- DAILY GPI
- MEXICO GPI
- SHALE DAILY
- NGI ALL NEWS ACCESS
- NGI MIDDAY PRICE ALERT
- NGI FORWARD LOOK
- NGI WEEKLY NEWSLETTER
- NGI BIDWEEK ALERT
- NGI BIDWEEK SURVEY
- NGI WEEKLY GPI
- Publishing Calendar
- Subscriber Notice Regarding NGI's Decimal Point Precision and Use of Assessments - Sep. 5
- NGI's MidDay Price Alert
- Price Data "Learn More"
- Gas Price "Snapshots"
- >Forward Basis Prices
- >Daily Prices
- >Weekly Prices
- >Bidweek Prices
- Bidweek Alert Data
- Shale Gas Prices (subscriber-only)
- NGI Price Index Methodology (pdf)
- NGI Shale Price Index Methodology (pdf)
- NGI Mexico Price Methodology (pdf)
- NGI Datafeed Spec and Automation
International Unconventional Development
International Unconventional Resource Development
With unconventional resource development reshaping the energy potential of both the United States and Canada, the success story that has been playing out in North America has not gone unnoticed elsewhere in the world. Many U.S. operators, along with foreign producers that have entered into joint venture arrangements in the U.S. to gain access to unconventional producing technology, are eager to apply what they have learned to unconventional oil & gas basins around the world. Oil and gas bearing shale opportunities are not a unique resource to North America, and are actually well distributed across all five other habitable continents. In fact, the U.S. and Canada do not even necessarily have the largest of these oil and gas resources. According to EIA and Advanced Resources International figures, China holds the largest technically recoverable shale reserves of natural gas, and Russia takes the number one spot for shale reserves of oil outside of the United States.
It is worth noting that technically recoverable reserves are usually much higher than economically recoverable reserves. Technically recoverable reserve figures also change as extraction technologies develop and the formations containing the hydrocarbons become better understood. In addition, most technically recoverable reserves can become economical in a sufficiently high price environment.
On the flip side, shale and tight sands development can be curtailed by government regulation. Not every U.S. state is friendly to the practice of hydraulic fracturing, and the same holds true from country to country. For example, in Europe, fracking is currently illegal in Bulgaria, Czech Republic, France, Luxembourg, and the Netherlands. Subsurface property rights also play a defining role. In the U.S., mineral rights are largely defined, but this is certainly not the case throughout the world.
NGI believes the biggest factors that are necessary for the successful development of unconventional oil & gas formations are:
Private and/or Clearly Defined Ownership of Subsurface Oil and Gas Rights
Availability of Capable Independent Operators, Rigs, and Fracking Equipment
Presence of an Established Infrastructure
Access to Water Necessary for Hydraulic Fracturing
Favorable Governmental Policy
Since covering all countries with shale potential would be beyond the scope of this writing, and would almost certainly require an entire book, we have chosen to highlight some of the areas with significant shale potential, to provide a brief summary of where non-U.S. shale development stands, and to outline some of the major issues that threaten future progress.
Canadian unconventional development has been taking off for awhile now, with many different resource plays already producing. The most important of the shale and tight sands plays are arguably the Montney, Duvernay, and the Horn River, all three of which are profiled in separate sections of the Factbook. These three formations lie in western Canada in British Columbia and Alberta. All three have active natural gas and oil production and have been producing for about half a decade. Most producers here have been focused on oil production, in no small part because of the recent decline in natural gas prices because of booming U.S. production. These lower natural gas prices have been especially harsh to western Canadian producers who, when shipping gas east via TransCanada's mainline, must compete directly with the burgeoning gas production from the Marcellus Shale.
However, there may be some hope for forthcoming gas demand in Canada. As several LNG export facilities on the west coast of British Columbia are approved and potentially come on-line, demand for local gas production may increase. But unfortunately for producers, NGI does not currently expect Canadian LNG export terminals to play a significant role in the demand picture until at least 2018, if at all. We believe many of the proposed LNG export facilities in Canada will require oil-based pricing in order to be economically viable, a stipulation which would-be capacity subscribers have been resisting. But producers could still benefit from incremental local demand for natural gas in Canada from companies using in-situ oil sands recovery techniques that often require large amounts of gas to generate steam.
