SABIC to ally with two engineering services companies

Saudi Arabia Basic Industries Company (SABIC) is moving toward alliance with a short selection of two companies to provide engineering services in similar way to Saudi Aramco General Engineering Services plus (GES+) pre-qualification program.

SABIC is preparing a call for tender for engineering services and project management consultancy (PMC) support.

In the same way as the Saudi Aramco GES+ contract, the qualified engineering companies should be awarded to provide SABIC with:

 - Feasibility Study

 - Pre-front end engineering and design (pre-FEED)

 - Front end engineering and design (FEED)

 - project management consultancy (PMC)

In respect with the number and size of the facilities SABIC is planning to qualify only two engineering services companies instead of five for Saudi Aramco GES+.

Once qualified, these two companies should be given the opportunity to upgrade and revamp one SABIC plant each.

Then if the engineering performances are measured successful, SABIC will split its 15 plants in Saudi Arabia between the two qualified companies.

These 15 companies should be selected among:

 - Kemya and PetroKemya

 - Arrazi, GAS and Hadeed

 - Sadaf, Sabtank, Safco, Sharq

 - Ibn Albaytar, Ibn Rushd, Ibn Sina, Ibn Zahr

 - Yanpet and Yansap

Actually six engineering companies have expressed their interest to SABIC to be invited to bid:

 - Fluor Corporation from USA

 - Hyundai Engineering and Construction from South Korea

 - Jacobs Engineering from USA

 - KBR from USA

 - Samsung Engineering from South Korea

 - Technip from France

SABIC E&PM leads the bidding and selection process

On SABIC side the process is managed by SABIC Engineering and Project Management (SABIC E&PM).

SABIC E&PM is a Department created in 2003 to develop and maintain an organizational structure, systems, procedures and best practices related to the major projects execution.

In that respect, SABIC E&PM is the center of excellence and expertise for engineering and project management.

The added value for SABIC relies on the quality of the engineering and project management services provided internally by the SABIC E&PM teams.

SABIC affiliates are considered as customers, to whom SABIC E&Pm is offering their expertise and services as soon as the operating units face major projects running out of their capabilities either because of the size, the complexity or the lack of available resources at a given period of time.

The first discussions between SABIC E&PM with the six potential bidders, confirmed the interest for this approach as long as the conditions of the tender are well defined and the key performances indicators (KPI) are also well known to measure success when contracts are awarded.

At tendering stage price per man hour will be the driver.

While in charge, the KPIs will require the engineering services companies to add resources to deliver on quality and on time.

In this context the outcome of the first discussions is for SABIC E&PM to be more specific in its requirements before proceeding with its call for tender that should take place in mid 2013.

For Saudi Aramco, the GES+ program had also involved seven companies at start from which five had been selected (Jacobs, KBR, Mustang Engineering, Foster Wheeler, SNC Lavalin).

In the meantime, Foster Wheeler has been replaced by WorleyParsons from Australia.

With SABIC they will be only two, scaling up the level of competition between Fluor, Hyundai E&C, Jacobs, KBR,  Samsung Engineering and Technip.

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

together WE achieve

Based in Abu Dhabi within the United Arab Emirates (UAE), the Abu Dhabi National Company (ChemaWeYaat) was established recently in 2008 as the spearhead of the petrochemical industry in the UAE.

In order to create immediately a regional champion and develop synergies, the stakeholders transferred their respective petrochemical assets into their purposely formed ChemaWeYaat subsidiary.

As a result ChemaWeYaat is currently owned by:

 - Abu Dhabi National Oil Company (ADNOC) 20%

 - International Petroleum Investment Company (IPIC) 40%

 - Abu Dhabi Investment Council (ADIC) 40% 

As a result of the consolidation exercise in ChemaWEEyaat of their respective petrochemical assets, the owners transferred:

 - ADNOC Abu Dhabi Polymers Company (Borouge) located in Ruwais

 - ADNOC Borouge Marketing PTE in Singapore

 - Ruwais Fertilizers Industries (Fertil)

 - Overseas IPIC petrochemical activities. 

In Abu Dhabi, the main ChemaWeYaat petrochemical assets are located in:

 - Madeenat Al Gharbia

 - Al Taweelah

In setting up this regional champion, ADNOC and its partners aim at building ChemaWeYaat market leadership on reliability, quality, cutting-edge technology and competitive feedstock.

In order to develop synergies and share good practice without delay, ChemaWeYaat is active member of the Gulf Petrochemicals & Chemicals Association (GPCA).

ChemaWeYaat is also partnering with international chemical operators, engineering companies and licensors such as ADNOC, Borealis, Neste Jacobs, or WorleyParsons to develop the most advance expertise in the hydrocarbon transformation.

ChemaWEyaat Key Figures

As national company, ChemaWeYaat is not listed and does not publish figures

ChemaWEyaat Projects and Business Highlights

As a young company made of production units coming from different horizons, the priority for ChemaWeYaat is to implement an integrated business model as its closest competitors in the Gulf.

Benchmarking Ras Laffan Indusrial City in Qatar or Al-Jubail Industrial City in Saudi Arabia, Abu Dhabi wants to build the Chemical City for ChemaWeYaat.

In December 2010, the Abu Dhabi Government made the choice of the location and approved the master plan of the future petrochemical complex to be erected there.

This master plan is designed around the sites of Madeenat ChemaWeYaat Al Gharbia, as well as the other production site in Al Taweelah.

Located on the Western Region of Abu Dhabi, Al-Gharbia benefit from 70 square kilometers next to Ruwais industrial complex.

On the model of Ras Laffan, Al-Gharbia include an export terminal, facilities to take in seawater, and a cooling system for the industrial city.

KOC to invest $7 billion in Lower Fars heavy crude oil

The national upstream Kuwait Oil Company (KOC) is considering to move into the engineering, procurement and construction (EPC)stage for the Lower Fars phase-1 project since WorleyParsons completed the front end engineering and design (FEED) work in 2012.

This phase-1 is part of the Lower Fars heavy crude oil scheme planned by KOC to meet its oil production targets for 2018.

These targets of crude oil production have been defined with the OPEC organization in order to guaranty its member to represent at least 40% of the global production.

This 40% is the minimum level that OPEC members consider to control crude oil market prices.

For Kuwait it means to produce 4 million b/d in 2020 compared with the actual 3 million b/d.

In respect with the depletion of the oil fields currently in operation, Kuwait measured that only the al-Ratqa heavy crude oil fields in the north of the country have enough in-place reserves to provide Kuwait with sufficient quantities to compensate the depletion and to bring additional barrels to meet 2018 targets.

KOC is aiming at a first step of 60,000 b/d production out of the heavy crude oil fields in 2018 to ramp it up to 270,000 b/d by 2020.

KOC estimated the development of the Lower Fars heavy crude oil field to require $7 billion capital expenditure.

Lower Fars will be the first crude oil field development in Kuwait to use unconventional technique such as the cyclic steam stimulation (CSS).

The purpose is to deploy the most advanced techniques of enhanced oil recovery (EOR) to stretch the plateau production as long as possible.

In this context, the Lower Fars phase-1 project will include:

 - Data colletion

 - Drilling operations for hundreds wells

 - Perform pilot cases combining EOR techniques to optimize production

 - Water treatment facilities

 - Infrastructures in respect with the remote location in the north of Kuwait. 

WorleyParsons designed Lower Fars in three packages

Since WorleyParsons completed the FEED on this Lower Fars phase-1, KOC is willing to move into the EPC stage for which three packages shall be awarded.

