Maersk awards Tyra Southeast production platform 

AP Moeller – Maersk (Maersk) and its partners in the Danish Underground Consortium (DUC), Shell, Nordsofonden and Chevron have decided to invest $800 million capital expenditure in a new offshore platform at the Tyra Southeast oil and gas field.

Located  approximately 200 kilometers offshore the west coast of Denmark in the North Sea, Tyra is part of the DUC scheme to develop the Danish oil and gas fields since 1972.

After the first discovery of the Dan field followed by Gorm and Skjold, Maersk and its DUC partners developed Rolf in the west side and Tyra on the east side.

Over the years, Maersk and its partners deployed a complex of more than 30 platforms to support the wellheads and for processing the oil and gas before exporting them through 215 kilometers pipelines.

The oil and gas processing platforms are concentrated in Gorm and Tyra.

All these platforms are inter-connected through a subsea network of infield and transfer oil, gas and condensate pipelines giving the name of Danish Underground Consortium to the partnership between the operating companies.

In the Danish Underground Consortium, the working interests are shared between:

 - Maersk 31.2% is the operator

 - Shell 36.8%

 - Nordsofonden 20%

 - Chevron 12%

With this DUC program, Denmark managed to stand self-sufficient in the oil and natural gas since 1991.

Twenty years later, in 2011, DUC supplies to Denmark:

 - 69 million barrels of crude oil

 - 5.5 billion standard cubic meters of natural gas

In its territorial water, Denmark still holds significant oil and gas reserves, but as most of the North Sea the fields are maturing and the production flattening unless additional investments should be made with new technologies to enhance the oil and gas recovery rate of the in-place reserves.

Maersk and DUC partners select Bladt to build Tyra

The expansion project in Tyra is part of DUC program to increase the oil and gas production in Denmark.

With Tyra Southeast, DUC should add 50 million barrels of oil equivalent (boe) to the Danish production over the next 30 years.

This production should be split between:

 - 20 million barrels of crude oil

 - 170 billion cubic feet of natural gas

In this phase, Maersk and its DUC partners have planned to invest $800 million capital expenditure in the Tyra Southeast project.

This Tyra Southeast project includes a:

 - New unmanned platform

 - Bridge to tie-in the existing Tyra central processing platform

 - Wellheads and wellheads structures

 - 12 additional wells

Maersk and its DUC partners, Shell, Nordsofonden and Chevron, selected the Danish engineering company Bladt Industries (Bladt) to build the Tyra Southeast unmanned platform.

Bladt will design and build the jacket and the topsides  of the platform.

According to the term of the engineering, procurement and construction (EPC) contract, the Tyra Southeast platform should have a four legs jacket supporting 1.100 tonnes structure and topsides.

Bladt will build the Tyra southeast platform in its facilities of Aarlborg in Denmark.

As part of the enhanced oil recovery goal of this expansion project, Maersk and its partners have required Bladt to give priority to the energy and process efficiency in the design of the Tyra Southeast platform.

With Bladt to deliver the Tyra Southeast platform at the end of 2014, Maersk and its DUC partners, Shell, Nordsofonden and Chevron expect to start production in 2015 and to reach the peak of production of 20,000 boe/d in 2017. 

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Zadco to prepare call for tender on Umm al-Dalkh

After awarding Upper Zakum EPC-2 contract to Petrofac, the Abu Dhabi Zakum Development Company (ZADCO) is preparing the invitation to bid (ITB) for the development of Umm al-Dalkh, offshore Abu Dhabi in the United Arab Emirates.

On April 11th, 2013,  ZADCO awarded the engineering, procurement and construction (EPC) contract for the second package (EPC-2) of the Upper Zakum (UZ750) field development to a consortium of Petrofac Emirates and Daewoo Shipbuilding and Marine Engineering (DSME) from South Korea.

In this consortium Petrofac Emirates results from a joint venture between Petrofac from UK and the local Mubadala Petroleum (Mubadala) company.

Signed on the base of $3.79 billion capital expenditure, this EPC contract will provide Petrofac Emirates with $2.9 billion stake.

In February 2013, Petrofac had been given as the lowest bidder of a rebid organized for this package Upper Zakum EPC-2.

Since then ZADCO and its partners took some time to analyze in detail each offer as the top three bidders were so close.

Established in November 1977 to develop and operate the offshore field of Upper Zakum (UZ), ZADCO is a joint venture between:

 - Abu Dhabi National Oil Company (ADNOC) 60%, the operator

 - ExxonMobil Abu Dhabi Offshore Petroleum Company Ltd. (EMAD) 28% 

 - Japan Oil Development Company Ltd. (Jodco) 12%.

Located 84 kilometers northwest offshore Abu Dhabi and 56 kilometers from the export terminal on Zirku Island, Upper Zakum is the second largest crude oil field in the Gulf and the fourth one in the world.

In the same offshore area ly the fields of Umm al-Dalkh and Satah.

Originally developed by the Umm al-Dalkh Development Company (UDECO), ADNOC decided in 1988 to merge this company with ZADCO to unitize the development process and the means of production.

Tebodin completed the FEED on Umm al-Dalkh EOR

Umm al-Dalkh is covering 168 square kilometers only 25 kilometers distance from Abu Dhabi shore.

Lying by 2,310 meters, the Umm al-Dalkh field is composed of two reservoirs.

Discovered in 1969, Umm al-Dalkh has been developed in connection with Upper Zakum, 66 kilometers further north on the way to the export terminal based on the Zirku Island.

Currently, the crude oil extracted from Umm al-Dalkh is transported to Upper Zakum through a 14-inch pipeline where both fields production is carried out to Zirku Island by a 42-inch pipeline.

In 2010, the Dutch engineering company Tebodin won a first contract to enhance the production of Umm al-Dalkh.

According to this contract, Tebodin provided engineering, procurement, construction management (EPCM) services to:

 - Modify existing facilities

 - Add a new control system

- Install electrical submersible pumps

 - Electrical panels

 - Subsea power supply cable from the central platform

Then Tebodin was awarded the front end engineering and design (FEED) for another enhanced oil recovery (EOR) expansion including:

 - Gas injection

 - Water cuts handling.

With this last project, ZADCO is targeting to increase capacity from the current 13,000 B:d to 20,000 b/d.

Tebodin completed the FEED so that ZADCO is now preparing the invitation to bid for the engineering, procurement and construction (EPC) contract.

ZADCO is expecting to receive the technical and commercial offers on the third quarter 2013 in order to make the final investment decision (FID) and award the EPC contract before the end of the year.

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Mustang-Hejailan completed FEED on Midyan Project

Since Mustang-Hejailan completed the front end engineering and design (FEED) contract for the development of the Midyan offshore gas field, Saudi Aramco evaluated the bids submitted for the engineering, procurement and construction (EPC) contract of the Mustang onshore package of the project.

Located 135 kilometers northwest of the Port of Duba in the Western Province of Saudi Arabia, Midyan is the first large offshore non-associated gas field developed by Saudi Aramco in the Red Sea.

Lying in 1,200 meters of water depth along the Gulf of Aqaba at the border with the Jordan territorial water, Midyan benefits from the uplift of Cretaceous and Tertiary sediments.

Discovered in 1980s, Saudi Aramco had little interest for non-associated gas fields, even less offshore until the recent years and the decoupling of the gas prices from the crude oil prices.

With most of it power generation and petrochemical industry being fed by crude oil above $100 per barrel, the decoupling of the gas prices motivated Saudi Aramco to review all the potential source of natural gas that could be monetized in substituting crude oil in these applications.

In this context, Saudi Aramco identified Midyan non-associated gas and condensate gas field as one of the best opportunities to be developed in the northwest of the Kingdon of Saudi Arabia (KSA).

