossing support structures will be constructed predominantly from steel and will be designed
to ensure that they remain in place and continue to support the Leviathan infrastructure
throughout the projects lifespan. Based on the analogous structures used during the Tamar
development project, each structure will have the approximate dimensions of nine (9) m x three
(3) m (W x L) giving a land take per structure of approximately 27 m2. The net effect of pipeline
crossings on overall seabed land take is considered negligible as although the crossing structures
represent additional footprint, they act to elevate the pipelines away from the seafloor and thus
reduce the land take associated with the pipelines.
Crossing support structures will be installed from either the MSV or the OCV with ROV assistance
during placement. This will be performed prior to the DP Pipelay Vessel reaching the crossing
location to minimize the holding time during pipelay.

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Future platform and pipeline operations are beyond the scope of this document and will be
addressed in the Noble Energy operations and maintenance plans and procedures.
3.2.4 Leak Detection

The production system for full field development of the Leviathan Field will feature in excess of:
352.5 km of subsea production pipelines; 235 km of MEG supply lines; and 117.5 km of
electrohydraulic umbilicals. Maintaining system integrity of infrastructure throughout the
operations phase is critical to managing the environmental impact of the project. The following
measures will be implemented to monitor subsea system integrity:
 Continuous monitoring of arrival pressure and flowrate of production fluids at the LPP to
aid in rapid detection of a substantial loss of containment in the subsea production system.
A low pressure trip on the LPP inlet facilities will detect any major breach in the pipelines
and initiate production shut-down by isolating the system at the wellheads;
 A Production Management System (PMS) will be implemented which will receive and
process subsea sensor readings from the infield infrastructure. This will be capable of
performing a continuous mass balance on the production system and will thus detect
potential leaks;
 Continuous monitoring of MEG pumping rates and inventory levels on the LPP to aid in
rapid detection of a substantial loss of containment in the subsea MEG system;
 Continuous monitoring of production chemical consumption rates to aid in detection of
loss of containment from umbilical cores;
 Continuous monitoring of hydraulic fluid consumption, with any continuous use indicating
a loss of containment from the hydraulic cores within the umbilical;
 Periodic visual surveys, using ROVs, of the production system to identify signs of
infrastructure damage or leaks; and
 A pipeline integrity assurance program will be implemented in accordance to Noble
Energy’s Global Integrity Management Program. This is based on a risk based approach
and will consider operational data from other systems operating under analogous
conditions.
3.2.5 Sources of Discharge into the Sea
Discharges into the marine environment may impact water quality with the potential for negative
impacts on local marine ecosystems. Discharges to sea in Israeli economic waters during the
construction and operations phases of the Leviathan Field development are detailed in the
following sections. Accidental releases with the potential to arise as a result of the project are
considered within Section 4.2.
3.2.5.1 Construction
During the construction phase of the Leviathan project the primary sources of discharges to the
marine environment will be marine vessels associated with installation and commissioning of the
subsea infrastructure. Vessel discharges will include sanitary waste, grey water, organic waste,

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and deck runoff. Additionally ballast and bilge water will be discharged at various times throughout
the installation campaign. All discharges will be performed in compliance with relevant
international and local regulations.
Based on data collected during the drilling of the Leviathan 4 well (Noble Energy Mediterranean
Ltd, 2016a) domestic effluent generation rates are estimated on a per person basis and are
provided in Table 3-14.
Table 3-14: Domestic Effluent Generation Rates (per person)

Discharge Type Average Daily Rate (liters/day-person)
Sanitary Water 72
Grey Water 250
Organic Food Waste 6
During subsea facilities installation a range of marine vessels will be utilized. The largest of these
is expected to be the DP Pipelay Vessel which, based on Allseas Solitaire, will have
accommodation for up to 420 persons. This is considered representative as this vessel has
previously been utilized on the broadly analogous Tamar development. Other vessels with
substantial personnel capabilities include the MSV and the OCV, both of which are likely to have
accommodation facilities in excess of 100 POB. Additional personnel located offshore will include
those present on smaller vessels, such as supply and standby vessels, which may be expected
to house between 20 and 40 POB each.
Based on all vessels being fully manned and in operation simultaneously, the peak offshore man
count during the Leviathan development phase is estimated at approximately 700. The peak
domestic effluent rates for a total compliment of 700 offshore workers have been estimated and
are presented in Table 3-15.
Table 3-15: Peak Domestic Effluent Rates (700 Persons Offshore)