Speaking of which, oil sands/bitumen are another important source of unconventional production in Canada. For more information about that, please refer to our Canadian Oil Sands page at www.naturalgasintel.com/canadian-oil-sands.
According to the U.S. Energy Information Administration, Mexico has 545 Trillion Cubic Feet (Tcf) of technically recoverable shale gas resources, the sixth most of any country in the world. Even if Mexico were only able to convert 10% of those reserves into production, that would be enough to fuel Mexican natural gas consumption for more than 20 years, based on Mexico's 2014 dry gas consumption of 2.587 Tcf.
Most shale resources in Mexico are in the northeast near the Gulf of Mexico coast, including the Burgos Basin, and the Eagle Ford Shale, which continues down into Mexico from South Texas. The Texas side of the Eagle Ford is now pretty well understood by operators, and we believe these companies will be able to leverage their experience to the portion of the formation that lies south of the border. Eventually, that is.
In December 2013, the Mexican congress passed a bill ending the 75-year state oil monopoly, thereby finally allowing foreign companies to have a shot at developing Mexico's reserves. But that effort has been slow to get off the ground, and on-land drilling activity continues to spiral lower in the country (see Daily GPI, Aug. 14, 2014). Mexico had 84 oil & gas rigs working within its borders in June 2012, but just 15 in October 2015.
Even when unconventional development in Mexico does pick up, it won't be without complications. The geological structure of the Eagle Ford in Mexico is said to be more complex, and it may take quite a bit of practice to achieve similar results to what operators are experiencing on the U.S. side of the play. Other possible obstacles to Mexican shale production could include, but are not limited to, the capabilities of the local shale service sector, little current infrastructure in the Burgos Basin, a lack of water in the immediate area, which is necessary for hydraulic fracturing, a dearth of natural gas processing plants, public safety concerns, and potential limits on upstream investment (albeit less so since December 2013).
Yet another threat to the developing Mexico's shale resources are fast growing natural gas imports from the United States, and the longer it takes Mexico to get the ball rolling on implementing its energy reforms, the more opportunities the U.S. will have to ship additional gas south of the border. Since 2007, U.S. natural gas exports to Mexico have grown from less than 1.0 Bcf/d to more than 3.0 Bcf/d, led by new gas fired electricity capacity in the northern part of the country. Several industry pundits estimate those exports could double by the end of the decade.
Mexico already has begun working with foreign entities on the midstream side of things, as Sempra Energy's iEnova subsidiary had invested US$3.5 billion in Mexico's gas and power infrastructure as of December 2014, and Kinder Morgan, TransCanada, and Howard Energy Partners have a presence in Mexico as well. Furthermore, Mexico's state owned power utility Comisión Federal de Electricidad (CFE) is expected to tender several other gas pipeline projects in the coming months.
For more on Mexico's emerging natural gas pipeline grid, please refer to NGI's 2016 North American Natural Gas Pipelines and Shale Resource Plays Map at www.naturalgasintel.com/natural-gas-shale-basin-pipeline-market-point-map
During the last ten years, China has morphed from being a net exporter of natural gas to importing more than 2 Tcf per year of the fuel, despite the fact that the country has the largest estimated reserve of shale gas in the world. Given that the International Energy Agency expects Chinese natural gas demand to grow by approximately 10% per year through 2019, the country is undoubtedly chomping at the bit to develop its vast unconventional resources. Thus far most shale activity in China has been focused in the Sichuan Basin, home of Fuling, the country's first shale gas field, where activity continues to grow. As recently as March 2014, China Petroleum and Chemical Corp. (Sinopec) said it had "made significant breakthroughs" in shale gas exploration and development and that it plans to develop the Fuling Field faster than previously thought, with annual production of 10 billion cubic meters (353 Bcf) by 2017 (see Shale Daily, March 25, 2014). Sinopec also expects to apply what they are learning at Fuling to other projects in the country. Moreover, several Chinese companies, including Sinopec, CNOOC, PetroChina, Haimo Oil & Gas, and Sinochem Petroleum, have taken non-operated joint venture positions in various unconventional oil & gas fields in North America over the last few years, in part to learn more about the technology required to unlock the unconventional formations back home.