Saudi Aramco drilled up to seven delineation and development wells, in shallow and deep water of the Red Sea with a total depth of 5,300 meters.

The last discovery was made lately in 2012, only 26 kilometers away from the Port of Duba, confirming all the potential of the Midyan gas field.

In May 2012, Saudi Aramco had awarded the FEED contract to Mustang from The Wood Group in consortium with the local:

- Faisal Jamel Al-Hejailan Engineering Company (Mustang-Hejailan),

 - Dar Al-Riyadh Engineering Consultants (DAR)

 - Petro-Infrastructure Engineering Consultants Company (PI Consult)

This consortium was created by Mustang in order to meet the requirements of the General Engineering Services Plus (GES+) initiative developed by Saudi Aramco to favor the local content in Saudi Arabia with high added value engineering services activities.

Larsen & Toubro (L&T) leads Midyan EPC competition

From this FEED work, Mustang-Hejailan assisted Saudi Aramco to organize the call for tender of the EPC contract to cover: 

 - Upstream 

 - 135 kilometers gas export pipeline to Duba power plant

 - Gas central processing facility (CPF) to be located in the Duba Industrial City

Saudi Aramco had qualified companies to be invited to bid: 

 - Chiyoda from Japan

 - GS Engineering & Construction from South Korea

 - JGC from Japan

 - Larsen & Toubro (L&T) from India

 - Petrofac from UK

 - Samsung Engineering from South Korea

 - Tecnidas Reunidas from Spain

 - Technip from France

According to the EPC contract to be awarded soon, the central gas processing plant would have a capacity of:

- 75 million cf/d natural gas 

 - 4500 b/d condensates

On this base, the Midyan gas field should be able to supply the Duba power plant to be added to the project, during 20 years.

To leverage the return on capital employed in the project the onshore facilities will be constructed on skids as an offshore project in order to facilitate its transfer to another field when Midyan would have depleted after the 20 years of operations.

All the engineering companies submitted their bids on January 2013.

Since then, Saudi Aramco evaluated the technical and commercial offers.

Although the project was estimated to require $800 million capital expenditure, Larsen & Toubro is leading the competition with an offer below $400 million.

Saudi Aramco is now ready to sign the contract in order to see Midyan gas central processing facility in operations in 2015, while Larsen & Toubro (L&T) is collecting gas facilities projects after winning Oman PDO Saih Rawl phase 2.

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Daelim in the lead for KNPC Mina Al-Ahmadi FCC EPC

Daelim Industrial from South Korea submitted the lowest bid for the engineering, procurement and construction (EPC) contract of the Fluid Catalytic Convertor (FCC) and Sour Water Treatment package of the Kuwait National Petroleum Corporation (KNPC) refinery at Mina Al-Ahmadi in Kuwait.

With this first package to be awarded soon, KNPC confirms its intention to move ahead with its $18 billion capital expenditure Clean Fuels Project (CFP) project.

The Kuwait refineries are very old and suffered from severe damages during the Iraqi invasion in the 1990s.

In addition the current output of these refineries is no longer in line with the domestic demand and the Kuwait export strategy.

Since the years 2000s, KNPC is working on the Clean Fuels Project (CFP) to revamp, upgrade and expand the refineries in Kuwait.

The CFP project involves the three refineries currently in operations in Kuwait:

 - Mina Al-Ahmadi refinery in the north with 466,000 barrels per day (b/d) capacity

 - Mina Abdullah refinery in the south with 270,000 b/d capacity

 - Shuaiba refinery in the center with 200,000 b/d capacity.

The purpose of the CFP project is to:

 - Concentrate and increase refining capacities on Mina Al-Ahmadi and Mina Abdullah from current 736,000 barrels per day (b/d) to 800,000 b/d.

 - Improve the operating performances and the energy efficiency of the refineries

 - Optimize KNPC hydrocarbon products production between the refineries

 - Produce transportation fuels with low sulfur content and in line with the Euro IV standards

 - Reduce the carbon dioxide emissions

 - Widen Kuwait petrochemical portfolio with new and high added value by-products

 - Close the Shuaiba refinery too costly to revamp.

With this scope of work, the CFP project entered the active bidding phase since the state-owned oil refiner KNPC selected Foster Wheeler for the project management consultancy (PMC) contract in December 2012.

KNPC qualified seven bidders for three EPC packages 

In addition to the Fluid Catalytic Convertor and Sour Water Treatment package to be awarded soon, the Kuwait CFP project includes three main packages:

 - Revamping and upgrade of the Mina Al-Ahmadi refinery

 - Revamping, upgrade and expansion at the Mina Abdullah refinery, plus the dismantling of the Shuaiba refinery

 - Expansion of the facilities and utilities at the Mina Al-Ahmadi refinery

These three packages are at bidding stage since April 28th when KNPC opened the call for tenders (CFT) in providing the bidding documents.

At the end of the qualification process of the engineering companies invited to participate to the CFP project call for tender, KNPC selected seven consortium let by:

 - Chiyoda from Japan

 - Fluor from USA

 - JGC from Japan

 - KBR from USA

 - Petrofac from UK

 - Saipem from Italy

 - Tecnicas Reunidas from Spain

In order to receive techncial and commercial bids as consistent as possible at first time, KNPC is planning site visits and pre-tender meetings with the contenders until July 2013.

All the clarifications inquiries must be submitted by the bidders to KNPC and Foster Wheeler before August 4th.

These pre-qualified consortium will be allowed to quote only one or two packages among the three.

With the support of Foster Wheeler providing PMC services, KNPC set November 10th 2012 as the deadline for the submission of the technical and commercial offers for this Clean Fuels Project (CFP) packages in expecting the award on early 2014.

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BP selects bidders for Tangghu LNG FEED competition

The International Oil Company (IOC) BP and its partners in the Tangguh Expansion Project are currently qualifying the engineering companies to be invited to bid (ITB) on the onshore Tangguh third LNG Train and the production platforms to be installed offshore the Irian Jaya District of the West Papua Province of Indonesia

Since 2007, the two trains Tangguh liquefied natural gas (LNG) plant is operated by BP with 37.16% working interests.

With BP the Tangguh joint venture represent mostly stakeholders coming from Asia:

 -  Mitsubishi Inpex Berau B.V with 16.30%

 - China National Offshore Oil Corporation (CNOOC) 13.90%

 - Nippon Oil Exploration Limited and Japan Oil, Gas and Metals National Corporation through Nippon Oil Exploration (Berau) Ltd 12.23%

 - Mitsui & Co. Ltd., and Japan Oil, Gas and Metals National Corporation through KG Berau/KG Wiriagar 10%

 - Sumitomo Corporation and Sojitz Corporation through LNG Japan Corporation 7.35%

 - Talisman 3.06%

The Tangguh LNG plant is mostly supplied in natural gas from two offshore platforms producing natural gas and condensate from the large Vorwata field lying across the Berau-Bintuni Bay. 

In August 2012, BP and its partners started to work on the third Tangguh LNG Train project and decided to proceed by competitive front end engineering and design (FEED) in order to save time on the execution phase.

Two new platforms to supply Tangguh LNG Third Train

In June 2013, BP and its partners selected three consortia to be invited to bid (ITB) on this FEED competition for the Tangguh Third LNG Train.

This third LNG Train should have the same size as the first ones with a capacity of 3.8 million t/y.

BP is planning to get the technical and commercial offers of the three bidders in September 2013 for this onshore Tangguh Expansion Project estimated to require $7.8 billion capital expenditure,

By the end of the year, one or two of the three consortia will be invited to perform the FEED and to submit their proposal for an engineering, procurement and construction (EPC) contract in following.

