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UAE's Shah gas project seen achieving full capacity in Q2

The Shah gas project which began operations this year in the United Arab Emirates will achieve full production in the second quarter, earlier than expected, a top company official said on Tuesday.

"Initial production from the field started in January and currently we are in the process of ramping up production to full capacity, which we expect to achieve during quarter two," Saif Ahmed al Ghafli, chief executive of Al Hosn Gas, told an industry conference in Abu Dhabi.

Al Hosn Gas is the Shah gas development joint venture in which the Abu Dhabi National Oil Company (Adnoc) holds a 60 percent share and US-based Occidental Petroleum the other 40 percent.

In January the chief executive of Adnoc said the project was expected to reach full capacity by end-2015.

The multi-billion dollar project is meant to produce usable gas from Shah's high-sulphur field.

The project is expected to process around 1 billion cubic feet per day (bcf/d) of sour gas into 0.5 bcf/d of usable gas in the remote desert and is vital for keeping the UAE supplied with fuel and reducing its growing gas imports.

The success of the Shah gas project will spur other regional gas development projects and a slew of similar projects are already lined up by Adnoc in the UAE, said Ghafli.

Phase 12 of the South Pars gas field is due to go online in a ceremony to be participated by President Hassan Rouhani in the

The biggest phase of the South Pars field, Phase 12, will officially launch operation before the end of the current Iranian year (March 20) an in a ceremony in the presence of President Hassan Rouhani, South Pars officials announced on Sunday.

In February, Managing Director of South Pars Oil and Gas Company Ali Akbar Sha'banpour elaborated on the features of Phase 12, and said, "Its area, and respectively production capability, is three times greater than the regular phases of the offshore field."

Sha'banpour said that Phase 12 exploits three billion feet of sour gas from the seabed, equal to 84 million cubic meters, and after separating its gas derivatives, injects some 75 million cubic meters of sweet gas to the trans-Iranian gas pipeline network.

According to him, three main derricks and one satellite derrick are installed for the Phase 12, which altogether transfer that volume of gas to the refineries in the Iranian mainland.

He said that implementing the project took 110 months, equal to nine and a half years.

Focusing on Iran and Qatar's difference in gas output from the joint field, the managing director said that Iran's current production of 15 billion cubic meters, while Qatar produces 22 billion cubic feet.

He noted that Iran's 51% share in production of the required facilities for construction of the oil and gas facilities needed in the South Pars Field has increased to 66% in construction of the wide-scale Phase 12.

Phase 12 of South Pars, shared by Iran and Qatar, is the largest phase in this gigantic gas reservoir.
This phase is expected to start producing at least 500 mcf/d of gas before the cold season starts for injection into national pipeline.
The high-pressure flare of the refinery of this phase became operational in August.

Based on coordination made between the contractor and the outsourcer of the project, gas produced from the five wells of this field was delivered to an onshore refinery in December.

By drilling 12 wells, one billion cubic feet a day of sour gas is expected to be delivered to the onshore refinery. This amount of production started with 500 mcf/d.

Iranian engineers and technicians have been operating Phase 12 of South Pars with seriousness and testing different sections of this refinery.
The steam production, air compressors and gas receiving units are now operational. Other sections like water desalination and wastewater treatment units have also become operational for inauguration.

Phase 12 of South Pars gas field is under development to produce 75 million cubic meters (mcm) of rich gas for delivery to national gas pipeline and liquefied natural gas (LNG) production plants. Out of this amount, 25 mcm will be injected to national pipeline and the rest will go for LNG production. This phase is also expected to produce 120,000 b/d of gas condensate and 750 tons a day of sulfur.

The main contractor in the development of Phase 12 of South Pars is Petropars Company. The onshore installations of this phase are located 70 kilometers from Assalouye

ADNOC and Wintershall present core sample from Shuwaihat field to The German Minister of Economy Sigmar Gabriel

Abu Dhabi National Oil Company (ADNOC) and Wintershall set a joint signal for the successful progress of their cooperation: In the framework of a meeting of the UAE-German Joint Commission on Economic, Trade and Technical Co-operation in Abu Dhabi, H.E. Abdulla Nasser Al Suwaidi, Director General of the Abu Dhabi National Oil Company (ADNOC), and Dr. Rainer Seele, CEO of Wintershall, presented German Minister for Economy and Energy Sigmar Gabriel with a drilled core sample from the Shuwaihat Field as part of the Technical Evaluation Agreement (TEA). The dill core, a cylindrical rock sample, origins from targeted hydrocarbon reservoirswhichis from around 150 Million years old. Shuwaihat field is located in the western region of Abu Dhabi. As operator Wintershall, together with the Austrian OMV, is responsible for evaluation of the field. The appraisal well was launched in spring 2014.
For Sigmar Gabriel the Shuwaihat project is testament to the considerable potential offered by German-Emirati partnerships: "The United Arab Emirates are an important partner for Germany. The United Arab Emirates is an important partner for Germany. It is not only the duty of politics to make this partnership a lively one. It i's primarily the duty of companies to shape this partnership. We need more cooperation among companies. I'm convinced that Emirati and German companies gain more when both sides are willing to learn from each other and contribute their own strengths and possibilities to the common cause. ADNOC and Wintershall give a good example in that respect."

