Semi-sub Chevron Buckskin project at pre-FEED stage

The US super major Chevron and its partners, Maersk Oil (Maersk) from Denmark, Repsol from Spain and Samson Offshore Company (Samson) from USA, may consider to move a step ahead with the development of the oil and gas field Buckskin in the US part of the Gulf of Mexico meanwhile  exploration should continue in the neighboring oil and gas field Moccasin.

Located in the Blocks 785, 872 and 736 of the Keathley Canyon approximately 350 kilometers south of Louisiana Gulf of Mexico coastline, the Buckskin and Moccasin oil fields were expected to be developed together.

In 2008 Repsol discovered Buckskin by 2,100 meters of water depth and 9,000 meters of total depth.

Few miles away, Chevron hit oil in 2011 at Moccasin by 2,000 meters of water depth and 9,600 meters total depth.

With these two discoveries, Chevron and its partners made the decision to initiate pre-front end engineering and design (pre-FEED) work with WorleyParsons in July 2013.

But in the meantime the exploration in Bockskin and Moccasin went in different ways.

In addition to the three years difference between both discoveries, the appraisal campaign went smoothly in Buckskin while Chevron and its partners were meeting some difficulties with Moccasin.

These different routes of development between Bucksin and Moccasin took importance on the second half 2013 as these field are owned by different joint ventures.

Since Repsol  discovery in 2008, Bucksin, Chevron took the operatorship role with working interests shared between:

 - Chevron 55% is the operator

 - Maersk 20%

 - Repsol 12.5%

 - Samson 12.5%

In Moccasin, the different partners hold stakes such as:

 - Chevron 43.75% is the operator

 - BP 43.75%

 - Samson 12.5%

In this context of multiple partners with different interests, the question came up if Buckskin and Moccasin should be developed jointly as originally planned.

WorleyParsons and Intecsea on Buckskin pre-FEED 

Since July 2013, WorleyParsons and its subsea engineering company Intecsea have been working on the pre-FEED of the Buckskin and Moccasin development.

Intecsea is proceeding to the preliminary design of the deep water subsea system from the seabed to the topsides.

The topsides and the hull to support them are pre-designed by WorleyParsons.

Benchmarking the previous Chevron Jack and St Malo joint semi-submersible (semi-sub) platform, WorleyParsons is proposing a similar semi-sub hull design.

In the case Moccasin could not be tied-in Buckskin semi-sub offshore platform, Chevron is prospecting around alternative source of supply from marginal field in stand-by as not large enough to justify stand alone floating production units.

ExxonMobil and Statoil may offer these opportunities at the everyone benefit since all the corresponding fields could be developed without delay.

In this scenario, Chevron and its partners Maersk, Repsol and Samson, may decide to engage the front end engineering and design (FEED) work on Buckskin semi-submersible platform in the coming months of 2014 regardless the situation in Moccasin.

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Saudi Aramco to award shale gas treatment FEED

The world largest company by the size of crude oil reserves, Saudi Aramco, is planning to award the front end engineering and design (FEED) contracts for the gas central processing facilities to support the development of the shale gas exploration – production in three regions of Saudi Arabia.

 In 2013, Saudi Arabia was the fourth largest producer of natural gas in the world, but despite this strong position it does not meet all its needs on the domestic market covered by crude oil at high costs.

In addition the vast majority of the gas produced in Saudi Arabia is, so called, associated gas, meaning that the gas production in Saudi Arabia is directly correlated to the oil production.

So far this close link between the gas production and the crude oil production was not an issue but some game changers could impact heavily this historical situation with major consequences in the Kingdom.

Among these game changers the development on fast track of the shale oil in USA comes on the top, followed by the restoration of the trading relationships with the neighbor Iran and the increasing production in Iraq could exercise some pressure on the production of crude oil in Saudi Arabia to maintain an acceptable market price of the crude oil barrel for the producing countries.

In such a context, Saudi Arabia needs to develop its production on non-associated gas in order to supply its power generation facilities running currently with crude oil and to provide the feedstock to its newly built petrochemical industry designed around mixed crackers accepting ethane as well as naphtha.

To do so and despite all the environmental constraints, Saudi Aramco is prioritizing the development of the shale gas because of the available reserves in the Kingdom.

Saudi Aramco to build three central processing facilities

If we consider that the USA may become self sufficient in crude oil by 2017, this term is given as the target for Saudi Arabia to develop three shale gas fields:

 - Empty Quarter

 - Jafurah in the north

 - South Ghawar in the Eastern Province

For these three shale gas fields, Saudi Aramco is planning to build three corresponding:

 - Gas central processing facilities (CPF)

 - Offsites and utilities

After a feasibility study completed in July 2013, Saudi Aramco is evaluating the offers for the FEED work of these packages.

The bidders belongs to the short list of the engineering companies qualified by Saudi Aramco for the General Engineering Services Plus (GES+) contracts:

 - Jacobs Engineering (Jacobs)

 - KBR

 - Mustang Engineering (Mustang)

 - SNC Lavalin

  - WorleyParsons

Then Saudi Aramco had also qualified Foster Wheeler, which was originally part of the GES+ engineering services providers, and Fluor.

These Saudi Aramco projects are so much critical for Saudi Arabia that design work out-of-Kingdom will be accepted from the bidders. 

In order to meet the deadline of 2017, Saudi Aramc is planning to award the FEED contract on mid 2014 so that the engineering, procurement and construction (EPC) contracts could be sanctioned on early 2015 for these Empty Quarter, Jafurah and South Ghawar gas central processing facilities and offsites – utilities packages.

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BP Rumaila project includes CPS and IPC packages

BP and its partnering national oil companies, China National Petroleum Corporation (CNPC or PetroChina), and Iraq State Oil Marketing Organization (SOMO) have called for tenders the Produced Water Re-Injection (PRWI) project to develop the giant Rumaila oil and gas field in the south of Iraq.

Approximately 80 kilometers long and 20 kilometers wide, Rumaila is one of the largest oil field in the world.

With an average production of 1.5 million barrels per day (b/d) of crude oil, the BP Rumaila oil field is the major contributor to the Iraq national production just above 3 million b/d.

So the development of the Rumaila oil and gas field by BP and its partners is strategic to support the economical growth and the social stabilization in Iraq.

Rumaila oil field had been discovered by BP in 1953, but it is only in November 2009 that BP managed to take it over together with PetroChina and SOMO during the license rounds organized by the Iraq Government to award technical services contracts (TSC) to the foreign companies willing to invest in Iraq.