This Tangguh Third LNG Train will be supplied in natural gas by two additional offshore platforms to be installed in 50 meters of water depth over three separate fields: Wiriagar Deep, Roabiba and Ofaweri.

All together with the Vorwata field already in production, these three fields discoveries are estimated to contain 14.4 trillion cubic feet (tcf) proven reserves of natural gas.

With more than 3,000 tonnes of topsides each, these production platforms will be connected to the Tangguh LNG Plant through 24-inch and 16-inch pipelines.

WorleyParsons completed the FEED of these platforms in 2013.

Local contractors and international engineering companies have expressed interest for these Tangguh offshore production platforms including:

 - Bakrie Industries

 - Gunanusa

 - Han Jung

 - Hyundai Heavy Industries (HHI)

 - Larsen & Toubro

 - McDermott

 - Meindo Elang Indah

 - Nippon Steel

 - Pal Indonesia

 - Saipem SMOE

 - Swibber Offshore with Emas Offshore

 - Technip

 - TL Offshore

BP and its partners are planning to issue the tender for the Tangguh offshore platforms in September 2013 so that the EPC contract could be awarded on first half 2014 for a completion of the Tangguh onshore and offshore projects in 2017.

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ONGC may re-tender Bassein Expansion EPC contract

The national oil company (NOC), Oil & Natural Gas Corporation (ONGC) is considering on last minute to rethink the scope of work for its Bassein Expansion project offshore India.

Although the Bassein Development project has reached its final bidding stage to award the engineering, procurement and construction (EPC) contract, ONGC may postpone the award again to change the scope of work.

The Bassein project is located along the west coast of India shallow water.

Lying by 70 meters water deep in the Arabian Sea, the South Bassein gas field stands 80 kilometers northwest of Numbai in Maharashtra.

Discovered in 1976, ONGC started the production of natural gas only in 1987 because of the high sulfide content of the field.

The Bassein Platform A (BPA) and Bassein Platform B (BPB) were the first gas processing platforms to enter commercial operations in 1987 and 1988 respectively.

Then after pre-treatment offshore, the gas is exported to the Hazira gas processing plant.

Designed to last 25 years, the high content of sulfides and the new regulations edited by the Indian Oil Industry Safety Directorate (OISD) require the existing platforms and infrastructures to be revamped in parallel to the Bassein project expansion.

ONGC to phase South-Bassein gas field development

All together with the revamping/upgrading of the existing facilities and with the construction of additional production infrastructures, ONGC is planning to spend more than $6 billion capital expenditure in order to maintain production until 2030.

Planning this revamping/upgrading and expansion of the Bassein gas field in several phases, ONGC had planned for this first expansion with approximately $500 million capital expenditure covering a:

 - New central processing platform (BCPA-3) to be bridged to the existing platform BCPA-2

 - New living quarters platform (BLQ-3) to host 50 to 100 persons

 - New wellhead platform equipped with nine slots for exploration or production

 - Modifications on the existing central processing platform BPA

The new central processing platform BCPA-3 should run:

 - Two raw natural gas separators plus space for further expansion with a third unit

 - Two gas compressors with a capacity of 5 million cubic meter per day each

 The wet gas separators will have a production capacity per unit of:

 - 5 million cubic meter per day (cbm) of gas

 - 6000 barrels per day (b/d) of liquids 

Afcons, L&T and Swiber at final stage for Bassein

For this Bassein expansion project, 15 engineering companies from India and abroad where qualified by ONGC and withdrew the corresponding call for tender for the EPC contract.

Originally, ONGC had requested the technical and commercial bid to be submitted on July 9th 2013, but this deadline has been postponed several times up to August 30th.

Still now, it is unclear if ONGC will proceed with current bids or re-tender the whole package as ONGC is considering significant modifications in the scope of work.

Only three bidders are reported to have returned their bid:

 - Afcons from India

 - Larsen & Toubro (L&T) from India

 - Swiber from Singapore

Considering the risks of delay on the project, a re-tender could only be organized with a short notice for all bidders, excluding by fact all the companies not yet in competition.

Therefore and regardless ONGC final decision to go for re-bid or not, the competition for the Bassein Expansion project will be concentrated on Afcons, L&T and Swiber for a challenging execution on fast track.

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Nigeria to restore refining capacities with private loans

On September 4th 2013, the Nigeria private Dangote Group (Dangote) sealed a financial agreement with 12 banks for a $3.3 billion loan to build a greenfield refinery and petrochemical complex in Olokola in the south of Nigeria.

With $8 billion capital expenditure, this $3.3 billion loan will contribute to the $6.75 debt financing required to complete the equity directly provided by the Dangote Group.

Ranked as the richest man in Africa and among the top 25 in the world with $20 billion fortune, the billionaire Aliko Dangote controls about 30% of the Nigerian Stock Exchange with most of his interest concentrated on the cement and food industry in Nigeria and sub-Sahara Africa.

As the largest crude oil producer in Africa Nigeria is sick from its refining industry with 445,000 barrels per day (b/d) capacity through four refineries.

Two of these refineries are located in Port Harcourt, one in Kaduna and one in Warri.

All together these refineries are only running at 20% of their nominal output.

Therefore Nigeria is turning to become Africa largest importer of refined products, petrochemicals and fertilizers.

With a population to reach 200 million inhabitants before 2020, Nigeria cannot afford to continue to rely on 80% import to cover its domestic needs in transportation fuels and fertilizer to boost the agriculture at the convenient levels.

In this context, Dangote decided to invest $8 billion capital expenditure in a greenfield integrated refinery and petrochemical complex with the support of a consortium of 12 banks.

The international Standard Chartered Bank and the local Guaranty Trust Bank coordinated the pool of the national and foreign banks to support the $3.3 loan.

UOP, EIL, Saipem won Dangote Olokola first contracts

 With the signature of the financing, Dangote awarded the first contracts for the Integrated Refinery and Petrochemical Complex.

The refining technology has been licenced from the US-based UOP/Honeywell.

The Indian state-owned engineering services company India Engineers Limited (IEL) has been appointed to provide project management consultancy (PMC) from the design stage to the execution phase.

In March 2013, Saipem was awarded the contract for the front end engineering and design (FEED) and the engineering, procurement and construction (EPC) contract for the fertilizer plant with the support of the Indian services from Tata Projects for the project management consultancy (PMC)

This fertilizer plant will be located in Edo State while Dangote selected the Olokola Free Trade Zone (FTZ), across the Ogun and Ondo States, to build the integrated and petrochemical complex.

The Dangote refinery and petrochemical complex will be designed with a capacity of:

 - 400,000 b/d of crude oil

 - 600,000 tonnes per year (t/y) of Polypropylene

Since the first contracts have been awarded to UOP/Honeywell, IEL,  Saipem, and Tata Projects, Dangote expect the Olokolay Refinery and Petrochemical complex to come on steam in 2016.

For more information and data about oil and gas and petrochemical projects go to Project Smart Explorer

Kenarong – Pertang competitive FEED to be an option

Murphy Oil Corporation (Murphy Oil) and the Malaysian oil company Petronas are considering the option to organize a competitive front end engineering and design (FEED) to develop the Kenarong and Pertang natural gas fields of the Block PM311 in the shallow water of the east coast of the Malaysia peninsula.

Based in El Dorado, Arkansas, USA, Murphy Oil is focusing on the oil and gas exploration and production in North America, West Africa and Southeast Asia.

In that respect Murphy Oil started to take interests in Malaysia in 1999 from where it currently produces 45% of its net production.

With production sharing contracts (PSCs) in the Blocks K, H, SK309, SK311 and PM311, Murphy Oil has a long standing experience of the operations in Malaysia and maintains a close cooperation with the local company Petronas.