"The United Arab Emirates offer investors excellent conditions. Nevertheless, we do of course have clearly defined expectations regarding our potential partners," says H. E. Abdulla Nasser Al Suwaidi. "We believe that, in addition to offering a unique profile and extensive expertise, companies in particular need to bring genuine added value to the partnership. And our previous experience with Wintershall confirms that we have chosen a right partner for evaluating the Shuwaihat field."

Dr. Rainer Seele adds: "It's only through trust, fairness and knowledge about the partner's strengths that partnerships can be established that remain excellent and successful in the long term. In this spirit of partnership, our cooperation with the Shuwaihat project has developed excellently in recent years. I'm therefore highly confident that ADNOC and Wintershall will make the exploration and evaluation of the reservoir into a great success for both our companies."
In June 2012, ADNOC, Wintershall and the OMV company from Austria concluded an agreement to conduct a technical evaluation of the Shuwaihat sour gas and condensate field. The reservoir evaluation includes up to three field exploratory wells (onshore and offshore) and a 3D seismic survey. The wells will be sunk to a depth of about 4,000 metres. Due to its high hydrogen sulphide and carbon dioxide content, the Shuwaihat sour gas reservoir places particularly high technical demands on the exploration and production, and requires a high degree of safety as well as the use of high-tech equipment. Wintershall can draw on more than 40 years of experience in the field of sour gas production in Germany and is also applying this know-how in appraising the Shuwaihat field: for example, pipes made of special steel, numerous shut-off valves on the drilling rig and gas detectors prevent hydrogen sulphide from escaping in an uncontrolled manner.

A successful evaluation could make Shuwaihat one of the most important natural gas and condensate fields in the western region of Abu Dhabi. It would also help to meet the increasing demand for hydrocarbons in the United Arab Emirates and contribute to the country's long-term export capabilities.

Lukoil and Hyundai Engineering clinch gas plant contract in Uzbekistan

Lukoil and a consortium headed by Hyundai Engineering (South Korea) has signed a contract for procurement and construction of the Kandym Gas Processing Plant in Uzbekistan

The facility will have an annual capacity of 8.1 billion cubic metres of gas and will process sour natural gas from the Kandym group of fields located in the Bukhara Region of Uzbekistan to produce treated natural gas and stable gas condensate, as well as solid and granulated sulphur.

The construction of the Kandym Gas Processing Plant is Lukoil's largest investment project in Uzbekistan. The project will create over 2,000 jobs. During the peak construction period, it will employ more than 10,000 workers at various facilities. The project will include all the necessary health, safety and environmental protection measures.

Hyundai Engineering will prepare the project feasibility study and detailed design.

Lukoil has been implementing the Kandym project in partnership with the National Holding Company Uzbekneftegaz since 2004 as part of the Kandym-Khauzak-Shady-Kungrad PSA.

The Kandym group consists of six gas condensate fields – Kandym, Kuvachi-Alat, Akkum, Parsankul, Khoji and West Khoji.

Ilam gas refinery produces 2.638 tons of LPG

Tehran - Ilam gas refinery has managed to produce more than 2.638 tons of LPG over the first 323 days of current Iranian calendar year since March 21 2014.

Managing director of Ilam gas refinery Najaf Balali further noted that four storage tanks had been built for storing liquid gas.Ilam gas refinery LPG product is quoted at Iran energy burse as well, he said in a shana.ir report.

He added the refinery has also produced more than 1.423 billion cubic meters of gas during the aforementioned period.

Production of 45.766 thousand tons of sulfur during the period is the other achievement of the refinery. Ilam gas refinery is responsible for meeting gas needs of Ilam, Kermanshah, Kordestan provinces as well as part of Hamdan province.

Located 25 km northwest of Ilam city, Ilam gas refinery has been designed in two phases taking 6.8 million cubic meters of sour gas per day which are being sweetened for providing of aforementioned provinces gas needs as well as injection to gas grid.

370 thousand cubic meters of ethane, 300 cubic meters of propane and 340 tons of sulfur per day are the other products of the first phase of the refinery.