With more than 20 billion barrels of crude oil recoverable reserves lying by only 2,400 meters depth, BP and its partners could accept the very low remuneration fee of $2 per barrel in compensation of the planned $15 billion capital expenditure to develop the field.

More than 350 wells are in operations and 150 more are to be installed on the next three years.

In order to help Iraq to meet its target of 6 million b/d of production by 2017, BP and its partners, are expect to take a leading role in developing Rumaila with the most advanced technologies of enhanced oil recovery (EOR) by water injection.

In that perspective BP, PetroChina and SOMO share the efforts according to their working interests:

 - BP holds 38% and is acting as the operating company

 - PetroChina handles 37%

 - SOMO keeps the remaining 25%

In 2011, BP and its partners had appointed WorleyParsons to provide Rumaila development front end engineering and design (FEED) work for the development of Rumaila in multiple phases.

WorleyParsons completed Rumaila development FEED

From the FEED work BP, PetroChina and SOMO are planning to build for the first phase the Produced Water Re-Injection (PWRI) project phase-1 which includes two packages:

 - Integrated Processing Complex (IPC)

 - Cluster Pump Stations (CPS)

The IPC package will be an oil and gas central processing facility to separate oil, gas, condensate and water.

This IPC package will also include the gas compression and the water treatment facilities. 

Running with three processing trains of 150,000 b/d each, the Rumaila Integrated Processing Complex Phase-1 will have a total capacity of 450,000 b/d.

The CPS package covers the pumps station for the water re-injection.

The CPS unit will receive the water from the separation unit and water treatment facility operated in the IPC package.

The treated water will then be sent back to the production wells pads through infield pipelines.

Because of the large size of Rumaila field, two water treatment facilities for re-injection, one in the north and one in the south.

Each water treatment unit will have a capacity of of 80,000 b/d of water.

Seven engineering companies are in competition for these Rumaila IPC and Rumaila CPS engineering, procurement and construction (EPC) contracts that BP, PetroChina and SOMO should award in 2014 for a production of the Rumaila produced water re-injection (PWRI) by the end of 2016.

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

Giant Pao de Acucar in Block BM-C-33 reaches FEED

The giant discovery Pao de Acucar and its adjacent fields, Seat and Gavea, are reaching the front end engineering and design (FEED) stage to develop the prolific Block BM-C-33 pre-salt in the ultra deep water of the Campos Basin offshore Macae, in the State of Rio de Janiero, Brazil.

This Block BM-C-33 is currently developed by Repsol-Sinopec Brazil (Repsol-Sinopec) together with the national oil companies (NOCs) Statoil from Norway and Petrobras from Brazil.

In 2010, the Spanish company Repsol and the China Petroleum and Chemical Corporation (CPCC or Sinopec) established a joint venture Repsol-Sinopec Brazil  to lead exploration and production in Brazil.

In this Repsol-Sinopec joint venture, the both partners share the interests in such a way that:

 - Repsol 60% is the operator

 - Sinopec 40%

With interests in the Campos Basin, Esperito Basin and Santos Basin, the Repsol-Sinopec Brazil joint venture holds the largest interests among the foreign companies operating in Brazil.

The Repsol-Sinopec joint venture is leading the development of the Block BM-C-33 with Statoil and Petrobras whereas the working interests are shared as following:

 - Repsol-Sinopec 35% is the operator

 - Statoil 35%

 - Petrobras 30%

In 2011, Repsol-Sinopec and its partners discovered the Gavea field identified as one of the 10 largest finds in Brazil that year.

Then the Pao de Acucar discovery still in the Block BM-C-33 appears to have one of the thickest column of hydrocarbons ever known in Brazil with more than 500 meters.

Covering 708 square kilometers, the Block BM-C-33 is located approximately 200 kilometers southeast Macae on the Brazilian shore.

Lying by 2,800 meters water depth, the Block BM-C-33 is ranked among the most challenging ultra deep water fields in the Campos Basin.

All together the three discoveries Seat, Gavea and Pao de Acucar of the Block BM-C-33 are estimted to retain:

 - 700 million barrels of good quality light crude oil

 - 3 trillion cubic feet (tcf) of natural gas.

Despite the ultra deep water conditions, the challenge to develop such pre-salt offshore oil and gas fields relies on the export of gas.

KBR and WorleyParsons completed feasibility studies

The large quantity of associated gas requires the engineering companies working on the feasibility studies to find the most cost effective solution for the monetization of the natural gas.

Since 2012, KBR and WorleyParsons envisaged all kinds of solutions for this Block BM-C-33 development so that Repsol-Sinopec and its partners, Statoil and Petrobras, are now voting for a conventional scheme based on:

 - Offshore platform or Floating production, storage and offfloading (FPSO) vessel

 - Gas export pipeline to shore

 - Onshore gas central processing facility (CPF)

The offshore platform option could well be a SPAR type of tension leg platform (TLP) type.

A SPAR should be the first one of that kind in Brazil and rises questions about local content capabilities.

Instead a FPSO design should be more conventional for Brazil.

However this offshore platform or FPSO should have a treatment capacity up to:

 - 150,000 barrels per day (b/d) of oil

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

The final size of the offshore production unit will depend on further discoveries in the Seat reservoir in the Block BM-C-33.

The San Paolo-based engineering company Promon is still working on the feasibility study on the best way to export and treat the natural gas with the gas central processing facility that could be located in Macae.

These feasibility studies for the Pao de Acucar offshore platform or FPSO and Macae gas treatment facilities are well enough in progress to allow Repsol-Sinopec to call for tender the FEED contracts to develop the Block BM-C-33.

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

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

Takamul to call for tender Sohar PTA and PET projects

The joint venture Oman International Petrochemical Industry Company (OIPIC) between the State-owned companies Takamul Investment Company (Takamul), Oman Oil Company (OOC) and the South Korean LG Corporation (LG) is preparing the call for tender to invite engineering companies to bid for the engineering, procurement and construction (EPC) of a purified terephthalic acid (PTA) unit and a polyethylene terephthalate (PET) unit in the proposed petrochemical complex in Sohar.

In December 2012, Oman Oil and LG established a joint venture to build a world-scale petrochemical complex in Sohar whereas the working interests were shared:

 – 70% Oman Oil the operator

 – 30% LG

This decision was a major step change in Oman strategy with an economy so far depending on oil and gas exploration, production and exportation.