The first package is the most important with:

 - Crude oil central processing facilities (CPF)

 - Water treatment plant

 - Hazardous waste disposal treatment plant for water effluent

The second package is to link production location with Al-Ahmadi export terminal on the coast with:

 - Infield pipelines system

 - Water supply inlet pipeline to the CPF from Sulaibiya water treatment plant

 - Export pipeline of 24-inch diameter and 165 kilometers long

The third package will contains:

 - Offsites and utilities

 - Local production infrastructures

In respect with the unusual aspects of the project KOC will assess the expertise of the potential bidders in the different techniques to be used in this first heavy crude oil development.

Most likely, most of the engineering companies will need to team up in consortium to cover all required specialties.

KOC should call for bids on first half 2013 in order to make the final investment decision (FID) on the second half for this Lower Fars phase-1 heavy crude oil project.

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

Saudi Arabia Key Projects and Business Highlights

More than any other country, Saudi Arabia initiated in 2012 one of the most versatile program of investment for projects of the oil and gas and petrochemicals industry from offshore upstream to high performances chemicals.

Following the discoveries in the Egyptian side of the Red Sea, Saudi Aramco started also offshore exploration on the west side of the Red Sea.

While having the world fourth largest reserves of conventional natural gas, Saudi Arabia is burning 3 million /d of crude oil that should be substituted by natural gas.

In respect with the spread of prices between crude oil and natural gas, all the projects to implement this switch from oil to gas, are highly profitable.

Saudi Arabia needs gas to supply its power generation, as feedstock for its petrochemical industry, and to inject in depleting oil fields to boost production.

As Saudi Arabia is running short of natural gas, Saudi Aramco launched exploration and testing program to develop its shale gas resources.

In parallel to its upstream capital expenditure, Saudi Aramco keeps the pace downstream with the

 - Revamping and upgrade of its existing refineries, in Riyadh, Yanbu, Ras Tanura, and PetroRabigh

 - Construction of new refinery in Jizan and expansion in Luberef

 - Petrochemical expansions of PetroRabigh in joint venture with Sumitomo, SATORP in joint venture with Total, Saudi Kayan with Dow, Sahara and Tasnee.

But on the petrochemical side, Saudi Basic Engineering Corporation (SABIC) is the most active with major project in:

 - Kemya with ExxonMobil

 - Sadaf with Shell

SABIC is also investigating opportunities in shale gas, but in USA and only to buy it as competitive feedstock to balance its production and risks between North America and Middle East.

In 2012, both companies, Saudi Aramco and SABIC enforced their respective policy for the localization of the the engineering services in pre-qualifying Fluor, Jacobs Engineering, KBR, Mustang, WorleyParsons.

All these decisions made in 2012, will drive the projects and the selection of the suppliers and contractors in 2013. 

Saudi Aramco makes gas discovery in Read Sea

Saudi Arabia consumes 3 million barrels per day of crude oil for domestic consumption that could be substituted by natural gas.

In the same time, Saudi Arabia holds 282.6 trillion scf of natural gas reserves, ranking in the fourth position in the world.

>>> More information

Saudi Arabia: the next country to develop shale gas

Since Saudi Arabia is struggling to increase its natural gas production to meet its fast growing demand, the national oil company Saudi Aramco investigate all potential sources of supply, onshore and offshore, conventional and unconventional.

>>> More information

Saudi Aramco selected EPCs for Jizan Refinery

Saudi Aramco made a decisive step forward in selecting the engineering companies to build the $7 billion Jizan refinery and terminal project.

To balance its economical development between its different provinces, Saudi Arabiathrough Saudi Aramco had selected the city of Jizan,

>>> More information

SABIC and Shell to expand Sadaf joint venture

In November 2012, Saudi Basic Industries Corporation (SABIC) and Shell have decided to work on expansion opportunities of their joint venture Saudi Petrochemical Company (Sadaf).

These expansion ambitions are not limited to the sole Saudi Arabia

>>> More information

SABIC to benchmark Saudi Aramco GES+ services

Saudi Arabia Basic Industries Company (SABIC) is moving toward alliance with a short selection of two companies to provide engineering services in similar way to Saudi Aramco General Engineering Services plus (GES+) pre-qualification program.

SABIC is preparing a call for tender for engineering services and project management consultancy (PMC) support.

In the same way as the Saudi Aramco GES+ contract, the qualified engineering companies should be awarded to provide SABIC with:

>>> More information

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

Energising The Future

The Barhain Petroleum Company (BAPCO) is a national oil company wholly owned by the Government of Bahrain.

BAPCO is one of the oldest oil and gas company in the Gulf, established in Bahrain by the Standard Oil Company of California in 1929.

First oil was discovered in 1932 and the first refinery was built in 1936 with a capacity of 10,000 b/d which played a strategic role during the second World war.

This refinery was expanded to 250,000 b/d capacity in 1968.

In 1976, the company was incorporated as a national oil company called Bahrain National Oil Company (BANOCO).

In 1981, BAPCO was reactivated as a 60/40 joint venture between Bahrain Government and Caltex from USA.

In 1999, The Bahrain Government merged BANOCO and BAPCO in taking also 100% ownership of the newly BAPCO integrated company.

Today BAPCO is leading operations:

 - Upstream with oil and gas onshore and offshore exploration

 - Midstream with 54 kilometres pipelines to supply crude oil from Saudi Arabia and 14 million barrels storage capacity with natural gas and refined products marine terminal.

 - Downstream with the Sitra refinery still with its 250,000 b/d capacity from which 84% of the crude oil is coming from Saudi Arabia as feedstock.

From its Sitra refinery, BAPCO is selling 8% of its production on the domestic market and exporting the 92% to Middle East, India, the Far East, South East Asia and Africa.

In Barhain, BAPCO supplies the natural gas to the power generation facilities and other industries.

BAPCO Key Figures

2011 Revenues: $10.22 billion

BAPCO Projects and Business Highlights

Upstream, BAPCO signed production sharing agreements (PSA) with Occidental Petroleum from USA and PTTEP from Thailand to explore new fields onshore and offshore.

BAPCO intends to gather an monetize the flared gas and to develop and implement the enhanced oil recovery (EOR) techniques on the existing fields.

In that perspective, BAPCO signed with Noga a development and production sharing agreement (DPSA) 

Midstream, BAPCO is planning a new natural gas import terminal to meet its increasing domestic power consumption and to supply the refinery.

Downstream, the limited oil and gas resources in Bahrain, positions BAPCO refinery at the core of the local economy in exporting most of the refined Saudi crude oil.

Therefore BAPCO is planning to revamp and expand the refinery with additional 100,000 b/d capacity.

Since most of the refined crude oil is already imported from Saudi Arabia, the expansion of the refinery requires to build a new pipeline to increase the supply of crude as feedstock.

This pipeline should be 70 kilometers long to connect Ras Tanura refinery in Saudi Arabia to Sitra in Bahrain.

WorleyParsons is actually completing the front end engineering and design (FEED) work on this connection.

Then BAPCO is planning to call for the tenders of the engineering, procurement and construction (EPC) of the pipeline on the first half 2013.

In parallel, BAPCO completed the feasibility study of the revamping and expansion of refinery.

Now BAPCO is preparing the calls for tender for the FEED contracts of refinery for the second half of 2013.