GASCO and ADGAS award EPC Contracts for Integrated Gas Development Expansion - IGD-E (Phase 1) Packages for a total price of around 5.9 Billion Dirhams (around US$ 1.6 billion)

On Behalf of ADNOC , Abu Dhabi Gas Industries Ltd. ( GASCO ) and Abu Dhabi Gas Liquefaction Company Ltd ( ADGAS ) have confirmed the award of the following contracts for Engineering, Procurement, Construction and Commissioning(EPC) works for the Integrated Gas Development Expansion (IGD-E) Phase 1 Project on Lump Sum Turnkey Basis.

1- Das Island facilities (Package No. 1)
2- Offshore Pipeline (Package No. 2)
3- Onshore Pipeline and Habshan Modifications (Package No. 3)

IGD-E Project is a unified project to further increase Offshore gas processing capacity by an additional 400 MMSCFD Offshore HP Gas from Das Island to Habshan. This will be in addition to the current gas processing capacity of 1,000 MMSCFD realized under the OAG and IGD Projects.

The new facilities at Habshan-5 will also accommodate an additional onshore Gas 300 MMSCFD from Abu Dhabi Company for Onshore Oil Operations (ADCO) North East Bab (NEB-III). In addition to 439 MMSCFD from North West Abu Dhabi offshore fields.
The details of IGD-E (Phase 1) Packages are as follows:

ADGAS IGD-E - Das Island facilities (Package No. 1):

IGD-E Package No. 1 consists of the following new facilities in Das Island that will be required for increasing the offshore gas processing capacity:

- New 4th gas dehydration train.

- New common dry gas compression after cooler.

- Land reclamation

The EPC Contract has been awarded on 3rd Feb 2015 to Consortium Tecnimont, Italy & Archirodon, Greece at a contract price of approx. US$ 491 MM with a completion period of 40 months.

The initial phase of the project execution will commence from the Contractor's Home Office in Milan, Italy and will later move to the site at Das Island for construction activities.

GASCO IGD-E - Offshore Pipeline (Package No. 2):

IGD-E Package No. 2 consists of the 117 km offshore segment of the new 42" IGD-E pipeline. The selected offshore route for the new IGD-E pipeline parallels the existing 30" OAG pipeline route, which runs from Das Island to the pipeline corridor shore crossing tie-in at Ras Al Qila.

The EPC Contract has been awarded to M/s National Petroleum Construction Company (NPCC), UAE on 3rd Feb 2015 at a Contract Price of approx. US$ 410 MM with a completion schedule of 40 months.

The initial Phase of the project execution will commence from the Contractor's Home Office in Abu Dhabi, UAE and will later move to the offshore sites for construction activities.

GASCO IGD-E - Onshore Pipeline and Habshan Modifications (Package No. 3):

IGD-E Package No. 3 consists of the following new facilities that will be required to handle the additional offshore Gas:

- New 114 km onshore segment of the 42" IGD-E pipeline. The selected onshore route continues from Ras Al Qila parallel the existing 30" OAG pipeline to a point near Habshan Area, then detours from OAG Pipeline Habshan 5 Plant with a new established corridor.

- New Units are required at Habshan 5 to receive the Gas from the new 42" IGD-E pipeline. The new Habshan 5 units will also be the destination of additional onshore sour Gas from ADCO's North East Bab Development (NEB-III).

- New condensate pipeline to transport stabilised condensate from Habshan 5 to Habshan Complex Condensate Storage Unit.

- New two (2) Package Boilers for steam generation in Habshan 5.

- New tie-ins and modifications will be required for the integration of the new units with Habshan 5 and Habshan Complex to allow optimum processing of Gas.

The EPC Contract has been awarded on 3rd Feb 2015 to Tecnicas Reunidas, Spain at a Contract Price of approx. US$ 685 MM with a completion period of 40 months.

The initial Phase of the Projects execution will commence from the Contractors Home Office in Madrid, Spain and will later on move to the Sites of the Onshore Pipelines and Habshan for construction activities.

GASCO and ADGAS will direct their EPC Contractors to maximize in these projects the local contents in terms of materials, equipment and services.

The Front End Engineering Design (FEED) for the IGD-E Project was completed in April 2014 and during execution of FEED high significance was been given to HSE aspects in order to eliminate and adverse impact on the environment and the surrounding community in line with ADNOC HSE Code of Practices.

These Projects will also provide excellent opportunities to UAE Nationals for training and learning through exposure and interaction with these experienced Engineering Companies to enable them manage future projects, operate and maintain the Plants after project completion and handover.

Gasco awards Spain’s Tecnicas $700m gas contract

Abu Dhabi Gas Industries, known as Gasco, said yesterday that it had awarded a US$700 million contract to Spain’s Tecnicas Reunidas for a major natural gas expansion project aimed at alleviating the emirate’s gas shortage.