Benchmarking Saudi Arabia, the Sultanate of Oman decided to reduce its reliance on oil and gas exportation in developing a petrochemical industry. 

Since the signature of the Oman Oil and LG joint venture in 2012, the first invitation to bid (ITB) were expected in 2013 but the project was moving slowly because of the lack of feedstock, leading to postpone the qualification process and the EPC contracts tendering.

With major upstream projects moving ahead, Oman Oil is now getting confident to built enough oil and gas production capacity to feed its Sohar petrochemical complex.

WorleyParsons won Sohar PTA – PET PMC contract

Established in 2006 as the Oman Oil downstream arm, Takamul  has been involved in Sohar Petrochemical complex project so that the working interests in OIPIC are actually distributed:

 – Takamul 20% the operator

 – Oman Oil 50%

 – LG 30%

In Sohar Petrochemical complex, Takamul and its partners prioritized the production of basic polymers in order to supply the domestic market with the fundamental materials to support the daily consumption in the Sultanate, such as plastic bottles, packaging, home plastic goods, polyester.

In this perspective Takamul begins with the construction of:

 – Purified terephthalic acid (PTA) unit

 – Polyethylene terephthalate (PET) unit

 – Purified isophthalic acid (PIA) unit

Although the PIA is to be combined with the PTA to produce PET, this unit is very specific, thus is being developed separately from the PTA and PET units.

From the front end engineering and design (FEED) being completed, the Sohar Petrochemical complex should have the following production capacities:

 – 1.1 million tonnes per year (t/y) of PTA

 – 500,000 t/y of PET

 – 100,000 t/y of PIA

On the current estimations, the construction of Sohar PTA and PET production units should require $600 million capital expenditure.

With WorleyParsons appointed as project management consultant, Takamul, Oman Oil and LG are expecting to award the EPC contracts by the end of 2015 in order to start production by 2018.

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

Gazpromdobychashelf, the wholly owned Gazprom subsidiary and operator of Shtockman projects, has annouced to expect the completion of the FEED for the offshore pipeline at the end of the year.

In parallel, WorleyParsons is making good progress on the FEED of the FPSO, the solution selected for the second and third phases of Shtockman.

With a weight of 253 000 t and a length of 320 m these two vessels would process the gas condensates and store them before offloading shuttle tankers.

This concept has been preferred on the FPO selected for the first phase where the gas and condensates should be treated onshore.

These pipelines will be therefore different as multiphases flow for Shtockman phase 1 to carry on the gas and condensates mixture to the shore while it should be a single phase gas pipeline for the phases 2 and 3.

These different concepts are progressing at their own speed, so that Andrey Petrulevich, the Gazpromdobychashelf Deputy Head of industrial safety, monitoring and risks analysis declared that technically nothing prevent the third phase from starting to produce gas and condensate before the first and the second phases are commissioned.

Total and Statoil, who share 49% of Shtockman phase 1, are still in discussion with the Russian government on tax break to make final decision.In addition to the production FPO and FPSOs, Gazprom has decided to build a stop-over offshore platform in the Barents Sea to host living quarter, support the food supply and helicopters logistic. 

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Mariner is the first field to be developed from the $9.6 billion capital expenditure Mariner & Bressay project located in the UK North Sea

Because the offshore ultra heavy crude oil is one of the most challenging exploration & production of the Oil&Gas sector, Statoil decided to proceed step by step. Mariner will go first and Bressay will follow one year behind. All the decisions made for Mariner will apply for Bressay.

In Mariner Statoil owns 61.5%, ENI 28.9% and Nautica Petroleum 6%.

Ultra heavy crude fields require pioneering technology in order to be developed that Statoil experienced successfully in the development of the Grane field in Norway and the Peregrino field in Brazil.

Because of the low well flow rates and early water break-through there is a need for many wells, artificial lift, and a process designed to handle large liquid rates and oil-water emulsions. 

A total of 145 reservoir targets for production or injection are planned for Mariner. While the number of well slots at the platform is less, this will be solved through use of multi-branch technology, sidetracks and reuse of slots.

To meet with the requirements of the ultra heavy crude oil, Statoil designed the Mariner offshore platform project based on a:

 – Production, drilling and quarter (PDQ) platform based on a steel jacket

 – Floating storage unit (FSU), to be normally unmanned operated to store the diluent required to help the ultra heavy crude oil fluidity and the oil/water separation process.

The pumping operations will use a combination of 21 electric submersible pumps (ESP) in the down-hole of the wells and 28 water injection pumps on the up-hole to increase the well pressure. 

Aker Solutions is actually performing the Front End Engineering and Design (FEED) of the 26,000 t topsides in order to treat 320,000b/d liquids including 80,000 b/d crude oil.

The selected Engineering companies in competition for the Engineering Procurement & Construction (EPC) contracts are the following:

 – Kvaerner with Heerema Fabrication Group

 – Daewoo Shipbuilding & Marine Engineering with CB&I

 – Hyundai Heavy Industries with WorleyParsons

 – Samsung Heavy Industries with KBR

Statoil expects to float the calls for tenders for the EPC contracts on mid 2012 for a final investment decision on year end.

The deck construction should start in 2014, so that Mariner full completion and operation is scheduled in late 2016.

 

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$1.5 billion Dorra offshore packages for bid next quarter

The Dorra gas field is located in the so called Divided Zone between Saudi Arabia and Kuwait.

According to the agreement signed in 1965 between the two countries, this Divided Zone results from the ex Neutral Zone, 300 km Northeast Dammam in Saudi Arabia and 130 km South Kuwait city, where each country can decide for the  Oil & Gas resources development as long as they remain equally shared.

Kuwait and Saudi Arabia are moving ahead with plans to develop the offshore Dorra non-associated gas field.

Al-Khafji Joint Operations (KJO), the Saudi/Kuwaiti operator which works in the Divided Zone between the two countries, has appointed the Australian WorleyParsons engineering company to work on the Front End Engineering and Design (FEED).

WorleyParsons is actually completing the FEED and running through clarifications with the qualified contractors.

This Dorra gas field development offshore package should include:

– 6 Offshore platforms

 – Interconnecting flowlines between the platforms

 – Gas gathering equipment

 – 200 km, 30 inch pipeline

 – 100 km sub-sea cables

In the Onshore package, the Dorra gas field project will cover the gas processing facility.

This onshore package is estimated to $1 billion capital expenditure.