The Kenarong and Pertang natural gas fields lye by 74 meters of water depth in the shallow water of the Block PM311 approximately 150 kilometers northeast Kuala Terengganu on the peninsular Malaysia east coast.

These fields were discovered in 2004 by 3,500 meters of total depth offering a good quality natural gas with low percentage of carbon dioxide content.

In the Block PM311 and PM312, Murphy Oil and Petronas share the working interests such as:

 - Murphy Oil 75% is the operator

 - Petronas 25%

The Kenarong and Pertang natural gas fields were left undeveloped for some years, but the recent evolution of the natural gas consumption in Malaysia with a flattening production motivated Murphy Oil and Petronas to gear up their development including the option to call for competitive FEED in order to save  time at the execution phase.

Two offshore platforms for Kenarong and Pertang fields

Because of the respective position of the Kenarong and Pertang fields, the offshore project should include:

 - Central processing platform (CPP) to be located above Kenarong

 - Wellhead platform to be positioned at Pertang

The two platforms will be connected together and should weight 11,000 tonnes

The central processing platform should be equipped to treat:

 - 80 million cubic feet per day (cf/d) of gas

 - 1,500 barrels per day (b/d) of condensate

The CPP should also support the infrastructures of the living quarter to host 20 crew members.

So far Murphy Oil and Petronas were planning to call for tender the FEED contract to be awarded on first quarter 2014 and to use the FEED conclusions to organize the bidding process for the engineering, procurement and construction (EPC) contract.

But in that case the EPC work has little chance to start before 2015 leading to commercial operations not earlier than 2017.

In proceeding with the competitive FEED Murphy Oil and Petronas may take the risk to increase the costs of the project, but can expect the first production to flow out of Kenarong and Pertang gas fields offshore peninsular Malaysia in 2016.

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Dialog-Vopak to feed Petronas Pengerang power plant

The Malaysian Dialog Group Berhard (Dialog) and the Rotterdam-based Royal Vopak (Vopak) are preparing the final investment decision (FID) on the Pengerang LNG Terminal project in the Johor Province at southern Peninsular Malaysia while the local engineering company Anewa is completing the construction of the first phase of giant Independent Deepwater Petroleum Terminal for the first quarter 2014. 

In 2011, Dialog and Vopak established a joint venture to design, build and operate the largest oil and gas petrochemical terminal in South East Asia and the largest in Malaysia.

This project is part of the Malaysia Economic Transformation Program (ETP) to support the Government strategic plan NKEA, standing for new key economic area and addressing the oil, gas and energy sector with 12 Entry Point Projects (EPP).

In this area, the Malaysian Government is planning to create seven local oil storage and trading hub including one in Pengerang as to be ideally located in the Johor Province at the utmost southeast peninsular Malaysia just in front of Singapore.

Located in Pengerang, this oil and gas and petrochemical storage and terminal project will support the development of the adjacent $20 billion capital expenditure Petronas Refinery And Petrochemical Integrated Development (RAPID) project.

In the Pengerang Johor Terminal project Dialog and Vopak share the working interests in such a way:

 - Dialog 51% is the operator

 - Vopak  49%

When running into commercial phase, the local Johor Government is due to take 10% share in the operating company.

Because of its size and diversity of the liquids and gas to be stored and distributed in the Pengerang Terminal, Dialog and Vopak decided to proceed in phases.

In 2011, Dialog and Vopak made the FID for the first phase of the crude oil terminal with a capacity of 1.3 million cubic meter storage capacity of liquids.

Anewa to complete Johor oil Terminal on early 2014

In the same time they awarded to Anewa, a company of Dialog Group, the front end engineering and design (FEED) work for the first phase of the Pengerang crude oil terminal.

Then Anewa was appointed for the engineering, procurement and construction (EPC) contract of this first phase to be completed by the end of 2013 or on early 2014.

Depending on the development of Dialog and Vopak trading activities in the region, the crude oil terminal will be expanded by an additional 1 million cubic meters storage capacity that should be in place in 2017 at the latest.

In parallel to the crude oil terminal, Dialog and Vopak are preparing the Pengerang liquefied natural gas (LNG) Terminal project.

As the crude oil terminal, Dialog and Vopak are phasing up the Pengerang LNG Terminal project.

Directly linked to the Petronas Pengerang Gas-fired Power Plant project to supply electricity to the RAPID project, the first phase of the Pengerang LNG Terminal is due to start in 2014 for a completion in 2016.

It should include two tanks with 360,000 cubic meters gas storage capacity with regasification facilities.

The second phase of the Pengerang LNG Terminal should be a replicate of the first phase with the same structure and capacity.

In respect with the development of Petronas RAPID project, Dialog and Vopak expect the Pengerang LNG Terminal Phase-2 to come on stream in 2018.

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Total made final decision to develop Incahuasi gas field

The French major company, Total and its partners, Gazprom from Russia and Tecpetrol de Bolivia (Tecpetrol), made the final investment decision (FID) to develop the gas and condensate discoveries from Incahuasi in Bolivia.

In a country where the production of natural gas is historically dominated by Petrobras from Brazil and Repsol from Spain,  Total started the exploration in Bolivia in 1996 in the Aquio and Ipati blocks.

Despite the nationalization of the natural gas industry in 2006 by President Evo Morales, Bolivia remains the second largest owner of natural gas reserves in South America after Venezuela.

With only two clients , Brazil and Argentina, Bolivia is the largest exporter of natural gas in South continent of Americas.

These two countries, Brazil and Argentina have also significant reserves of gas, but mostly offshore for the Brazil and mostly unconventional in Argentina.

In both cases the development of their domestic resources will take time while the local consumption will continue to grow and will require to increase import from neighboring countries such as Bolivia.

In Bolivia the natural gas fields are trapped in the deep underground of the Andes Mountain Range.

After the successful drilling of the ICS-2 exploration well in the deep underground,  Total and its partners Gazprom and Tecpetrol made the final investment decision to develop the Incahuasi discovery.

The Incahuasi gas field is located in the Ipati Block approximately 250 kilometers southwest of Santa Cruz.

Because of the 6,000 meters depth from the Andean foothills, the Incahuasi reservoir is submitted to high pressure and high temperatures calling for special drilling and production techniques.

Total tendered Incahuasi project on competitive FEED

Within Incahuasi project, Total and its partners share the working interests such as:

 - Total 60% is the operator

 - Gazprom 20%

 - Tecpetrol 20%

With the experience acquired from the Elgin-Franklin project in the North Sea, Total is providing a unique expertise to operate such deep buried gas field with challenging operating conditions.

Based on this expertise Total is planning to develop Incahuasi with:

 - One production well in the Aquio Block

 - Two production wells in the Itapi Block

 - GAs central processing facility (CPF)

 - Export pipelines system for the natural gas and the condensate to Peru and Argentina.

The gas central processing facility should have a capacity of 230 million cubic feet per day (cf/d).

In addition Total is considering additional exploration and appraisal wells in the Aquio and Itapi Blocks for further expansion.

In the first phase, Total and its partners are planning to invest $500 million capital expenditure and the full field development is estimated to require a total of $1 billion investment over the next five years.

On this base and in order to develop the Incahuasi project on fast track, Total and its partners organized a competitive front end engineering and design (FEED).

In the same time as they made the final investment decision, Total and its partners, Gazprom and Tecpetrol de Bolivia awarded the engineering, procurement and construction (EPC) contract to the winner of the competitive FEED in expecting the first commercial operations by 2016.

For more information and data about oil and gas and petrochemical projects go to Project Smart Explorer

JGC and Fluor to build Baytown USGC Ethane cracker

Chevron Phillips Chemical Company LP (ChevronPhillips) made the final investment decision (FID) to build its Cedar Bayou US Gulf Coast Petrochemical (USGC) project in Baytown, Texas, USA.

