Kenai Peninsula selected to host Alaska SC LNG Trains

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

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

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

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

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

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

The partners shared the work load so that:

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

 – ConocoPhillips is focusing on the LNG plant

 – ExxonMobil is performing the technical studies of the project

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

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

Alaska SC LNG to benefit from ConocoPhillips Kenai

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

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

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

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

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

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

 – Eight compression station along the export pipeline

 – Five take-off points for local delivery

 – Alaska Nikiski LNG Plant

 – Ice-free sea water marine terminal

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

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

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

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

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Uzekistan Lukoil Kandym FEED work nears completion

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

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

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

 – Lukoil 85%

 – Uzbekneftegas 15%

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

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

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

 – 3.8 billion cubic meters of gas

 – 19,000 tonnes of condensate

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

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

This expansion should start commercial operations in 2014.

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

Hyundai Engineering completed Kandym FEED

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

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

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

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

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

 – 100 gas production wells

 – 400 kilometers of gas gathering pipelines system

 – Gas booster compression station

 – Gas central processing facility (CPF)

 – 70 kilometers export pipeline

 – Gas treatment facilities

 – 90 kilometers water inlet pipeline

 – Water treatment facilities

 – 80 MW gas-fired power plant

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

 – Campground for 1400 persons

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

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

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

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

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Petroceltic to prepare FEED on Ain Tsila development

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

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

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

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

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

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

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

 – Petroceltic 38.25% is the operator

 – Sonatrach 43.375%

 – Enel 18.375%

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

Petroceltic Ain Tisla CPF to be similar to BHP Ohanet

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

 – 2.2 trillion cubic feet (tcf) of gas

 – 70 million barrels of condensate

 – 113 million barrels of liquid petroleum gas (LPG)

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

In that perspective the Ain Tsila project includes:

 – 124 vertical wells

 – Gas central processing facility (CPF)

 – Water separation

 – Condensate and LPG recovery units

 – Gas compression unit

 – Export pumps

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

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

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

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

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

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

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

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Weatherford completed Gharraf oil field FEED work

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

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

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

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

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

 – Petronas 45% is the operator

 – Japex 30%

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

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

Petronas to add three processing trains in Garraf

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

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

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

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

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

 – Gas treatment plant

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

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

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

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

 – EPC-1: Crude oil Trains 3, 4 and 5

 – EPC-2: Gas Treatment plant

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

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

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