The Tarim Basin in China holds unconventional promise as well, but most likely at a high cost. Wood Mackenzie notes the depth of the target shales in the basin could exceed 4,500 meters, and that the basin is located in a remote part of the county which is punctuated by the world's second largest shifting desert sand, thus making it difficult to access the water necessary to hydraulically fracture the rock.
Shale development in China is not without its issues, however. Unlike in the U.S., where supply and demand dictate price, the Chinese government largely determines prices. This has caused some concern for shale gas development, since in order to entice producers to incur the risk of development, they must achieve a price high enough for them to earn an acceptable rate of return on their investment. This issue was touched on in January 2014 by Gordon Kwan, regional head of oil and gas research at Nomura Holdings, in an e-mail to Bloomberg News: "Long term, we believe the government must raise domestic selling prices for natural gas and increase shale-gas subsidies further to motivate producers."
Another factor that could potentially slow the development of shale gas development in China is the mega-contract signed in May 2014 to have OAO Gazprom supply China National Petroleum Corporation an estimated $400 billion worth of natural gas for more than 30 years, starting in 2018. By the end of this decade, Russia could be supplying almost 10% of China's gas supplies. But this development could simply defray China's dependence on LNG imports, meaning the country will still need to advance its internal shale production to meet future demand.
Russia is estimated to have the largest technically recoverable shale oil reserves of any country outside of the United States, most of which lie in the Bazhenov formation, a massive area that encompasses nearly one million square kilometers in West Siberia. According to the U.S. Energy Information Administration, the Bazhenov holds and estimated 1.2 trillion barrels of oil, about 75 billion of which might be recoverable.
The Bazhenov underlies Russia's main conventional production region and has yet to put forth any significant production from horizontal wells. However, it seems interest may be picking up. In January 2014 Salym Petroleum Development, a joint venture between Royal Dutch Shell and Gazprom, announced that it had begun drilling on the first of five horizontal wells over the next two years. Exxon Mobil and BP have separate joint ventures with Roseneft to develop Russian shale, and as recently as March 2014, Total S.A. was rumored to be in talks with partner Lukoil regarding Lukoil's projects in the Bazhenov. Many have compared the Bazhenov to the Bakken Shale in North Dakota.
What may come of this major shale oil deposit is difficult to say given the political uncertainty of the region, particularly in the aftermath of Russia's military actions in Ukraine, and the high costs of de-risking the basin. After the dissolution of the Soviet Union, companies such as BP, ConocoPhillips and ExxonMobil have attempted operations in the country, but none had any real success. Russian oil production to date is still dominated by domestic companies the biggest of which being Rosneft, which according Eastern Bloc Energy accounted for about 24% of total Russian oil production during 2012.
Russia is also a leading exporter of natural gas to Europe, but exports from the country have declined at an annualized trend-line rate of 1.3% per year since 2005.
Some of the earliest international shale activity was focused in Poland beginning around 2007, but development has proven difficult because of geological complexity and regulatory issues. The Polish government desperately wishes to kick-start domestic natural gas production, believing it essential to relieve some of the country's dependence on gas supplies from Russia as well as domestic coal production and its associated environmental impacts. Recent tensions in the area have added pressure on regulators to entice companies to drill for Polish gas. Thus far only a handful of horizontal test wells have been drilled with no notable success, but there still may be hope yet for Polish shale development. In January 2014 San Leon Energy announced a successful vertical test in the Baltic Basin. The test demonstrated sustained production at a rate of 45 to 60 Mcf per day after six weeks of well clean-up. Encouraged by the results, San Leon plans to drill a long horizontal well with a multi-stage frack job as soon as possible. Remarking on the results San Leon Executive Chairman Oisin Fanning said, "This is the most encouraging vertical shale well test in Poland to date. We have moved a long way towards 'cracking the code' towards commercial production from our unconventional plays.
"These learnings will be put to good use in the planned multi-staged fracked horizontal well in the Lewino area, where we believe we shall be able to stimulate the entire vertical extent of the Ordovician interval with each frac, and prove commercial flow rates," Fanning added.
