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| Since 2013, YPF and Chevron have worked together to develop shale resources at the Loma Campaña Project in Argentina’s Vaca Muerta formation (photo courtesy of YPF). |
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As the U.S. shale oil and gas industry enters an era in which development has become fiscally beneficial for the right kind of producer, operators and NOCs in certain other parts of the world seem poised to follow suit. Unconventional production is already online in Argentina, and wells across Poland and Australia are being drilled and cased every day, with fracing scheduled in the near, foreseeable future. Even where regulatory, social or technological challenges exist, as is the case in the UK, Spain, Russia and China, steady progress is being made to, in the very least, survey and estimate the presence of shale oil and gas.
It often seems to be the case, internationally, that development is stalled by one of two scenarios: a lack of technical knowledge and equipment, or a lack of public or governmental support. In some cases, progress has stalled indefinitely, as is true in France, where hydraulic fracturing has been outlawed completely. This report will look at a few of today’s most active international shale plays.
INTERNATIONAL OUTLOOK
When considering hydrocarbon resources outside of the U.S., the International Energy Agency (IEA) provides an annual, five-year, oil market outlook, the latest of which was released last month. This year, the agency said it is likely that the unconventional supply revolution seen in North America over the past several years will expand outside those borders by 2019. IEA also projected a slowdown in global oil demand growth and “OPEC capacity growth facing headwinds.”
The IEA report, Medium-Term Oil Market Report 2014, goes on to point out that a handful of countries are seeking to play catch-up with the U.S. as a producer of shale and light, tight oil (LTO). By 2019, it estimates, tight oil supplies outside of the U.S. could hit 650,000 bpd, including 390,000 bpd from Canada, 100,000 bpd from Russia and 90,000 bpd from Argentina. In the same period, however, the IEA forecasts that the U.S. will double its LTO output to 5 MMbpd.
WESTERN EUROPE
Long marked by their tendency to locate large populations on comparatively small amounts of land, Western European nations continue to struggle to meet growing domestic energy consumption demands without increasing their import reliance. According to recent information from the U.S. Energy Information Administration (EIA), the UK, in 2013, joined many of its mainland European neighbors as a net importer of petroleum products for the first time. The UK, with France, Germany and Spain, may find that partial answers to its energy supply questions lie in the shale pay zones beneath its borders.
However, even where shale oil and gas reserves have been located—through estimation or through exploratory drilling—these countries still contend with above-ground issues, such as how best to regulate shale permitting and approval, and whether or not to allow fracing. While each country has made moves to determine how, and if, shale projects develop within its boundaries, there have been larger measures across the continent, aimed at guiding how European nations handle this emerging sector.
After making a strong push to update existing European Union (EU) regulations regarding shale E&P in fourth-quarter 2013, the European Parliament (EP), a legislative component of the EU, was in compromise mode by March. Initially, in October 2013, EP members had voted to send up proposed legislation that would make shale gas projects of any size, which routinely employ fracing, subject to environmental impact assessments. Current EU regulations stipulate that only shale gas extraction projects producing at least 500,000 m³/d are required to submit impact assessments. Although the EP was not able to include language that makes these assessments mandatory for shale gas projects, it did augment the proposed legislation, so that new project aspects would have to be accounted for.
United Kingdom. It has been a busy year for the British Geological Survey (BGS), which, in association with the Department of Energy & Climate Change (DECC), released data from three studies on shale geology and resource estimation between June 2013 and June 2014. The latest resource estimates encompass an area in Scotland’s Midland Valley, which stretches east from Glasgow to beyond Edinburgh, to the northeast. Shale formations have inherently complex geology and, in this case, the BGS reported that there was a limited amount of “good quality” seismic and borehole data available for estimation purposes, giving the survey a higher degree of uncertainty than its predecessors. Still, the area is estimated to hold 49.4 Tcf to 134.6 Tcf of gas-in-place, and 3.2 Bbbl to 11.2 Bbbl of oil-in-place.
The prospective Carboniferous shales studied at Midland, according to BGS, “occur within a stacked rock sequence” and are, individually, “thinner than in many unconventional gas and oil systems worldwide.” BGS noted that reserve and recovery estimates were not possible at such an early date, without the drilling and testing of new wells to determine flowrates.