The contract is for “package 3” of the huge Integrated Gas Development (IGD) expansion project, which aims to yield 400 million cubic feet of gas from Abu Dhabi National Oil Company’s offshore oilfields by 2017.

The extra supply is badly needed to meet domestic demand, which has been growing at a rate of 15 per cent a year and has required the country to import gas in recent years. Gasco said the new contract is the fourth to be awarded to the Spanish firm in Abu Dhabi.

“TR has successfully completed a project for the petrochemical complex of Borouge, the Sahil and Shah Field Development project, and it is just starting up the Shah Gas Gathering Centre,” Gasco said in a statement.

The project consists of several gas processing units, gas pipelines, condensate pipelines and all required interconnections.

It is part of the broader IGD project, led by the Abu Dhabi national energy companies Gasco, Adgas, and Adnoc.

Gasco completed the initial US$11 billion IGD project in 2013, facilitating the transfer of 1 billion cubic feet a day (cfd) of high-pressure gas from the offshore Umm Shaif field via Das Island to onshore processing facilities at Habshan and Ruwais. Shell, Total, and Partex also are partners in the IGD.

The $10bn Shah project, another of the emirate’s projects to add new gas, began producing gas at the end of last year. Adnoc and partner Occidental Petroleum are bringing Shah’s difficult-to-process “sour” (heavy in hydrogen sulphide) gas to market. Adnoc and Shell are also developing the Bab field’s sour gas.

UAE’s Shah Gas Project Online, To Reach Full Capacity By Year-End – ADNOC

The United Arab Emirates’ Shah gas project has started operations and is expected to reach full capacity by year end, the head of state-run Abu Dhabi National Oil Company (ADNOC) said on Monday.

The multi-billion dollar, technically challenging project with U.S.-based Occidental Petroleum is meant to produce usable gas from Shah’s high-sulphur field.

“Successful commissioning of Shah gas project has started… We look forward to reaching full capacity this year,” ADNOC Chief Executive Abdulla Nasser Al Suwaidi told an energy event in Abu Dhabi.

The project to process around one billion cubic feet a day (bcf/d) of sour gas into 0.5 bcf/d of usable gas in the remote desert is vital for keeping the UAE supplied with fuel and reducing its growing gas imports.

As well as gas for industry and power generation, Shah will produce significant volumes of condensate, a light oil that can be used to make vehicle fuels.

“With the Shah gas development start-up we will see the UAE accounting for almost five per cent of global sulphur production,” the UAE energy minister Suhail bin Mohammed al-Mazrouei said at the same event.

The UAE had said it plans to produce 22,000 tonnes of sulphur a day by 2015, which positions it to be a leading world sulphur exporter.

Sulphur is used in the manufacturing of fertilisers and sulphuric acid, which is used in oil refining, wastewater processing and mineral extraction.

ADNOC holds a 60 per cent share in the Shah gas development joint venture, called Al Hosn Gas, while Occidental holds 40 per cent.

Fourth refinery unit of SP phases ready for launch

Executive operations for launching the fourth unit of the refinery of phases 15 and 16 of South Pars (SP) Gas Field in Bushehr province have begun, said the managing director of Pars Oil and Gas Company (POGC).Ali Akbar Shabanpour added that this division, consisting of three sour gas processing units, is expected to become operational by November 21, IRNA reported.

He added that the third unit, fed by the sour and dry gases of SP phases six, seven and eight, was launched on November 16.

Shabanpour said that with the launch of the sweet gas production unit, more than half of the refining project went on stream.

Announcing that the construction of a 32-inch pipeline transferring gas from SP phases 15 and 6 to platform A of Phase 18 has been completed, he noted that currently the platform is ready to deliver gas to onshore facilities."Once the pipelines connecting SP phases 15 to 18 are tested, the platform will begin gas extraction with a capacity of 500 million feet in the coming days," he said.

The POGC chief noted that three refinery units of phases 15 and 16 are expected to produce 40 mcm per day for winter. By developing phases 15 and 16, the Oil Ministry aims to produce daily amounts of 56.6 mcm of natural gas, 75,000 barrels of gas condensates, 400 tons of sulfur and 1.05 million tons of LPG (propane and butane) and 1 million tons of ethane per year.

The phases onshore and offshore establishments include two drilling rigs, two 32-inch offshore gas transfer pipelines with a length of 115 kilometers, two 4.5-inchglycol transfer pipelines with a length of 115 kilometers and a number of gas sweetening units.

A consortium of domestic firms, including Aria Naft Shahab and Iranian Offshore Engineering and Construction Company, are contractors of the phases' onshore and offshore development projects.

SP produces 300 mcm of gas per day, accounting for 72 percent of the country's gas consumption.

