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Karish & Tanin – A Transformational Project in Israel
Energean Israel is the Operator of the Karish and Tanin leases, offshore Israel. The fields are world class assets with 2.2 TCF of natural gas and 31.8 million barrels of light hydrocarbon liquids independently audited 2P reserves plus 5.4 BCM of gas and 1.0 mmbls of liquids 2C resources. Moreover, NSAI has audited 2.94 TCF of gas plus 78.8 mmbls of liquids unrisked prospective resources.
According to a CPR produced by NSAI in June 2018, the Karish Field contains 282.2 mmboe 2P reserves plus 34.7 mmboe 2C resources (70% net to Energean).
Energean made Final Investment Decision for the development project in March 2018, after having signed 12 Gas Sales and Purchase Agreements for 4,6 BCM in total annually and secured financing for the project. The Karish main field will be the first asset to be developed in the Karish and Tanin blocks by the Group. Karish was selected as the initial development as it is the largest discovery, is expected to provide the highest yield of liquid per volume of produced gas and is the closest discovery to shore. The assets required to develop this field will be installed and commissioned by early 2021 with the intention of introducing a second source of gas supply into the Israeli market as soon as practicable.
TechnipFMC has been awarded a lump sum EPCIC Contract. Stena Drilling has been awarded the contract to drill three development wells plus optional wells into the Karish discovery during 2019.
The Company has decided to develop both the Karish and Tanin fields using an FPSO (Floating Production Storage Offloading) that will be installed 90 km offshore, making it the first FPSO ever to operate in the Eastern Mediterranean. The FPSO will have a gas treatment capacity of 800 MMscf/day (8 BCM/per annum) and liquids storage capacity of 800,000 bbls, which the Company believes provides a flexible infrastructure solution and, potentially the scope to expand output for potential additional projects.
First steel was cut on the FPSE in Cosco yard, in Zhousan, China on November 26, 2018. Keel laying took place successfully on 13th April 2019.
Capex for the Karish development (First Phase) is estimated at US$1.6 billion. Production from the field is expected to commence in Q1 2021.
The Karish and Tanin fields, approximately 40 km apart, are located in the north of Israel’s exclusive economic zone (EEZ).
Both fields are part of the prolific Early Miocene Tamar Sands play. The fields are located north of the Tamar field, in water depths exceeding 1,700 metres.
The Karish main field, located within the Karish lease, was discovered in 2013 and is located 25km northeast of the currently-producing Tamar field. The Karish main field is approximately 16km2 with a maximum estimated hydrocarbon column of 300 to 400m.
The Levantine Basin, in which the Karish and Tanin assets are located, contains up to 10,000m of Mesozoic and Cenozoic rocks above a rifted Triassic-Lower Jurassic terrain. The northern boundary of the Levantine Basin is defined by Cyprus and the Larnaca Thrust Zone, and its northwestern margin by the Eratosthenes Seamount. The Nile Delta Cone and the East Mediterranean coast define its southwestern and eastern margins.
The pressure volume-temperature models carried out in Karish demonstrate normal temperature and pressure for the depth of the reservoir. The field has strong vertical and lateral connectivity with faulting not expected to compartmentalise and a single gas-water contact has been evidenced by the seismic available for the Karish main field.
The Karish asset itself is a large two-way closure that sits on the southern upthrow side of a large down-to-the-north fault and is defined by 3D seismic data (2009 and 2010 Noble surveys). The Karish main field was evaluated by Noble in 2013 using a single discovery well (“Karish-1”) which was drilled by Noble to a depth of approximately 4,800m (true vertical depth subsea (“TVDSS”)). The discovered hydrocarbons within the Karish and Tanin Leases are contained with the Early Miocene submarine fan deposits of the Tamar Sands. Seismic data further suggests continuity of the main Miocene sands between the Leviathan, Tanin and Karish fields.