In following this decision ChevronPhillips selected the 50/50 joint venture of JGC Corporation from Japan and Fluor Enterprises Inc. from USA for the engineering, procurement and construction (EPC) contract of the ethane cracker package of the project.

Chevron Phillips Chemical Company LP is a wholly owned company of Chevron Phillips Chemical LLC, a 50/50 joint venture between Chevron Corporation (Chevron) and Phillips 66.

In the race to take the best advantage of the competitive shale gas resources in USA, ChevronPhillips had been among the pioneers to announce in March 2011 its intention to expand its existing site in Cedar Bayou with an ethane cracker as a feeder of its US Gulf Coast Petrochemical project.

With 1.5 million tonnes per year (t/y) capacity, USGC will be the largest ethylene plant in the world.

Including the ethane cracker, ChevronPhillips has budgeted the design and execution of the USGC Petrochemical project to $5 billion capital expenditure.

In 2012 The Shaw Group performed the front end engineering and design (FEED) of the project.

Meanwhile the FEED execution, The Shaw Group entity, ex Stone & Webster, in charge of the project has been taken over and integrated by Technip from France.

Therefore ChevronPhillips USGC ethane cracker will use a Technip license.

For the EPC contract JGC and Fluor established a 50/50 joint venture where:

 - JGC will have the leading role for the engineering and procurement of the process units

 - Fluor will handle the engineering and procurement of the offsites and utilities

Technip and Zachry won USGC Polyethylene Plants

As part of the US Gulf Coast Petrochemical complex, ChevronPhillips awarded two large polyethylene facilities to the partnership Gulf Coast Partners made of Technip from France and Zachry Industrial Inc. (Zachry) from Texas, USA.

With a capacity of 500,000 t/y of polyethylene per unit, these plants should be located in Old Ocean, close to the existing ChevronPhillips Sweeny facilities.

For these production units, ChevronPhillips will use its proprietary Advanced Dual Loop bimodal technology in order to maximize the flexibility of the production along a large bandwidth of polymers.

In order to cover all the types of demands of the domestic market, ChevronPhillips is planning to produce:

 - Bimodal polyethylene polymers

- High Density polyethylene

 - Linear Low Density polyethylene

 - Metallocene-based polymers

 While Technip will provide ChevronPhillips with its Stone & Webster proprietary furnaces and process equipment, Zachry will share it 15 years experience in engineeering and services on the existing facilities of the Sweeny site.

On the Baytown ethane cracker awarded to JGC - Fluor, as well as in the Old Ocean Polyethylene plants allocated to Technip -Zachry, ChevronPhillips expect to start the execution work on early 2014 for first production to start in 2017.

For more information and data about oil and gas and petrochemical projects go to Project Smart Explorer

IPIC qualified bidders for Fujairah Refinery Phase-1

The Abu Dhabi-based International Petroleum Investment Company (IPIC) is preparing the call for tender for the engineering, procurement and construction (EPC) contract of the Fujairah Refinery Phase-1 in the United Arab Emirates (UAE).

Established in 1984 by Abu Dhabi Government , IPIC has the mission to support energy projects outside of the Abu Dhabi Emirate.

The goal is to provide the Abu Dhabi Emirate with reliable accesses to market abroad and with profitable return on capital invested.

In that respect IPIC is focusing on upstream, midstream and downstream projects that can generate synergies with Abu Dhabi Energy sector.

With the Fujairah Refinery, Abu Dhabi will get direct access to the Gulf of Oman, shunting the critical Strait of Hormuz.

With the Fujairah Refinery project, Abu Dhabi will meet a double target, to secure its export of crude oil as well as increasing the added value of its export is selling high added value hydrocarbons instead of crude oil.

In addition Fujairah will generate about 400 permanent jobs for UAE Nationals.

For these  reasons Abu Dhabi Government selected, through IPIC, Fujairah to build this large refinery and petrochemical complex.

Fujairah occupies a strategic position with its access to the Oman Gulf and because it benefits from the crude oil supply through the crude pipeline supplying the UAE Main Oil Terminal.

Technip completed Fujairah Refinery project FEED

The contracts for the project management consultancy (PMC) and front end engineering and design (FEED) of the Fujairah Refinery had been awarded to Stone and Webster in 2011, belonging to the Shaw Group at that time.

Since then Stone and Webster was acquired by Technip from France while the rest of Shaw Group activities were taken over by CB&I from USA.

In 2012, Stone and Webster- Technip completed the FEED work for the Fujairah Refinery.

From the FEED work the Fujairah Refinery should have a capacity of:

 - 200,000 barrels per day (b/d) of crude oil

 - 1.2 million tonnes per year (t/y) of polypropylene 

In addition and because of the geographical situation and power needs of the Fujairah Emirates, the Fujairah Refinery project will also include a power plant.

This power plant will supply the Fujairah Refinery and Petrochemical complex as well as the local electrical power grid.

Requiring $3.5 billion capital expenditure, IPIC is planning to implement the Fujairah Refinery project in two phases:

 - Phase-1 : Refinery and Power plant

 - Phase-2: Petrochemical complex

 Then IPIC and Stone and Webster - Technip have decided to organize the call for tender of the Fujairah Refinery in two packages:

 - EPC-1 will include the process units

 - EPC-2 will cover the infrastructures, offsites and utilities.

Six engineering companies have been qualified by IPIC for EPC contract of the Fujairah Refinery Phase-1.

They should submit the technical offer at the end of 2013 with the commercial offer to follow in first quarter 2014.

In targeting a final investment decision (FID) on second half 2014, IPIC is planning the first production of the Fujairah Refinery in 2017.

For more information and data about oil and gas and petrochemical projects go to Project Smart Explorer

Anadarko and Eni to review Afungi LNG Park phases

The Anadarko Petroleum Company (Anadarko) from USA and the national oil company (NOC) Eni from Italy are facing some delays in the implementation of the giant project for the liquefied natural gas (LNG) to be built at Afungi, in the northeastern province of Cabo Delgado in Mozambique.

Although Anadarko and Eni have different interests in Mozambique, since Anadarko is operating the Area-1 while Eni is leading the Area-4 of the Rovuma Basin.

In their respective area, Anadarko and Eni are heading respectively complex joint ventures where the working interests are shared in:

 - Area-1, Anadarko is the operator with 26.5%, with Mitsui E&P 20%, Empresa Nacional de Hidrocarbonetos (ENH) 15%, ONGC 10%, BPRL Ventures Mozambique B.V. 10%, Videocon 10%, PTTEP 8.5%

 - Area-4, Eni is the operator with 50%, China National Petroleum Corporation (CNPC or PetroChina) 20%, ENH 10%, Galp Energia (Gapl) 10%, Kogas 10%.

In addition Eni is still looking for at least one other partner to join the team in the Area-4 in order to dilute its level of risk and possibly bring some LNG expertise with companies like Shell.

If the size of the onshore and offshore projects imposes to involve multiple partners, this fragmented structure does not help to make decision.

Then, the Mozambique Government imposed to both operators, Anadarko and Eni to join forces on the Onshore Mozambique LNG project in order to limit all impacts in Afungi and the Cabo Delgado Province.

Bechtel, CB&I-Chiyoda, JGC-Fluor in competitive FEED

For this Onshore Mozambique LNG project, KBR and Technip performed a pre-front end engineering and design (pre-FEED) to recommend Anadarko and Eni to build the jointly operated Afungi LNG Park along the coast of the Cabo Delgado Province.

From this conceptual study, the Afungi LNG Park should have the capacity to host up to ten LNG Trains.