Efforts are underway to increase the field's gas output by 100 mcm by March 20, 2015.

All SP phases are expected to become operational by 2017.

Transporting Sour Gas in a Non-Corrosive Form Through Use of Remote Dehydration Units

A major challenge faced by many natural gas developments in the MENA and CIS regions is transporting raw, wet, sour gas from wells to the Central Processing Facility (CPF). The presence of H2S or CO2 and H2O in raw wellhead fluids creates a highly corrosive environment, which dictates the use of expensive corrosion resistant materials such as nickel alloys or stainless steel.

Petrofac designed, built and commissioned a sour gas processing plant in the CIS region, which includes remote, unmanned Gas Treatment Units (GTUs). The GTUs are located up to 16 km away from the CPF, and receive sour raw gas from the wells for treatment using conventional TEG dehydration. The main function of gas dehydration is to dry the gas, thereby eliminating one of the components that causes corrosivity of the gas. This avoided the requirement for cladding the large bore, sour gas transfer pipelines with corrosion resistant alloys (CRA), which would have resulted in high costs, mitigating schedule and construction challenges involved in the installation of CRA pipelines.

Dealing with raw, wet, sour gas is a global challenge faced in many plants worldwide, and has been a major cost and schedule challenge due to the use of corrosion resistant materials. The development solution illustrated in this document depicts an innovative method for transporting sour gas for treatment without the use of large bore CRA pipelines, and can reduce costs of construction and procurement substantially. Similar applications can be made in large scale natural gas processing plants where sour gas and H2O combinations exist, provided that thorough cost analysis is performed to determine the technical and financial viability of the option.

GTU operating data in the form of online water content measured by dew point analysers are documented in this report. Laboratory analysis of the dry sour gas and lean TEG are also included, with the results demonstrating the successful performance of the GTU design.

One of the main challenges in the upstream oil and gas processing industry is transporting raw, wet, sour gases from the wells to the central processing facility (CPF). “According to the International Energy Agency, about 43% of the world’s natural gas reserves, excluding North America, are sour. The Middle East, which contains the world’s most sour gas reserves, contains 60% sour gas” (Huo, 2012).

Sour gases contain H2S and /or CO2.When combined with free or condensed H2O, sour gases exhibit highly corrosive tendencies which warrant the use of expensive corrosion resistant alloys or stainless steel materials. This increases procurement and construction costs greatly, as well as logistics and transportation costs as many of these materials have to be imported. Furthermore, CRA requires specialised complex welding procedures, and intricate QA/QC testing. Sour gases are already expensive to treat due to the requirements of sweetening and sulphur recovery units, and the metallurgy requirements for transporting sour gas to the CPF further increases the project cost.

Occidental Finalizes Deal to Sell Shah Stake to Abu Dhabi's Mubadala - Report

Occidental Petroleum Corp. is in the final steps of finalizing a deal to sell three quarters of its 40% stake in the $ 10 billion Shah natural-gas project in the United Arab Emirates to Abu Dhabi-owned Mubadala Development Co., Energy Intelligence reported.

The deal, which is expected to be announced later this month, has a price tag of around $3 billion, the industry publication reported, quoting unnamed sources.

Shah is expected to start production by the end of the year. Oxy plans to continue to operate the field.

When operational, Shah is expected to process one billion cubic feet a day of sour gas into about 500 million cubic feet of fuel daily. It may also process 4,400 tons of natural-gas liquids a day, 35,000 barrels a day of condensates and 9,200 tons a day of sulfur.

Addressing Safety Challenges of Operating in Sour Gas Fields: A Case Study from the Middle East

The Shah Gas field in Abu Dhabi, UAE is one of the most challenging gas extraction development projects in the world. Spanning an area of 15 square kilometers, the field has an H2S concentration of over 20 percent.

While the operator is protecting its facilities using leading industry gas monitoring and protection systems, the risk of unexpected toxic gas release or leak is always present. The challenge was to ensure that personnel stayed safe from the time they entered the oilfield to the time they exited it.

Schlumberger, one of the main contractors identified the gap in the safety of personnel while in transit through this toxic oilfield. To deal with the challenge, Schlumberger sought the help of a safety solutions provider with a track record for innovation - United Safety.
After a series of discussions between the operator, contractor and the safety provider, it was clear that there was a need to develop an innovative solution that provides early warning gas detection while on the move, ensures immediate availability of breathing air protection and allows communication and documentation of hazards and air status within a crew transportation vehicle.

The result is a Vehicle Gas Protection System (VGPS) with an integrated gas detection system and a proprietary Breathing Air Management System that enables users to transit safely through potentially toxic environments. The VGPS is now deployed in two field vehicles in the Shah field.
This case study looks into the process of innovation and discusses the benefits of a collaborative relationship between operators, contractors and safety providers to solve the safety challenges of operating in sour gas fields.