In late May, BGS released its second survey of UK shale potential, this time focusing on an area bordering the coast, south of London, called the Weald basin. Here, resource estimates were placed at 2.20 Bbbl to 8.57 Bbbl, with “no significant gas resource recognized, using the current geological model.” Again, given the general amount of uncertainty associated with shales, additional drilling and testing will be necessary to get a better idea of what production could look like at Weald.
And, not to forget the study that started it all, BGS, back in June 2013, released its first independent research on shale gas potential, specifically looking at the “Bowland basin and beyond,” and estimated that the region held nearly 1,300 Tcf of gas. This earliest survey, which covered an area between the later Weald and Midland studies, was intended to, according to BGS at the time, “give industry and regulators an indication of how best to plan future exploratory drilling.”
More than a year later, after bouts of public outcry over fracing and permitting delays, UK Energy Minister Michael Fallon has now said that his department will revise how it handles shale development, aiming to replace “inflexible rules with an improved approach.” Fallon said he has introduced a “new flexibility to licenses,” which will result in landholders being able to retain larger areas than before. Fallon also said that the new system will involve production plans, which will govern acreage used for production, and retention agreements, which outline work plans agreed upon between the license-holder and the DECC.
As the UK reevaluates its approach to shale, operators, both domestic and foreign, are moving forward with plans. In January, Total acquired a 40% interest in two UK shale gas exploration licenses, covering 240 km2 in the Gainsborough Trough area of the East Midlands region. Petroleum Exploration and Development Licenses (PEDL) 139 and 140 joined Total’s existing shale gas portfolio. The French operator signed on to partner with four firms, including IGas. Total said it will assume operatorship from IGas, as the project moves toward development from initial exploration.
In a later development in May, IGas, agreed to purchase another of the license partners, Dart Energy, for roughly $198 million. The combination of the two E&Ps, has created the largest acreage-holder in the UK, with more than 1 million net acres under license, including shale. In the meantime, the PEDL 139/140 partnership has completed 3D seismic acquisition on the licenses, as part of a $46.5-million work program, which will include drilling and testing a vertical exploration well, and associated well pad construction, with potential for a second, horizontal appraisal. Elsewhere this year, IGas drilled the Irlam-1 well on its Barton Moss concession in March.
Meanwhile, Cuadrilla Resources has, since April, worked steadily to submit, and receive approvals for, a handful of shale projects in the county of Lancashire, on the UK’s western coast. By late June, the company had received validation and acceptance of applications for up to four shale gas exploration wells, each, at two sites, Roseacre Wood and Preston New Road; the second of which is shown in Fig. 1. The company is seeking permission to drill, frac and flow-test gas from wells in an area called the Fylde, from which they can tap into the underlying Bowland shale. The company estimates that its Lancashire licenses could hold up to 200 Tcf of trapped shale gas.
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| Fig. 1. Cuadrilla Resources is seeking permission to drill, frac and flow-test gas from wells at two shale sites in the UK, including one at Preston New Road (photo courtesy of Cuadrilla Resources). |
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Another UK operator, Egdon Resources, recently expanded its onshore UK unconventional portfolio, acquiring Alkane Energy in May. Through the addition, Egdon gained 10 licenses covering 66,867 net acres prospective for shale gas. Of these, the company said it considers three of the licenses as having the most potential: PEDLs 043 and 169 (Gainsborough Trough in the East Midlands basin), and PEDL 191 (in the Bowland basin).
France. As of October 2013, France continued to uphold its ban on fracing, with its Constitutional Court ruling against U.S. firm, Schuepbach Energy. The company had challenged the revocation of its exploration permits following the passage of a fracing ban in 2011 by former President Nicolas Sarkozy. However, France’s oil and gas lobby, L’Union Française des Industries Pétrolières, in a press conference from February, took the stance that shale gas would be a major shake-up in the global oil and gas industry over the coming years. So, there may be hope, yet.
POLAND
Although Poland has cleared the first hurdle to shale development, by allowing companies to conduct basic exploration and drilling campaigns without major hindrances, business has not been as quick-paced as some had anticipated. After Exxon Mobil, Marathon Oil and Talisman pulled out of the country, a handful of players remain, and operations are moving steadily ahead, as companies get better at connecting technology and technique in the largely unexplored geography.
