Larsen & Toubro wins Oman PDO Saih Rawl phase 2

>On August 27th 2012, Petroleum Development Oman LLC (PDO) awarded to Larsen & Toubro from India the engineering, procurement and construction (EPC) contract for the Saih Rawl Depletion Compression Phase 2 (SRDC2) project.

Nine engineering companies were in competition to win this order of $235 million.

The Saih Rawl gas field is located in Center Oman where PDO started operations in 1991 with a large gas Central Processing Facility (CPF).

Then the natural gas is piped to the LNG Trains located at Qahlat for export and Sur Fertilizer plant.

After years of production the Saih Rawl gas field is maturing and losing a part of its natural pressure.

PDO invested $550 million in the Saih Rawl Depletion Compression phase 1 (SRDC1) project to boost Saih Rawl gas field in using the depletion compression process.

The depletion compression is reducing the back-pressure at the wellhead to boost the gas inlet pressure from 35 to 96 bar for export.

Anyway and despite the installation and commissioning of the Saih Rawl Depletion Compression phase 1 last year, the natural depletion of the Saih Rawl gas field continues so that the inlet pressure at the CPF should come down to 13 bar by 2015.

In that perspective PDO anticipates with Saih Rawl Depletion Compression phase 2 project.

In its EPC contract Larson & Toubro‘s scope of work includes:

 - 4 parallel compression trains of 76 MW for a total capacity of 30 million standard cubic meter per day (mmscmd) of gas

 - Modifications of the condensate handling system at the Saih Rawl CPF

 - Installation of a pair of inlet separators for a total capacity of 18 mmscmd

PDO and Larsen & Toubro are planning the completion of the Saih Rawl Depletion Compression phase 2 project in 2014.

Larsen & Toubro aims at Qatar Dolphin gas compression

Larsen & Toubro is one of the six engineering companies in competition for the Dolphin Energy Ltd (Dolphin) gas compression expansion project in Ras Laffan Indusrial City in Qatar.

Created in 1999, Dolphin is a joint venture based in Abu Dabi, UAE, between:

 - Mubadala, a wholly owned Abu Dhabi Government national oil company (NOC), 51%

 - Total from France 24.5%

 - Occidental Petroleum from USA 24.5%

If the Abu Dhabi Emirate is rich of oil, it is short of natural gas.

With a local natural gas demand increasing for power generation, gas injection and petrochemicals applications, Abu Dhabi created Dolphin Energy to treat and export natural gas from Qatar to the UAE.

In the agreement between Qatar and Abu Dhabi, the raw natural gas is processed in Ras Laffan Industrial City to produce:

 - Natural gas (methane) exported to the UAE

 - Ethane used as feedstock locally for the Ras Laffan petrochemical industry

 - other NGL such as propane and butane for international trading.

In 2007, JGC from Japan built up the first Dolphin gas compression facility with capacities of:

 - 110,000 b/d of condensate

 - 4,400 t/d of ethane

 - 2,800 t/d of propane

 - 1,800 t/d of butane

Now Dolphin is planning the expansion of the existing Ras Laffan gas central processing facility (CPF).

The expansion of Dolphin Ras Laffan gas CPF is supposed to include:

 - Gas compression facility of 1 billion cf/d additional capacity of natural gas

 - Upgrade Ras Laffan Dolphin utilities

 - Piping and hydraulic work

This expansion is to match with the available capacity of the 364 kilometer gas pipeline connecting Qatar to the UAE across the Arabian Gulf.

Designed and installed by Saipem in 2006 for a capacity of 3.2 billion cf/d of natural gas, the Dolphin gas pipeline is currently operated at 2 billion cf/d.

The Dolphin Ras Laffan gas compression project is to fill up the capacity of the Dolphin gas pipeline with this addition 1 billion cf/d expansion. 

With capital expenditure estimated around $250 million, Dolphin is planning the completion in 2015.

After winning the Lekhwair Gas Field Development project  and the Saih Rawl Depletion Compression phase 2 project, both from PDO, Larsen & Toubro is targeting the Dolphin gas compression expansion EPC contract against its main competitors Dodsal and Punj Llyod from India, GS engineering & Construction from South Korea, Saipem from Italy and Technip from France. 

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Keppel Subic to build Malampaya compression platform

On December 7th 2012, Shell Philippines Exploration B.V. (Shell), Chevron Malampaya LLC (Chevron), Philippines National Oil Company Exploration Corporation (PNOC) will celebrate the kick off of the Malampaya Phase 3 project with a “Strike steel” ceremony in the Keppel Subic Shipyard in Zampales, Philippines.

This Malampaya Phase 3 project is part of the expansion of the Malampaya Deep Water Gas-To-Power project to explore and develop the offshore natural gas field under the Service Contract 38 license in the Philippines.

During this ceremony, Shell and its partners in the Service Contract 38 license will assist to the cutting of the first steel plate to be used for construction of the third Malampaya compression platforms.

Within this Service Contract 38, Shell and its partners share the consortium working interests in the Malampaya gas field with:

 - Shell 45% is the operator

 - Chevron 45%

 - PNOC 10%

Discovered in the 1990, the Malampaya gas field is located 80 kilometers northwest of Palawan island, about 3,000 meter depth from the sea level.

Very quickly the finding appeared to be significant with:

 - 2.7 trillion cubic feet (tcf) of natural gas

 - 85 million barrels of condensate

Then Shell and it partners had to over come multiple challenges to develop the Malampaya gas field which started commercial operations in 2001 and required $4.5 billion capital expenditure.

While the gas field is located in deep water, the production platforms could be located in the shallow water, at the limit of the continental shelf.

The Malampaya Deep Water Gas-To-Power includes:

 - Offshore production platform with separation of the condensate

 - Export gas pipeline from the Malampaya gas field to the Batangas island 500 kilometers north

 - Catenary-anchored leg mooring boy for the export of the condensate

 - Onshore gas central processing facility (CPF) on the Batangas Island

Then the CPF supply 2.700 MW power plant for Luzon.

After 10 years production, Shell, Chevron and PNOC had to work on new investment to compensate the depletion of the actual Malampaya gas field.

Fluor won Shell Malampaya Phase 3 EPCM contract

Shell and its partners, Chevron and PNOC, made the final investment decision (FID) for Malampaya expansion project comprising two phases:

 - Phase 2 is to increase production capacity in drilling and developing additional wells

 - Phase 3 includes a new depletion compression platform to be linked to the existing one.

The phase 2 should cost $250 million and should be completed in 2014.

The phase 3 is budgeted for $750 million capital expenditure and planned to come on stream in 2015.

This platform will be the first of that kind to be designed engineered and constructed in Philippines.

The Texas-based engineering company Fluor completed the front end engineering and design (FEED) of the Malampaya compression platform in its Manila and Cebu offices in Philippines.

Then Fluor Offshore Solutions has been awarded the engineering, procurement and construction (EPC) support contract.

In this contract Fluor with provide Shell, Chevron and PNOC with detailed design, engineering, procurement and execution support services for the supervision of the plaform frame sub-contracted to the local Keppel Subic Shipyard in Zampales.

With this Malampaya phase 3, Shell,Chevron and PNOC are offering to Philippines the first offshore compression platform of that kind made locally including the topsides. 

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Heerema won Alba third compression platform EPCI

In April 2013, the Houston-based Marathon Oil Corporation (Marathon) and its partners, Noble Energy (Noble) and the Compania Nacional de Petroleos de Guinea Ecuatorial (GE Petrol) awarded the engineering, procurement, construction and installation (EPCI) contract to Heerema Fabrication Group (HFG) for the Alba PSC B3 gas compression platform.