The Tamar Sands are further subdivided into more detailed reservoir units (A-D Sands, with A being stratigraphically the youngest). The C Sands at Karish are approximately 130m TST and are interpreted to be extensive across the entire structure. The fluid in the Karish C reservoir is substantially richer than that discovered in the other Levantine basin fields such as Tanin, Tamar and Leviathan. The B sands at Karish, while thinly bedded, can be identified on the available image logs.
The reservoir at Karish is well defined and well understood as it is analogous to the reservoir sands at Tamar and Leviathan and the 3D seismic data available is of excellent quality.
Within the Karish field a seismic amplitude anomaly associated with the C sands has been identified. This anomaly was tested by Karish-1, and other similar anomalies have been observed in the Karish North Upthrown prospect and the Karish Northeast prospect
NSAI CPR (June 2018) certified 2.497 TCF of gas plus 39 mmbls of light hydrocarbon liquids un-risked prospective resources (70% net to Energean). Energean has decided to drill an exploration well in Karish North in March 2019.
Offshore/onshore development mix
According to TAMA 37/H section 6.2, priority should be given in the development plan to the location of offshore treatment facilities over onshore installations. According to this section, prior to making a decision regarding the development plan, the Petroleum Commissioner will summit the proposed development mix to the National Council for approval. The development plan includes production and treatment facilities in the deep sea that will be located close to the Karish gas reservoir, about 90 km ashore, and includes full treatment facilities on Floating Production Storage and Offloading (FPSO), which will include gas treatment facilities, condensate separation, as well as operational storage volumes for condensate. The storage volumes will allow continuous gas production while separating the condensate, storing it and unloading it from the storage tanks on the FPSO to a shipping vessel to transport it to the end consumer. The natural gas will undergo full treatment on the platform and from there, it will be transmitted underground until the pipeline will be connected to the national transmission system.
On the FPSO, electric compressors, flow meters and pressure and flow control systems will be installed, that will work in constant contact with the INGL and the national transmission system, and will enable control over pressure and gas quantities when the pipeline reaches the shore and connects to the transmission system.
The onshore pipeline segment and up to 10 km ashore, will form part of the national transmission system, will be operated by INGL and will provide the connection possibility offshore to additional suppliers. Therefore, the actual connection point to the transmission system will be carried out offshore, around 10 km ashore. At this connection point, valves will be installed on the main offshore pipeline, which will enable the connection of future suppliers without interruption to the ongoing operation of the system, which is proposed in accordance with the Government’s decision as a result of the desire to reduce future pipeline work and additional shorelines by other suppliers.
The coastal facilities will include an underground pipeline, an underground station (CVS) about 300m from the coastline and a gas station (PRMS) in favor of the connection to the existing transmission system close to Ma’ayan Zvi sewage treatment plant. The components of the gas station – PRMS include end fittings for the pipeline, valves and pressure and flow control systems as well as operational flow meters. A larger breakdown of this station appears in the System Description section further, in this document. In conclusion, the construction of the treatment system on a floating platform close to the production wells avoid abolishes the need for additional treatment facilities and simplifies the production process. The development mix does not include treatment facilities on the territorial area of the State of Israel, neither offshore nor onshore. The gas that will flow to the shore will be launched as a final product at the INGL’s national transmission system.
Description of the system
Most of the components of the system are offshore. The system includes subsea production facilities and a pipeline system for collection and delivery to the treatment facility, offshore treatment and storage systems (FPSO) and a pipeline system of natural gas to connect to the national transmission system.
Components of the offshore system
The main components of the offshore system, with an emphasis on a Karish field, are located about 90 kilometers offshore and at a water depth of about 1,700 meters. The FPSO is located above the Karish field, which is planned for development in the first stage. The FPSO will be anchored to the seabed through anchors and will remain in place for development and production from the Tanin field. The main components of the system are: • Production wells, main wells, manifolds and subsea pipelines. • FPSO – an offshore production, treatment and storage facility, as well as condensate loading systems on transport vessels. • Communication and control systems. • Transmission pipeline of natural gas from the FPSO ashore.