With 5 million tonnes per year (t/y) capacity per LNG Train, Anadarko and Eni had in mind to phase the Onshore Mozambique LNG project in five folds of two LNG Train each.

This scenario would have allowed Anadarko, Eni and their respective partners to start up the first shipments from the Afungi LNG Park in 2018.

In this perspective Anadarko and Eni decided to organize competitive front end engineering and design (FEED) in order to short cut bidding and development lead time.

Currently three teams are in competition for this FEED:

 - Bechtel

 - CB&I and Chiyoda

 - JGC and Fluor Transworld Services (Fluor)

The competitors are expected to return their best technical and commercial offer on first quarter 2014.

After evaluation, the winner of this competitive FEED will be given the engineering, procurement and construction (EPC) contract for the first two LNG Trains with the option for the second series of two LNG Trains.

Unfortunately the time given for the evaluation of the competitive FEED offers, will lead Anadarko, Eni and their respective partners to come for approval to Mozambique Government at the Presidential election period planned in September 2014.

In this context, it appears challenging for Anadarko, Eni and their respective partners to move Onshore Mozambique LNG project into EPC phase on time to start commercial operations in 2018, but more likely in 2019 or 2020.

For more information and data about oil and gas and petrochemical projects go to Project Smart Explorer

Emirates LNG to replace FSRU by land-based terminal

The Abu Dhabi-based companies Mubadala Petroleum (Mubadala) and the International Petroleum Investment Company (IPIC) have decided to stop the just starting first phase of the Emirates LNG project in Fujairah, United Arab Emirates (UAE), to rethink the whole concept of this liquefied natural gas (LNG) import and regasification terminal.

Originally designed by the French engineering company Technip, the Emirates LNG project was intended to be developed in two phase:

 - Phase-1: Floating storage and regasfication unit (FSRU)

 - Phase-2: Landed-base regasification and storage terminal

In July 2013, Mubadala and IPIC had awarded the engineering, procurement and construction (EPC) contract for the Emirates LNG Phase-1 to the US-based company Excelerate Energy (Excelerate).

To deliver the FSRU corresponding to this first phase, Excelerate had planned to allocate one of the eight units currently in construction at the Daewoo Shipbuilding and Marine Engineering (DSME) shipyard in South Korea.

According to these FSRU units work in progress, Excelerate should have been able to deliver the Emirates LNG vessel mid 2015.

In the Emirates LNG consortium, Mubadala and IPIC share 50/50 the working interests whereas Mubadala is the Abu Dhabi Sovereign Wealth and IPIC and Abu Dhabi state-owned company.

This concentration of interests coming from Abu Dhabi into a Fujairah project is motivated by the reliance of the Abu Dhabi Emirates economy on the Strait of Hormuz.

With Fujairah giving direct access to the Gulf of Oman and thus to the Indian Ocean without depending from the Strait of Hormuz, Abu Dhabi secures its export of crude oil but also its import of natural gas.

Mubadala and IPIC to retender Emirates LNG in 2014

Abu Dhabi is importing gas from Qatar and needs alternative source of supply to feed its power generation and water desalination facilities and continue to boost its oil production and petrochemical sector.

Because of the increasing threat on the Strait of Hormuz through the tension with Iran, Abu Dhabi had decided to develop its Emirates LNG project on fast track.

Despite all the additional capital expenditure, Mubadala and IPIC in charge of the project decided to phase it with this FSRU option that could guaranty to be in operations in 2015.

Then Mubadala and IPIC had more time to build the second phase in concrete buildings in an adjacent site of the Fujairah combined power generation and water desalination facilities.

The FSRU and land-based terminal were designed with total capacity of 1.2 million cubic feet per day (cf/d) of gas or 9 million tonnes per year (t/y) of LNG.

In the recent context where the USA resume discussions with Iran in the perspective of relaxing tensions in the Gulf, Abu Dhabi may have considered that the degree of urgency that has led to design and build the Emirates LNG project in two phases including the FSRU was not longer so relevant.

Therefore, Mubadala and IPIC are now working to design and build this Emirates LNG project in Fujairah in a single phase, all grounded.

In that perspective, Mubadala and IPIC will invite all the engineering companies in competition for the Fujairah Emirates LNG phase-2 to retender for the whole project in 2014.

For more information and data about oil and gas and petrochemical projects go to Project Smart Explorer

ONGC to award pre-FEED on KG-DWN-98/2 deepwater

The India state-owned company Oil and Natural Gas Corporation (ONGC) is on the way to award the contract to perform the pre-front end engineering and design (pre-FEED) work for the development of the KG-DWN-98/2 project in the deep water of the Krishna Gadavari (KG) Basin offshore the Andhra Pradesh coast at the northeast of India.

Adjacent to the prolific KG-DWN-98/3, known as KG-D6 Block, operated by Reliance Indusries Limited (RIL) and BP, the KG-DWN-98/2 Block is finally reaching the development phase with the national oil company (NOC) ONGC acting on its own.

Taken over from the Scotland-based Cairn Energy (Cairn) in the year 2005, the KG-DWN-98/2 Block appeared very early promising for its gas resources but took longer time to ONGC to evaluate liquids reserves especially in crude oil.

Because of the size and complexity of the field located approximately 200 kilometers from Vishakhapatnam by water depth ranging from 300 meters to 3,000 meters in the Bay of Bengal, the KG-DWM-98/2 Block has been divided in two areas to undertake its exploration.

In the Northern Discovery Area (NDA), ONGC achieved eight successful drillings in the Annapurna, Kanakadurga, Padmawati, A, E, D/KT, U and W wells in water depth between 600 and 1,300 meters.

Regarding the Southern Discovery Area, the exploration appeared much more challenging because of the ultra deep water of 2,800 meters to hit oil and gas in UD-1 discovery.

ONGC to develop KG-DWM-98/2 Block on fast track

From its first discoveries, ONGC declared the KG-DWM-98/2 commercially viable in 2009 and 2010 and has been expecting to set joint venture with international oil companies (IOCs) to provide support in this large but highly technical development.

Contacts were made and memorandum of understanding (MOU) were signed with Shell, Statoil, ConocoPhillips and Petrobras, but none of them could come to production sharing agreements (PSA) mostly due to the unbalance between the project size or risks and its potential pay-back limited by India market prices driven by Government Decree to $7 per million btu.

The KG-DWM-98/2 Block is estimated to hold 900 million barrels of crude oil and 3 trillion cubic feet (tcf) of natural gas out of which ONGC expects 20% to be recoverable reserves.

With nearly 200 million additional reserves the KG-DWM-98/2 Block contributes significantly to increase India proven reserves in a context where its domestic demand is about to double by 2030.

Considering that the oil and gas production stood flat of the last years because of too many old fields declining, ONGC cannot wait any longer and has decided to move forward in the development of the KG-DWM-98/2 Block.

Without the support of foreign operating company, ONGC is going to rely on the expertise of the engineering companies to provide the most effective concept to develop the KG-DWM-98/2 project with an investment estimated to $9 billion capital expenditure.

In respect with the fast track vision expressed by ONGC to develop this KG-DWM-98/2 project, it appears most likely that the winner of the pre-FEED on mid-2014 will also be awarded the FEED contract on early 2015 so that the engineering, procurement and construction (EPC) contract should into completion by 2018. 

For more information and data about oil and gas and petrochemical projects go to Project Smart Explorer

Gendalo-Gehem bidders to include Indonesia partners

The US major company Chevron and the Italian national oil company (NOC) Eni are reviewing the qualification of the contractors in competition for the floating production and offloading (FPO) vessels required for the development of the Gendalo and Gehem liquids-rich gas fields in the Makassar Strait offshore the East Kalimantan Province of Indonesia.