Discharge Type Average Daily Discharge (m3 / day)
Sanitary Water 50.5
Grey Water 175
Organic Food Waste 4.3
Discharges of Bilge, Ballast and deck water run-off cannot be quantified at this stage; however all
of the above will be discharged in compliance with MARPOL 73/78 and Barcelona Convention
requirements.
Additional discharges will arise from fluid discharge at the seabed during commissioning of
pipelines and control systems. These have previously been quantified in Section 3.2 and are not
discussed further in this section.
Discharges to the marine environment associated with the construction and commissioning of the
LPP are not within the scope of this assessment, however these will occur. Discharges arising as

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a result of construction / commissioning operations on the LPP will occur in the shallow water
(approx. 86 m) immediately surrounding the LPP. Any discharges associated with the LPP will be
minimized where practicable and will be subject to obtaining the relevant discharge permits prior
to discharge occurring.
3.2.5.2 Operation
During the operations phase of the Leviathan development there will be no continuous discharges
into the marine environment from the subsea production system (upstream of the LPP). This is a
result of the closed loop nature of the production system, with no requirement for marine vessel
support dedicated to production system operation. Discharges arising from the LPP are
specifically excluded from the scope of this assessment.
Intermittent discharges to the marine environment will occur as a result of operation of

hydraulically actuated valves on the infield infrastructure. Hydraulic fluid will be vented from these
valves when they are allowed to move to their fail safe position, but is not anticipated when they
are actuated in the other direction (from fail safe). As such a complete valve cycle (open to close
to open, or vice versa) will result in a single discharge event.
The approximate discharge volume associated with a single discharge event from all infield valves
(manifold and Xmas tree mounted) is an instantaneous release of 261 liters based on the initial
eight (8) development wells. Of this approximately 117 liters is attributable to valves on the Infield
Gathering Manifold.
There will be no discharges of hydraulic fluid from the production pipeline SSIVs (located in close
proximity to the LPP) as the controls system for this equipment will be of a closed loop
configuration with all vented fluids routed to the LPP for treatment, re-use or discharge as
appropriate.
Actuation of subsea valves is only anticipated to occur during up-set operations or to enable
maintenance and field shutdown. As such it has been nominally assumed that all subsea valves
will, on average, be cycled twice per year. This will result in an annual discharge of hydraulic fluid
(MacDermid Oceanic HW540P) of 522 liters. This discharge will be in the deepwater infield area
(as per common industry practice) and will be distributed across the eight (8) well locations and
the single Infield Gathering Manifold location.
Non-routine discharges occurring during Leviathan Field development will include any discharges
arising from intervention activities and associated vessel presence. Any such operations will be
subject to dedicated assessments and are not considered further within this assessment.
Discharges to the marine environment associated with the operation of the LPP are not within the
scope of this assessment, however these will occur. Discharges arising as a result of operations
on the LPP will occur in the shallow water (approx. 86 m) immediately surrounding the LPP. Any
discharges will be treated to at least the most stringent applicable discharge quality and will be
minimized where practicable. All discharges will be logged and subject to obtaining the relevant
discharge permits.

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3.3 Noise Hazards

Noise in the offshore environment may arise from either surface or underwater sources and can
impact a wide range of fauna both physically and behaviorally. Noise is defined as unwanted or
potentially harmful sound.
Noise sources occurring in Israeli waters associated with the Leviathan development have been
identified for the construction and operations and are detailed in the following sections.
3.3.1 Construction Noise Sources

Note that noises arising from drilling activities, particularly underwater noise, is out-with the scope
of this assessment. Information pertaining to drilling activities is available in the Leviathan drilling
EIA (Noble Energy Mediterranean Ltd, 2016a).
Underwater Noise Sources

A large number of vessels will be required over the course of the construction phase which will
generate underwater noise levels greater than the background levels. The main sources of
underwater noise during the construction phase will be associated with the propulsion systems of
the vessels required for these activities. Supply and standby vessels will be required throughout
the construction phase, while other vessels will only be on site during specific operations. For
example, the pipelay vessel will only be present during the laying of flowlines and pipelines.
Table 3-16 presents the total operational duration of all vessels expected to be required during
construction phase (installation, pre-commissioning and commissioning) assuming stand-alone
MEG pipelines. These vessels will contribute to underwater noise.
Table 3-16 Installation, Construction and Pre-commissioning Vessel Requirements
Total days on
Vessel Operations No of vessels
site
Pipelay Vessel 1 223 days
Pipelay Supply Vessel 1 223 days
Offshore Construction Vessel 1 110 days
Multipurpose Support Vessel with ROV 1 408 days

Standby Vessel 1 408 days
Supply Vessel 2 408 days
Helicopter 1 63 hours
Marine noise associated with vessels is characterized by low frequency sound from engine
vibrations, broadband sound generated by hydrodynamic flow over a ship’s hull and higher
frequency tonal noise associated with propeller action and cavitation (Hildebrand, 2009). Noise
levels tend to be higher for larger vessels and will increase with increasing vessel speed.