Production wells, main wells, manifolds and subsea pipelines
Karish development includes at the first phase, three production wells. Additional drillings will be carried out in accordance with the surveys’ findings and the actual production quantities. The system includes a wellhead and a marine pipeline connecting each wellhead to the manifold. From the manifold a 10” diameter pipe ring is planned for the flow of all the production products (gas, condensate and water) to the FPSO for further separation and treatment. The development of Tanin, around 40 kilometers southwest of Karish will include two production wells, a manifold and a pipe ring with a diameter of 12” to FPSO. The drilling array is presented in the following two figures. Additional drilling will be carried out as needed according to the actual production rates and the system’s development.
Floating Production Storage and Offloading (FPSO)
This is a floating platform anchored at the seabed by 14 anchors. The length of the platform is about 230 meters and the width is about 50 meters. The total volume of liquids storage is approximately 160,000 cubic meters (about 1,000,000 barrels), and the maximum number of workers is about 72. In practice, it is estimated that there will be about 35 production workers and about 15 security guards. The FPSO will be designed to treat approximately 4 billion cubic meters of gas per year (BCM/y), and with the ability of a simple expansion to upgrade its capacity to about 8 billion cubic meters of gas a year. On the FPSO, the gas is separated from the liquid and undergoes treatment, flow and pressure control and counting prior its discharge onshore. Before reducing the gas pressure on the FPSO, a MEG chemical is injected to prevent hydration and freezing. The fluid separation that is separated from the gas is transferred to a parallel dedicated treatment system where the following main actions are performed:
- Water and condensate separation and treatment system of produced water.
- Condensate separation from the water and MEG (Mono Ethylene Glycol)
- Treatment and stabilization of the condensate and its storage in the storage tanks located in the FPSO’s abdomen
- Separation of MEG from the water by boiling and evaporation of the water and returning the MEG (in a closed circulation system) to the process.
- Storage of excess production and handling before discharge into the sea.
It should be noted that due to the proximity of the FPSO to the production wells, there is no need for MEG injection at the wellhead. This greatly simplifies the treatment of MEG and water on the FPSO. The MEG is injected after separation of the initial production and condensate at the FPSO, prior to reducing the gas pressure.
Here are some technical details, simulations and views of the FPSO.
Natural gas pipeline from the FPSO ashore
A 90-km-long transmission pipeline to the coast, a 24-inch diameter steel pipe in deep water. Approximately 15 kilometers from the shore, the diameter will be increased to 30-inch in order to enable the connection of future suppliers and to increase the transmission capacity. The pipelines will be wrapped in polypropylene and in a shallow concrete shell in shallow water up to a depth of 400 meters. The pipeline will be planted 1.2 meters below the seabed from 60-meter depth and until the shore. The connection between the FPSO and the pipeline will be carried out by means of 16 risers. Between the connection of the risers to the deep water pipeline an SSIV remote control valve will be installed as well as a facility for conductors transfer in the pipeline for maintenance and control purposes. The route of the pipeline passes through the northern part of the pipeline corridor according to TAMA 37/H and north of the Leviathan pipeline and the existing INGL pipeline on landing at Dor Beach. On the rise to the continental shelf, the pipeline passes through the northern part of the Dor interference. Three communication lines will be shared during the laying of the pipeline. The location and route of the crossing will be determined during the detailed planning and in coordination with the relevant infrastructure elements. About 10 kilometers from the shore will be installed on the pipeline from marine bodies, connection points for future suppliers. This installation is designed to reduce the need to another coast crossing in the future if there are additional suppliers. The connection point to the national transmission system will be carried out offshore, around 10 kilometers ashore. The coastal crossing will be carried out by means of HDD horizontal drilling about 50m north of the Leviathan pipeline crossing.