From the feasibility study, the BAPCO Sitra refinery project should include four packages for FEED contract

 - Residue conversion unit

 - Hydrocracker and associated units

 - Crude units and associated facilities

 - Offsites and utilities

The largest package should be the Residue conversion unit due to treat heavy crude oil before refining.

But the most critical package will be the Offsites and utilities as to be integrated into the existing facilities.

In addition BAPCO is planning to appoint an adviser to select the technology that should be tendered mid 2013.

In this context, BAPCO is planning to award the estimated $6.5 billion capital expenditure EPC contracts of the four refinery packages by 2014 in order to run into commercial operations in 2017.

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

Shell and Saudi Aramco prepare bids for Kidan FEED

Shell and Saudi Aramco are working, through their joint venture South Rub Al-Khali Limited (SRAK), on the call for tenders of the front end engineering and design (FEED) of the Kidan gas field development project.

Saudi Arabia holds the third largest reserves of non-associated natural gas in the Middle East after Iran and Qatar.

But Shell estimates that three-quarters of this gas is trapped in sour or tight gas formations.

In this context, Saudi Aramco never put the exploration and production of its non-associated gas on the first page of its priorities.

With actual gas prices floating at their lowest ever levels under the pressure of the US market, Saudi Aramco may question even more the interest for such large investments.

But in parallel, Saudi Arabia consumption of energy is ramping up calling for more supply of crude oil.

With a barrel standing above $100, the production of electricity out of crude oil becomes questionable.

In addition the use of expensive crude oil as feedstock of the petrochemical sector is eroding the historical competitive advantage of Saudi Arabia in its integrated upstream-downstream business model.

Since Saudi Arabia is willing to boost its petrochemical industry to reliance on crude oil and create jobs for the younger generation, gas appears as a reasonable alternative.

In second half 2010 Shell and Saudi Aramco signed a second contract to explore 210,000 square kilometers in the Rub al-Khali, or Empty Quarter, region in southeast of Saudi Arabia.

Such area is about as large as the whole UK, so that both companies decided to focus on the Kidan formation.

Through this agreement, Shell and Saudi Aramco reactivated their 50/50 joint venture South Rub Al-Khali Limited (SRAK) to start a new appraisal program of the Kidan sour gas fields.

In December 2010, Shell and Saudi Aramco got the permit from the Saudi Ministry of Petroleum and Mineral resources for the exploration of the Rub Al-Khali region.

WorleyParsons completed Kidan feasibility study

In January 2011, Shell and Saudi Aramco selected the Australian engineering company WorleyParsons to perform the feasibility study of gas processing facilities for the Kidan project.

From the first results of this exploratory campaign, Shell and Saudi Aramco estimated the investment to develop Kidan to $8 billion capital expenditure.

Because of the amount and the remote location of the Kidan gas field, far from infrastructures, Shell and Saudi Aramco are planning to proceed in two phases of $4 billion capital expenditure each.

The first phase should include the gas processing facilities, but the high content of the Kidan sour gas field of hydrogen sulfur (H2S), up to 35%, require from start a sulfur treatment unit.

From the feasibility study completed by WorleyParsons, the Kidan gas processing facility should include:

 - Dehydration and dew-pointing unit

 - Gas sweetening

 - Condensate stabilization

 - Export gas compression

This Kidan gas processing facility should be designed with a capacity of 500 million cf/d of natural gas in order to match with the phases 1 and 2 of SRAK development.

This gas processing facilities will be connected to the Saudi transportation network by an export pipeline to be part of Kidan project.

Under the pressure of Saudi Aramco to get this gas out on short term, SRAK is preparing the call for tender of the FEED contract.

As part of Saudi Aramco policy to favor the local content, only the engineering companies pre-qualified by their General Engineering Service plus (GES+) contract should be invited to bid.

Since WorleyParsons replaced Foster Wheeler among the GES+ pre-qualified companies, the call for tender should be sent only to:

 - Jacobs ZATE

 - KBR-AMCDE

 - SNC Lavalin – Zuhair Fayez

 -WorleyParsons 

 Through their joint venture SRAK, Shell and Saudi Aramco expect to release the call for tender for the FEED of the Kidan gas field development project on first half 2013 for the award on second half 2013.

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

Shell to start upstream and postpone LNG Trains

Since November 2012, the Anglo-Dutch international company, Shell, and China National Petroleum Company (CNPC or PetroChina) multiplied announcements to reconsider their Arrow LNG project in the Queensland in eastern Australia.

Shell and PetroChina wholly own the Arrow LNG project through a 50/50 joint venture with the intention to invest $20 billion capital expenditure in the development of the Bowen and Surat onshore gas fields and Curtis Island export liquefied natural gas (LNG) trains.

On the upstream side of the Arrow LNG project, Shell and PetroChina are planning to extract the coal-seam gas (CSG)  from the coal-bed methane of the Bowen and Surat basins located 160 kilometers west of Brisbane.

For the export of the gas, Shell and PetroChina were initially considering to build a LNG facility on the Curtis Island.

Designed to reach 18 million t/y capacity, Arrow LNG should include two series of two LNG trains of 4.5 million t/y capacity each.

The Bowen and Surat gas fields should be connected to the Curtis Island by a gas export pipeline from the Bruce Highway to Curtis Island.

But this Arrow LNG project comes in the fourth position in the series of similar LNG projects to be all erected in the Curtis Island:

 - Australia Pacific LNG by Origin Energy and ConocoPhillips

 - Gladstone LNG by Santos, Total, Petronas and Kogas

 - Queensland Curtis LNG by BG Group

In addition to Arrow LNG, Shell has interests in other LNG projects in Australia with Prelude FLNG, Crux FLNG and Gorgon LNG together with Chevron.

Trough this large observer position, Shell could measure the consequences on the costs and time frames of this accumulation of LNG projects, onshore  in the Queensland as well as offshore Western Australia with there respective onshore LNG facilities.

When Shell, ExxonMobil and Chevron, the operator, made the final investment decision (FID) on Gorgon LNG, the budget was estimated around $37 billion capital expenditure with first production to come on stream on 2014.

Actually Shell estimates that it should cost $20 billion more.

Shell to award FEED contract on Arrow LNG upstream

In the Queensland, the three LNG projects already engaged will require more than $70 billion with free space available for LNG trains expansion.

These projects are also challenged by costs escalation because of the local labor work force shortage.

In addition two of them, Gladstone LNG and Queensland Curtis LNG, may have hard to develop the upstream side capacity sufficiently to load the designed export LNG trains

In the context of costs escalation and available LNG capacities on the Curtis Island, Shell and PetroChina are reconsidering their strategy to develop Arrow LNG in two phases:

 - Phase 1: To implement the upstream coal-seam gas production within a planning matching with budgeted costs and using available capacities from in coming Curtis Island LNG facilities for liquefaction

 - Phase 2: To build new LNG trains in addition to existing LNG facilities or separately as initially planned.

Shell currently holds discussions with Santos and BG Group to investigate opportunities for a deal allowing Arrow LNG to share their respective LNG trains facilities for export in the meantime to launch the phase 2.

On Arrow LNG upstream portion of the project, Shell and PetroChina are evaluating the engineering companies in competition for the front end engineering and design (FEED)  of the coal-seam gas production.

The scope of work should cover:

 - Wellhead equipment and installation

 - Gas gathering system

 - Gas compression station

 - Water treatment facilities

If successful, the FEED contract should be converted into engineering, procurement and construction management (EPCM) contract by the end of 2013.