This re-qualification process comes after the decision made in 2013 by Chevron and Eni to declare “failed bid” the call for tender issued for the engineering, procurement and construction (EPC) contract of the FPOs to be installed on the Gendalo and Gehem gas fields.

Located in the Strait of Makassar, the Gendalo and Gehem gas fields  are 120 kilometers distant from each other and lying by 1,829 meters of water depth.

Located at the foot of the Indonesia Continental Shelf in the Kutal Basin, the Gendalo – Gehem project will be the deepest project of that size achieved in Indonesia.

With the development of the Gendalo and Gehem FPO project, Chevron and Eni intend to develop Maha and Gendang gas fields neighboring Gendalo.

The Maha and Gendang gas fields should be tied-back to the Gendalo FPO, so that together with Gehem, Chevron and Eni could access recoverable reserves estimated to 4 trillion cubic feet (tcf) of natural gas.

In this Gendalo -Gehem project, the working interets are shared in such a way that:

 - Chevron 80% is the operator

 - Eni 20%

 - Indonesia Government holds 10% provision share that it can exercise at any time through the national company Pertamina.

In 2012 Technip and WorleyParsons completed the front end engineering and design (FEED) of the Gendalo – Gehem project where:

 - Technip was in charge of the Gendalo and Gehem FPOs

 - WorleyParsons took care of the subsea, umbilicals, risers and flowlines (SURF) package

New competition in Chevron Gendalo-Gehem FPOs

Chevron and Eni selected the FPO concept to develop Gendalo-Gehem because of their location 150 kilometers and 90 kilometers respectively from the onshore Santan Storage Terminal and Bontang LNG Terminal.

In this configuration, Gendalo and Gehem FPO will treat the raw gas and export the natural gas by subsea pipelines to the Santan Terminal.

Gathering the gas and condensate through 80 kilometers of umbilicals,

 - Gendalo FPO will have a treatment capacity of 420 million cubic feet per day (cf/d) of gas and 30,000 barrels per day (b/d) of condensate.

 - Gehem FPO will be slightly different with 700 million cf/d of gas and 25, b/d of condensate.

In this context, three teams of engineering, procurement and construction (EPC) companies were qualified for the call for tender organized in 2013 for the Gendalo Gehem FPOs:

 - McDermott with Samsung Heavy Industries, STX Offshore and the local Singgar Mulia

 - Petrofac with Daewoo Shipbuilding and Engineering (DSME), RNZ and the local Inti Karya Persada Technik

 - Saipem with Hyundai Heavy Industries, SMOE and the local Tripatra Engineering and Construction (Tripatra) and Gunanusa.

Unfortunately the lowest bidder, McDermott and its partners, submitted an offer 20% above Chevron and Eni estimates allowing to declare the tendering process “failed bid”.

In addition to the pricing issue, questions came up regrading the compulsory share of local content proposed by some bidders in respect with the Indonesia regulation.

For the re-tender of the Gendalo and Gehem FPOs, Petrofac team should not participate, instead Chevron and Eni qualified a new team led by the Japanese Toyo Engineering Company (Toyo or TEC) and supported by Cosco Shipyard from China and the local Meindo Elang Indah.

In calling for this second round tender of the EPC contract in 2014, Chevron and Eni expect now the Gendalo and Gehem FPOs to load first gas and condensate shipments by second half 2017.

For more information and data about oil and gas and petrochemical projects go to Project Smart Explorer

Consol and Range to supply shale gas to Ineos cracker

The US-based junior companies Consol Energy Inc. (Consol) and Range Resources Corporation (RRC or Range Resources)  signed long term agreements with the Swiss registered petrochemical company Ineos Group AG (Ineos)  to import shale gas from the USA to supply its ethylene cracker at Grangemouth complex in Scotland, UK.

This brownfield Grangemouth ethane cracker project is one of the first example illustrating how the competitive shale gas produced in US can help to restore the European petrochemical industry.

Based in Pittsburg, Pennsylvania, Consol is one of the largest independent producer of shale gas from the Appalachian basin with 5.7 trillion cubic feet (tcf) proved reserves of natural gas.

In the same way Range Resources is a typical junior company which contributed to the extraordinary development of the shale gas and coal bed methane development in the US with interests in the Appalachian and Southwestern basins.

In 2013, Range Resources increased its proved reserves by 26% and replaced 612% of its production on the same period.

In this context of solid and sustainable growth, Range Resources is interested to export a part of its shale gas production to Europe where the gas prices are about four times higher than in US.

This significant price gap between Europe and US is directly affecting profitability of large petrochemical complex such as Ineos Grangemouth.

In October 2013, Ineos was about to close this Grangemouth petrochemical complex, one of the largest in Europe.

Not only the gas prices in Europe are higher than in US, but the decline of the maturing fields in the UK North Sea is reducing by 50% the available capacity of natural gas to feed Ineos crackers at the scale of Grangemouth complex.

Ineos to build Grangemouth Ethane Terminal fast track

In securing competitive feedstock from Consol and Range Resources, landed in UK at about 50% below current North Sea prices,  Ineos is now able to reconsider the future of this critical petrochemical complex to make it running at the optimal capacity of 700,000 tonnes per year (t/y) of ethylene.

Ineos signed a shipment agreement with Evergas for the export of ethane through dedicated LNG carriers from US to Grangemouth where Ineos is planning a large LNG import terminal.

The construction of this Grangemouth LNG Import Terminal will be implemented on fast track.

It should have a storage capacity of 33,000 tonnes of ethane and downloading capacity of 2,000 tonnes per day (t/d).

Ineos selected the site in Grangemouth to build this new LNG import terminal and is expecting to complete the front end engineering and design (FEED) at the end of first quarter 2014.

Then Ineos is planning to award the engineering, procurement and construction (EPC) contract in following so that the first shipment of LNG could be landed in Grangemouth Ethane Terminal in 2016.

For more information and data about oil and gas and petrochemical projects go to Project Smart Explorer

Fluor and WorleyParsons designed Tengiz Expansion

The California-based international oil company (IOC) Chevron Corporation (Chevron) and its partners, the Kazakh national oil company (NOC) KazMuniaGas (KMG), the global leader ExxonMobil and the Russia company LukArco (Lukoil) are closely reviewing the offers of the engineering companies to award the engineering, procurement and construction (EPC) contract for the Future Growth Project (FGP) to expand the Tengizchevroil (TCO) oil field on the west side of Kazakhstan.

Covering 2,500 square kilometers near the Caspian Sea, the TCO oil field development includes the Tengiz field, the Korolev field and some other prospects to be developed.

Discovered by 4,000 meters depth in 1930s, while the Soviets were prospecting the Pre-Caspian Depression, the first well started to produced the first oil from the Tengiz field only in 1979.

Together with the Korolev and associated fields, Tengiz is estimated to hold up to 9 billion barrels of recoverable reserves of crude oil from about 26 billion barrels of in-place reserves.

Despite its large size, Tengiz had been left undeveloped during decades because of its technical challenges.

The first tests had indicated that Tengiz reservoir should accumulate high temperature, high pressure and high hydrogen sulfide content requiring skill of art expertise most advanced technologies.

In 1993, Kazakhstan and Chevron established the joint venture Tengizchevroil (TCO) from Chevron and the local Tengizneftegas Production Association, and signed a 40 years agreement.

In 1997, LukArco (Lukoil) took share in the TCO joint venture so that the working interests stand currently between:

 - Chevron 50% is the operator

 - ExxonMobil 25%

 - KMG 20%

 - LukArco  5%

Local content required for TCO Future Growth Project

Since its first development, Tengiz production has been supported by the construction of crude oil processing facilities called Complex Technology Lines (CTL) to separate the associated natural gas, the liquid petroleum gas (LPG) and the hydrogen sulfide.

