The U.K. had expected 2018 and 2019 to be pivotal years for U.K. shale gas. INEOS, Cuadrilla, and IGas all had an exciting array of prospects to drill, with energy heavyweights ENGIE, Total, and Centrica waiting in the wings. Domestic opposition to hydraulic fracturing (fracking) has caused a severe bottleneck and only three exploration targets have been drilled. That said, initial results have been fairly encouraging, with both Cuadrilla and IGas reporting some success.
Britain’s shale ambitions are largely driven by waning North Sea production and the current deficit against domestic demand amounts to around one trillion cubic feet (Tcf) per annum (in spite of a recent production surge) with the figure set to rise steadily over the next 20 years. One-third of gas imports come from either Russian fields or LNG supplies of mixed provenance.
Figure 1. Falling North Sea gas production could create a huge energy deficit.
The British Geological Survey has estimated around 1300 Tcf GIIP (P50) for the Bowland Shale in Northern England and 4.4 billion barrels (Bbbl) OIIP for the Southern Weald Basin. A further 80 Tcf GIIP and 6 Bbbls OIIP (P50) have been inferred for the Scottish Midland Valley but – due to the fracking restrictions – this basin is off-limits for the foreseeable future. Smaller coal bed methane (CBM) potential has been identified in Wales and the English Midlands, but Welsh parliament has also blocked fracking to limit this resource.
Figure 2. U.K. shale gas licenses and key shale plays
Cuadrilla kicked off U.K. shale gas exploration 2010 – 2012 and drilled four Bowland Shale targets in Lancashire but frack-induced seismicity at Preese Hall in 2012 led to a moratorium. This was lifted in 2017 when Cuadrilla returned to Lancashire to drill and frack at Preston New Road, which tested reasonably well at up to 0.2 MMcfg/d. This was despite only fully fracking and completing two out of 41 planned frack stages in the Bowland Shale; a further 13 stages were only partially fracked and not completed, whilst the remaining stages were not fracked at all, in order to manage induced seismicity. IGas and INEOS followed suit at Tinker Lane in Nottinghamshire, and although the well did not encounter the Bowland Shale, samples taken from shale beds within the shallower Millstone Grit exhibited excellent shale gas potential. The IGas-INEOS partnership has just concluded the Springs Road exploration well with promising results including a 250m Bowland Shale interval and further gas indications in the Millstone Grit and the deeper Arundian Shale. Downhole data is now being evaluated.
Figure 3. Fizzing gas-rich core from a shale section in IGas’ Springs Road well
INEOS and Cuadrilla have led a broad appeal from operators for a relaxation in environmental standards which are seen by the industry to be highly restrictive, specifically in relation to induced seismicity. Although Central government would probably like to loosen the regulations, local and national opposition to both approved and planned activity, combined with the current Brexit-focused political landscape, means that it is unlikely there will be any respite in the near term. Perhaps this prompted Cuadrilla’s decision to abandon planned drilling at Roseacre Wood and focus on Preston New Road. Third Energy has deferred its plan to re-enter and frack Kirby Misperton 8 in Yorkshire.
English shale ambitions are also largely isolated. Scotland, Wales, Ireland, and most of Western Europe have either prohibited or suspended fracking or are in the process of doing so. France has taken it a step further and legislated to terminate all E&P, with Spain potentially set to follow, Italy has an ongoing 18-month moratorium which may result in a similar E&P phase-out, Denmark has stopped onshore licensing, and the Netherlands has suspended onshore licensing.
So, what remains? Poland has returned to unconventionals with active CBM evaluation ongoing between PGNiG and the coal mining sector, and a number of shale-potential blocks offered for tender in 2018 – 2019, while Ukraine is also offering new acreage including blocks with shale gas potential. Both Poland and Ukraine suffered setbacks to their shale ambitions when a number of U.S. majors withdrew in 2012 – 2015, so it remains to be seen how the necessary investment will be attracted.