To be located offshore Equatorial Guinea, the Alba gas field lies by 75 meters shallow water depth of the West Africa Continental Shelf, 32 kilometers north of Bioko Island.

Discovered in 1984, the Alba wet gas field entered into production in 1991.

Since 2002, Marathon, through its local subsidiary Marathon Equatorial Guinea Production Ltd (GE Petrol) is developing the non-associated gas of the Alba field with Noble represented by its local company Samedan of North Africa Inc. (Samedan), and the local CNPGE.

All together they share the working interests in the Alba gas field in the following way:

 - Marathon 63% is the operator

 - Noble 34%

 - GE Petrol 3%

As a liquids rich gas field, the Alba field is currently one of the largest producer of natural gas and condensate of the Guinea Gulf.

Alba gas reserves are estimated to 4.6 trillion cubic feet (tcf) from which the production of condensate has reached 65,000 barrels per day (b/d).

Over the years Marathon and its partners expanded Alba offshore facilities with two production platforms B1 and B2 supporting 11 producing wells and 5 gas injection wells. 

The gas and condensate are extracted and exported to gas central processing facility (CPF) located onshore at Punta Europa on the Bioko Island.

Once treated the dry gas represents 130 million cf/d of feedstock to be converted into 3,000 tonnes per day (t/d) of methanol and 3.7 million t/t of liquefied natural gas (LNG).

With this monetization of the natural gas, Marathon contributed to eliminate the flared gas.

Marathon to ramp up gas supply to Bioko Island LNG 

In parallel the condensate are separated in five different natural gas liquids (NGL) such as butane and propane.

In these different gas treatment and monetization units, Marathon holds different working interests:

 - 52% in the Alba liquefied petroleum gas (LPG)

 - 45% in the Atlantic Methanol Production company (AMPCO)

 - 60% in the Bioko LNG plant.

In this context and in respect with the remaining reserves of the Alba wet gas field, Marathon and its partners, Noble and GE Petrol, have decided to continue the development of the Alba field with a third gas compression platform.

Headquartered in The Netherlands, Heerema Fabrication Group (HFG) won the EPCI contract to build this Alba B3 gas compression platform.

This B3 platform should be bridged to the existing B2 platform.

With a total weight of 6,000 tons, the topsides should count for 4,500 tons and the jacket for the remaining 1,500 tons.

These topsides have been designed to fit in a cube of 40 meters side and the jacket as a square of 33 meters side supported by 81 meters height legs.

Designed at front end engineering and design (FEED) stage by Wood Group, the Alba B3 compression platform should have a capacity of:

 - 990 million cf/d of natural gas

 - 75,240 b/d of condensate

Heerema will subcontract the process part of the detailed design to  lv-Oil & Gas also from the Netherlands.

In close co-operation with Marathon, lv-Oil & Gas will executes its section of the contract from its Houston, Texas, office.

The transportation and installation will be performed by the Heerema Leiden office in The Netherlands.

The flare structure and the bridge will be executed in Equatorial Guinea as part of the local content of the Alba B3 gas compression platform project.

With this EPCI contract awarded to Heerema, Marathon and its partners, Noble and GE Petrol, are expected to install the Abla B3 gas compression platform in 2015 for commercial operations to start in 2016.

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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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Kingfisher to lead Lake Albert and refinery projects

After resolving tax and refinery disagreements between Tullow Oil plc (Tullow) from UK, Total from France, the China National Offshore Oil Corporation (CNOOC) from China and the Uganda Government, the Kingfisher project is ready to take off.

The Kingfisher project is to develop the previously called Block-3A located in the northwest of Uganda along the shores of Lake Albert.

Discovered in 1938, the Albert Lake Rift Basin had been left unexplored during 60 years.

Tullow took first interests in Uganda in 2004 and performed the Kingfisher-1 discovery in the Block-3A in 2006.

Then Tullow acquired 100% interests of the Block-2 in 2007 and of the Block-1 in 2010.

Along this period of exploration, the estimation of the recoverable reserves were continuously revised upward to actually exceed 2 billion barrels of oil equivalent (boe) concentrating approximately 60% of all the Uganda reserves.

The development of these Blocks in the Albertine Rift Basin may require more than $15 billion capital expenditure on the top of which should be added all the costs of infrastructures to export and/or transport the oil and gas from this far remote area.

In this context, Tullow offered in 2011 to share interests with Total and CNOOC through a Sales and Purchase Agreement (SPA) that should leave each partner with 33% ownership of each blocks.

In 2012, the Uganda Government approved the farm-out agreement between Tullow and its partners where:

 - Total holds 33% of the Block-1 and is the operator in partnership with Tullow and CNOOC

 - Tullow owns 33% of the Block-2 and is the operator in partnership with Total and CNOOC

 - CNOOC takes 33% of the Block-3A, renamed Kingfisher, and is the operator in partnership with Total and Tullow

In respect with the size and reserves of the three blocks the development capital expenditure of the three blocks should be split:

 - Block-1 $7 billion

 - Block-2 $4 billion

 - Block-3A $4 billion

Among these fields, Kingfisher (Block-3A) should be the first block to be developed under the lead of CNOOC.

Petrofac completed Kingfisher pre-FEED for CNOOC

In 2012, CNOOC awarded the pre-front end engineering and design (pre-FEED) to Petrofac from UK.

From this pre-FEED, CNOOC could organize the call for tender for the front end engineering and design (FEED) contract.

Currently CNOOCand its partners Tullow and Total are evaluating the technical and commercial offers submitted by:

 - Saipem from Italy

 - Wood Group from UK

 - WorleyParsons from Australia

Petrofac did not compete in the FEED as it wants to be listed for the engineering, procurement and construction (EPC) contract to be invited to bid (ITB) after the completion of the FEED work.

In respect with Kingfisher estimated reserves of 800 million boe, Petrofac could develop a comprehensive pre-FEED so that the FEED contract should cover:

 - Well pad design

 - Flowlines and gathering system

 - Process scheme and production

 - Water injection

 - Water station

 - Central processing facility (CPF)

 - Tanks farm

 - Trucks loading facilities

 - Power generation

The central processing facility should be located at Buhuka.

In a first phase, this central processing facility should have a capacity of 20,000 barrels per day (b/d) that should be expanded to 40,000 b/d in a second phase.

In this first phase the crude oil will be exported through 85 kilometers pipeline to a greenfield refinery to be located in Hoima.

This refinery is subject to intensive discussions between Tullow, Total, CNOOC and Uganda Government as the companies would like to size it just to meet the domestic market while the Government aims at favoring the transformation in Uganda to export higher added value with refined products.

For instance they compromised on a 30,000 b/d capacity that should be expanded in the future to 60,000 b/d in respect with the domestic market demand.

In parallel, Tullow, Total and CNOOC are working on different alternatives of export pipelines:

 - 250 kilometers to Jinja

 - To Tanzania coast in turning around the Great Lakes

 - To Mombasa or Lamu on the Kenya coast

With the FEED contract to be awarded soon, CNOOC and its partners Tullow and Total expect Kingfisher (Block-3A)  and the Hoima refinery to start commercial operations in 2017.

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Daewoo Engineering wins Akkas Gas processing plant

The South Korean Gas Corporation (KOGAS) and the local Iraq National Oil Company (INOC) have awarded to Daewoo Engineering, & Construction Corporation (Daewoo Engineering) also from South-Korea, the engineering, procurement and procurement (EPC) contract for the gas central processing facility (CPF) of the Akkas gas field in the western of Iraq.

Located in the Al-Anbar Province, 460 kilometers northwest of Bagdad, close to the Syrian border, Akkas is the first non-associated gas field to be developed as part of the license rounds proposed by the Iraq Federal Government to foreign companies after the second Iraq war.