European firms vie for Iranian gas project

Informed sources told Fars News Agency that Switzerland had recently approached the Iranian Oil Ministry officials for starting negotiations about importing gas.

Also, Greece had indirectly called for Iran's gas exports since the European country's officials believed that Iran could transfer its gas to Greece through Turkey and then to other countries across the Europe.

Other countries which have entered direct gas talks with Iran include Germany (a member of the world powers negotiating with Tehran over its nuclear program), Poland, Japan, Austria, Oman, Turkey and Iraq.

According to the sources, the European and other countries' officials and analysts believe that Iran is the safest supplier of energy in the world.

Earlier this month, Managin Director of the National Iranian Gas Company Hamid Reza Araqi said that several European states had negotiated with Iran to assess the conditions for importing gas from the country as an alternative for their Russian supplies. "The European countries are negotiating with us and tasting the conditions in a bid to have an alternative for supplying gas," Araqi said.

He noted that European countries are willing to import gas from Iran in order to get rid of their strong dependence on Russia's gas.

Araqi noted that all gas consumers are looking for alternate gas suppliers and all exporters are also considering ways for exporting their gas, including pipeline and LNG, implying that the same supply-and-demand strategy increases the chance for the start of Iran's gas supply to Europe in the near future.

In July, Iranian Deputy Oil Minister Ali Majedi announced that the Iranian oil ministry has large-scale programs underway to export natural Gas to European nations.

"We have macro-scale plans to supply gas to Europe," Majedi said.

He noted that Europeans have shown deep interest in importing Iran's gas in a bid to relieve themselves from Russia's monopoly over supplies to Europe.

Iran sits atop the world's largest gas reserves. Iran is currently producing more than 700 mcm/d of sour gas which is fed into petrochemical plants, power plants, domestic industries, oil wells and households. A portion of this production is exported.

Tourmaline Plans to Grow Production by Over 40,000 boepd During Q4 2014

Tourmaline Oil Corp. (TSX: TOU) ("Tourmaline" or the "Company") is pleased to provide an operations update.

The Company plans to add 43,000 boepd of new sustained production during the balance of 2014 through completion and start-up of five new facility projects. The first of these projects, the compression and dehydration facility at Sundown B.C., commenced production during the first week of September and will allow for 50 mmcfpd of incremental production during the fourth quarter. The Musreau, Alberta and Doe, B.C. 50 mmcfpd plant expansions are both on schedule to commence production during the first week of October. Construction of the Spirit River 3-10 sour gas injection plant will be completed by October 15 and start-up of the sour gas injection site and electrical power generation capability at the plant will be completed during the second half of October with the plant achieving full production in early November. The Wild River 50 mmcfpd plant expansion is currently under construction and remains on schedule for an early December start-up. The associated Berland-Wild River pipeline lateral will be completed in October. This lateral will provide incremental natural gas volumes for the 100 mmcfpd Wild River plant expansion in 2015.

These significant production additions during the last four months of the year will allow the Company to achieve full-year 2014 average production guidance of 120,000 boepd and a 2014 exit volume of 150,000 - 155,000 boepd.

Tourmaline continues to operate 20 drilling rigs and has drilled 68 new wells since spring break-up. Strong well results continued in all three core operated areas.

Highlights include:

45 horizontal wells drilled and completed in the Alberta Deep Basin through to September 2014. Of the 33 wells that have 30 days of production history, 32 have exceeded the internal Company 30-day IP template of 5 mmcfpd. The average 30-day IP of these 33 wells is 10.6 mmcfpd.

The initial Triassic Doig horizontal at Sundown B.C. production tested at 15.2 mmcfpd at a flowing casing pressure of 14.5 MPa during a 3-day test. The Company has a very large inventory of Doig horizontal locations in B.C. that complement the existing Montney inventory.

The initial Dunvegan duplex vertical new pool wildcat in the Alberta Deep Basin production tested at 17.3 mmcfpd at a flowing pressure of 9.7 MPa during a 3-day production test. Multiple step-out locations are planned on the original 3D seismic defined feature and the Company has captured additional identical 3D defined features elsewhere in the Deep Basin. The Dunvegan duplex play is one of several high potential new plays that the Company is pursuing in the Deep Basin, complementing the enormous existing Cretaceous development drilling inventories.