Chevron retained four shale concessions in southeastern Poland (Frampol, Grabowiec, Krasnik and Zwierzyniec) for a total of 1.1 million acres. Last year, the major drilled its first exploration wells in the Zwierzyniec and Krasnik concessions, and a 3D seismic survey was underway on the Grabowiec tract, with completion slated for second-quarter 2014. Chevron planned to explore throughout 2014.
Operator San Leon Energy is moving forward with its exploration and drilling schemes, leveraging farm-ins and commercial agreements with the goal of bringing its fields closer to production, Fig. 2. In early July, the company signed a JV with Palomar Natural Resources (PNR) covering seven concessions in Poland’s Permian basin, including Siekierki and Rawicz gas fields. The JV will drill, evaluate, complete and test at least two wells at Rawicz, in the southern Permian, with the first well planned for the third or fourth quarter. At Siekierki, in the northern Permian, the JV will work over, recomplete and test three existing wells, beginning in the third or fourth quarter.
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| Fig. 2. San Leon Energy has signed several agreements with hopes of moving its Polish concessions closer to production (photo courtesy of San Leon Energy). |
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Back in April, San Leon made additional moves to address production potential at Siekierki, when it announced progress on commercial development with Baker Hughes Poland Sp. Z.o.o. After signing a Letter of Intent in February, the two companies had agreed to commercial terms for Blocks 206, 207 and 208, including workovers on the four Trzek wells, three of which are addressed in the PNR JV. San Leon also signed a farm-out agreement with TransAtlantic Petroleum Ltd, in May, for concessions in Poland’s Permian/SW Carboniferous basin.
According to April’s operational information from 3Legs Resources, the company had drilled, cased and cemented the third and final well of its 2013–2014 drilling program, Lublewo LEP-1ST1H. The well was the third lateral, and the seventh overall, that the company’s JV with ConocoPhillips, Lane Energy Poland, had drilled on its western Baltic basin concessions since 2010, Fig. 3. 3Legs Resources also continued exploratory efforts, carrying out 3D and 2D seismic surveying on two of its concessions.
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| Fig. 3. 3Legs Resources flowed gas from a single-stage frac at its Łebień LE1 well December 2010, and has since focused on its other Polish wells (photo courtesy of 3Legs Resources). |
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RUSSIA
In mid-2013, the EIA took stock of shale oil and gas resources outside of the U.S., and identified Russia as holding an estimated 75 Bbbl of technically recoverable shale oil, and 285 Tcf of technically recoverable shale gas.
One of the longer-standing JVs in Russia, Salym Petroleum Development (SPD), has seen Shell and Gazprom Neft work together to drill 900 wells since spudding their first in 2004. In January, SPD started drilling its first horizontal appraisal well in the Bazhenov formation at the Upper Salym prospect, as part of a pilot project (Fig. 4); the JV plans to drill five horizontal appraisals in 2014–2015, using multi-stage fracturing technology. Previously, SPD had drilled three vertical exploration wells, and collected 3D seismic, cores and well logs at Upper Salym. According to the JV, oil reserves at Upper Salym total 25 million t.
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| Fig. 4. Salym Petroleum Development drilled its first horizontal appraisal well on Russia’s Bazhenov formation earlier this year (photo courtesy of Salym Petroleum Development). |
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Gazprom Neft has also seen movement on its other unconventional projects. In April, the operator tested a new well at 50 m³/d from the Bazheno-Abalaksky formation, in the Palyanovskaya zone. As the company prepares for commercial development of unconventional oil reserves, it said it plans to continue to study the Bazheno-Abalaksky complex, with four inclined wells approved for drilling in 2014.
The company is also investigating shale resource potential through a second JV with Shell, the Khanty-Mansi Oil and Gas Union, which is conducting geological research on the Yuilsk-4, Yuilsk-5, and South Lungorsky-1 sites in the Khanty-Mansi Autonomous District. And, in March, one of its subsidiaries, Gazpromneft-Khantos, was granted a license for geological exploration of the deep oil-saturated prospective horizons in the Achimov and Bazhenov formations at southern Priobskoye field.
Other Russian companies also have partnered with foreign E&Ps to learn more about unconventional plays. In May, Lukoil signed an agreement with Total to create a JV for exploring and developing the Bazhenov formation’s tight oil potential in Western Siberia. Initially, the JV will assess the technical feasibility of developing the tight oil potential on four licenses in the Khanty-Mansi Autonomous District. The companies said seismic acquisition was scheduled to start this year, with exploration drilling slated for 2015. Around the same time, in late May, Rosneft signed an agreement with a unit of BP to implement a joint, two-phase pilot project to develop the Domanik shale formations, and any future unconventional resource potential in the plays.