From the actual level of exploration the Akkas gas field is expected to hold between 3.3 and 5.6 trillion cubic feet (tcf) reserves of non-associated natural gas from which KOGAS and its partner NOC are planning to extract more than 2.1 tcf.

In October 2010, KOGAS in joint venture with KazMunaiGas (KMG) from Kazakhstan and the Iraq state owned company INOC applied to participate to the reverse auctions of the third license round organized by the Iraq Federal Government.

These license rounds were based on Technical Service Contracts (TSC) meaning that the winner of the bid is supporting all investment until a plateau production level above which it is compensated by a remuneration fee per barrel produced.

Since the contract is defined as “technical”, this remuneration fee is fixed regardless the commercial value of the oil and gas. 

In October 2011, KOGAS and its partners were awarded the Technical Service Contracts (TSC) for the Akkas gas field with a remuneration fee of $5.50 per barrel of oil equivalent (boe) based on a plateau production of 400 million cubic feet per day (cf/d) during 13 years.

KOGAS to meet Iraq Government plateau production

In the meantime KMG withdrew from the project and sold its shares in the Akkas gas field to KOGAS to stand alone with the local NOC and share the working interests such as:

 - KOGAS 75% is the operator

 - INOC25%

In addition to Akkas, KOGAS has interests in three other oil and gas field development projects in Iraq:

 - Badra crude oil field in the northeast of Bagdad with Gazprom, Petronas, TPAO and OEC

 - Mansuriya natural gas field in the southeast of Bagdad with TPAO, Kuwait Energy Co. (KEC) and OEC

 - Zubair crude oil field near Basra in the south of Iraq with Eni, Occidental Petroleum (Oxy) and MOC

The Akkas gas field is covering 986 square kilometers and should require $2.66 billion capital expenditure from KOGAS as part of its Technical Service Contracts (TSC).

In October 2012, KOGAS completed the front end engineering and design (FEED) for the development of the Akkas gas field. 

Despite the danger of the Al-Anbar Province along the Syrian border where KOGAS contractors had workers killed and kidnapped in April, KOGAS received four bids for the EPC contract  of the Akkas gas central processing facility (CPF).

From this call for tender, the South-Korean Daewoo Engineering company submitted the most competitive bid, just below $800 million. 

With a capacity of 400 million cf/d of natural gas in line with the contractual plateau production level, this EPC contract includes the:

 - Akkas gas central processing facility (CPF)

 - Associated gas gathering inlet pipeline

 - Export pipeline

In awarding the Akkas gas central processing facility (CPF) to Daewoo Engineering in July, KOGAS and INOC are targeting the first production in 2015.

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Saudi Aramco to evaluate Fadhili gas plant FEED bids

The national oil company Saudi Aramco is currently evaluating the tenders submitted by the qualified engineering companies in competition to provide the Fadhili Gas Processing Plant project with the front end engineering and design (FEED) work.

This project is part of Saudi Arabia program to develop natural gas production from onshore and offshore gas fields as well as the associated gas from the oil fields currently in production.

Although Saudi Arabia holds the sixth largest reserves of natural gas  in the world, the country is continuously suffering of shortage since the expansion of the petrochemical and power generation sectors.

In addition the widening gap between the crude oil price and the gas price is motivating Saudi Arabia to convert the use of crude oil and naphtha as feedstock into cheaper natural gas  and condensate.

In this context, Saudi Arabia is aiming at producing 15 billion cubic feet per day (cf/d) of natural gas  in 2018.

With this perspective, Saudi Aramco is working on:

 - Gathering the associated gas from the giant Khursaniyah oil field

 - Developing the non-associated gas from Arabiyah, Hasbah and Karan gas fields.

In this program the main challenge relies on the high sulfur content of the gas with the consequences to increase the production costs and to cause delays as experienced in the Wasit gas development project.

Saudi Aramco qualified bidders beyond GES-plus list

Because of these challenges Saudi Aramco decided to enlarge the list of the bidders beyond the engineering companies pre-qualified through their General Engineering Services-plus (GES-plus) contract.

Originally Saudi Aramco had put in place the GES-plus scheme with foreign engineering companies in order to develop the local content of the FEED work through alliances with local contractors and services companies.

In counter part of the efforts of these foreign companies to train local engineers and share knowledge with Saudi third parties, Saudi Aramco would give them the first priority on any FEED work to come.

To guaranty to these companies some kind of break-even profit, Saudi Aramco selected only five companies to join this GES-plus scheme: Jacobs Engineering (Jacobs), KBR, Mustang Engineering (Mustang), Foster Wheeler and SNC Lavalin.

Currently WorleyParsons replaces Foster Wheeler in that GES-plus list.

From this base of the GES-plus listed engineering companies (Jacobs,KBR, Mustang , SNC Lavalin and WorleyParsons) , Saudi Aramco re-qualified Foster Wheeler and added Fluor to be invited to bid on the Fadhili Gas central Processing facility (CPF) project as long as these companies commit to perform 36% of the estimated 400,000 man-hours in the Kingdom.

Located in the Eastern Province with a capacity of 1 billion cf/d of sour gas the Fadhili Gas CPF should include:

 - Raw gas inlet and processing facilities

 - Natural gas liquids (NGL) fractionation unit

 - Sulphur recovery unit

 - Dedicated co-generation power plant

Through this process, the Fadhili Gas CPF project should deliver 520 million cf/d of natural gas to the market.

Saudi Aramco is planning  this FEED contract to take nine months so that the engineering, procurement and construction (EPC) should be awarded on the third quarter 2014 for commercial operations in 2018.

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

Shell and ExxonMobil court InterOil for new LNG project

The super major companies Shell from The Netherlands and ExxonMobil from USA are head to head in intensive negotiations with InterOil Corporation (InterOil) for the development of world scale liquefied natural gas (LNG) projects in Papua New Guinea (PNG).

Listed in New York Stock Exchange, InterOil was established in 1997 to take a leading role in the energy sector of Papua New Guinea.

After building up and operating the first crude oil refinery in Port Moresby, Papua New Guinea, InterOil took over Shell retail and distribution network in Papua New Guinea in 2006.

In parallel InterOil acquired its first licenses for oil and gas exploration in 2005.

After the first discoveries in Moose in 2005, the Elk and Antelope appeared to be promising enough  to support a LNG project.

In 2010 GLJ Petroleum Consultants estimated the resources in:

 - Elk to 631 billion of barrel equivalent oil (boe)

 - Antelope to 1.52 billion boe.

Based on these reserves, InterOil made several attempts for joint venture and frame agreement with other junior companies to develop different LNG projects.

Until end of 2012, none of these  projects could reach the final investment decision (FID) in the time frame allowed by the licenses awarded to InterOil.

As a result in November 2012, the Government of Papua New Guinea decided to increase its stake in the Gulf LNG Project from the original 22.5% to 50%.

In addition and in order to secure the flawless execution of the project, PNG Government and InterOil decided to set partnership with a major company providing its technological expertise and project management experience for a world scale LNG project.

In this scenario the Gulf LNG project should be phased up with a first LNG plant sized at 3.8 million t/y of LNG instead of the original 8 to 10 million t/y.

This first phase should come on stream in 2016 and should be followed up by a second and a third phase expected to start commercial operations in 2018 and 2020.

Gulf LNG in competition with PNG LNG expansion

The Gulf LNG project has been designed around two packages, upstream and midstream.