The drilling rig count in Poland has ranged between 3 and 9 since June 2012, but has veered toward the higher end of that range in recent months.
Even after the fall of the Soviet Union many European countries remain tethered to Russia for natural gas. This is especially true in Eastern Europe where the USSR built most of the pipeline infrastructure. Given the recent tension between Russia and the Ukraine, many European leaders have sounded the call for the investigation of alternative sources of energy to decrease their dependence on Russian gas. Aware of the successes on the North American continent, many operators are interested in the possibility of applying the processes of hydraulic fracturing and horizontal drilling to European oil and gas resources that would otherwise be unreachable with conventional techniques. Although European countries are trying to gain a better understanding of what resources are available to them, most are still far from commercial production. The state of European shale development was summed up quite nicely in March of 2014 by Raymond James analyst Pavel Molchanov, who said, "Shale gas production in Europe is effectively zero. Twelve months from now it will still be zero. Five years from now, it will be more than zero."
"Over the next five years, [European] countries will have to identify where their resources are and build out the infrastructure for this industry to develop -- that can include developing pipelines and training workers," he said. "This also means getting the required rigs to drill for shale gas, which are in the U.S. and Canada, but don't really exist in Europe."
The road to fracking Europe's shale may be a bumpy one, however, as protests against hydraulic fracturing have been held in several European countries already. Public opposition remains a real barrier especially given the higher relative population density of Europe compared to that of the United States or Canada. It is hard to avoid drilling near communities with a "not in my backyard" stance when, in much of Europe, just about everywhere is someone's backyard. Bulgaria, Czech Republic, France, Luxembourg, and the Netherlands have already banned the practice of fracking and proposals to do so exist in other countries such as Germany. It will take some serious effort on the part of governments and would-be drillers to build trust within their communities so that Europe can begin the path toward a more energy independent future.
In addition, the United States is expected to have nearly 10 Bcf/d of LNG export capacity by 2020, much of which could be shipped to Europe. That would likely help reduce the urgency to develop Europe's shale reserves, everything else being equal.
One area in Europe that may be less averse to shale development is the United Kingdom, which features the Bowland Shale in Northern England, the Weald Basin in Southern England, and the Midland Valley of Scotland. But operators don't seem to be in much of a hurry to develop these resources. The United Kingdom has had 2 or fewer land drilling rigs working in each month since June 2012, and as of the end of 2014, the U.K. had no commercial shale gas production.
Number four in estimated technically-recoverable reserves of shale oil and second in shale gas, Argentina clearly has large unconventional potential, which companies such as Apache, EOG, ExxonMobil and others are trying to develop. Exploration thus far has centered on the Neuquen Basin to the east of the Andes Mountains which hosts the Los Molles and Vaca Muerta shales. The EIA estimates the Los Molles shale contains technically recoverable resources of 275 Tcf of shale gas and 3.7 billion barrels of oil and condensate, while the oilier Vaca Muerta shale comes in at 308 Tcf of natural gas and 16 billion barrels of oil. YPF S.A. and Chevron reported in late 2015 the discovery of a super well, the Loma Campana 992, in the Vaca Muerta with an impressive initial production of 1,630 b/d.
Although there has been conventional oil & gas activity in the Neuquen Basin for more than 100 years, unconventional development is still very much in the exploratory phase as operators in the area probe the underlying shale reservoirs to determine if full-scale development could be profitable. Some have had better results than others thus far and it remains to be seen if either the Vaca Muerta or the Los Molles will go fully commercial.
As recently as April 2014, Chevron signed agreements with YPF S.A. to continue the development program in the Vaca Muerta announcing plans to invest an additional $1.6 billion. Chevron has been public with its excitement over the Vaca Muerta and also its faith in the Argentine government on which Chevron spokesman Kent Robertson remarked, ".provincial governments in the area of the Vaca Muerta understand oil development. They support it. So that's one less barrier."