Figure 4. Drilled and planned U.K. shale gas wells: n.b. Preese Hall [PH1], Preston New Road [PNR], Kirby Misperton 8 [KM8], Springs Road [SR1], and Tinker Lane [TL1]
Returning to Britain, what lies ahead? More than 12,000 sq km of shale acreage was awarded under the U.K.’s 14th Onshore Round in 2016. INEOS was the largest awardee and has clearly broadcast its intentions, with a reported 30 wells applications on its own and in partnership with IGas. INEOS owns Grangemouth refinery in Scotland and is keen to identify domestic condensate feedstock sources. Nonetheless, even if all the onshore operators fulfill their 14th Round drilling commitments, there will still only be around 50 shale exploration wells in the U.K. Compared to 74 in Poland, far less than the tens of thousands in the U.S., it becomes obvious that the U.K. will need to be fortunate to gather substantial data. This links with the energy supply perspective that unconventional reservoirs are not expected to become a significant part of the domestic energy mix in the near-to-medium term. Longer term, industrial development of shale is highly reliant on adequate data gathering and a consistent investment environment – it’s still too early to make a call on either. Early drilling results support further exploration of U.K. shale resources. The challenge now is increasing technical capacity and successfully managing public concerns. Away from shale, the Horse Hill oil discovery in tight carbonates near Gatwick Airport may provide some potential relief as successful development of this unconventional reservoir could stimulate onshore E&P.
Poland is amongst the fastest growing European economies, with an educated population, EU membership, and a strong industrial base. But its domestic hydrocarbon supplies are nowhere near adequate for its needs – gas production of around 220 Bcfg per annum meets about a third of requirements, whilst 15 MMbo per annum provides just 7% of the typical oil demand.
Poland currently imports around 60% of its gas from Russia but – unlike neighbouring Germany – is reluctant to depend on Russian gas to fuel its industrial development. State owned PGNiG, and partly state-owned LOTOS have invested in the Norwegian Continental Shelf and the Baltic Pipe is scheduled to be completed in 2022. Norway will then become Poland’s major gas supplier and direct Russian gas input is expected to end, although Russia will almost certainly contribute to future LNG imports.
Domestic production provides about a quarter of Poland’s gas demand and this figure is projected to drop to 20% by 2022. The country tried to reverse this trend when it embarked on Europe’s most aggressive shale gas exploration programme – attracting the likes of Chevron, ConocoPhillips, Eni, ExxonMobil, Marathon, Shell and Talisman – and 72 shale wells were drilled between 2009 and 2015. However the results were highly underwhelming and, with the industry hard-hit by falling prices, most foreign E&P investment withdrew.
Figure 1. Polish hydrocarbon concessions with Upper Silurian Coal Basin area highlighted
What Poland does have in abundance is coal and the country’s production of 150 million tonnes per annum satisfies the local market. However EU member countries are committed to a 7% reduction in CO2 emissions by 2030 (against a 2005 benchmark), so coal mining offers a poor long-term solution. But what about Coal Bed Methane (CBM) – a much cleaner process than coal mining?
During the height of the Polish shale rush, PGNiG drilled two CBM wells on its 2/2017/L Miedzyrzecze concession in the south of the country. Gilowice 1 & 2h targeted well mapped coal beds in the Upper Silesian Coal Basin (USCB), but the wells were suspended and only completed in 2016 when hydraulic fracturing, and testing over 9 months, produced sustained flows of 175,000 cfg/d.
Figure 2. Upper Silurian Coal Basin licensing – hydrocarbon blocks in green, coal blocks in red; Gilowice drilling highlighted via the bright green dots.
PGNiG has teamed up with three domestic coal companies – PGG, JSW and Tauron – to better understand the play and is now drilling a follow-up Gilowice appraisal programme. As well as Miedzyrzecze and nearby coal licences, several small local and regional companies hold prospective E&P acreage in the USCB which could be further exploited for CBM. Indeed, the Polish Geological Institute has estimated potential recoverable resources of 6 Tcfg.
Figure 3. Polish unconventional hydrocarbon exploration acreage
In the absence of offset Polish data, it’s useful to look at a US analogy for a hint of what might be in store for Poland, in this case, a multi-lateral coalbed methane well in La Plata Co, Colorado.
The well has grossed 4.29 Bcfg production in just under three years of production, has a relatively flat decline curve, and has a Best Efforts EUR of 14+ Bcfg, with a low current water cut, and a relatively small land footprint of about 0.5 sq km (130 acres) accommodating all laterals.