The upstream part of InterOil Gulf LNG project should include:

 - 11 production wells in Elk and Antelope fields

 - Water injection wells

 - Compression facilities

 - Gas central processing facility (CPF) with 1,800 cubic feet per day (cf/d) capacity

 - 120 kilometers dry gas export pipeline and condensate pipeline

 - 100,000 barrels condensate storage facilities

 - Condensate offloading facilities to ships

The midstream package of InterOil Gulf LNG projects should cover:

 - Three LNG Trains of 3.8 million t/y each

 - LNG storage tank farm

 - LNG export terminal with connecting and offloading system

 - Offsites and utilities

 - Campground

Based on this front end engineering and design (FEED) InterOil and the PNG Government have initiated discussion with Shell to take shares in the project.

In the meantime, ExxonMobil and InterOil signed an exclusive provision by which ExxonMobil would acquire 4.6 trillion cubic feet from the Elk and Antelope fields.

With this additional supply of natural gas, ExxonMobil could secure the feedstock for a third LNG Train at its ongoing PNG LNG project.

ExxonMobil is currently completing the $19 billion construction of the two first LNG Trains in Papua New Guinea where the existing infrastructures were designed to support two additional trains with a capacity of 6.9 million t/y.

In a way the PNG Government realizes that ExxonMobil solution offers the simplest and most profitable solution to develop the Elk and Antelope gas fields but in another way the partnership between Shell and InterOil would balance ExxonMobil position in Papua New Guinea.

For these reasons, it could also be that InterOil and Papua New Guinea Government decide to develop both projects, first Gulf LNG Train with Shell, and  third PNG LNG Train with ExxonMobil in parallel in order to avoid further delays to sign LNG export agreements.

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

Kenai Peninsula selected to host Alaska SC LNG Trains

The super major companies ExxonMobil, BP, ConocoPhillips and TransCanada have selected Nikiski on the Kenai Peninsula in South Central Alaska to locate the liquefied natural gas (LNG) plant for their giant Alaska South Central (SC) LNG Project.

Over the last years these companies realized that the huge discoveries of natural gas accumulated in Alaska North Slope could no longer be exported to USA after the glut of production generated by the domestic shale gas.

From the last estimation the North Slope is containing more than 200 trillion cubic feet (tcf) probable reserves of natural gas out of which  a first 35 tcf have already be qualified as proven reserves.

With the evolution of the technology, there is no doubt that a significant share of these probable reserves should be converted into proven reserves.

Sitting on one of the largest reserves of natural gas in the world, after investing $700 million capital expenditure, ExxonMobil, BP, ConocoPhillips and TransCanada need to find urgently a way out of the North Slope that had appeared first a promising highway to bonanza and turned to a non-drive end.

In 2012, ExxonMobil, BP, ConocoPhillips and TransCanada mobilized 200 of their best specialists for brain storming and proposing recommendations of possible North Slope ways out.

The partners shared the work load so that:

 - BP is in charge of the upstream side of the project to maximize gas production from the North Slope

 - ConocoPhillips is focusing on the LNG plant

 - ExxonMobil is performing the technical studies of the project

From these conclusions, 20 locations were shortlisted to install the Alaska South Central LNG Trains plant on the south coast of Alaska.

After inspecting all these places, ExxonMobil, BP, ConocoPhillips and TransCanada have selected Nikiski on the Kenai Peninsula in South Central Alaska.

Alaska SC LNG to benefit from ConocoPhillips Kenai

It happens that ConocoPhillips had established a first LNG plant in Kenai about 40 years ago.

Even though the new Alaska SC LNG project should be erected in a different site, the currently running Kenai LNG plant and export terminal will provide the partners with reliable record of data about the region.

With capital expenditure estimated to range between $45 and $65 billion, ExxonMobil, BP, ConocoPhillips, and TransCanada are working on the pre-front engineering and design (pre-FEED).

From the team work performed by the partners at the conceptual level, the Alaska SC LNG Project should include:

 - Gas central processing facility (CPF) located on the coast of the North Slope to proceed to a first treatment of the raw gas before transportation.

 - 1,200 kilometers and 42-inch export pipeline from the North Slope gas CPF to the South Central LNG plant

 - Eight compression station along the export pipeline

 - Five take-off points for local delivery

 - Alaska Nikiski LNG Plant

 - Ice-free sea water marine terminal

The pipeline will have a transportation capacity of 3 billion cubic feet per day (cf/d) of natural gas.

From ConocoPhillips expertise with its proprietary Cascade LNG process, the Alaska SC LNG Plant should be designed around three LNG Train with a total capacity of 15 to 18 million tonnes per year (t/y).

After selecting Nikiski in the Kenai Peninsula, ExxonMobil, BP, ConocoPhillips and TransCanada are targeting to complete the front end engineering and design (FEED) in 2016 for first production in 2020.

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

Uzekistan Lukoil Kandym FEED work nears completion

The Russia largest privately-owned company Lukoil Oil Company (Lukoil) and the national oil company (NOC) Uzbekneftegas National Holding Company (Uzbekneftegas) are completing the front end engineering and design (FEED) work for the expansion of the Kandym gas field in the Bukhara region, at the center west of Uzbekistan.

In June 2004, Lukoil and the State-owned company Uzbekneftegas signed a production sharing agreement (PSA) to develop three gas fields in Uzbekistan, named Kandym, Khauzak and Shady.

In this PSA, Lukoil and Uzbekneftegas agreed to cooperate in the development of these gas fields and to share the working interests during 35 years in such a way that:

 - Lukoil 85%

 - Uzbekneftegas 15%

At that time the first target is to appraise these fields to evaluate the size and the quality of their reserves in natural gas.

The first production started from the Khaukaz and Shady gas fields in 2007.

In November 2011, Lukoil and Uzbekneftegas extended the production to the Shady West area so that in 2012 the Khaukaz and Shady gas fields could deliver:

 - 3.8 billion cubic meters of gas

 - 19,000 tonnes of condensate

In parallel to this first phase of development, Lukoil and Uzbekneftegas completed their evaluations of commercial reserves in natural gas and condensate of the three fields.

With 26 billion cubic meters additional reserves of gas, Lukoil and Uzbekneftegas initiated the second phase of the project with the development of the north Shady area.

This expansion should start commercial operations in 2014.

 So far the exploration and development of the Khaukaz – Kandym – Shady gas fields required $2.5 billion capital expenditure and now Lukoil and Uzbekneftegas are preparing to invest an additional $3 billion to develop Kandym along the boarder with Turkmenistan.

Hyundai Engineering completed Kandym FEED

In August 2011, Lukoil and Uzbekneftegas sanctioned the call for tender of the pre-front end engineering and design (pre-FEED) and FEED to Hyundai Engineering Construction Ltd (Hyundai Engineering) for the Kandym Group of Fields Development project.

In that respect the Kandym project covers in fact the development of 6 gas and condensate fields: Akkam, Kandym, Khodji, North Shady, Parsankul and West Khodji, all located in the Karakul District of the Bukhara Region.

The gas treatment strategy as these fields took more time to Lukoil and Uzbekneftegas as the reservoirs contain a high content of hydrogen sulfides.

In March 2012 Lukoil and Uzbekneftegas established the Kandym Enterprise Construction Directorate to run the joint venture dedicated to this Kandym Group of Fields Development project.

From the FEED work completed by Hyundai Engineering, the Kandym project should include:

 - 100 gas production wells

 - 400 kilometers of gas gathering pipelines system

 - Gas booster compression station

 - Gas central processing facility (CPF)

 - 70 kilometers export pipeline

 - Gas treatment facilities

 - 90 kilometers water inlet pipeline

 - Water treatment facilities

 - 80 MW gas-fired power plant

 -  Storage and loading terminal for natural gas, condensate and granulated sulfur

 - Campground for 1400 persons

The Kandym Gas central processing facility (CPF) should have a capacity of 810 million cubic feet per day (cf/d).