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While noise data is not available for specific vessels identified as representative of those that will
be used on the Leviathan project, published sound power level spectrum data for typical vessels
of a similar type and size is available. Figure 3-13 presents typical sound power level spectra for
standby / guard vessels, MSV, and pipelay vessels.
Figure 3-13: Installation, Commissioning and Pre-commissioning Vessel Underwater

Noise Characteristics
190
180
Third octave band source level (dB re 1 µPa‐m)
170
160
150
140
130
120
1 10 100 1,000 10,000 100,000
Frequency (Hz)
Guard vessel (modelled; Breeding et al., 1996) MSV / supply vessel (Wales & Heitmeyer, 2002)
Pipelay (Hannay et al., 2004)
Background levels of ambient noise in the low range spectra (10 – 300 Hz) throughout the world’s
oceans is dominated by anthropogenic activities, primarily large scale shipping. Low frequency
noise below 300 Hz shows very low attenuation over substantial distances and can result in
significant ocean / basin wide background noise levels, even when the measurement site is tens
to hundreds of kilometers from the nearest area shipping activity. As a result ambient noise levels
in the world’s oceans in the low frequency band (that most associated with anthropogenic activity)
range from 80 to 90 dB (re 1 μPa), although this may be expected to be higher in basins close to
heavy shipping channels.
Owing to its proximity to the Suez Canal (approx. 200 km) and the shipping lanes associated with
it, background noise in the Levantine basin may be expected to be greater than those typically
found in the world’s oceans. Potter et al. (1997) measured ambient noise levels in shallow water
(i.e., 4 to 5 m depth) offshore Haifa. At low frequencies (a few hundred hertz or less), the ambient
noise spectra exhibited characteristics of medium to heavy shipping noise. As such a background
noise level of 100 dB (re 1 μPa) is considered in this assessment.
Figure 3-14and Figure 3-15show the propagation of underwater noise from the installation vessels
anticipated to be used for pipelay activities associated with the Leviathan Field development.
Figure 3-14is based on operations in the deepwater environment, while Figure 3-15utilises the
same basis but applied to the environment close to Israeli territorial waters. These show that
sound generated in either of these environments as a result of Leviathan development activities

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will show rapidly decreasing sound pressure (as measured in dB) as it propagates across the
environment, until it reaches the assumed background level of 100 dB (re 1 μPa).
Observable incremental noise as a result of the Leviathan Field development activities is expected
to be limited to a radius of approximately 7 km in the deepwater and 12 km in the shallow water.
The majority of this area is limited to an incremental noise level of less than 10 dB (re 1 μPa).
Figure 3-14: Modelled Propagation of Underwater Sound during Pipelay (deep water)

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Figure 3-15: Modelled Propagation of Underwater Sound during Pipelay (shallow water)
Atmospheric Noise Sources

Atmospheric noise sources associated with the construction phase of the Leviathan project will
primarily arise from three (3) sources:
1. Vessel propulsion systems;
2. Construction activities on board vessels; and
3. Intermittent helicopter flights to and from construction vessels.
The scope of this Production EIA extends from the LPP (10 km offshore) to the infield
infrastructure approximately 125 km offshore. As such atmospheric noises arising from the project
are not expected to significantly impact onshore communities. However it should be noted that
periodic onshore disturbances will occur as a result of helicopter flights transferring personnel
to / from onshore locations to the construction vessels. Transfers are expected to occur once a
week during the construction phase and will present only a brief increase in background noise.
Further, to minimize the impact of these flights, all scheduled flights will be scheduled during day-
time hours and will avoid low flying over populated areas.
Any emergency helicopter flights will be routed by the most direct, approved flight path from their
onshore location.
3.3.2 Operational Noise Sources

Following field start-up there will be no vessels or surface facilities permanently on station and
dedicated to the operation of the subsea production system (the LPP is excluded from this
assessment). As such continuous underwater noise sources will be limited to low level noises

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associated with multi-phase flow of production fluids through the production system. During
normal operation the velocity of gas flowing through the production system will be maintained
below conventional limits to minimize pipeline erosion and protective scale stripping. Maintaining
velocities below these limits will also act to minimize subsea noise production.
No atmospheric noise sources directly related to the operation of the subsea production system
are expected during the operations phase.
3.4 Hazardous Materials