Shell and PetroChina are reaching the final stage of the technical and commercial bids submitted by:

 - Amec and Clough

 - Fluor

 - Foster Wheeler with SKM Engineering

 - WorleyParsons

Regarding the Arrow LNG trains facility that should come in Phase 2 , Shell and PetroChina qualified:

 - CB&I from USA with Saipem from Italy

 - Chiyoda from Japan

 - Fluor from USA with JGC from Japan and Clough from Australia

 - KBR from USA with China Huanqiu Contracting & Engineering Corporation( HQCEC) with John Holland

With this two steps approach on the Arrow LNG project, Shell and PetroChina expects to keep costs under pressure on the upstream portion and to save time and money for natural gas export in benefiting from the LNG trains projects already in progress from Santos or BG Group on the Curtis Island in the Australian Queensland in order to start production and export by 2018.

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

Fluor and WorleyParsons in JV with KING and KGNT

In May 2012, TengizChevrOil (TCO), the joint venture between Chevron, ExxonMobil, KazMunaiGas (KMG) and LukArco (Lukoil), awarded a first FEED and EPCM contract to a Fluor-led joint venture with WorleyParsons and Kazakh companies KING and KGNT for the Wellhead Pressure Management package of the Tengiz Future Growth Project (FGP) in Kazakhstan. 

Together with the Korolev field, Tengiz is one of the world largest crude oil field discovered on the last 40 years.                                           

Located in western Kazakhstan, Tengiz and Korolev are given to hold 26 billion barrels of crude oil as in-place reserves out of which 6 to 9 billion (23 to 35%) should be recoverable reserves.

Tengiz field covers 2,500 square kilometers with one of the world onshore deepest reservoir as lying between 4,000 and 6,000 meter deep.

Discovered in the 1930s, the natural pressure of the reservoir due to its deep in the ground geologic position and its content of highly corrosive sour gas were causing some challenges for large scale exploration and production until Kazakhstan and Chevron signed a 40 years agreement and formed the TengizChevrOil (TCO) joint venture in 1993.

Because of the size and complexity of the field, Kazakhstan and Chevron opened the TCO joint venture to other partners so that they share today the working interests between:

 - Chevron 50% is the operator

 - ExxonMobil 25%

 - KazMunaiGas (KMG) 20%

 - LukArco (Lukoil) 5%.

Since 1994, Chevron and its partners started to build series of crude oil processing facilities, called Complex Technology Lines (KTL), to ramp up the production of crude oil, natural gas, liquefied petroleum gas (LPG) and sulfur.

As Tengiz is rich of sour gas, TCO decided to use it to compensate the natural depletion of the field by re-injection in the reservoir.

Together with Fluor and WorleyParsons, Chevron and its partners ExxonMobil, KMG and Lukoil, developed this technology with new processes called:

 - Second Generation Plant (SGP)

 - Sour Gas Injection (SGF) facilities

This SGP/SGF technology was implemented in 2008 boosting the crude oil production to 540,000 b/d.

Since 1993, Chevron invested $20 billion to develop Tengiz and introduce this unique enhanced oil recovery (EOR) solution based on high pressure hydrogen sulfide injection.

From this successful experience, Chevron is working on the deployment of this sour gas injection solution at large scale on the Tengiz field with the TCO Future Growth Project.

With the Future Growth Project, TCO is willing to take a leap in boosting again the crude oil production from 24.2 million tonnes (193 million barrels) in 2012 to 36 million tonnes (290 million barrels) in 2016

GE Nuovo Pignone to supply the gas compressors

Chevron and its partners ExxonMobil, KMG and Lukoil will invest up to $20 billion capital expenditure in this Future Growth Project (FGP) to be developed in three phases:

 - Extensive drilling program of 190 wells

 - Wellhead pressure management program (WPMP)

 - Sour gas injection

The drilling program is already on going to deploy the production wells and injection wells across Tengiz field.

Then TCO selected for the so called FGP – WPMP project the KPJV  joint venture made on Fluor,WorleyParsons and the local contractors KING and KGNT for the design and engineering of the wellhead pressure management program package.

Within the KPJV joint venture, the engineering companies share interests such as:

 - Fluor 30% is the leader

 - WorleyParsons 30%

 - KING 20%

 - KGNT 20%

In parallel GE Nuovo Pignone has been selected for the compressors.

Most of the engineering work will be performed in Farnborough Fluor and  WorleyParsons office.

The project to be executed in modular design includes:

 - New gathering system

 - Crude processing facilities with 260,000 b/d capacity

 - Crude tank farm

 - Gas processing facilities with 960 million cf/d capacity

 - Power generation

 - Offsites and utilities

Regarding the contracting activities, Kazakhstan is keen to show how much such giant project can contribute to the development of the local communities.

Actually 80% of TCO employees are Kazakh and  the local Authorities expect this percentage to increase with the Future Growth Project in performing most of the construction work in Kazakhstan.

This sourcing strategy motivates Fluor and WorleyParsons to design the Wellhead pressure management package in modules. 

Chevron is the largest producer of crude oil in Kazkahstan; in combining Fluor and WorleyParsons experience in sour gas injection together with a strong local content sourcing policy, Chevron and its partners ExxonMobil, KMG and Lukoil expect to implement the sour gas injection in the Tengiz Future Growth Project with the good acceptance of the local communities.

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

Block 61 among world largest tight gas development

In January 2013, BP received the technical and commercial offers from the engineering companies bidding on the key packages of its Block 61 tight gas full field development phase-1 project in the Sultanate of Oman.

Last September, BP had announced to scale up its capital expenditure from $15 billion to $24 billion to develop and turn the complex fields such as Khazzam and Makarem of the Block 61 into production.

Located in the Al-Dahirah Governorate, at center west of Oman, the Block 61 covers 2,800 square kilometers as one of the world largest tight gas field currently under greenfield development.

Discovered in the 1990s, by 4,500 to 5,000 meters depth, this field is made of four main reservoirs, including Khazzam and Makarem, estimated to contain 20 to 30 trillion cubic feet (tcf) of natural gas.

Because of its complexity and remote location requiring advanced technology for production and heavy infrastructures for transportation, this Block 61 have been left untapped.

It is only in 2007 that the Sultanate of Oman and BP signed a production sharing contract (PSC) giving BP 100% of the working interests to explore and develop the Block 61.

Immediately in following Global Geophysical Services and PGS Data Processing ME performed an intensive campaign of 3D seismic data acquisition to detail the field and confirm its potential reserves.

In 2011, BP performed successfully the first horizontal well with hydraulic fracturing technique.

The first natural gas production was sent to the Saih Rawl gas central processing facility (CPF) engineered and constructed by  in Oman.

From these first tests BP awarded the pre-front end engineering and design (pre-FEED) and FEED work to WorleyParsons Oman to designed its Oman Full Field Development phase-1 program to produce 1 billion cf/d of natural gas during 25 years.

The hydraulic fracturing process used by BP requires a significant consumption of soft water to facilitate the tight gas production.

This soft water is loaded with chemical products to facilitate the gas mobility in the reservoir.

At the production well, this water is separated from the gas and requires a waste treatment by desalination.