The compression stations to boost the gas to the Kandym Gas central processing facility (CPF) should be located at Kuvachi-Alat and Northern Shady.

As the project has been approved by the Uzbek Government, Lukoil and Uzbekneftegas are planning Hyundai Engineering to start the engineering, procurement and construction (EPC) work of the Kandym project on the second half 2014 in expecting the first train of the Kandym central processing facility to come into commercial operations at the end of 2016.

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

Petroceltic to prepare FEED on Ain Tsila development

The Irish junior company Petroceltic International plc (Petroceltic) and its partners, the Algerian national oil company (NOC) Sonatrach and the Italian utility Enel, are preparing to move into the front end engineering and design (FEED) phase of the Ain Tsila discovery within the Isarene gas and condensate field in the center east of Algeria.

Based in Dublin, Petroceltic has a strong focus on Algerian resources as one of the key supplier of Europe in Gas.

Petroceltic signed the Isarene production sharing contract (PSC) in 2004 and proceeded with the first exploration phase of the Isarene area until August 2012.

After the Ain Tsila discovery, Petroceltic and its partners Sonatrach and Enel could post their Declaration  of Commerciality (DOC) and obtain the approval from the Algerian Authorities for the corresponding development plan in December 2012.

In line with the Isarene PSC, the full field development plan has been registered for a 30 years period in beginning with the Ain Tsila project.

Over the years there were some changes in the ownership of the Isarene PSC with Petroceltic farm-out agreements to Sonatrach and Enel in 2012.

As a result the actual situation of Isarene field working interests stand as following:

 - Petroceltic 38.25% is the operator

 - Sonatrach 43.375%

 - Enel 18.375%

Located in the liquids-rich Illizi Basin, the Ain Tsila discovery is estimated to hold 304 million barrels of oil equivalent (boe) of proven and probable reserves (2P).

Petroceltic Ain Tisla CPF to be similar to BHP Ohanet

From the 2P reserves and along the 30 years of the Isarene PSC, Petroceltic and its partners are planning to extract:

 - 2.2 trillion cubic feet (tcf) of gas

 - 70 million barrels of condensate

 - 113 million barrels of liquid petroleum gas (LPG)

To do so, Petroceltic development program for the Ain Tisla project is to maintain the plateau production during 14 years at 355 million cubic feet per day (cf/d) of wet gas.

In that perspective the Ain Tsila project includes:

 - 124 vertical wells

 - Gas central processing facility (CPF)

 - Water separation

 - Condensate and LPG recovery units

 - Gas compression unit

 - Export pumps

 - 100 kilometers export pipeline to the Tin Fouye Tabankort (TFT) field for connection into the Algeria Gas Transmission System.

The Ain Tsila project feasibility study was completed in 2012 but the In Amenas attack, less than 100 kilometers away, had slowed down the development program.

 So the FEED work for the Ain Tsila project originally planned in 2013 should start in 2014.

After a first series of 18 vertical wells, Petroceltic and its partners, are planning to cadence 12 new wells per year.

From the first phase the Ain Tsila central processing facility should be very similar to the BHP Billiton Ohanet project with a single train of 355 million cf/d capacity of wet gas.

In awarding the FEED contract in 2014, Petroceltic and its partners Sonatrach and Enel are expecting to sanction the Ain Tsila engineering, procurement and construction (EPC) contract in 2015 for the first production to start in 2017.

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

Weatherford completed Gharraf oil field FEED work

The Swiss-based oil and gas fields services company Weatherford International Ltd (Weatherford) completed the front end engineering and design (FEED) of the Gharraf, or Garraf,  oil and gas field operated by the Malaysia national oil company (NOC) Petronas, Japan Petroleum Exploration (Japex) and the local North Oil Company  (NOC) in Iraq.

Located at the northwest of Al-Refaei, approximately 85 kilometers north of the City of Nasiriya somewhere half way between the Tigris and Euphrates rivers in the southeast of Iraq, Gharraf is ranked as the fifth largest oil and gas field in Iraq with reserves estimated to 1 million barrels of oil equivalent (boe).

Discovered only in 1984, Gharraf had been awarded during the second license round by the Iraq Government to Petronas and its partners Japex and NOC.

At that time Petronas and its partners accepted a Technical Services Contract (TSC) from Baghdad with a remuneration fee of $1.49 per barrel (RFB).

In this typical Iraq license round TSC, Petronas and its partners are sharing the working interests such as:

 - Petronas 45% is the operator

 - Japex 30%

With this short compensation Petronas and its partners committed to invest in order to increase the production from current 35,000 barrels per day (b/d) to 230,000 b/d of oil and gas,out of the Gharraf by 2017. 

In 2011 Petronas start drilling operations and mandated Weatherford to perform the FEED work for the development of the field.

Petronas to add three processing trains in Garraf

From Weatherford conclusions, Petronas and its partners Japex and NOC decided to proceed with the Garraf Phase-1 project to increase the oil and gas production from the given 35,000 b/d to 100,000 b/d with the first two processing trains.

These first two trains are currently starting operations so that the targeted 100,000 b/d should be reached in 2014.

With the Garraf Phase-2 project, Petronas and its partners are intending to reach the committed plateau production of 230,000 boe/d in two steps.

The first step will see the addition of a new central processing facility (CPF) including:

 - Two new crude oil trains of treatment, the Trains 3 and 4

 - Gas treatment plant

Each crude oil train will have a capacity of 55,000 b/d while the gas plant should be able to treat 170 million cubic feet per day (cf/d).

With this Garraf Phase-2 first step Petronas and its partners should reach 200,000 b/d of crude oil.

The second step is to add a fifth train (Train 5), in order to reach the targeted plateau production of 230,000 b/d.

In this configuration, Petronas and its partners are preparing the call for tender for the engineering, procurement and construction (EPC) of this Garraf Phase-2 project in two packages:

 - EPC-1: Crude oil Trains 3, 4 and 5

 - EPC-2: Gas Treatment plant

With this definition, Petronas, Japex and North Oil Company are planning to issue the calls for tenders of the Garraf Phase-2 project on mid-2014 in expecting the Trains 3 and 4 and the gas treatment plant to be in operation by 2018 and the Train 5 by 2020.

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

Larsen & Toubro wins Oman PDO Saih Rawl phase 2

>On August 27th 2012, Petroleum Development Oman LLC (PDO) awarded to Larsen & Toubro from India the engineering, procurement and construction (EPC) contract for the Saih Rawl Depletion Compression Phase 2 (SRDC2) project.

Nine engineering companies were in competition to win this order of $235 million.

The Saih Rawl gas field is located in Center Oman where PDO started operations in 1991 with a large gas Central Processing Facility (CPF).

Then the natural gas is piped to the LNG Trains located at Qahlat for export and Sur Fertilizer plant.

After years of production the Saih Rawl gas field is maturing and losing a part of its natural pressure.

PDO invested $550 million in the Saih Rawl Depletion Compression phase 1 (SRDC1) project to boost Saih Rawl gas field in using the depletion compression process.

The depletion compression is reducing the back-pressure at the wellhead to boost the gas inlet pressure from 35 to 96 bar for export.

Anyway and despite the installation and commissioning of the Saih Rawl Depletion Compression phase 1 last year, the natural depletion of the Saih Rawl gas field continues so that the inlet pressure at the CPF should come down to 13 bar by 2015.

In that perspective PDO anticipates with Saih Rawl Depletion Compression phase 2 project.

