Gazprom intends to sign Western Route gas transmission accord with China

Gazprom is to supply an additional 30 billion cubic metres of gas to China by its Western Route project (via the Altai Mountains border) in a 30-year agreement, according to chairman Alexei Miller

The current China-Russia Western Route natural gas pipeline connects gas plays in Western Siberia with the north-western part of China via Russia's Altai region

“We are going to sign a contract to supply 30 billion cubic meters of gas for 30 years, and various volumes within new contracts for the western route have been announced at the talks. A possibility of supplying 60 to 100 billion cubic meters of gas to China is being considered,” said Miller in response to questions from Russian president Vladimir Putin.

The meeting yesterday between the Gazprom head and Putin in Moscow was primarily to reassure European customers that Gazprom intends to honour its gas supply agreements despite on-political unrest due to the Ukraine crisis.

The current China-Russia Western Route natural gas pipeline connects gas plays in Western Siberia with the north-western part of China via Russia's Altai region.

“Yes, certainly, as for the western route, it has its own advantages,” Miller said in response to a question from Putin regarding the feasibility of increased western route transmission. “Firstly, the existing gas transmission system in Western Siberia will be involved. Secondly, there is no need to create gas chemical or processing capacities for the Western Siberian gas, therefore, the investments required for the western route will surely be smaller than for the eastern route.

“On the other hand, the potential is huge. It is even greater than in Eastern Siberia and, by all means, we can rapidly boost the volumes of gas supply via the western route to respond to growing demand in the Chinese market.”

No date was given regarding a finalisation of the agreement.

On May 21, 2014 Gazprom and China National Petroleum Corporation (CNPC) signed the purchase and sale agreement – the biggest one in the national history – for the Russian pipeline gas supply to China. The 30-year contract stipulates gas supplies in the amount of 38 billion cubic meters of gas per year.

Gazprom Neft-Rosneft constructs oil pipeline connecting Russia's most northerly onshore field

Messoyakhaneftegaz, a joint Gazprom Neft-Rosneft entity, has begun constructing a pressure oil pipeline from the Messoyakha field cluster located in northern Yamalo-Nenetskiy Autonomous Area to the Zapolyarye-Purpe trunk pipeline system

Oil transportation is planned to be started in late 2016 upon commissioning of the Vostochno-Messoyakhskoe field

The oil pipeline, with a maximum throughput capacity of seven million tonnes per year, will be laid from both sides at the same time for a total length of 96.5 kilometres.

Oil transportation is planned to be started in late 2016 upon commissioning of the Vostochno-Messoyakhskoe field.

The Messoyakha fields are the most northerly known onshore oil fields in Russia.

The project considers the need to minimise the impact on the polar environment and warrant safe and reliable operation of the oil transportation system in the harsh climate.

In particular, to conserve the permafrost layers, the oil pipeline is being placed on special supports with thermal stabilisation of the soil. The system of permanent control of the line condition and integrity uses a special fibre-optic cable laid along the entire track.

The oil pipeline will also be equipped with fire and security alarms and a video surveillance system.

The Indikyakha and Muduiyakha rivers encountered by the pipeline will be crossed underground without disturbing the riverbeds. To create the required underground tunnels, they will employ directional drilling. In the locations of deer migration and travels of indigenous people, the project provides for construction of 14 special passes and crossings.

The Messoyakha field cluster includes the Vostochno-Messoyakhskoe and Zapadno-Messoyakhskoe fields.

The licences for field exploration and development are owned by CJSC Messoyakhaneftegaz, which is controlled by Gazprom Neft and Rosneft on a parity basis.

Gazprom Neft performs the functions of the project operator.

The fields were discovered in the 1980s on the Gydan peninsula in the Taz district of the Yamalo-Nenetskiy Autonomous Area, 340-kilometres north of Novyi Urengoi in the arctic climatic zone in a region of undeveloped infrastructure.

The proved C1+C2 reserves of the fields amount to 465 million tonnes of oil and gas condensate and in excess of 170 billion cubic metres of gas.

Only the US, Canada, China and Argentina are at a stage to commercially produce gas from shale formations or oil from tight formations, according to the US Energy Information Agency.

Only the US produces both oil and gas on a significant scale, with only Canada, albeit on a much smaller scale, producing both.

China currently is producing minor volumes of shale gas with Argentina at present producing small volumes of tight oil, although fracking has been used in Australia and Russia.

