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NEWS

 

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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