Tourmaline is the fifth largest Triassic Montney producer in Western Canada through ongoing development of the Sunrise-Dawson-Sundown area, where the Company just completed drilling the 110th horizontal liquids-rich Montney well. The Sunrise-Dawson-Sundown complex, however, is only the first of four Montney EP areas that the Company plans to develop. Tourmaline has extensive land holdings and drilling inventories in the Montney play areas at Kakwa-Resthaven Alberta, the emerging liquids rich Montney play at Pouce-Coupe-Progress, and the developing Montney EP area at Blueberry-Inga-Red Creek in British Columbia. The Company plans multiple horizontal wells in these three emerging areas during the next 18 months to complement the ongoing activity at Sunrise-Dawson.

On the Peace River High Charlie Lake oil complex, the 1-22 Earring well is producing at 570 bbls/day oil and 500 mcfpd of natural gas after the first seven days of production. This is the third well at Earring, located at the northern end of the 70 mile long Charlie Lake pool. The Company expects to have an additional 25 wells on production from the complex by year end.

The Company has increased full-year 2014 capital spending guidance by $100 million to $1.35 billion due to the acceleration of the second Wild River facility expansion from 2015 to 2014, and the drilling of approximately 25 more wells in 2014 than originally planned in the 15-rig program. This has resulted in an increase in 2015 preliminary production guidance from 159,000 boepd to 164,500 boepd.

Forward-Looking Information
This press release contains forward-looking information within the meaning of applicable securities laws. The use of any of the words "forecast", "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends" and similar expressions are intended to identify forward-looking information. More particularly and without limitation, this press release contains forward-looking information concerning Tourmaline's plans and other aspects of its anticipated future operations, management focus, objectives, strategies, financial, operating and production results and business opportunities, including anticipated petroleum and natural gas production for various periods, capital spending, the timing for facility expansions and facility start-up dates, as well as Tourmaline's future drilling prospects and plans, business strategy, future development and growth opportunities, prospects and asset base. The forward-looking information is based on certain key expectations and assumptions made by Tourmaline, including expectations and assumptions concerning: prevailing commodity prices and exchange rates; applicable royalty rates and tax laws; interest rates; future well production rates and reserve volumes; operating costs the timing of receipt of regulatory approvals; the performance of existing wells; the success obtained in drilling new wells; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the successful completion of acquisitions and dispositions; the availability and cost of labour and services; the state of the economy and the exploration and production business; the availability and cost of financing, labor and services; and ability to market oil and natural gas successfully.

Although Tourmaline believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Tourmaline can give no assurances that they will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature it involves inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to: the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to reserves, production, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; interest rate fluctuations; marketing and transportation; loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to complete or realize the anticipated benefits of acquisitions or dispositions; ability to access sufficient capital from internal and external sources; failure to obtain required regulatory and other approvals; and changes in legislation, including but not limited to tax laws, royalties and environmental regulations. Readers are cautioned that the foregoing list of factors is not exhaustive.

Additional information on these and other factors that could affect Tourmaline, or its operations or financial results, are included in the Company's most recently filed Management's Discussion and Analysis (See "Forward-Looking Statements" therein) , Annual Information Form (See "Risk Factors" and "Forward-Looking Statements" therein) and other reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or Tourmaline's website (www.tourmalineoil.com).

The forward-looking information contained in this press release is made as of the date hereof and Tourmaline undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless expressly required by applicable securities laws.

Additional Reader Advisories

Boe Conversions
Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an indication of value.

Production Tests
Any references in this release to IP rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue to produce and decline thereafter and are not necessarily indicative of long-term performance or ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Such rates are based on field estimates and may be based on limited data available at this time.

Iran to Start 3rd Gas Processing Plant of South Pars Phases 15, 16

The plant takes sour gas from phases 6, 7 and 8 of the mega gas field, the oil ministry's website reported.

The first and second gas processing plants of phases 15 and 16 are fully operational with processing 25 million cubic meters per day (mcm/d) of sour gas as the third gas processing plant experiencing pre-commissioning phase.

The three gas processing plants are expected to process at least 40 mcm/d of gas in winter.

Earlier, Managing Director of the Pars Oil and Gas Company (POGC) Ali Akbar Shabanpour said that the operator of the phases has already completed installation of the platform of phase 16 as drilling operations in the two phases have been completed.

He added expert teams have been dispatched to the location of the platform to bring it online before November.

Development plan of the South Pars gas field phases 15&16 aims at production of 56.6 mcm of gas, 75 thousand barrels of gas condensate and 400 tons of sulfur per day.

The two phases will also yield 1.05 million tons of liquefied gas including LPG, propane and butane as well as one million tons of ethane mainly for use as feedstock by petrochemical plants.

Offshore and onshore installations of the two phases include two drilling platforms (each with 11 wells), two 32 inch and two 4 inch gas pipelines with 115 km length, sweetening facilities and the related services.

South Pars gas field accounts for 300 mcm of gas or 72 percent of natural gas consumption of the country per day.