In respect with the near completion of the FEED,  Al-Khafji Joint Operations (KJO) is set to issue the call for  tenders for the  estimated $1.5 billion engineering, procurement and construction (EPC) contract for the offshore non-associated Dorra gas field on next quarter.

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BP to invest $15 billion to develop Oman tight gas

BP’s Khazzan tight gas project in Block 61 is one of the company’s top five upstream projects globally. BP’s Khazzan project is also the first and largest of its kind in the Middle East.

In January 2007 BP signed a major exploration and production sharing agreement with the Government of Oman for the appraisal and development of Block 61 and the Khazzan and Makarem gas fields.

The agreement covers an area of some 2,800 km² in central Oman, which contains a number of tight gas reservoirs which were first discovered in the 1990s.

Drilling commenced in September 2008. Then, in March 2011 BP Oman achieved a major milestone with the first gas export from the Extended Well Test project delivered to the government-owned gas plant at Saih Rawl.

The development of the tight gas reservoirs is a significant technical challenge owing to the low porosity of the reservoir rock.

BP is applying innovative technology to unlock this tight gas, drilling horizontal wells and using hydraulic fracturing technologies to force cracks in the rock to encourage flow.

BP Oman has announced in Muscat to award several contracts for the appraisal of the Khazzan & Makarem gas fields in Oman’s Block 61.

The contracts include those for:

 – Seismic acquisition services to US’ Global Geophysical Services

 – Seismic reprocessing to Cairo-based PGS Data Processing ME 

 – Select stage engineering to Worley Parsons Oman, including the evaluation of options for the appraisal phase of early production of the Khazzan & Makarem gas fields.

 – Drilling rigs to Oman-based Dalma Energy & Co LLC to supply two rigs, with drilling planned to commence by the end of 2008

The contracts awarded by BP mark the beginning of a multi-year appraisal programme to understand the nature of the reservoirs which contain difficult to extract tight gas located at a depth of 4,500-5,000 metres

The plan for 2012 is to drill more horizontal wells. That is the way tight gas production evolved in North America which enable multiple fractures.

The tight gas production needs a lot of wells to be developed, because the flow rates of individual wells are quite low.

Water treatment: a key package of the whole project

Fracturing needs to use a lot of water which can be obtained from shallow, saline aquifers.

This non-potable water is desalinated in using a reverse osmosis plant and adding various chemicals to make the gels that hold open the fractures.

In a potential full field development at Khazzan, more than 300 wells will be producing waste water.

The plan is to drill disposal wells to re-inject the water back into the deep subsurface.

Water management is going to be one of the big issues and something that will require significant capital expenditure in terms of having to desalinate water and dispose of that water once we pump it back.

As a greenfield development, this tight gas project has to bear in addition the capital expenditure of the entire associated infrastructure, including pipelines, the gas processing plant, roads, camps, offsites & utilities.

That makes this initial development to look relatively expensive, but Oman needs this gas. BP Khazzan & Makarem is one of the few options available to the country for new gas supply on a significant scale.

The discussions have begun on the commercial terms with the government, they are expected to be completed by 2013, with 1.2 billion cf/d of processed gas being produced towards the end of 2016.

WorleyParsons working on the pre-FEED

Since WorleyParsosn is working on the pre-FEED, the priority is given to the accommodation of the working area to help the construction to begin in 2013. 

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

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With Qatar $400 million rescue package, ERC is building a state-of-the-art greenfield second-stage oil refinery in the Greater Cairo Area expected to be completed by 2015.

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

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KNPC to pre-qualify EPCs for CFP and NRP projects

Expected on June 13th, the state-owned oil refiner Kuwait National Petroleum Co (KNPC) has decided to postpone to July 4th the dead line for the engineering companies to submit their expression of interest (EOI) for the calls for tenders to be issued for the multiple engineering, procurement and construction (EPC) contracts requested for the Clean Fuel Project (CFP) and New Refinery Project (NRP) projects.

These projects were on hold since 2008, these three weeks are to complete the bidders list.

Together these projects represent $33 billion capital expenditure, about $18 billion for CFP and $15 billion for NRP.

The CFP and NRP projects are intended to meet the new international standards of clean fuel emissions and to increase gasoline capacities in order to meet the local market demand.

KNPC Clean Fuel Project (CFP)

The CFP project would:

 – Involve building at least 30 units at Mina Abdulla and Mina al Ahmadi refineries

 – Produce 10 parts per million (ppm) of low sulphur diesel (<1%) and Euro IV gasoline

 – Provide additional fuel by-products

Following the CFP upgrade, the refining capacity of:

 – Mina al Ahmadi would drop to 346,000 b/d from 466,000 b/d now

 – Mina Abdulla would increase to 454,000 b/d from 270,000 b/d

As a result, the refining capacity following the CFP upgrade would come  to 800,000 b/d.

Since 2008, 37 reactors and vessels were ordered as long lead items, 30 of them were  received by the  company during this year as the manufacturing and delivery of such equipment takes along time.

The CFP will be tendered in three packages.

New Refinery Project (NRP)

The 4th refinery or  the New Refinery Project (NRP) in Zoor area, is one  of the largest strategic projects in the state of Kuwait as its capacity will be around 615,000b/d.

It that sense it will be one the largest refining plants in the Middle East.

The NRP main objective is to  supply power generation plants in Kuwait with  environment friendly fuel and  provide an alternatives  for gas imports  and heavy fuel consumption.

It  will also  be capable of opening  new world  markets for Kuwait petroleum products.

Once the CFP and NRP are completed the refining capacity available to KNPC will rise to around 1,400.000 b/d from the actual 736,000 b/d.

The CFP and NRP projects complement each other and will lead to the  processing of  high quality petroleum products that will open new market outlets  across the world an enhance their competitive ability at those markets.

Designing and manufacturing of the reactors and separation vessel for the project were ordered as long lead items and manufactured.

In fact 36 reactors and 6 vessels have already been delivered  to the company in view of the fact that their manufacturing needs rather a long time.

KNPC has already received approval of the concerned agency to allocate the site in Zoor area for the NRP.

$300 million PMC contract for CFP and NRP 

With market needs increasing and the actual refineries aging, Kuwait seems now ready for decision with the preparation work being tendered in May.

No less than 12 engineering companies had been pre-qualified for this preparation work, all of them will also bid for the CFP and NRP main packages.