The EIA study found that production in all four countries increased their tight oil and gas outputs in 2014 and at a higher rate than production from non-shale formations.

In the Marcellus region of the US, natural gas production has tripled within 3 years from an average of 4.8 billion cubic feet per day in 2011 to an average of 14.6 billion cubic feet in 2014; whilst oil production in the Bakken has nearly matched this, growing from an average 400,000 barrels per day in 2011 to an average 1.1 million barrels per day in 2014.

Canadian tight oil production has doubled in the last three years from 200,000 barrels per day in 2011 to 400,000 barrels per day in 2014; whilst shale gas increased at a similar rate from 1.9 billion cubic feet per day in 2011 to 3.9 billion cubic feet per day in May 2014.

Chinese companies, Sinopec and PetroChina recorded commercial production of shale gas totalling 0.163 billion cubic feet per day in 2014 which accounts for 1.5% of the country’s total natural gas production, but targets to increase this to 15% by 2020.

Argentine tight oil production currently amounts to 20,000 barrels per day, mainly from the Vaca Muerta’s Neuquen Basin from YPF and Chevron’s joint production.

The EIA recognises exploration efforts of countries including Algeria, Australia, Colombia, Mexico and Russia into shale oil or gas but adds that all are currently lacking the “ logistics and infrastructure necessary to support [rapid commercialisation] ”.

In addition, ownership of mineral rights, taxation regimes and social protests are also impacting upon the global development of shale resources.

The shale gas revolution has revived North American natural gas production. Shale gas is 37% of the US production today, up from 2% a decade earlier. The gas production boom has resulted in plummeting gas prices, which dropped from their 2008 high of $8.84 per million Btu (MMBtu) to $2.94 per MMBtu in July 2012. Water management costs account for approximately 10% of a well’s operating expense, leaving the industry vulnerable to escalating and variable water management costs in a time of low prices and slim profit margins. Water management decisions within shale gas production fall into two primary categories: water utilization within hydraulic fracturing operations and disposal of wastewater from drilling and production. A variety of water sources support oil and gas production, including fresh or brackish water from surface or groundwater withdrawal, treated industrial or municipal wastewaters, and recycling of the water produced along with oil and gas. The cost of procuring this water is relatively small, averaging $3.00 per 1,000 gallons in the Marcellus region.1 IHS preliminary models show that freshwater withdrawal accounts for less than 1% of the total water management cost. The volume of water used in shale plays gets a lot of attention. However, assuming 5,000 new shale gas wells are drilled each year, water demand for fracturing would require approximately 25 billion gallons, less than 0.03% of total water use in the United States.2 Although this is a tiny portion of the nation’s total water use, seasonal and regional variations in water availability can cause economic and environmental stress, adding to the public’s concern over water use in oil and gas operations. Wastewater management is the primary driver of water-related costs. In Pennsylvania alone, approximately 4,700 unconventional oil and gas wells have been drilled.3 The active wells in this region will yield more than 10 billion gallons of flowback and produced water during their operational life. In unconventional plays across North America, the industry is facing the challenge of managing this water in environmentally and economically sustainable ways. Decisions made about water management will have an impact not only on the industry’s costs and profitability, but also on regional water supplies, infrastructure, and local economies. Changes in regulation and growing public focus increase the challenge of water management. Environmental imperatives are evolving; and the public is concerned about the long-term impact of operations on local water supplies, implications for public health, the risk of mishandling and

accidents, and deterioration of local infrastructure. Assessing water-related costs will help operators manage their bottom line and allow technology providers to evaluate and understand the opportunities in this market.

THREE IMPORTANT QUESTIONS FOR OIL MARKET

The oil market is in a state of flux. Prices have fallen by over 50pc since last summer. The Organisation of the Petroleum Exporting Countries (Opec) seems to have forgotten its lines. There are howls of pain from large and small oil producers alike.

Against such a backdrop, it is tempting to focus on the here and now.

Although prices may be down for some years, the world’s demand for energy is likely to increase by almost 40pc over the next 20 years or so, driven by growth in developing economies.

To be in a position to meet those needs – and so facilitate that growth – we need to lift our sights from the current hurly-burly and look to the future.

The majority of the big new projects currently being considered by the major companies won’t even start to produce oil until long after today’s volatility has been worked through.

And looking at today’s oil price and extrapolating forward risks generating hog cycles that feed future booms and busts.

There are at least three important questions to consider.

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