Four bidders for Saih Rawl gas central processing plant

Therefore the BP Oman full Field Development phase-1 project has been designed with:

 - Fracturing equipment

 - Well testing facilities

 - 500 kilometers of flowlines

 - Central Processing facilities

 - Gas processing plant with 1.2 billion cf/d capacity

 - 100 kilometers export gas pipeline

 - Infrastructures

 - Waste water treatment facility

In January 2013, BP received the tenders for the engineering, procurement and construction (EPC) contracts for two EPC packages:

 - Flowlines, Central processing facilities, gas central processing plant, export pipeline and associated facilities

 - Early development phase, gas gathering, wellsides and export system (GWES) facilities, building and infrastructures work

Four teams of engineering companies submitted an offer for the first EPC package:

 - Bechtel from USA with Bahwan Engineering Company from Oman

 - CB&I from USA with Larsen & Toubro from India

 - Petrofac from UK with Consolidated Contractors Company (CCC) from Greece

 - Technip from France with Galfar Engineering & Contracting and Al-Hassan Engineering Company and Special Technical Service, all three from Oman

Three bidders returned offers for the second EPC package:

 - Bechtel from USA

 - Carillion Alawi from UK and Oman

 - WorleyParsons Oman

With these technical and commercial bids submitted, BP is ready to go for this Oman Full Field Development phase-1 considering that the phase-2 should be mostly concentrated on the expansion of the drilling operations and multiplication of the production wells of this Block 61 tight gas.

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

RiCoal selected Rostov for its Petrochemical complex

The Russian joint venture RiCoal Chemical Coal Plant (RiCoal) is planning to build a world-scale Coal-to-Olefin and petrochemical complex in Rostov-on-Don in the south of Russia.

Estimated to require $2.5 billion capital expenditure, RiCoal selected Rostov-on-Don location because of available coal and natural gas available in the region and the easy access to export markets for the petrochemical production.

RiCoal is a joint venture of local partners including:

 - Gefest-Rostov producing polymers for oil and gas anti-corrosion agents

 - Spetzmontazhproekt-6 is a contractor specialized in construction of industrial buildings and large infrastructures

 - Stroitelno-montazhny poezd-162 is an engineering company based in Bataisk

 - Krosna Bank is a registered Russian bank.

Because of the shortage of petrochemical products in the region, the RiCoal partners identified the opportunity to take advantage of the huge local reserves of coal in the Donbass Basin and of the natural gas available all over between the Azov Sea, the Black Sea and the Caspian Sea to work on this Coal-To-Olefin and petrochemical complex.

RiCoal to combine Coal-To-Methanol and Methanol-To-Olefin processes in Rostov petrochemical complex

The process of the project is split in two stages:

 - Stage 1 will use natural gas and coal to produce syngas to be then converted into methanol, the optimized process to convert Coal-To Methanol (CTO)

 - Stage 2 will use Methanol-To-Olefins (MTO) technologies to produce ethylene, propylene and their derivatives into polyethylene and polypropylene.

The Don River is navigable all year round facilitating the export toward Central Europe, Kazakhstan, Turkey or Ukraine.

The RiCoal project should consume:

 - 1.5 million tons per year (t/y) of coal

 - 1.6 billion cubic meters per year (cm/y) of natural gas.

RiCoal signed an agreement with Gazprom for the natural gas supply and other contracts are in discussion to secure feedstock.

The RiCoal project will require to build:

 - 1,730 t/y coal-to-methanol plant

 - 333,000 t/y polypropylene facility

 - 269,000 t/y polyethylene unit

 - 122,000 t/y acid acetic plant

 - 100,000 t/y acetic anhydride

 - 1.6 billion cm/y gas compression station

 - 40 kilometers water supply pipeline

 - 18 kilometers natural gas inlet pipeline

 - 10 kilometers electrical power lines

 - 12 kilometers railways connection

In the first phase, RiCoal will use the existing export terminals,and in a second phase will build its own export terminal.

Regarding the financing of the infrastructures, RiCoal is in discussion with the Rostov Region Government to provide the financing considering that the RiCoal Coal-To-Olefin project should create more than one thousand permanent jobs in the region. 

WorleyParsons completed RiCoal feasibility study

On the first quarter 2013, WorleyParsons completed the feasibility study and the front end engineering and design (FEED) of the RiCoal project.

As a result the licensors and the suppliers of large equipment have been pre-qualified, some have already been selected:

 - Coal equipment: Russia and FAM Germany

 - Air Separation: Air Products from UK

 - Natural gas steam reforming: Haldor Topsoe from Denmark

 - Coal gasification: GE from USA or Siemens from Germany

 - Methanol manufacturing: Haldor Topsoe from Denmark

 - Methanol to Olefins: UOP from USA

 - Polyethylene and Polypropylene: Ineos from USA and Basf from Germany

 - Power generation: GE from USA and Siemens from Germany

 - Power boilers and other equipment: Foster Wheeler from Russia and Finland

To support the project, RiCoal is looking for strategic partners in Russia and overseas to provide financial equities and technological expertise in similar projects.

This fund raising exercise should be completed by mid 2013.

Then the engineering, procurement and construction (EPC) phase should start on the second half of 2013.

WorleyParsons and SNC Lavalin are among the pre-qualified companies to be invited to bid, but RiCoal is currently expanding the list with US based engineering companies.

With a construction to be completed at the end of 2015, the RiCoal Coal-To-Olefin project should see the first shipments to take place on the first half 2016.

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

Hyundai Heavy Industries (HHI) wins Rosebank FPSO

The super major Chevron from USA and its partners, Statoil from Norway, OMV  from Austria and Dong from Denmark, have awarded the Floating Production, Storage and Offloading (FPSO) vessel of the Rosebank project to the South Korean Hyundai Heavy Industries (HHI).

The Rosebank project is located 175 kilometers northwest of the Shetland Islands close to the limits of the UK territorial waters.

Lying on the Corona Ridge of the Faroes – Shetland Channel by 1,115 water depth, the Rosebank oil and gas field is one of the largest discovery of this untapped region as it covers the Blocks 213/26 and 213/27.

Between 2004 and 2007, Chevron and its partners spent $327 million to explore these Blocks and realize the potential of the Rosebank project.

With reserves estimated to 250 million barrels of oil equivalent (boe), Chevron and its partners hold the license on the biggest reservoir of the UK Continental Shelf (UKCS) that could contain up to one fifth of the remaining crude oil reserves in the UK.

In 2011, Chevron and its partners evaluated the development of the Rosebank oil and gas field to require $6 to $8 billion capital expenditure.

Chevron is leading the Rosebank joint venture with working interests shared between:

 - Chevron 40% , the operator

 - Statoil 30%

 - OMV 20%

 - Dong Energy (Dong) 10%

During the pre-front end engineering and design (pre-FEED) and front end engineering and design (FEED) phases of the project, WorleyParsons and Wood Group bagged most of the contracts from Chevron and its partners.

In 2011, WorleyParsons signed the pre-FEED of the FPSO.

From this pre-FEED, Chevron and its partners decided to develop the Rosebank oil and gas field with a:

 - FPSO

 - Export natural gas pipeline

 - Subsea production system

 - Production wells

 - Water injection wells

 - Semisubmersible drilling rig

Chevron boosted Rosebank FPSO capacity since FEED

In July 2012 WorleyParsons UK and its Houston-based subsidiary IntecSea booked the FEED contract for the FPSO and its associated subsea production system and infrastructure.

In parallel, in November 2012, Chevron and its partners selected JP Kenny from the Wood Group to perform the pre-FEED and FEED work on the export gas pipeline to the Shetland Island.

According to the term of the contract, JP Kenny will also provide the:

 - Early procurement support for this 230 kilometers (143 miles) pipeline

 - Structural design for the deepwater pipeline end manifiold (PLEM)

Rosebank being located on the northwest of the Laggan-Tormore gas field operated by Total, the Rosebank export pipeline will plug in the Laggan-Tormore Shetland Islands Regional Gas Export line.