In parallel 9 companies including AMEC, Fluor, Technip, Jacobs Engineering and WorleyParsons are bidding for the Project Management Consultancy (PMC) contract estimated around $300 million.

As its neighbors, Saudi Aramco and Qatar Petroleum, KNPC is moving from the Upstream centric NOC profile to the integrated Upstream-Downstream business model in order to reduce its reliance on barrels prices fluctuations.

According to the Kuwait News Agency (KUNA), KNPC is planning to complete the CFP and NRP projects by 2018 with an estimated capital expenditure about $33 billion.

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

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Ma’aden awards FEED and reconsiders PMC contracts

Although the PMC contract for the Ma’aden Phosphate city project was intended to be awarded together with the FEED contract to Jacobs, Ma’aden has decided finaly to separate both contracts.

Ma’aden Phosphate Company (MPC) is a joint venture with SABIC in which the Saudi Arabian Mining Company (Ma’aden) owns 70% and SABIC 30%.

The Al Khabra Project, or called Phosphates City project, is located at Waad Al-Shamal in the Umm Wual area,  40 kilometres northeast of Turayf in the Sirhan-Turayf region in the North of Saudi Arabia and wholly owned by Ma’aden.

The greenfield project is located approximately 100 kilometers to the west of the Ma’aden Phosphate Company beneficiation complex.

Other new plants to produce ammonia and phosphate based fertilizers complimenting the industries at Wa’ad Al Shamal will be constructed at Ras Al Khair in the Eastern Province to be near port facilities

Ma’aden is targeting to supply merchant grade phosphoric acid to go into the global markets of the fertilizer, food and animal feed industries.

Wa’ad Al-Shimal will take advantage of rich phosphate deposits located at Ma’aden’s Al-Khabra mine, processing the ore into diammonium phosphate (DAP or P2O5) fertilizer for export to international markets.

The project envisages an open pit mine and treatment process adding close to 1.5 million t/y P2O5 to Ma’aden’s phosphate capacity.

The project would mainly use existing port, rail and infrastructure developments put in place by the Saudi Arabia Government.

The feasibility study confirmed the viability of the project to supply highly demanded phosphate intermediate products.

The Phosphate city project will include:

 – Phosphoric acid (MGA) production

 – Purified phosphoric acid

 – Sodium tri-poly-phosphate

 – Mono-calcium phosphate

 – Di-calcium phosphate.

These new products will help Ma’aden‘s increase its phosphate product mix.

The project is based on measured resources at Al Khabra mining license which stand at 236 million metric tons grading at 17% to 19.6% P2O5.

The deposit has very low metal content, ensuring that the resulting phosphoric acid will be of the highest quality, suitable for use in the food and feed industries.

The Umm Wual area contains further JORC compliant indicated resources of 450 million metric tons as well as significant further potential resources which Ma’aden is continuing exploration activities in the area to expand that resource.

The project would principally utilize existing port, rail and infrastructure developments put in place by the Saudi government as part of a national program of infrastructure enhancement.

The project represents $5.6 billion capital expenditure in phosphate mining and processing facilities is part of Ma’aden’s commitment to diversify Saudi Arabia activities in the downstream sector.

Ma’aden awards the FEED to Jacobs Engineering

May, 2012 – Ma’aden has awarded the front-end engineering and design (FEED) contract of its $5.6 billion  at Wa’ad Al-Shimal to U.S. company Jacobs Engineering Group Inc. (Jacobs).

The scope of the work of the FEED contract covers $4 billion capital expenditure out of the whole project, including:

 – Mining facilities

 – Eight processing plants

 – Utilities and offsite package

Jacobs FEED contract represents 400,000 man hours.

In addition the $4 billion facilities covered by the FEED contract awarded to Jacobs, the overall project requires:

 – A power distribution plant

 – Associated infrastructure.1

Following the engineering, procurement and construction (EPC) of the project is expected to be completed by 2016.

Maaden in brief

Ma’aden’s Phosphate business currently consists of Ma’aden Phosphate Company, a joint venture with SABIC in which Ma’aden owns 70% and SABIC 30%, and the Al Khabra Project which is wholly owned by Ma’aden.

Ma’aden Phosphate Company (MPC) exploits the phosphate deposit at Al Jalamid in the North of Saudi Arabia and utilises local natural gas and sulphur resources to manufacture Diammonium Phosphate (DAP) at processing facilities at Ras Al Khair on the Arabian Gulf coast.

These facilities have the flexibility to also produce Monammonium Phosphate (MAP).

The DAP produced by MPC is sold into the global markets.

Surplus ammonia from the operation is exported or sold domestically. MPC commenced initial production of DAP on the 17th June 2011.

WorleyParsons which has a long history of co-operation in mining with Ma’aden to produce fertilzer may take this opportunity to come back in the expansion of the Al-Khabra phosphates.

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

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Chevron to award FEED for Rosebank FPSO

The Rosebank oil and gas field discovery is located on Blocks 213/26 and 213/27,  in the Faroe-Shetland Channel, 130 km northwest of the Shetland Islands in 1,115 m of water depth on the Corona Ridge near the UK border.

Rosebank is considered to be one of the biggest discoveries on the UK Continental Shelf (UKCS) with an estimated 250 million of barrels of oil equivalent (BOE) reserves.

Rosebank shares of interests are split as following:

 – Chevron 40% is also acting as the operator

 – Statoil from Norway 30%

 – OMV from Austria 20%

 – Dong Energy from Denmark, the remaining 10%. 

The Rosebank oil and gas field was discovered in August 2004, then in 2007, Chevron and its Rosebank partners completed a $327 million capital expenditure program to appraise the Rosebank oil and gas discovery.

Then Chevron, as operator, completed the Rosebank oil and gas field development plan in 2011, with first production expected to hit a plateau rate of

 – 75,000 b/d of oil

 – 100,000 million cf/d of gas

The Rosebank oil and gas field development is estimated between $6 and $ 8 billion capital expenditure.

To support this development Chevron and its partners Statoil, OMV and Dong Energy have decided to combine the operation of a semi-submersible drilling rig with a Floating, Production Storage and Offloading vessel (FPSO).

The semi-submersible drilling rig and the FPSO should be both purpose-built for Rosebank development.

In 2011, WorleyParsons from Australia had been awarded a pre-Front End Engineering and Design (pre-FEED) contract for the FPSO.