Apache has been testing the shale of the Neuquen Basin since at least 2008. The company reported results from a horizontal multi-stage well that it said produced at a rate of 7 MMcf per day during the summer of 2011. At that point the company had already drilled more than 70 unconventional wells in four Neuquen fields. However, in February 2014 Apache announced the sale of its Argentina assets to YPF S.A. in order to fund a debt reduction program as well as a share buyback.
In its first quarter 2014 conference call Schlumberger said its year-over-year growth in Argentina was strong, "driven by rig-based activity in the Vaca Muerta shale where we are also actively engaging with a number of customers on sub-surface studies and on projects to improve drilling and completion efficiency." This interest is readily apparent in the Argentina rig count, as the number of land rigs working the county has grown from 70 in June 2012 to 104 in October 2015, despite the falloff in global commodity prices over the last year.
Unconventional oil and gas development in Colombia is still in its early innings with E&Ps just starting to take notice of what plays exist and what sort of resource potential they may harbor. "Unconventional and offshore are new frontiers we want to open in Colombia to continue incorporating reserves," Colombia Deputy Energy Minister Orlando Cabrales said in an interview with Bloomberg in March 2014. While the national oil company Ecopetrol formerly controlled all Colombian hydrocarbons, reforms were enacted in 2003 that removed the administrative/regulatory responsibilities of Ecopetrol and handed upstream regulation to the National Hydrocarbon Agency and downstream regulation and coordination activities to the Ministry of Mines and Energy. Further reforms have allowed foreign companies to purchase shares of Ecopetrol and even compete with it directly. These reforms have brought about interest in the country from companies such as Canacol Energy, ConocoPhillips, Shell, ExxonMobil, and Chevron.
Colombia has known unconventional opportunities in the form of the Middle Magdalena Valley Basin's (MMVB) La Luna Shale and the Llanos Basin's Gacheta Shale, which the EIA estimated in June 2013 contained 18 Tcf and 2 Tcf of technically recoverable natural gas, respectively. The La Luna formation has also been known to contain large amounts of oil and wet gas and according to the EIA has been the primary focus of Colombian shale exploration as recently as 2013. Some have compared the La Luna to the Eagle Ford Shale of Texas and the first results are just starting to come in. Canacol Energy, in March 2014, reported results from its Mono Arana 1 exploration well in the MMVB La Luna. The well demonstrated a 24-hour flow rate of 590 barrels of oil per day from a naturally fractured area of the formation. The company reportedly holds about 545,000 net acres in the Magdalena Basin and 1.8 million net acres in the country as a whole.
The land oil and gas drilling rig count in Colombia has drifted lower in recent months, falling from 44 in June 2012 to 19 in October 2015, but that may stabilize in the months ahead. Nabors Industries noted on its 3Q15 earnings call that the Latin American market is very challenged these days, with the exception of Colombia, since many national oil companies are stressed for funds. The company has six of its high end PACE-X rigs, which are designed specifically for multi-well pad drilling, working in the country. Similarly, Occidental Production noted on its 3Q15 that it has been operating in Colombia for more than 30 years, and would like to increase its production there, albeit in more conventional formations.
In Australia, LNG exports and pipeline infrastructure have played a large role in the unconventional development story thus far. With significant demand for LNG from Asia, Australia is in a perfect position to capitalize. On the west and northwest coasts of Australia, LNG production has been ongoing since 1989 when the first shipment from the Northwest Shelf Project was sent to Japan. The west and northwest coasts differ greatly from the east coast and are in fact completely different markets because of the lack of a connecting pipeline. Since east coast gas has to this point been unable to access existing LNG terminals, its price has been much lower than that in the western markets. However, this may be about to change. As of October 2015, three LNG export projects have been approved, two of which are operating, with the third about to enter service. These three represent a combined capacity of 31 million tons per annum. In an October 2012 assessment the Australian National Institute of Economic and Industry Research (NIEIR) projected actual exports (not total combined capacity) in eastern Australia would increase to 2 MMTPA in 2015, 20 MMTPA by 2018 and possibly 24 MMTPA by 2023.