This Regional Gas Export pipeline is then connected to a new southeast export pipeline to St Fergus at the north of Aberdeen. 

Originally Rosebank was designed to process at plateau production:

 - 75,000 b/d of oil

 - 100,000 million cf/d of natural gas

Because of the promising oil and gas reserves of the Rosebank field, Chevron and its partners revised upward the size of the FPSO so that in the engineering, procurement and construction (EPC) contract awarded to Hyundai Heavy Industries (HHI). the FPSO should have the capacity to process:

 - 100,000 b/d of crude oil

 - 190,000 million cf/d of natural gas

In addition this FPSO should have storage capacities of 1.05 million barrels of crude oil.

With these performances, the FPSO should be 292 meters long, 30 meters wide and should weight 99,750 metric ton.

In respect with the harsh environment of the North Sea in this area, Chevron and its partners have opted for the Norwegian NORSOK standards to be applicable to the Rosebank FPSO while it will operate in the UK side of the North Sea.

This EPC contract has been awarded for the amount of $1.9 billion capital expenditure. 

To be build in Hyundai Heavy Industries shipyard of Ulsan in South Korea, Chevron and its partners, Statoil, OMV and Dong expect the FPSO to be delivered at the end of 2016 for commercial operations to start in 2017.

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

CNPC to join Petroecuador in Ecuador Refinery project

The giant China National Petroleum Company (CNPC or PetroChina) is currently in discussion with the national oil companies (NOCs) Petroecuador and Petroleos de Venezuela SA (PDVSA) to take a stake in the Ecuador Refineria del Pacifico project.

With a production of 500,000 barrels per day (b/d), Ecuador is the smallest member of the producing countries cooperating under the OPEC organization.

By comparison Ecuador production represents one sixth of Venezuela.

The national company Petroecuador is operating three refineries:

 - Esmeralda, in the eponym region, is the largest one with 110,000 b/d capacity

 - La Libertad, along the southwest Pacific Coast

 - Amazonas, in the Shushufindi region, in the northeast of Ecuador, is the smallest one.

Over the last years, Ecuador had to face a couple of challenges with these refineries that require now heavy investments.

Built in 1977, these refineries are aging and cannot run at their nominal capacities.

In parallel, Ecuador production has turned more and more to heavy crude oil as many other countries after the maturation of the conventional oil fields firstly developed 30 years ago.

In addition the domestic consumption of refined fuels is increasing constantly with the development of the country.

As a result, Ecuador is no longer able to refine its own crude oil and must import refined fuels.

Even if the export of crude oil represents 35% of the Ecuador Government budget, the import of expensive refined fuels compromises the trade balance of the country.

In order to help each other between political allies, Ecuador and Venezuela made a deal in 2008, to facilitate the refining of the Ecuador crude oil in Venezuela.

Unfortunately since this agreement was signed, Venezuela faced also some difficulties to maintain its full refining capacities, especially to treat heavy crude oil.

Thus, 53% of the refined fuels shipped from Venezuela back to Ecuador were in fact traded from third party countries such as Saudi Arabia.

Despite the quality of the relationships between the two countries, such model on the supply side cannot last too long.

Ecuador to revamp and upgrade old refineries

On the demand side, Ecuador signed in parallel an oil advance sales agreement with PetroChina.

According to this agreement, PetroChina paid $1 billion as down payment on the shipment of 69.12 million barrels due in the period 2009 – 2010.

In 2011 a similar agreement was signed again for two years based on 96,000 b/d.

As a consequence of this agreement, while the Ecuador export of crude oil was 55.5 million barrels on the first six months of 2012, PetroChina was quadrupling its share from 17% to 69% of these exports on the same period.

In this context and with the financing support from China, Ecuador is planning to invest:

 - $750 million to revamp and improve energy efficiency of the Esmeralda Refinery

 - $600 million to upgrade the Esmeralda Refinery with high-quality and low sulfur content products

 - $800 million to overhaul the Amazonas Refinery

 - $10,000 million to build a greenfield refinery and petrochemical complex, the Refineria del Pacifico project.

To be located close to Rio Manta in the Manabi province of Ecuador, the Refineria del Pacifico is designed to treat 300,000 b/d of crude oil, from light to heavy crude oil.

From the original project, the petrochemical complex to be built downstream the refinery has been reduced in order to contain the whole greenfield refinery and petrochemical complex in a budget of $10 billion capital expenditure.

Petroecuador awarded Refinery PMC to WorleyParsons

So far Petroecuador and PDVSA share the ownership of the Refineria del Pacifico greenfield projects in such a way that:

 - Petroecuador holds 51% and is the operator

 - PDVSA owns 49%

But in the context of the relationships described above between Petroecuador, PDVSA and PetroChina, the partners have opened discussions to allocate 30% of the Refineria del Pacifico project to PetroChina.

In this scenario, PDVSA would reduce its own stake by the same share, leaving Petroecuador unchanged.

With this program, Ecuador is targeting to ramp up its crude oil production to 530,000 b/d.

The production of refined products should go for 45% to the domestic market for transportation fuels and to supply the feedstock of the petrochemical complex.

The remaining part should be exported.

In November 2011, Petroecuador and PDVSA selected WorleyParsons for project management consultancy (PMC) to cover the :

 - Front end engineering and design (FEED) work

 - Future engineering, procurement and construction (EPC) contracts.

Currently the Brazilian engineering company, Odebrecht is already at work to prepare the construction site.

After more than $500 million capital expenditure already invested in the Ecuador Refinery project, Petroecuador and PDVSA expect to close the deal with PetroChina in coming weeks, in order to start production in 2016.

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

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

Anadarko combines subsea and FPU in Rovuma Area-1

The Houston based Anadarko Petroleum  (Anadarko) and its partners  Mitsui E&P (Mitsui), BPRL Ventures Mozambique B.V. (BPRL), Videocon Mozambique Rovuma (Videocon), PTTEP and ENH, are exploring all the potential solutions for the offshore part of its liquefied natural gas (LNG) project in the area-1 of the Rovuma Basin Offshore Mozambique.

Since 2011, Anadarko accumulated major discoveries in the Area-1 of the Rovuma Basin along the East Coast of Africa:

 - Properidade Complex

 - Gulfinho and Atum Complex

 - Bargentine

 - Camarao

 - Lagosta

Currently Anadarko and its partners accumulated 65 trillion cubic feet (tcf) recoverable reserves of natural gas from the Area-1, but in respect with the remaining part of the fields to be explored, Anadarko estimates that these reserves should exceed 100 tcf.

Since the Italian national oil company Eni is running on the same path within the neighboring Area-4, the Mozambique Government asked to both companies to cooperate in order to optimize resources and infrastructures in the development of their respective project.

In practice, Anadarko and Eni signed in December 2012 a  Heads of Agreement (HOA) to guide their cooperation in the development of their respective licensed Area.

The main focus of this HOA is the onshore LNG plant to concentrate the production and export of LNG for both groups of companies operating the Area-1 and the Area-4.

To be located in the Afungi LNG park, the Mozambique LNG project should require 10 LNG trains to be developed in phases depending on the speed of the implementation of the offshore production infrastructures.

This conventional concept to develop the Rovuma Basin with offshore production unit, export pipelines to shore and onshore LNG plant with vessels offloading facilities has been imposed by the Mozambique Government in order to maximize the added value of the project for the local economy.