In its EPC contract Larson & Toubro‘s scope of work includes:

 – 4 parallel compression trains of 76 MW for a total capacity of 30 million standard cubic meter per day (mmscmd) of gas

 – Modifications of the condensate handling system at the Saih Rawl CPF

 – Installation of a pair of inlet separators for a total capacity of 18 mmscmd

PDO and Larsen & Toubro are planning the completion of the Saih Rawl Depletion Compression phase 2 project in 2014.

Larsen & Toubro aims at Qatar Dolphin gas compression

Larsen & Toubro is one of the six engineering companies in competition for the Dolphin Energy Ltd (Dolphin) gas compression expansion project in Ras Laffan Indusrial City in Qatar.

Created in 1999, Dolphin is a joint venture based in Abu Dabi, UAE, between:

 – Mubadala, a wholly owned Abu Dhabi Government national oil company (NOC), 51%

 – Total from France 24.5%

 – Occidental Petroleum from USA 24.5%

If the Abu Dhabi Emirate is rich of oil, it is short of natural gas.

With a local natural gas demand increasing for power generation, gas injection and petrochemicals applications, Abu Dhabi created Dolphin Energy to treat and export natural gas from Qatar to the UAE.

In the agreement between Qatar and Abu Dhabi, the raw natural gas is processed in Ras Laffan Industrial City to produce:

 – Natural gas (methane) exported to the UAE

 – Ethane used as feedstock locally for the Ras Laffan petrochemical industry

 – other NGL such as propane and butane for international trading.

In 2007, JGC from Japan built up the first Dolphin gas compression facility with capacities of:

 – 110,000 b/d of condensate

 – 4,400 t/d of ethane

 – 2,800 t/d of propane

 – 1,800 t/d of butane

Now Dolphin is planning the expansion of the existing Ras Laffan gas central processing facility (CPF).

The expansion of Dolphin Ras Laffan gas CPF is supposed to include:

 – Gas compression facility of 1 billion cf/d additional capacity of natural gas

 – Upgrade Ras Laffan Dolphin utilities

 – Piping and hydraulic work

This expansion is to match with the available capacity of the 364 kilometer gas pipeline connecting Qatar to the UAE across the Arabian Gulf.

Designed and installed by Saipem in 2006 for a capacity of 3.2 billion cf/d of natural gas, the Dolphin gas pipeline is currently operated at 2 billion cf/d.

The Dolphin Ras Laffan gas compression project is to fill up the capacity of the Dolphin gas pipeline with this addition 1 billion cf/d expansion. 

With capital expenditure estimated around $250 million, Dolphin is planning the completion in 2015.

After winning the Lekhwair Gas Field Development project  and the Saih Rawl Depletion Compression phase 2 project, both from PDO, Larsen & Toubro is targeting the Dolphin gas compression expansion EPC contract against its main competitors Dodsal and Punj Llyod from India, GS engineering & Construction from South Korea, Saipem from Italy and Technip from France. 

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Keppel Subic to build Malampaya compression platform

On December 7th 2012, Shell Philippines Exploration B.V. (Shell), Chevron Malampaya LLC (Chevron), Philippines National Oil Company Exploration Corporation (PNOC) will celebrate the kick off of the Malampaya Phase 3 project with a “Strike steel” ceremony in the Keppel Subic Shipyard in Zampales, Philippines.

This Malampaya Phase 3 project is part of the expansion of the Malampaya Deep Water Gas-To-Power project to explore and develop the offshore natural gas field under the Service Contract 38 license in the Philippines.

During this ceremony, Shell and its partners in the Service Contract 38 license will assist to the cutting of the first steel plate to be used for construction of the third Malampaya compression platforms.

Within this Service Contract 38, Shell and its partners share the consortium working interests in the Malampaya gas field with:

 – Shell 45% is the operator

 – Chevron 45%

 – PNOC 10%

Discovered in the 1990, the Malampaya gas field is located 80 kilometers northwest of Palawan island, about 3,000 meter depth from the sea level.

Very quickly the finding appeared to be significant with:

 – 2.7 trillion cubic feet (tcf) of natural gas

 – 85 million barrels of condensate

Then Shell and it partners had to over come multiple challenges to develop the Malampaya gas field which started commercial operations in 2001 and required $4.5 billion capital expenditure.

While the gas field is located in deep water, the production platforms could be located in the shallow water, at the limit of the continental shelf.

The Malampaya Deep Water Gas-To-Power includes:

 – Offshore production platform with separation of the condensate

 – Export gas pipeline from the Malampaya gas field to the Batangas island 500 kilometers north

 – Catenary-anchored leg mooring boy for the export of the condensate

 – Onshore gas central processing facility (CPF) on the Batangas Island

Then the CPF supply 2.700 MW power plant for Luzon.

After 10 years production, Shell, Chevron and PNOC had to work on new investment to compensate the depletion of the actual Malampaya gas field.

Fluor won Shell Malampaya Phase 3 EPCM contract

Shell and its partners, Chevron and PNOC, made the final investment decision (FID) for Malampaya expansion project comprising two phases:

 – Phase 2 is to increase production capacity in drilling and developing additional wells

 – Phase 3 includes a new depletion compression platform to be linked to the existing one.

The phase 2 should cost $250 million and should be completed in 2014.

The phase 3 is budgeted for $750 million capital expenditure and planned to come on stream in 2015.

This platform will be the first of that kind to be designed engineered and constructed in Philippines.

The Texas-based engineering company Fluor completed the front end engineering and design (FEED) of the Malampaya compression platform in its Manila and Cebu offices in Philippines.

Then Fluor Offshore Solutions has been awarded the engineering, procurement and construction (EPC) support contract.

In this contract Fluor with provide Shell, Chevron and PNOC with detailed design, engineering, procurement and execution support services for the supervision of the plaform frame sub-contracted to the local Keppel Subic Shipyard in Zampales.

With this Malampaya phase 3, Shell,Chevron and PNOC are offering to Philippines the first offshore compression platform of that kind made locally including the topsides. 

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

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Heerema won Alba third compression platform EPCI

In April 2013, the Houston-based Marathon Oil Corporation (Marathon) and its partners, Noble Energy (Noble) and the Compania Nacional de Petroleos de Guinea Ecuatorial (GE Petrol) awarded the engineering, procurement, construction and installation (EPCI) contract to Heerema Fabrication Group (HFG) for the Alba PSC B3 gas compression platform.

To be located offshore Equatorial Guinea, the Alba gas field lies by 75 meters shallow water depth of the West Africa Continental Shelf, 32 kilometers north of Bioko Island.

Discovered in 1984, the Alba wet gas field entered into production in 1991.

Since 2002, Marathon, through its local subsidiary Marathon Equatorial Guinea Production Ltd (GE Petrol) is developing the non-associated gas of the Alba field with Noble represented by its local company Samedan of North Africa Inc. (Samedan), and the local CNPGE.

All together they share the working interests in the Alba gas field in the following way:

 – Marathon 63% is the operator

 – Noble 34%

 – GE Petrol 3%

As a liquids rich gas field, the Alba field is currently one of the largest producer of natural gas and condensate of the Guinea Gulf.

Alba gas reserves are estimated to 4.6 trillion cubic feet (tcf) from which the production of condensate has reached 65,000 barrels per day (b/d).

Over the years Marathon and its partners expanded Alba offshore facilities with two production platforms B1 and B2 supporting 11 producing wells and 5 gas injection wells. 

The gas and condensate are extracted and exported to gas central processing facility (CPF) located onshore at Punta Europa on the Bioko Island.

Once treated the dry gas represents 130 million cf/d of feedstock to be converted into 3,000 tonnes per day (t/d) of methanol and 3.7 million t/t of liquefied natural gas (LNG).

With this monetization of the natural gas, Marathon contributed to eliminate the flared gas.