Sinopec invests $254 million in Yuanba sour gas project

Sinopec invested RMB 1.58 billion ($254 million) on the Yuanba sour gas field in Sichuan province in the first half of 2014, putting China’s second-largest oil and gas producer on track to meet its planned annual investment target for the project.

The state-owned company intends to invest a total of RMB 2.3 billion to develop Yuanba this year, according to the city government of nearby Guangyuan.

Sinopec is counting on Yuanba to help provide a surge in gas output by the end of 2015, analysts have told Interfax. The first phase of the project has a production capacity of 1.7 billion cubic metres per year and is expected to be finished by the end of this year, Hou Xiaozhi, from Sinopec’s Southwest Oil & Gas Field subsidiary, told Interfax on Tuesday.

The second phase will double output to 3.4 bcm/y when it is completed by the end of 2015 and involve the drilling of 10 new wells.
An environmental impact assessment is expected to be approved by the Sichuan Provincial Appraisal Centre for Environment and Engineering on 20 July, said Hou.

Yuanba is Sinopec’s second-largest field in marine facies – a geological term referring to a distinct section of rock – after the Puguang field, also in Sichuan, entered operations in 2010.

Only around 5% of Yuanba’s output is hydrogen sulphide – much less than Puguang, according to Hou. While most of the technology used to explore Yuanba was adopted from that used to explore Puguang, Hou noted most of the equipment was supplied by Sinopec Engineering Incorporation.

Sinopec has completed 90% of the work on machinery to produce, gather and transport gas, and has installed 70% of the processing plant’s equipment. The first two equipment arrays are expected to be trialled for production in November, the Guangyuan city government said on Tuesday. Sinopec reported on 29 March that the Yuanba 1-1H well was producing 0.7 MMcm/d.

The timetable for Yuanba’s construction and operation appears to have slipped. It was slated to come onstream in June 2014, Hu Dongfeng, chief engineer of Sinopec’s Southern Exploration subsidiary, said in 2012. On 30 April, Sinopec reported it had finished procuring large-scale equipment for the purification plant.

RasGas records low greenhouse gas emissions in 2013

RasGas Company Limited (RasGas) has said its total greenhouse gas (GHG) emissions recorded in 2013 were lower than those documented in the previous year following the implementation of corporate policies and strategies to minimise carbon emissions.

In its Sustainability Report 2013, RasGas said its GHG emissions last year totalled 17.9mn tonnes of carbon dioxide (CO2) equivalent, as compared to 18.7mn tonnes recorded in 2012.

RasGas reported that it continues to minimise carbon emissions from its operations in line with the corporate GHG management strategy and policy that was approved in 2012.

The strategy and policy provided a platform to consider mitigation opportunities along the supply chain and for tackling current and future GHG challenges, the company said.

“In 2013, we took actions within our GHG management plan. We benchmarked our programme to identify best practices and areas for improvement and completed a desk review of mitigation opportunities,” added RasGas in its sustainability report.

The report further said RasGas benchmarked its emissions against other liquefied natural gas (LNG) producers by normalising emissions in tonnes as a percentage of the total weight of gas intake from the production reservoir.

RasGas said it ranked third among the 12 international companies benchmarked on this measure in 2013.

Also, the RasGas report said it continues to operate an acid gas injection scheme that stores CO2 and hydrogen sulphide that reduces CO2 and sulphur dioxide from the production process.

The report said 1mn tonnes of CO2 per year are re-injected into a saline aquifer in an onshore reservoir formation that is monitored using microgravity surveying techniques, which were determined to be the “best monitoring strategy”.

RasGas has also reduced the amount of gas flared in 2013, which was roughly 18% below the company’s target for the year. The most significant contribution, the report said, came from a passing-valves monitoring programme.

Flaring excess gas is one of the most significant contributors to national GHG emissions and accounts for 12% of Qatar’s energy-related GHG emissions.

In 2012, RasGas launched a fresh five-year flare minimisation plan covering its Ras Laffan facilities both on-site and off-plot, which was a continuation of the inaugural five-year plan.

The new plan, which is expected to be completed by 2016, aims to reduce flaring emissions from a baseline of 1.26% (volume of flared gas per unit of gas intake) in 2011 to 0.43% in 2016.

RasGas has also made improvements to flare gas control systems and sought improvements in plant reliability, which leads to reduced flaring. Other projects have also progressed, including action to eliminate flared sour gas by sending sour gas from the sour water degasser to the sulphur recovery unit incinerators.

The report also states that further reductions are planned via a jetty boil-off gas recovery project with Qatargas. Scheduled for completion this year, the project will enable previously flared boil-off gas from LNG ship-loading operations to be recompressed at a central facility.

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