Anadarko compares concepts for Prosperidade FPU

KBR and Technip completed the pre-front end engineering and design (pre-FEED) of this onshore Afungi LNG plant while three groups of companies are at work on a competitive front end engineering and design (FEED):

 - Bechtel from USA

 - CB&I from USA with Chiyoda from Japan

 - JGC from Japan with Fluor Transworld Service from USA.

Regarding the offshore part of the Mozambique LNG project Anadarko and Eni are working separately, out of the scope of their HOA.

Anadarko is planning to begin the development of the Area-1 by the Properidade complex.

Covering 260 square kilometers in the north of the Area-1, the Prosperidade complex contains 17 to 30 tcf of recoverable reservesout of 30 to 50 tcf in-place reserves of natural gas.

To perform the FEED on this offshore part of the project, Anadarko and its partners contracted three engineering consortia:

 - McDermott with Allseas

 - Saipem with Subsea7

 - Technip with Heerema, since both companies signed  a strategic alliance

In parallel the Houston-based IntecSea from WorleyParsons has been appointed by Anadarko and its partners to design the subsea gathering system.

If most of the production from the Properidade Complex is designed to be operated subsea, it will also require a floating unit to support the gas compression facilities to export the gas to the shore.

The subsea wells should have a flow rate between 100 and 200 million cf/d of gas.

The export pipeline should have a capacity of 2 billion cf/d of gas through twin pipelines of 22-inch each. 

From the conceptual study completed by KBR‘s Granherne, this floating production unit (FPU) should have a capacity of 2 billion cubic feet per day (cf/d).

Considering the sizing of the offshore gas compression facilities, Anadarko and its partners,  Mitsui E&P (Mitsui), BPRL Ventures Mozambique B.V. (BPRL), Videocon Mozambique Rovuma (Videocon), PTTEP and ENH are now evaluating all the alternatives for the hull including, ship-shaped hull, semisubmersible platform or SPAR for this Mozambique LNG FPU to be in operations in 2018.

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

BG Group opts for competitive FEED on QCLNG-2

The London-listed BG Group plc (BG) has decided to organize competitive bids on the front end engineering and design (FEED) for the expansion of its giant Queensland Curtis LNG (QCLNG) project in the Southeast of Australia.

In its first phase, the QCLNG project was the first one to be sanctioned with a final investment decision (FID) to produce liquefied natural gas (LNG) out of coalbed methane (CBM) fields in the Curtis Island, offshore the Queensland State in the southeast of Australia.

BG decision to move on the QCLNG project phase-2 is following the binding signature last May with the China National Offshore Oil Corporation (CNOOC) on an extended partnership in the Queensland Curtis LNG project.

This agreement is sealing the companies on the Heads of Agreement (HOA) inked in October 2012.

By this agreement, CNOOC is increasing its shares in the QCLNG project and is committing to more than double its purchase volume of LNG as the main customer for the QCLNG project.

According to the terms of this agreement, CNOOC:

 - Ramped up its working interests in QCLNG Train-1 from 10% to 50%

 - Committed to purchase a total of 8.6 million t/y of LNG instead of the previously 3.6 million t/y

 - Owns 25% interests in the Walloons Fairway BG Blocks of the CBM Surat Basin and Bowen Basin in Queensland

 - Invests jointly with BG in two additional LNG carriers

While CNOOC will not have any interest in QCLNG Train-2, this agreement opens the option for CNOOC to take 25% interest in one of the LNG trains to be added in the Queensland Curtis LNG expansion project

Based on this agreement BG could make the decision to speed up the Queensland Curtis LNG Project Phase-2 with a competitive FEED.

QCLNG  Phase-2 Project pre-FEED completed in July

From the Heads of Agreement signed in October 2012 with CNOOC, BG could anticipate on the opportunity to proceed with the QCLNG expansion project.

Therefore BG organized a competitive pre-front end engineering and design (pre-FEED) between six engineering companies, typically Amec, Bechtel, CB&I, Clough, Fluor and WorleyParsons.

This pre-FEED work should be completed by July 2013.

From this pre-FEED competition, BG will select two engineering companies to continue on a competitive FEED.

In 2014, BG will convert the contract of the competitive FEED winner into an engineering, procurement and construction (EPC) contract.

For this QGLNG Phase-2 project, BG intends to replicate the QCLNG Trains 1 and 2 architecture with the Trains 3 and 4 combined capacity of 8.5 million t/y of LNG.

The QCLNG expansion project should benefit from the existing 540 kilometers inlet gas pipeline, LNG storage facilities and marine offloading jetty for the LNG carriers.

So this QCLNG phase-2 project should include:

 - LNG Trains 3 and 4

 - Gas treatment facility

 - Water treatment facilities

Although BG estimates its resources in-place to 29 trillion cubic feet (tcf), mostly in the Surat Basin of Queensland State, BG is continuing its exploration campaign for CBM in the Owen Basin.

In addition BG started to test resources for shale gas and tight gas in the Cooper Basin.

With these new discoveries in the Bowen and the Cooper Basins BG secured enough resources to feed the third train of the Queensland Curtis LNG phase-2 project.

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

BP selects bidders for Tangghu LNG FEED competition

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

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

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

 -  Mitsubishi Inpex Berau B.V with 16.30%

 - China National Offshore Oil Corporation (CNOOC) 13.90%

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

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

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

 - Talisman 3.06%

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

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

Two new platforms to supply Tangguh LNG Third Train

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

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

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

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

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

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

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

WorleyParsons completed the FEED of these platforms in 2013.

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

 - Bakrie Industries

 - Gunanusa

 - Han Jung

 - Hyundai Heavy Industries (HHI)

 - Larsen & Toubro

 - McDermott

 - Meindo Elang Indah

 - Nippon Steel

 - Pal Indonesia

 - Saipem SMOE

 - Swibber Offshore with Emas Offshore

 - Technip

 - TL Offshore

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

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

Fluor at work on FEED for Sasol US Mega Projects

The South African company Sasol is currently proceeding to the selection of the license and technologies required for the olefins and derivatives production units of its integrated gas-to-liquid (GTL) and ethane cracker complex to be built at Lake Charles in Louisiana, USA.

With an estimated budget of $21 billion capital expenditure, the Sasol GTL and Ethane Cracker complex shall be the largest ever project in Louisiana.

As a world leader of synthetic fuel technologies from coal and natural gas, Sasol does not want to miss the opportunity of the abundant and cheap shale gas feedstock to expand its market leadership in USA.

In proposing its GTL - Ethane Cracker and Derivatives  integrated business model, Sasol intends to optimize its added value from the gap between the low gas prices and the high prices of the liquid fuels and petrochemical derivatives driven by the crude oil prices and the demand of the manufacturing industry in the US domestic market.

In this perspective, Sasol awarded in December 2012, the front end engineering and design (FEED) contract of the Lake Charles project to the Houston-based engineering company Fluor.

This FEED contract covers the GTL plant, the ethane cracker and the petrochemical facilities defined as Sasol US Mega Projects.

WorleyParsons appointed project manager consultant

In respect with the complexity and diversity of the processes and production units, Sasol has appointed WorleyParsons to provide project management consultancy (PMC) on the whole Lake Charles project.

According to its PMC contract, WorleyParsons will support Sasol project management from the FEED phase to the engineering, procurement and construction phase.

In parallel Sasol has also started to identify the best technologies to leverage its GTL- Ethane Cracker and derivatives integrated business model.