Hazardous materials are controlled in Israel by the “Hazardous Substances Law 5753-1993” and
its subsequent revisions. This defines “Hazardous Substances” as “a hazardous material or
harmful chemical” and is defined as:
 Hazardous material – Any substance identified under Schedule Two of law 5753-1993 be
it in its simple form or mixed / blended into other substances.
 Harmful Chemical – Any substance identified under Schedule One of law 5753-1993 be it
in its simple form or mixed / blended into other substances.
In general, hazardous materials include the following:
 Substances which contain prescription medicines;
 Substances which have a flash point of less than 55°C;
 Any material which contains components that are deemed to be any of:
o An oxidant;
o Toxic;
o Corrosive;
o Harmful;
o An Irritant;
o Carcinogenic;
o Infectious;
o Teratogenic;
o Mutagenic; or
o Ecotoxic.
3.4.1 Construction
At the current level of design the hazardous materials and quantities thereof to be used and
generated during the production system installation, pre-commissioning and commissioning
phases are not known. However, typical hazardous materials associated with offshore
construction and commissioning work include; fuel oil / diesel, oil based lubricants, organic
solvents, oil contaminated fabrics, medical supplies / wastes, and chemicals used to inhibit water
during hydrotest operations.

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Hazardous materials will be handled in accordance with company requirements and as a

minimum shall conform to national legislation. Where a hazardous material becomes a waste it
will be managed through the installation contractors Waste Management Plan (WMP), which itself
will be compliant with Noble Energy’s asset specific WMP, the requirements of which are laid out
in Noble Energy’s waste management program (Noble Energy Mediterranean Ltd., 2015).
Hazardous materials associated with the installation and commissioning phase of the project will
be assessed in detail during project detailed engineering when the EPC contractor has been
selected.
3.4.2 Operation
Throughout the Leviathan operational phase, hazardous materials will be present in the
production system as liquid and gaseous hydrocarbons. In addition, production chemicals
required to manage hydrate formation, pipeline corrosion and scale deposition are expected to
be classed as hazardous materials. Further, any solids produced (e.g. sand) from the production
wells will be hydrocarbon contaminated and should thus be considered a hazardous material.
During normal operations the Leviathan subsea production system (including chemical injection)
will be a closed system with no discharge to the marine environment. If a break of containment is
planned for any area of the production system, this will be subject to a dedicated planning and
permitting process which does not fall within the scope of this document.
Operational discharges of hydraulic fluid from the controls system are considered under
Section3.2.5.2.
3.5 Geological and Seismic Risk Assessment

As per the information presented in Chapter A, the Leviathan Field and the proposed development
infrastructure lie in what has historically been a geologically active area.
To ensure geological and seismic risks to the subsea production system are managed the
following engineering guidelines / standards will be applied during detailed design of the pipelines:
International Organization for Standards (ISO) 19901-2 shall be applied for the following
purposes:
 Estimating seismic load on the pipeline system outside of Israeli territorial waters;
 Estimating seismic load on foundations associated with the pipeline system outside of
territorial waters;
 Estimating seismic loads on pressurized components of PLETs and In Line Structures
(ILS) outside of territorial waters; and,
 Estimating seismic loads on foundations of equipment located within Israeli territorial
waters.

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Det Norske Veritas (DNV) standard DNV-OS-F101 shall be applied in order to estimate the
seismic response of the pipeline system outside of territorial waters when subject to seismic loads
as determined from ISO 19901-2. Guidelines from the Pipeline Research Council International
(PRCI), and the Multidisciplinary Center for Earthquake Engineering (MCEER) will be used as
appropriate;
DNV-OS-C101 shall be applied to determine limit states for foundation design associated with
infrastructure that is located outside of Israeli territorial waters;
ISO 19901-4 shall be applied to determine the seismic design criteria for foundations associated
with infrastructure that is located outside of Israeli territorial waters;
American Society of Mechanical Engineers (ASME) standard ASME B31.8 will be applied to
determine the seismic design criteria for PLETs and ILS associated with the pipeline infrastructure
outside of territorial waters;
Israeli Standard (SI) 413 will be used, in conjunction with the America Society of Civil Engineers
(ASCE) standards ACSE 7-05 and ASCE 7-10, to estimate seismic loads for the pipeline system
within Israeli territorial waters; and
Nederlandse Norm (NEN) standard NEN-EN 1594 shall be applied, in conjunction with PRCI /
MCEER guidelines to determine seismic design criteria for equipment foundations within Israeli
territorial waters.
3.6 Abandonment of the Field and Dismantling of the Infrastructure

The production life of the Leviathan Field is expected to be in excess of 30 years and as such
abandonment and decommissioning plans for the pipelines, umbilicals and infield structures will
not be developed prior to initial production. However, any future decommissioning plans / activities
will follow the general principles that all work will be conducted in a manner that is safe, does not
reasonably interfere with other users of the sea, and does not cause undue or serious harm or
damage to human, marine or coastal environments. Further, all activities will be completed in
accordance with the lease requirements associated with the Leviathan development, industry best
practice, applicable regulations in place at the time (including MoEP and MEWR requirements
and guidelines), and in compliance with industry-wide decommissioning requirements and
recommendations.