That's quite a big order to fill, and while initially the projects are expected to use coal-seam gas as feedstock, these companies will be looking to shale and tight sands for gas down the road. The EIA and Advanced Research International Inc. recently pegged Australia's shale gas and shale oil reserves at 437 Tcf and 17.5 billion barrels, respectively. Australia's Cooper Basin features tight sands, shale, and coal seams, which could be unlocked by unconventional technology. Because of its proximity and pre-existing infrastructure, the Cooper is an obvious choice for potential development and several companies including Beach Energy, DrillSearch Energy, Santos, and Senex have active evaluation programs there.
On the western side of Australia there is the massive Canning Basin. While less exploration has occurred here the resource potential is solid with EIA estimating 225 Tcf of recoverable shale gas from the Goldwyer Formation alone. Buru Energy completed the first 3D seismic survey of the basin in 2009 and Mitsubishi agreed to fund a $152.4 million exploration and development program in exchange for the ability to earn 50% interest in Buru's permits. ConocoPhillips, New Standard Energy, PetroChina, Hess and Apache have been engaged in farm-in and other activities in the Canning Basin within the past five years. The Western Australia Department of Mines and Petroleum estimated in a February 2014 report that nearly 300 wells had been drilled as of November 2013. There are three existing LNG export facilities in Western Australia, and another two are under construction, the Gorgon and the Wheatstone LNG projects. Both are well along in their development, and are expected to show first gas flows in 2016.
As of October 2015, Australia had 9 land drilling rigs working the country, down from a peak of 15 in October 2014.
According to the U.S. Energy Information Administration, there may be 390 Tcf of technically available shale gas out of the Karoo Basin in South Africa. As Shell notes on its website, "if enough natural gas is found [in the Karoo, which is primarily a gas formation], it could provide South Africa with a stable, cleaner-burning energy supply for power generation and economic activity for decades."
Falcon Oil & Gas observes that "The Karoo Basin covers 600,000 sq km in central and southern South Africa and contains thick, organic rich shales such as the Permian Whitehill Formation. Until recently, the Karoo Basin was not considered prospective for productive hydrocarbons resulting in very limited modern hydrocarbon exploration onshore in South Africa."
The problem, however, has been securing permits to extract that gas, and it's a problem that has lingered for years. In 2009, the Petroleum Agency South Africa (PASA) awarded Shell a Technical Cooperation Permit (TCP) for a one-year study to determine the Karoo's natural gas potential. This study provided a better understanding of the region's geology and shale gas potential, establishing a baseline to move forward with the process of pursuing natural gas exploration.
The results of this study were supposed to influence the country's decision to grant permits. But in February 2011, the South African Minister of Mineral Resources issued a moratorium on all new applications to explore the Karoo, and delayed the processing of existing permits until regulations involving unconventional exploration were published. That condition was seemingly satisfied in 2015, and Falcon expects to be awarded a license to explore for shale gas within the Karoo in 2016, along with its partner Chevron.
Shell has applied for rights to explore for natural gas in the Karoo as well, but there was no mention on its website of any progress on this front as of late November 2015.
South Africa could certainly use the additional production the Karoo may provide, as gas consumption in the country has soared since 2005, while domestic production began to decline in 2006.
Algeria has approximately 707 Tcf of natural gas shale reserves from several different formations, and given the history of oil and gas drilling within its borders, we believe the country is in relatively good position to bring some of those reserves into production. In fact, Repsol YPF is leading a consortium of companies to develop the North Reggane project in the Algerian Sahara desert, and expects to have first production online in 2016.
Algeria has featured between 37 and 56 land drilling rigs since June 2015.
Despite being one of the leading oil producers in the world, and the key OPEC nation, Saudi Arabia is far less influential on the world's natural gas front. In fact, some sources report the country doesn't produce enough for its own internal needs. Much of the country's domestic gas production is associated gas, but that mix could start to change.
In 2015, Ali al-Naimi, the minister of petroleum and mineral resources of Saudi Arabia, announced that Saudi Aramco will begin to develop its unconventional resources, in an effort to supply industrial projects within the Kingdom. This may be reflected in the country's land rig count, which has been climbing in recent months.
Saudi Aramco plans to focus on three shale areas in particular: South Ghawar, Jafurah, and the Rub'a al-Khali (a.k.a. the Empty Quarter). The country also plans to build three processing plants to support the expected increase in shale gas production.