Marathon to ramp up gas supply to Bioko Island LNG 

In parallel the condensate are separated in five different natural gas liquids (NGL) such as butane and propane.

In these different gas treatment and monetization units, Marathon holds different working interests:

 – 52% in the Alba liquefied petroleum gas (LPG)

 – 45% in the Atlantic Methanol Production company (AMPCO)

 – 60% in the Bioko LNG plant.

In this context and in respect with the remaining reserves of the Alba wet gas field, Marathon and its partners, Noble and GE Petrol, have decided to continue the development of the Alba field with a third gas compression platform.

Headquartered in The Netherlands, Heerema Fabrication Group (HFG) won the EPCI contract to build this Alba B3 gas compression platform.

This B3 platform should be bridged to the existing B2 platform.

With a total weight of 6,000 tons, the topsides should count for 4,500 tons and the jacket for the remaining 1,500 tons.

These topsides have been designed to fit in a cube of 40 meters side and the jacket as a square of 33 meters side supported by 81 meters height legs.

Designed at front end engineering and design (FEED) stage by Wood Group, the Alba B3 compression platform should have a capacity of:

 – 990 million cf/d of natural gas

 – 75,240 b/d of condensate

Heerema will subcontract the process part of the detailed design to  lv-Oil & Gas also from the Netherlands.

In close co-operation with Marathon, lv-Oil & Gas will executes its section of the contract from its Houston, Texas, office.

The transportation and installation will be performed by the Heerema Leiden office in The Netherlands.

The flare structure and the bridge will be executed in Equatorial Guinea as part of the local content of the Alba B3 gas compression platform project.

With this EPCI contract awarded to Heerema, Marathon and its partners, Noble and GE Petrol, are expected to install the Abla B3 gas compression platform in 2015 for commercial operations to start in 2016.

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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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Kingfisher to lead Lake Albert and refinery projects

After resolving tax and refinery disagreements between Tullow Oil plc (Tullow) from UK, Total from France, the China National Offshore Oil Corporation (CNOOC) from China and the Uganda Government, the Kingfisher project is ready to take off.

The Kingfisher project is to develop the previously called Block-3A located in the northwest of Uganda along the shores of Lake Albert.

Discovered in 1938, the Albert Lake Rift Basin had been left unexplored during 60 years.

Tullow took first interests in Uganda in 2004 and performed the Kingfisher-1 discovery in the Block-3A in 2006.

Then Tullow acquired 100% interests of the Block-2 in 2007 and of the Block-1 in 2010.

Along this period of exploration, the estimation of the recoverable reserves were continuously revised upward to actually exceed 2 billion barrels of oil equivalent (boe) concentrating approximately 60% of all the Uganda reserves.

The development of these Blocks in the Albertine Rift Basin may require more than $15 billion capital expenditure on the top of which should be added all the costs of infrastructures to export and/or transport the oil and gas from this far remote area.

In this context, Tullow offered in 2011 to share interests with Total and CNOOC through a Sales and Purchase Agreement (SPA) that should leave each partner with 33% ownership of each blocks.

In 2012, the Uganda Government approved the farm-out agreement between Tullow and its partners where:

 – Total holds 33% of the Block-1 and is the operator in partnership with Tullow and CNOOC

 – Tullow owns 33% of the Block-2 and is the operator in partnership with Total and CNOOC

 – CNOOC takes 33% of the Block-3A, renamed Kingfisher, and is the operator in partnership with Total and Tullow

In respect with the size and reserves of the three blocks the development capital expenditure of the three blocks should be split:

 – Block-1 $7 billion

 – Block-2 $4 billion

 – Block-3A $4 billion

Among these fields, Kingfisher (Block-3A) should be the first block to be developed under the lead of CNOOC.

Petrofac completed Kingfisher pre-FEED for CNOOC

In 2012, CNOOC awarded the pre-front end engineering and design (pre-FEED) to Petrofac from UK.

From this pre-FEED, CNOOC could organize the call for tender for the front end engineering and design (FEED) contract.

Currently CNOOCand its partners Tullow and Total are evaluating the technical and commercial offers submitted by:

 – Saipem from Italy

 – Wood Group from UK

 – WorleyParsons from Australia

Petrofac did not compete in the FEED as it wants to be listed for the engineering, procurement and construction (EPC) contract to be invited to bid (ITB) after the completion of the FEED work.

In respect with Kingfisher estimated reserves of 800 million boe, Petrofac could develop a comprehensive pre-FEED so that the FEED contract should cover:

 – Well pad design

 – Flowlines and gathering system

 – Process scheme and production

 – Water injection

 – Water station

 – Central processing facility (CPF)

 – Tanks farm

 – Trucks loading facilities

 – Power generation

The central processing facility should be located at Buhuka.

In a first phase, this central processing facility should have a capacity of 20,000 barrels per day (b/d) that should be expanded to 40,000 b/d in a second phase.

In this first phase the crude oil will be exported through 85 kilometers pipeline to a greenfield refinery to be located in Hoima.

This refinery is subject to intensive discussions between Tullow, Total, CNOOC and Uganda Government as the companies would like to size it just to meet the domestic market while the Government aims at favoring the transformation in Uganda to export higher added value with refined products.

For instance they compromised on a 30,000 b/d capacity that should be expanded in the future to 60,000 b/d in respect with the domestic market demand.

In parallel, Tullow, Total and CNOOC are working on different alternatives of export pipelines:

 – 250 kilometers to Jinja

 – To Tanzania coast in turning around the Great Lakes

 – To Mombasa or Lamu on the Kenya coast

With the FEED contract to be awarded soon, CNOOC and its partners Tullow and Total expect Kingfisher (Block-3A)  and the Hoima refinery to start commercial operations in 2017.

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

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Daewoo Engineering wins Akkas Gas processing plant

The South Korean Gas Corporation (KOGAS) and the local Iraq National Oil Company (INOC) have awarded to Daewoo Engineering, & Construction Corporation (Daewoo Engineering) also from South-Korea, the engineering, procurement and procurement (EPC) contract for the gas central processing facility (CPF) of the Akkas gas field in the western of Iraq.

Located in the Al-Anbar Province, 460 kilometers northwest of Bagdad, close to the Syrian border, Akkas is the first non-associated gas field to be developed as part of the license rounds proposed by the Iraq Federal Government to foreign companies after the second Iraq war.

From the actual level of exploration the Akkas gas field is expected to hold between 3.3 and 5.6 trillion cubic feet (tcf) reserves of non-associated natural gas from which KOGAS and its partner NOC are planning to extract more than 2.1 tcf.

In October 2010, KOGAS in joint venture with KazMunaiGas (KMG) from Kazakhstan and the Iraq state owned company INOC applied to participate to the reverse auctions of the third license round organized by the Iraq Federal Government.

These license rounds were based on Technical Service Contracts (TSC) meaning that the winner of the bid is supporting all investment until a plateau production level above which it is compensated by a remuneration fee per barrel produced.

Since the contract is defined as “technical”, this remuneration fee is fixed regardless the commercial value of the oil and gas. 

In October 2011, KOGAS and its partners were awarded the Technical Service Contracts (TSC) for the Akkas gas field with a remuneration fee of $5.50 per barrel of oil equivalent (boe) based on a plateau production of 400 million cubic feet per day (cf/d) during 13 years.

KOGAS to meet Iraq Government plateau production

In the meantime KMG withdrew from the project and sold its shares in the Akkas gas field to KOGAS to stand alone with the local NOC and share the working interests such as:

 – KOGAS 75% is the operator

 – INOC25%

In addition to Akkas, KOGAS has interests in three other oil and gas field development projects in Iraq:

 – Badra crude oil field in the northeast of Bagdad with Gazprom, Petronas, TPAO and OEC

 – Mansuriya natural gas field in the southeast of Bagdad with TPAO, Kuwait Energy Co. (KEC) and OEC

 – Zubair crude oil field near Basra in the south of Iraq with Eni, Occidental Petroleum (Oxy) and MOC

The Akkas gas field is covering 986 square kilometers and should require $2.66 billion capital expenditure from KOGAS as part of its Technical Service Contracts (TSC).