According to this pre-FEED work, the:

 – FPSO should have between 800,000 and 1.3 million barrels of crude oil storage capacity

 – Crude oil should be offloaded to shuttle tankers

 – Gas should be processed and piped to the 130 km Shettland Islands

The Front End Engineering and Design (FEED) work of this FPSO  is expected to begin in the second half of 2012 and should take 15 months for completion.

WorleyParsons, KBR and Wood Group are in competition for the FEED of this Chevron FPSO to be awarded newt quarter.

Seadrill, Fred Olsen, Transocean, Stena and Odfjell in competition for new-built semi-submersible drilling rig

Chevron called on drilling contractors in late January to respond to a formal multi-year charter tender expected to be released later this year.

Since the deep-water floater is intended for use in the UK’s West of Shetland region and in Newfoundland’s sub-Arctic waters, Chevron is looking for a semi-submersible drilling rig structure.

This semi-submersible drilling rig unit should be preferred according to Moss Maritime CS50 or CS60 and GVA 7500 designs to operate in the harsh environment of the North Sea in at least 7500 feet of water.

Seadrill and Fred Olsen are offering to charter Moss Maritime CS60 drilling rig types already in progress:

 – Seadrill has the West Mistra and West Rigel semi-submersible drilling rig in progress in Hyundai Samho Shipyard with delivery times in 2014 and 2015 for a capital expenditure of $ 650 million per unit.

 – Fred Olsen has a semi-submersible drilling rig also in progress in Hyundai expected in 2015 for a capital expenditure of $ 700 million.

In parallel Odfjell is in talk with Daewoo Shipbuilding & Marine Engineering (DSME)

The charter contract is estimated between $450,000 and $500,000 per day.

In the event the contract is awarded in the second half of this year, industry sources expect the new-built semi-submersible drilling rig will be delivered in 2014 at the earliest.

According to the actual planning, Chevron and its partners, Statoil, OMV and Dong Energy are expected to award the FEED next quarter and the semi-submersible drilling rig by the end of 2012 in order to make a final investment decision (FID) on early 2013, so that the drilling campaign could start in 2015 for Rosebank FPSO oil and gas production in 2017.

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

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Saudi Aramco and Sumitomo evaluate FEED tenders

When Saudi Aramco and Sumitomo had created the joint venture PetroRabigh in 2005, this complex was designed as the biggest integrated refinery and petrochemical complex in the World.

With a capacity of 400,000 b/d crude oil PetroRabigh has seen several upgrades and expansions.

The Front end engineering and design (FEED) had been done by Foster Wheeler and the engineering, procurement and construction (EPC) contract for the last refinery upgrade had been done on a lump sum turn key (LSTK) contract by the Spanish Technicas Reunidas.

Actually the refinery produces gasoline with a sulfur content of 300 parts per million (ppm) which needs to be reduced to 10 ppm in order to meet international environmental standards.

In that respect, Saudi Arabia has spent $ billion capital expenditure to up grade all the refineries in the Kingdom, now it comes the turn to align PetroRabigh on these standards.

Regarding the PetroRabigh refinery the estimated capital expenditure for this clean fuel project is around $1 billion.

The scope of work of this  FEED includes:

 – Designing the greenfield facilities

 – Set the specification for the whole list of equipment required

 – Evaluate with potential licensors the most costs efficient solutions

 – Adjust actual estimations regarding capital expenditure and operational costs

 – Estimate the number of man-hours and time frame forecast for the engineering, procurement and construction (EPC) phase of the project 

To pre-qualify the bidders, Saudi Aramco evaluated the engineering companies which had a proven experience in working in Saudi Arabia in large and complex projects and had previously performed FEED work in similar clean fuel projects.

Finally seven engineering companies submitted a tender to Saudi Aramco for the FEED of this PetroRabigh Clean Fuel project:

 – Foster Wheeler from USA

 – Jacobs Engineering  from USA

 – JCG  from Japan

 – KBR from USA

 – Sinopec from China

 – Tecnicas Reunidas from Spain

 – WorleyParsons from Australia

Saudi Aramco to test its GES+ initiative in practice

The bidding process for the FEED of this PetroRabigh Clean Fuel project comes right on time with the Saudi Aramco’s GES+ initiative in progress in parallel.

Saudi Aramco had launched this General Engineering Services Plus (GES+) initiative under the govern of the Saudi Government to increase the local content of its capital expenditure in high added values activities such as engineering.

The purpose of signing a GES+ contract with Saudi Aramco is to give the engineering companies the qualification to bid on engineering services, such as feasibility studies, FEED or PMC.

To meet the GES+ requirements and get qualified by Saudi Aramco, some global engineering companies have been working hard for more than one year and created joint venture with local contractors.

Actually only five engineering companies came successfully through this GES+ qualification process: Foster Wheeler, Jacobs, KBR, Mustang and SNC Lavalin.

If we cross check this list with the seven bidders of the PetroRabigh Clean Fuel project, we can see that only Foster Wheeler, Jacobs and KBR went through the both qualification process.

Anyway, the other bidders such as JGC, Sinopec, Tecnicas Reunidas, WorleyParsons may submit very aggressive tenders while they have not fulfilled the GES+ requirements yet.

For Saudi Aramco as well as for the engineering companies (Foster Wheeler, Jacobs Engineering, JCG, KBR, Sinopec, Tecnicas Reunidas, WorleyParsons) which have submitted bid on this project and for the engineering companies which have signed a GES+ contract (Mustang, SNC Lavalin), the PetroRabigh Clean Fuel FEED will be the first giant project to test at large scale how competitive bid and local content requirements can match together.

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

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WorleyParsons completed FEED for PDO Zauliyah

Petroleum Development Oman (PDO) is working on a new gas plant project at Zauliyah in central Oman adjacent to PDO’s existing Zauliyah Oil Production Station.

The greenfield project will process non-associated gas, water and condensates from the Hasirah and Hawqa fields in the Bahja-Rima area of PDO’s concession to boost output by over 1 million standard cubic meters per day (mmscmd) of natural gas.

The Hasirah oil reservoir has been in production since the mid 1980s, while  the Hawqa field was brought into operation in 1997.

Both fields are characterised as oil and gas reservoirs located in the Gharif and Buah formations.

While smaller than PDO’s gas processing plants at Saih Rawl and Saih Nihayda,the projected Zauliyah facility will still make a significant contribution to the company’s natural gas output.

From Front end engineering and design (FEED), PDO could estimate project capital expenditure around $100-150 million.