CHINA
Much like Russia, China sits atop large shale resources. In fact, EIA ranked the nation first in technically recoverable shale gas, with an estimated 1,115 Tcf, and third in technically recoverable shale oil, with an estimated 32 Bbbl. But, unlike Russian firms, Chinese companies have faced greater struggles in harnessing the right technology, for the right price, to effectively recover these resources. China is under pressure to boost domestic production, from whatever sources possible, to meet its demands at home.
In March, China Petroleum and Chemical Corporation (Sinopec) came out with its first “major breakthrough” of the year, announcing plans to develop its Fuling field into the country’s first shale gas project of its kind, with an annual production capacity of 10 Bcm, by 2017. The company said it expects the field’s capacity to hit 1.8 Bcm by the end of this year, and to swing up to 5 Bcm by 2015. Sinopec expects to develop some 340 Bcm of shale gas in two phases. It also said it plans to tap the Dingshan and Nanchuan blocks, in southeastern Sichuan.
China National Petroleum Corp. (CNPC), with various domestic partners, is also making progress on its unconventional projects, most notably on its Changning development in the Sichuan basin. In March, the operator announced that it had implemented its first synchronized zipper frac on four horizontal shale gas wells in its Changning H2 group. Soon after, CNPC announced that it had also begun drilling another well, this time in the Changning H3 group, with roughly 50 wells planned for the block.
AUSTRALIA
Calgary-based E&P PetroFrontier Corp. describes the onshore oil and gas landscape in Australia as being similar to Canada in the 1960s: “huge tracts of unexplored land in hydrocarbon-prone basins.” With a handful of exploration permits (EPs) covering more than 13 million acres in the southern Georgina basin, in Australia’s Northern Territory, the operator established a JV with Statoil for its holdings in 2012. The Norwegian major assumed operatorship in September 2013, and will carry on with the current exploration phase to the end of this year. PetroFrontier estimates that its permits hold, at the low end, un-risked prospective (recoverable) oil volumes of more than 14 Bbbl.
The JV has been busy since the beginning of 2014, having spudded, most recently, OzDelta-1, a vertical exploration well on EP 128, which was the fourth well, of up to five planned, in its 2014 Work Plan and Budget. Up to three of these wells, said the company, will be cased for future fracturing stimulation and production testing. As of late June, the fifth well was scheduled to be drilled in EP 128. The companies said they plan to conduct extensive openhole evaluations, with a well on each of their permits.
Australia-based Santos is also active in another unconventional area, with activity in the Cooper basin, north of Adelaide. Although the company largely focuses on LNG projects, including PNG LNG in Papua New Guinea and GLNG in Australia, it is still flowing gas from Cooper, too. At the end of last year, the company was flowing gas from its Moomba-194 vertical shale well, a follow-up to the existing Moomda-191, at an average of 3 MMcfgd.
ARGENTINA
EIA ranks Argentina in the top five, worldwide, in terms of technically recoverable resources, for both shale oil and gas, with 27 Bbbl and 802 Tcf, respectively. While many other nations are struggling with shale, operators in Argentina are well into production. The country’s own YPF signed an accord with Chevron in July 2013, to further shale development at the Vaca Muerta formation in Neuquén province. Chevron reaffirmed its commitment to development in April, with YPF estimating the initial investment at $1.2 billion.
Chevron completed four exploratory wells last year in its El Trapial concession, which targets the Vaca Muerta, and planned to production test the wells this year. The 2013 agreement between the two companies covers the Loma Campaña Project, and enables the first phase of development for that lease, including an initial 100-well drilling program over a 5,000-acre tract. For Chevron in the Vaca Muerta, 109 wells were drilled in 2013, and the plan for 2014 included approximately 140 wells. Chevron operated four concessions in the Neuquén basin in 2013, with an average net production of 18,000 bopd and 6 MMcfgd.
YPF’s efforts in Neuquén appear to be paying off, as the company announced in June that it had recorded its highest daily oil output in more than eight years in May, pumping more than 70,000 bpd. This figure includes production from the assets it acquired from Apache in an $800-million purchase in February. YPF also recorded positive gas output from the region, flowing more than 915 MMcfgd. 
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