In October 2012, KOGAS completed the front end engineering and design (FEED) for the development of the Akkas gas field. 

Despite the danger of the Al-Anbar Province along the Syrian border where KOGAS contractors had workers killed and kidnapped in April, KOGAS received four bids for the EPC contract  of the Akkas gas central processing facility (CPF).

From this call for tender, the South-Korean Daewoo Engineering company submitted the most competitive bid, just below $800 million. 

With a capacity of 400 million cf/d of natural gas in line with the contractual plateau production level, this EPC contract includes the:

 – Akkas gas central processing facility (CPF)

 – Associated gas gathering inlet pipeline

 – Export pipeline

In awarding the Akkas gas central processing facility (CPF) to Daewoo Engineering in July, KOGAS and INOC are targeting the first production in 2015.

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

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Saudi Aramco to evaluate Fadhili gas plant FEED bids

The national oil company Saudi Aramco is currently evaluating the tenders submitted by the qualified engineering companies in competition to provide the Fadhili Gas Processing Plant project with the front end engineering and design (FEED) work.

This project is part of Saudi Arabia program to develop natural gas production from onshore and offshore gas fields as well as the associated gas from the oil fields currently in production.

Although Saudi Arabia holds the sixth largest reserves of natural gas  in the world, the country is continuously suffering of shortage since the expansion of the petrochemical and power generation sectors.

In addition the widening gap between the crude oil price and the gas price is motivating Saudi Arabia to convert the use of crude oil and naphtha as feedstock into cheaper natural gas  and condensate.

In this context, Saudi Arabia is aiming at producing 15 billion cubic feet per day (cf/d) of natural gas  in 2018.

With this perspective, Saudi Aramco is working on:

 – Gathering the associated gas from the giant Khursaniyah oil field

 – Developing the non-associated gas from Arabiyah, Hasbah and Karan gas fields.

In this program the main challenge relies on the high sulfur content of the gas with the consequences to increase the production costs and to cause delays as experienced in the Wasit gas development project.

Saudi Aramco qualified bidders beyond GES-plus list

Because of these challenges Saudi Aramco decided to enlarge the list of the bidders beyond the engineering companies pre-qualified through their General Engineering Services-plus (GES-plus) contract.

Originally Saudi Aramco had put in place the GES-plus scheme with foreign engineering companies in order to develop the local content of the FEED work through alliances with local contractors and services companies.

In counter part of the efforts of these foreign companies to train local engineers and share knowledge with Saudi third parties, Saudi Aramco would give them the first priority on any FEED work to come.

To guaranty to these companies some kind of break-even profit, Saudi Aramco selected only five companies to join this GES-plus scheme: Jacobs Engineering (Jacobs), KBR, Mustang Engineering (Mustang), Foster Wheeler and SNC Lavalin.

Currently WorleyParsons replaces Foster Wheeler in that GES-plus list.

From this base of the GES-plus listed engineering companies (Jacobs,KBR, Mustang , SNC Lavalin and WorleyParsons) , Saudi Aramco re-qualified Foster Wheeler and added Fluor to be invited to bid on the Fadhili Gas central Processing facility (CPF) project as long as these companies commit to perform 36% of the estimated 400,000 man-hours in the Kingdom.

Located in the Eastern Province with a capacity of 1 billion cf/d of sour gas the Fadhili Gas CPF should include:

 – Raw gas inlet and processing facilities

 – Natural gas liquids (NGL) fractionation unit

 – Sulphur recovery unit

 – Dedicated co-generation power plant

Through this process, the Fadhili Gas CPF project should deliver 520 million cf/d of natural gas to the market.

Saudi Aramco is planning  this FEED contract to take nine months so that the engineering, procurement and construction (EPC) should be awarded on the third quarter 2014 for commercial operations in 2018.

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

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Shell and ExxonMobil court InterOil for new LNG project

The super major companies Shell from The Netherlands and ExxonMobil from USA are head to head in intensive negotiations with InterOil Corporation (InterOil) for the development of world scale liquefied natural gas (LNG) projects in Papua New Guinea (PNG).

Listed in New York Stock Exchange, InterOil was established in 1997 to take a leading role in the energy sector of Papua New Guinea.

After building up and operating the first crude oil refinery in Port Moresby, Papua New Guinea, InterOil took over Shell retail and distribution network in Papua New Guinea in 2006.

In parallel InterOil acquired its first licenses for oil and gas exploration in 2005.

After the first discoveries in Moose in 2005, the Elk and Antelope appeared to be promising enough  to support a LNG project.

In 2010 GLJ Petroleum Consultants estimated the resources in:

 – Elk to 631 billion of barrel equivalent oil (boe)

 – Antelope to 1.52 billion boe.

Based on these reserves, InterOil made several attempts for joint venture and frame agreement with other junior companies to develop different LNG projects.

Until end of 2012, none of these  projects could reach the final investment decision (FID) in the time frame allowed by the licenses awarded to InterOil.

As a result in November 2012, the Government of Papua New Guinea decided to increase its stake in the Gulf LNG Project from the original 22.5% to 50%.

In addition and in order to secure the flawless execution of the project, PNG Government and InterOil decided to set partnership with a major company providing its technological expertise and project management experience for a world scale LNG project.

In this scenario the Gulf LNG project should be phased up with a first LNG plant sized at 3.8 million t/y of LNG instead of the original 8 to 10 million t/y.

This first phase should come on stream in 2016 and should be followed up by a second and a third phase expected to start commercial operations in 2018 and 2020.

Gulf LNG in competition with PNG LNG expansion

The Gulf LNG project has been designed around two packages, upstream and midstream.

The upstream part of InterOil Gulf LNG project should include:

 – 11 production wells in Elk and Antelope fields

 – Water injection wells

 – Compression facilities

 – Gas central processing facility (CPF) with 1,800 cubic feet per day (cf/d) capacity

 – 120 kilometers dry gas export pipeline and condensate pipeline

 – 100,000 barrels condensate storage facilities

 – Condensate offloading facilities to ships

The midstream package of InterOil Gulf LNG projects should cover:

 – Three LNG Trains of 3.8 million t/y each

 – LNG storage tank farm

 – LNG export terminal with connecting and offloading system

 – Offsites and utilities

 – Campground

Based on this front end engineering and design (FEED) InterOil and the PNG Government have initiated discussion with Shell to take shares in the project.

In the meantime, ExxonMobil and InterOil signed an exclusive provision by which ExxonMobil would acquire 4.6 trillion cubic feet from the Elk and Antelope fields.

With this additional supply of natural gas, ExxonMobil could secure the feedstock for a third LNG Train at its ongoing PNG LNG project.

ExxonMobil is currently completing the $19 billion construction of the two first LNG Trains in Papua New Guinea where the existing infrastructures were designed to support two additional trains with a capacity of 6.9 million t/y.

In a way the PNG Government realizes that ExxonMobil solution offers the simplest and most profitable solution to develop the Elk and Antelope gas fields but in another way the partnership between Shell and InterOil would balance ExxonMobil position in Papua New Guinea.

For these reasons, it could also be that InterOil and Papua New Guinea Government decide to develop both projects, first Gulf LNG Train with Shell, and  third PNG LNG Train with ExxonMobil in parallel in order to avoid further delays to sign LNG export agreements.

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

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