This sour gas and re-injected in the reservoir to maintain the pressure and enhance the oil recovery (EOR) rate from Tengiz field.

If not carefully controlled, this re-injection of large quantities of sour gas may destabilize the crude oil reserves and turn Tengiz even more complex to develop.

In May 2012, TCO awarded the front end engineering and design (FEED) and engineering, procurement and construction management (EPCM) contract for the Wellhead Pressure Management package of the Tengiz Future Growth Project to a team led by Fluorand supported by WorleyParsons and the Kazakh Institutes KING and KGNT.

With the Future Growth Project, Chevron and its partners are planning to increase this capacity from the current 260,000 barrels per day to 780,000 b/d in two phases.

To proceed to the Tengiz Expansion, Chevron developed with his partners a new technology named Second Generation Plant (SGP) associated to Sour Gas Injection (SGF) facilities.

These crude oil processing SGP and SGF facilities will support the drilling program to add 190 wells in the Future Growth Project for a capital expenditure of $25 billion.

Because of the location,Chevron and its partners opted for a modular construction of the Second Generation Plants and Sour Gas Injection facilities.

Therefore the contenders to submit offers for the Future Growth Project construction had to propose world-class shipyards to produce and ship these complex modules in that quantity.

Two teams of South Korean contractors are in competition for the engineering, procurement and construction (EPC) contract of Future Growth Project.

Chevron and its partners had planned to sanction this contract last year but the Kazakh requirement to integrate 44% of local content in the Future Growth Project caused some delay to evaluate the local partners to be involved in the respective South Korean teams.

In order to manage the local suppliers and subcontractors, the Kazakh Government is putting in place the National Service Company (NSC) that will support TCO.

In parallel GE Nuovo Pignone has been awarded the gas compressors.

Since the Kazakhstan Government approved the TCO expansion project in October 2013, Chevron and its partners ExxonMobil, KMG and Lukoil are close the make a decision for the EPC contract of the Future Growth Project to come on stream in 2015 for the first phase and 2018 for the second phase.

For more information and data about oil and gas and petrochemical projects go to Project Smart Explorer

Foster Wheeler at FEED on MGSE gas compression

In October 2013, the national oil company (NOC) Saudi Aramco selected the Swiss-based engineering company Foster Wheeler to perform the front end engineering and design (FEED) work of the compression stations for the Master Gas System Expansion (MGSE) project.

To be implemented in phases, the Master Gas System Expansion project is vital for Saudi Arabia to support the development of its non-associated gas, unconventional gas and related condensate reserves.

With 285 trillion cubic feet (tcf) of proved reserves of natural gas, Saudi Arabia ranks among the top five countries in the word.

From gas production perspective, Saudi Arabia stands in the top ten countries globally with a year-to-year growth ranging between 5% and 10%.

Despite that, the domestic needs in natural gas for the power supply, house cooking  and petrochemical applications are ramping up in the same way, so that for the last twenty years Saudi Arabia maintains a strict zero net import/export balance.

In practice Saudi Arabia is using expensive crude oil to feed power plants and naphtha crackers wherever it cannot provide competitive gas supply.

From the 2011 production of 3.5 tcf of natural gas, Saudi Aramco is aiming at doubling it by 2030 including the compensation of the maturing fields depletion.

In addition to the challenge in volume, Saudi Arabia is to overcome the geographical spread of the country with resources located in different places from where it would like to grow its economical development from the Eastern Province to the Red Sea coast.

Saudi Aramco to invest $1.65 billion in MGSE phase-1

On the 1970s, Saudi Arabia started to monetize its gas reserves, and in the 2000s Saudi Aramco intended to gather all the associated gas flared until then from the crude oil fields production.

In that purpose, Saudi Aramco designed the first phases of the Master Gas System (MGS) crossing the country from Yanbu on the Red Sea to Shedgum in passing by Ryadh.

Now Saudi Arabia is willing to speed up the conversion of number of power plants from oil to natural gas.

In that perspective Saudi Aramco is extending the existing Master Gas System to the Western Province in order to supply the power plants located there.

Therefore the Master Gas System Expansion project phase-1 should include:

 - 500 additional kilometers of pipelines

 - Two gas compression stations

 - Offsite and Utilities

Estimated to require $1.65 billion capital expenditure, this first phase of the Master Gas System Expansion project should provide immediate return to Saudi Aramco by the savings made on the crude oil being replaced by the natural gas.

As soon as Foster Wheeler will have completed its FEED work on the compression stations, Saudi Aramco will award the engineering, procurement and construction (EPC) contract for this first phase of the Master Gas System Expansion project to come on stream in 2017.

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Toyo Engineering starts to harvest India LNG Terminals

The Indian leading midstream company Petronet LNG Limited (Petronet) has selected Toyo Engineering Company (Toyo or TEC) to expand its liquefied natural gas (LNG) terminal and regasification plant in Dahej, Gujarat, on the west coast of India.

India is the 13th largest gas consumer and 4th largest LNG importer in the world.

With a GDP growing at 6% per year, the energy demand is following the same pace.

But in the basket of the different sources of energy fueling India economical growth, the natural gas share is planning to jump from the current 9% to 20% by 2025.

According to Vision 2030, Natural Gas Infrastructure India source, the demand for natural gas should triple from 8 billion cubic feet per day (bcf/d) in 2013 to 25.3 bcf/d in 2030.

On the same period, the local production of natural gas should only double from 3.2 bcf/d in 2013 to 8.2 bcf/d in 2030.

India is currently operating only four LNG Import Terminals accumulating a capacity of 23 million tonnes per year (t/y) LNG, representing 35% of India gas supply.

In this context, India is planning to add a tenth of LNG Terminal and Regasification Plant projects where Petronet intends to play a key role.

Petronet was established in 1998 as a joint venture of the main oil and gas companies in India and the French gas specialist GDF-Suez sharing the working interests such as:

 - 50% are held by Gail Ltd, Oil and Natural Gas Corporation Ltd (ONGC), Indian Oil Corporation Ltd (IOC) and Bharat Petroleum Corporation Ltd (BPCL)

 - 10% belongs to GDF-Suez

 - 5.20% stand in the hands of ADB

Petronet prepares third LNG terminal at Gangavaram 

Since 2004, Petronet is operating the Dahej LNG import terminal and regasification plant with a capacity of 5.0 million t/y.

In 2009, Petronet proceeded to a first expansion of another 5.0 million t/y.

At that time IHI Corporation (IHI) and Toyo had been awarded the engineering, procurement and construction (EPC) contract for this Dahej LNG Terminal Expansion.

Now Petronet is making the final investment decision (FID) for a second expansion of this Dahej LNG Terminal.

With this expansion, Petronet would like to increase Dahej LNG Terminal from the current 10 million t/y to 15 million /y.

This second Dahej LNG Terminal Expansion projects should include:

 - LNG downloading system

 - Regasification facilities

 - Additional storage tanks

 - Gas Pipelines system

 - Offsites and Utilities

 - Connection to the existing plant.

For this Dahej LNG Terminal Expansion project, Petronet selected again Toyo to carry out the EPC contract on a lump sum turn key basis.

In the same time Petronet is working a third LNG terminal at Gangavaram on the east coast of India in the State of Andhra Pradesh.

With an initial capacity of 5 million t/y the Gangavaram LNG Terminal and Regasification Plant greenfield project will be expanded in a second phase to 10 million t/y. 

In awarding the Dahej Regasification Plant EPC contract on this first quarter 2014 to Toyo, Petronet is planning to receive the first shipments at the Dahej LNG Terminal Exapnsion project by 2017.

For more information and data about oil and gas and petrochemical projects go to Project Smart Explorer