For the tetramerization in the Ziegler alcohol and Guerbet units, Sasol will use its own proprietary processes.

Regarding the other critical technologies, Sasol selected:

 - ExxonMobil for the low density polyethylene (LDPE) unit

 - Scientific design for the ethylene oxide (EO) unit and the monoethylene glycol (MEG) unit

 - Technip Stone and Webster for the ethane cracker

 - Univation Technologies for the the linear low density polyethylene (LLDPE) unit

Based on these licenses, Sasol awarded the basic design for the corresponding petrochemical units to:

 - Mitsui Engineering and Shipbuilding (Mitsui) for the LDPE

 - Samsung Engineering America for the EO and MEG units

 - Toyo Engineering Corporation (Toyo) for the (LLDPE)

Sasol sized the US Mega Projects around the:

 - GTL plant with a capacity of 96,000 barrels per day (b/d) or 4 million t/y of natural gas

 - Ethane Cracker to be designed to produce 1.5 million tonnes per year (t/y) of ethylene.

Sasol to phase Lake Charles GTL and Ethane Cracker

The GTL plant will be built in two phases of 46,000 b/d each in order to adapt the production to the growing demand in the USA for GTL diesel fuel.

This GTL plant will also produce:

 - Naphtha

 - Liquid Petroleum Gas (LPG)

 - GTL-based high performances oils

 - Medium and hard wax

 - Paraffin

 - Linear Alkyl Benzene

Sasol is planning to make the final investment decision (FID) for the Lake Charkes Ethane Cracker and Derivates project in 2014 financed with an estimated $7 billion capital expenditure.

Then the FID for the GTL plant should be made in a second step in 2016 supported by an investment of $14 billion capital expenditure.

With the PMC support from WorleyParsons, Sasol expects Fluor to complete the FEED work for the Lake Charles GTL - Ethane Cracker and Derivatives US Mega Project in 2014 in order to start commercial operations by 2017 for the Ethane Cracker and Derivates, and 2019 and 2020 respectively for the two GTL trains.

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Chevron and partners pre-qualify contractors for Ubon

The US super major Chevron and its partners, the Thailand national oil company PTT Exploration and Production Public Company Ltd (PTTEP), Hess from USA and Mitsui Oil (Mitsui) are currently running the pre-qualification process to select the contractors to be invited to bid (ITB) for the construction of the offshore platform for the Ubon project.

With a production in 2011 of 65,000 barrels per day (b/d) of crude oil and natural gas liquids (NGL) and 867 million cubic feet per day (cf/d) of natural gas, Chevron is the largest operating company in Thailand.

Since Chevron and PTTEP have managed to start the first shipments from the previous projects Platong 2 and Greater Bongkok South in the Pailin Basin , they decided to implement the full field development of their license area with the Ubon project located in the Block 12/27 of the Contract 4.

In this Ubon project Chevron and its partners share the working interests in such a way:

 - Chevron 35% is the operator

 - PTTEP 45%

 - Hess 15%

 - Mitsui 5%

With a field of non-associated gas and rich of condensate, Ubon appears as one of the largest projects in the Gulf of Thailand.

Chevron opted for central processing platform and FSO

Technip completed the feasibility study to develop Ubon and proposed two scenario in respect with the high contend of NGL in the reservoir.

One scenario combined a floating, production, storage and offloading (FPSO) vessel with a wellhead platform.

The second scenario tied up a central processing platform with a floating storage and offloading (FSO) vessel.

Finally Chevron and its partners PTTEP, Hess and Mitsui preferred the association of the central processing platform with the FSO to develop Ubon and pre-qualify contractors.

This Ubon central processing platform should have a capacity of 115 million cf/d of natural gas and should be able to host 140 people in its living quarter.

The topsides for Ubon are estimated to weight 6,000 tonnes, for a total weight of the platform of 20,000 tonnes.

On this base, the pre-qualification process for the Ubon central processing platform has been pretty large as it enlisted:

 - China Offshore Oil Engineering Company (COOEC) from China

 - Daewoo Shipbuilding and Marine Engineering (DSME) from South Korea

 - Hyundai Heavy Industries (HHI) from South Korea

 - Malaysia Marine Heavy Engineering (MMHE) from Malaysia

 - McDermott from USA

 - Saipem from Italy

 - Samsung Heavy Industries (SHI)

 - SMOE from Singapore

In parallel, Chevron and its partners are proceeding to the pre-qualification for the FSO to have a storage capacity of 700,000 barrels of condensate.

Most of the shipyards in Asia are lining up to apply for this FSO.

Chevron to award Ubon FEED contract on next quarter

Since Technip completed the feasibility study for Ubon Full Field Development project,  Chevron and its partners released the tender for the front end engineering and design (FEED) contract of the project to:

 - Aker Solutions

 - EGD Consulting

 - Mustang from the Wood Group

 - Technip

 - WorleyParsons

Chevron and its partners PTTEP, Hess and Mitsui are planning to award the FEED contract for Ubon on third quarter 2013 in order to put the central processing platform and the FSO to come on stream offshore Thailand in 2017.

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

Kuwait Key Projects and Business Highlights

Kuwait holds the sixth largest reserves of conventional crude oil and rank among the top 10 producing countries in the world attracting all the engineering and services companies such as Bechtel, Halliburton, Schlumberger, Fluor, Foster Wheeler, WorleyParsons, Daelim Industrial.

Until 2008, the crude oil production in Kuwait was regularly increasing to exceed 2.5 million barrels per day (b/d).

Since then political divergences at the parliament about the energy policy and related major investments popped up and left on hold most of the greenfield and brownfield projects.

This situation affected directly the crude oil production as it came down below 2.5 million b/d in the period 2009 to 2011.

After some hard lessons learnt and the reshuffle of the energy industry management, the production started to come up again to 2.8 million b/d in 2012 and the decision were made to move forward on the major projects pending upstream and downstream.

In addition this new pushy policy is well supported by the discoveries of large oil fields in the western region of Kuwait.

With the on going capital expenditure and the development of these new fields, Kuwait is targeting 4 million b/d by 2020.

Anyway Kuwait wants in the same time to reduce its reliance on crude oil export in developing the downstream sector as its neighboring countries.

Consequently Kuwait is also exploring all opportunities to increase its production of natural gas to feed its power generation and petrochemical sectors.

Kuwait Refineries Clean Fuel Project at tendering stage

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

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KNPC awarded PMC contract to Foster Wheeler

On December 23rd, 2012, the state-owned oil refiner Kuwait National Petroleum Co(KNPC) selected Foster Wheeler for the project management consultancy (PMC) contract of the multi-billion Clean Fuels Project (CFP).

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KOC to invest $7 billion in Lower Fars heavy crude oil

The national upstream Kuwait Oil Company (KOC) is considering to move into the engineering, procurement and construction (EPC) stage for the Lower Fars phase-1 project since WorleyParsons completed the front end engineering and design (FEED) work in 2012.

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KOC to give priority to onshore exploration

During  Abu Dhabi International Petroleum Exhibition and Conference (ADIPEC), Kuwait Oil Company (KOC) announced to have received  mandate from Kuwait Petroleum Company (KPC) to increase crude oil production from actual 3 million b/d to 4 million b/d by 2030.

Considering the age and the level of maturity of the actual fields in operations to deliver 3 million b/d of crude oil, the replacement of depleting fields must also be considered in the total amount of barrels per day to be put in production to reach this target of 4 million b/d in 2020.

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