The PDO Zauliyah gas processing facility is designed for 1.2 mmscmd capacity.

The project scope includes:

 – Gas handling facilities

 – Processing trains

 – Sulfur recovery unit

 – Installation of interconnecting flow lines and other off-plot facilities

The dry gas processed in the Zauliyah plant will be exported to customers via the existing South Oman Gas Line.

Off-gas from the plant will be channelled to the associated gas facility of the nearby Zauliyah Oil Production Station where it will be mixed and used for the station’s gas lift compressors.

Produced water from the gas plant will be routed to the oil production station’s dehydration tanks.

As natural gas is continuously produced, wellhead pressure is projected to decline over the lifetime of the field predicted to come for depletion that by the year 2025.

Then only the Hawqa field will continue to produce natural gas.

WorleyParsons provided the FEED for the PDO Zauliyah gas processing facility project.

14 EPC bidders on PDO Zauliyah gas project

PDO received no less than 14 bids from local and international engineering contractors to build the Zauliyah Gas Plant project:

 – Consolidated Contractors Company (CCC) from Greece

 – Dodsal from UAE

 – Engineering Procurement & Project Management (EPPM) from Tunisia

 – Essar from India

 – Galfar Engineering & Contracting from Oman

 – Indian Oiltanking from India

 – Jahanpars Engineering & Construction Company from Iran

 – Larsen & Tubro from India

 – Posco Engineering Company from South Korea

 – Tata Projects from India

 – Tecna from Argentina

 – WorleyParsons from Australia

The successful bidder will be awarded an Engineering-Procurement-Construction (EPC) contract to build the PDO  Zauliyah gas processing plant according to WorleyParsons’s FEED, to be completed and come on stream in 2015.

PDO in brief

Petroleum Development Oman is the NOC in the Sultanate dedicated to exploration and production.

PDO accounts for more than 70% of the country’s crude-oil production and nearly all of its natural gas supply.

The first economic find of oil was made in 1962, and the first consignment of oil was exported in 1967

PDO is owned by:

 – The Government of Oman with 60% interest

 – Shell 34%

 –  Total 4%

 – Partex 2%

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

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ENI and GDF-Suez combine FEED and EPC bids to speed up Indonesian Muara Bakau development

After the successfully appraisal of the Jangkrik natural gas discovery, ENI and GDF-Suez intend to speed up the development of the  Muara Bakau PSC, Kutei Basin, East Kalimantan, Indonesia.

Overall, in Indonesia, ENI is very active as it holds working interests in twelve permits, and operates six of them.

ENI offshore activities are located in the Tarakan and Kutei Basins, offshore Kalimantan, north of Sumatra and West Timor.

ENI and GDF-Suez capital expenditure for the Jangkrik project is estimated to $2 billion.

In the Muara Bakau natural gas field, the working interests within the joint venture are shared between :

 – Eni from Italy 55% who is the operator

 – GDF-Suez from France 45%

Following the successful Jangkrik-2 appraisal well, ENI and GDF-Suez joint venture has decided to perform in following the assessment of the technical and commercial viability of a fast-track development of the gas.

The natural gas of the Jangkrik field should provide feedstock to the Bontang LNG plant on the East Kalimantan, Indonesia.

The Jangkrik-2 appraisal well is located in the Makassar Strait of Indonesia, approximately 70 kilometers from the East coast of Borneo, Indonesia.

The natural gas reservoir lies by 2449 m depth in 425m of water depth.

First tests show a natural gas of excellent quality with a low rate of contaminants.

The natural gas production is expected to reach 360 million cf/d.

The Jangkrik offshore field development includes:

 – Drilling production wells

 – Installation of a new-built Floating Production unit for gas and condensate treatment

 – Construction of a natural gas and condensates transport facility connecting the gas to the existing onshore Bontang LNG and condensates to the treatment plants in the area.

 – Sub-sea, Umbilical, Risers, and Flowlines (SURF package)

 – Sub-sea production system with control systems and manifolds

To develop the Jangkrik project on fast-track, ENI and GDF-Suez agreed on organizing the calls for tender in combining the Front end engineering and design (FEED) with the engineering procurement and construction (EPC) contracts.

From the project feasibility study the:

 – Floating production unit will be 200 meters long and weight 20,000 t with 360 million cf/d capacity.

 – Gas and condensates pipelines should be 86 kilometers long offshore and 6 kilometers long onshore.

ENI and GDF-Suez call for tenders three packages

Four groups in competition for Jangkrik floating production unit

ENI and GDF-Suez have pre-qualified the following Group to bid for the joined FEED and EPC contracts:

 – Chiyoda and Hyundai Heavy Industries

 – Petrofac and Daewoo Shipbuilding Marine & Engineering (DSME)

 – Saipem and Tripatra Engineers & Construction

 – Technip and McDermott

SURF Package 

For the SURF package (Sub-sea,Umbilical, Risers and flowlines) ENI and GDF-Suez qualified:

 – McDermott

 – Saipem and Swiber Offshore

 – Technip

 – Timas Suplindo and WorleyParsons and Subsea7

 – Tripatra Engineers & Construction with Emas-AMC

Sub-sea production system, control systems and manifolds

For this specific package , ENI and GDF-Suez could only play with the three classical bidders:

 – Aker Solutions

 – FMC

 – GE Vetco-Gray

In respect with their fast-track development program of the Jangkrik natural gas, ENI and GDF-Suez are expecting to issue the calls for tender in summer in order to make the final investment decision (FID) in first quarter 2013 for a completion and start-up in 2016.

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

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PetroChina to secure its oil supply chain  from Athabasca Fort McMurray to Kitimat, BC

Step by step the China National Petroleum Company (CNPC or PetroChina), is putting in place all the pieces of its upstream puzzle from Athabasca, Alberta oil sands fields to Kitimat, BC.

In 2011, PetroChina payed $1.9 billion capital expenditure to Athabasca Oil Sands Corporation (Athabasca) to acquire 60% of the MacKay River and the Dover oil sands projects.

In January 2012, PetroChina completed the full acquisition of the MacKay River oil sands field from Athabasca Oil Sands Corporation in spending additional $680 million in capital expenditure for the remaining 40% of the field.

The MacKay River and Dover oil sands fields are located in the middle of the oil rich Athabasca in the northeast of Alberta.