3-51

Levethian Project 07 - Chapter - C - Final

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Leviathan Field Production EIA

Chapter C – Description of Actions Stemming from Performance

3.0 CHAPTER C – DESCRIPTION OF ACTIONS STEMMING FROM

Client Doc. No: LPP-PM-NEM-EIA-PLN-0002

Figure 3-1 Leviathan Field Location in the Eastern Mediterranean

Client Doc. No: LPP-PM-NEM-EIA-PLN-0002

Development of the Leviathan Field is envisaged as a subsea tieback of approximately 117.5 km

Client Doc. No: LPP-PM-NEM-EIA-PLN-0002

Figure 3-2 Leviathan Development Overview

Client Doc. No: LPP-PM-NEM-EIA-PLN-0002

Client Doc. No: LPP-PM-NEM-EIA-PLN-0002

Figure 3-3: Leviathan Development Schedule

Client Doc. No: LPP-PM-NEM-EIA-PLN-0002

3.2 Description of the Application

The locations of Leviathan-3 through to Leviathan-10 are shown in Figure 3-4.

Figure 3-4: Map of Leviathan Production Wells for First Gas

Client Doc. No: LPP-PM-NEM-EIA-PLN-0002

Wellhead and Xmas Tree Installation

Commissioning of Xmas tree mounted valves is included under pre-commissioning and

Infield Facilities, Installation, Tie-in, Pre-Commissioning & Commissioning

Client Doc. No: LPP-PM-NEM-EIA-PLN-0002

Figure 3-5: Infield Production Infrastructure Schematic

The anticipated installation, tie-in, pre-commissioning, and commissioning activities associated

Client Doc. No: LPP-PM-NEM-EIA-PLN-0002

3.2.1.1 Support Vessels

Client Doc. No: LPP-PM-NEM-EIA-PLN-0002

No of Working period Schedule Fuel Consumption Total Fuel

DP Pipelay Vessel 1 18 1 130 2,340

Pipe Supply Vessel 1 18 1 15 270

Standby vessel 1 84 All 2.4 201.6

Supply vessel Note 1 2 84 All 12 1008

Helicopter 1 5 hrs 1 0.40 Te / hr 2.0

3.2.1.2 Infield Infrastructure and Installation

Infield Production Flowlines

Client Doc. No: LPP-PM-NEM-EIA-PLN-0002

Table 3-2: Infield Flowline and PLET Land Take

Description Location Wells Tied-in Land Take (m2)

Flowlines (22.5 km) Note 1 Distributed All 8,001

PLET - Single Infield Gathering Manifold Lev-3 90

PLET - Single Infield Gathering Manifold Lev-4 / Lev-8 90

PLET - Single Infield Gathering Manifold Lev-5 90

PLET - Single Infield Gathering Manifold Lev-6 / Lev-7 90

PLET - Single Infield Gathering Manifold Lev-9 / Lev-10 90

PLET - Single Lev-3 Lev-3 90

PLET - Single Lev-5 Lev-5 90

PLET - Twin Lev-4 / Lev-8 Lev-4 / Lev-8 120

PLET – Twin Lev-6 / Lev-7 Lev-6 / Lev-7 120

PLET - Twin Lev-9 / Lev-10 Lev-9 / Lev-10 120

Client Doc. No: LPP-PM-NEM-EIA-PLN-0002

Infield Tie-in Jumpers

Figure 3-6: Siem Stingray – ROV / Multipurpose Support Vessel

Client Doc. No: LPP-PM-NEM-EIA-PLN-0002

Infield Gathering Manifold

The Infield Gathering Manifold will have approximate dimensions of 10 m by 20 m (W x L) with a

Client Doc. No: LPP-PM-NEM-EIA-PLN-0002

Infield Subsea Distribution Unit – MEG

Infield Umbilicals and Flying Leads

Table 3-3: Infield Umbilical Cores

Client Doc. No: LPP-PM-NEM-EIA-PLN-0002