The MacKay River field is approximately 28 kilometers northwest of Fort McMurray, Alberta, and the Dover field is 95 kilometers northwest of Fort McMurray, Alberta

In March 2012, PetroChina has expressed interest to submit a competitive bid to build the $5.5 billion Enbridge Northern Gateway oil sands pipeline.

In parallel PetroChina is pushing hard to come back on the joint venture to take a stake of this Northern Gateway oil sand pipeline after having pulled out five years ago.

For PetroChina this Northern Gateway oil pipeline project is strategic as it should have a capacity to carry 550,000 b/d oil from northern Edmonton, Alberta to a marine export terminal to be built in Kitimat, BC.

In chasing long term positions in Athabasca Fort McMurray oil sands, in the Northern Gateway oil pipeline and in the Kitimat oil export Terminal, PetroChina consolidates its supply chain to China

WorleyParsons to provide engineering services for MacKay River and Dover oil sands fields

In this context, PetroChina has decided to move ahead on the development of the Mackay River and Dover oil sands projects.

The MacKay River an Dover oil sands fields are located in the middle of the oil rich Athabasca in the northeast of Alberta.

The MacKay River field is approximately 28 kilometers northwest of Fort McMurray, Alberta.

It should be developed in using steam assisted gravity drainage (SAGD) process as in situ oil recovery method.

Under SAGD, oil sands companies inject steam underground to melt thick tar-sands deposits.

The melting oil is then collected through a second pipeline and pumped up to the surface.

The MacKay River should produce 150,000 b/d of bitumen to be reached in phases.

At the phase one PetroChina is aiming at 35,000b/d bitumen.

 The MacKay River project should include:

 – Central processing facility

 – Well pad

 – Water source and disposal wells

 – Camps

 – Pipelines and utility corridors

The Dover project will consist of:

 – Two processing facilities

 – Associated infrastructure such as steam generation and distribution

 – Oil/water separation

 – Water treatment

 – Oil field gathering system

In the contracts signed with PetroChina, WorleyParsons will provide for:

 – Mackay River: engineering and procurement services to build well pad facilities at the oil field.

 – Dover: Initial design (pre-FEED) of the field development before the full front end engineering and design (FEED) task.

The engineering and procurement services contract on Mackay River should take 14 months while the pre-FEED on Dover should need eight months. 

The construction of the MacKay River and Dover projects will begin on second half 2012  as PetroChina expects the completion of the project and operations to start up in 2014 with the support of WorleyParsons.

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

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Technip and WorleyParsons completed the FEED

Chevron had awarded the front end engineering and design (FEED) for the development of Gengalo – Gehem project to:

 – Technip Jakarta office in Indonesia and Houston office in Texas, USA, for the two large Floating Production Units (FPU) package

 – Worley Parsons Indonesia for the Subsea and Flowline system package.

From these FEED performed by Technip and WorleyParsons, the packages are estimated to:

 – $1 billion for the construction of the FPUs

 – $2 billion for the Subsea and Flowline system

The high amount of the Subsea and Flowline system package is justified by Chevron‘s intention to tie Maha and Gandang fields in Gendalo FPU, as all located in the Strait of Makassar but at 20 kilometers distance from each other.

The Gendalo – Gehem is a non associated natural gas and condensate project developed by a joint venture in which the working interest are shared between:

 – Chevron 80% who will be the operator

 – ENI 20%

According to the FEED performed by Technip the:

 – Gendalo FPU will also treat the gas collected from Maha and Gandang fields with a total gas processing capacity of  420,000 mcf/d natural gas and 30,000 b/d condensate

 – Gehen FPU is designed to process 700 mcf/d natural gas and 25,000 b/d condensate

Then the natural gas and the condensate will be transported from the FPUs to the Santan Terminal, East Kalimantan through subsea pipelines with the respective length:

 – 150 km from Gendalo

 – 88 km from Gehem

A part of the gas will be sold as such and another part will supply the Bontang LNG facility.

All together Gendalo – Gehem and the connected Maha and Gandang fields should contain 4 trillion cf of recoverable gas reserves from which Chevron and ENI expect to produce at peak 1.1 billion cf/d of gas and 31,000 b/d condensate.

Korean EPC to win Gendalo – Gehem FPUs package

According to the Indonesian regulation, the Gendalo – Gehem project should have at least 35% of local content.

But the sizes of the FPUs, hundreds meters long,  and the 25,000 t topsides weight have requested Chevron to proceed with a strict selection of the potential EPCs having at least experienced $1 billion offshore projects.

In this context Chevron and ENI qualified three teams for the Call for Tender, each one having a South Korean contractor:

 – Saipem goes with Hyundai Heavy Industry (HHI) and the local Tripatra with the support of SMOE (Singapore) and Gunanusa (Indonesia)

 – McDermott submitted an invidual bid as still in discussion with Samsung Heavy Industries and STX Offshore is running for  and the local Singgar Mulia

 – Petrofac teams up with Daewoo Shipbuilding Marine & Engineering (DSME) for the hull, the Malaysian RNZ and the Indonesian Inti Karya Persada Technik for the topsides

In this contest, a South Korean EPC (Hyundai Heavy Industry, Samsung Heavy Industries, STX or Daewoo Shipbuilding Marine & Engineering (DSME)) should win the hulls of the Gendalo -Gehem FPUs 

Chevron and ENI qualify four teams for Subsea part

According to the FEED executed by Worley Parsons, the Subsea and Flowline system package will include the engineering, procurement, construction (EPC) and installation of:

 – 150 km natural gas and condensate export pipelines from Gendalo to the Santan Terminal Onshore Kalimantan

 – 88 km natural gas and condensate export pipelines from Gehem to Santan Terminal

 – SURF package (Subsea, Umbilicals, Risers, Flowlines)

Chevron and ENI qualified four groups of bidders:

 – France’s Technip with Dutch Heerema Marine Contractors and Singapore’s Swiber Offshore 

 – Italy’s Saipem with Indonesia’s Rekayasa Industries

 – UK’s Subsea7 with Indonesia’s Timas Suplino

 – Dutch Allseas with Singapore’s Emas Offshore

The installation of 630 km of pipelines, 80 km of umbilicals, 120 subsea flowlines connections by 1500 meters deep will require the winning team to charter a fleet of shallow to deep water S-Lay and J-Lay vessels.

To assess how much the team of EPCs in competition are aligned and able to execute and complete in 2016 the Gendalo -Gehem project, Chevron and ENI will invite all the contractors for pre-bid meetings to award the FPUs and Subsea packages on early 2013.

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

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