As the case study and preliminary resources estimates illustrate, success at Gilowice and the wider USCB could result in a very useful contribution to Poland’s future energy balance – 6Tcfg equates to 9 years of domestic demand at current consumption. Moreover, it could also re-invigorate unconventional exploration in Poland, with the government offering new shale prospective blocks. Polish CBM offers a potential gas supply guarantee in the near to medium term, and a bridge to the next phase of the country’s hydrocarbon sector.
On 22nd September 2017, the Noble Globetrotter II left the Bulgarian port of Varna, in the Western Black Sea. The drillship is on a single well contract to Total and is expected to spud the Rubin 1 NFW on the 1-21 Han Asparuh licence before the end of the month.
Figure 1. 1-21 Han Asparuh licence
Rubin 1, the second well on the block, is to be drilled in 1,300-1,600 m of water 90km SE of Cape Kaliakra and 14km NE of the 2016 Polshkov 1 wildcat which drilled in 1,900m of water, and operator Total later announced as an oil discovery. It is understood that Polshkov was drilled to 5,500m, short of its 7,000m PTD, and targeted syn- and post-rift Cenozoic plays, overlying Mesozoic carbonate fault blocks. Rubin will likely have similar PTD and objectives and is expected to take 90 days to drill. The Polshkov and Rubin locations were selected based on 3,000km of 2D and 7,740 sq km of 3D seismic acquired during 2013. The 1-21 Han Asparuh licence covers 14,220 sq km and was awarded in August 2012 to OMV (30% equity and operator), Total (40%) and Repsol (30%), with Total taking operatorship on 1 April 2014 ahead of the drilling programme. On 12 April 2017 the licence was extended by 135 days to allow for the drilling of Rubin and is now valid until January 2018.
40 years of exploration
Offshore exploration in the Western Black Sea started in the mid 1970’s in Romanian waters where over 90 wells have been drilled to date. The first offshore wells in Bulgaria were drilled in the mid 1980’s with 30 spudded since. In Turkish waters, north and west of the Bosphorus Strait, 10 exploration wells are known to have been drilled. Romania has seen most of the discoveries made with the first commercial oil production commencing from Petrom’s Lebada East field in 1987. On the Bulgarian shelf Texaco discovered the Galata gas field in 1993 which came onstream in 2006. West of the Galata Field, Melrose Resources (later acquired by Petroceltic) discovered the Kaliakra and Kavarna gas fields in 2007 & 2008, followed by Kavarna East in 2010. The first, and only, western Black Sea success in Turkish waters was the Istranca gas discovery made by Turkish Petroleum Corp (TPAO) on the shelf in 2012.
Figure 2 Western Black Sea fields, discoveries & exploration drilling
Deepwater exploration drilling started with Arco’s Limankoy 1 and 2 wildcats offshore Turkey in 1999. However, it was in Romania that ExxonMobil, in a joint venture with OMV Petrom, made the first deepwater gas discovery on the XIX Neptun Deep block with the 2012 Domino 1 wildcat. Through 2014 and 2015 the JV drilled two appraisal wells plus four further wildcats that included the Pelican South and Califar gas discoveries. Also during 2015 Lukoil drilled two wildcats NE of Neptun Deep on the E X-30 Trident block with Daria 1 coming up dry but Lira 1 adding to the discovery list. In the same year Shell and TPAO drilled the Sile 1 wildcat on Turkish block D23 but were less successful abandoning the well after technical problems and two mechanical sidetracks. In 2016 Polshkov 1 brought the total number of deepwater discoveries in the basin to five and was the first to encounter oil.
Figure 3 Western Black Sea exploration drilling timeline, by country
Bulgaria and Turkey both rely heavily on oil and gas imports; coal also currently accounts for over 40% of energy consumed in both countries. Romania is a net exporter of natural gas and gas products, with established connectivity to European markets, and imports about twice as much oil as the country produces to satisfy local consumption. Consequently the regional demand for new hydrocarbon sources is well established, as is the necessary infrastructure connecting markets further afield.
A commercial discovery at Rubin would open up the western Black Sea for further development, following on from the Romanian successes 120km to the NE where Pelican South and Domino are thought to contain 3.5 Tcfg. A final investment decision is anticipated in 2018, with the project expected to be worth up to US$ 2 billion.
Technical success at Rubin would derisk nearby exploration; ExxonMobil and OMV Petrom have delineated at least nine further deepwater prospects on Neptun Deep licence, mainly in Late Miocene sands, whilst Lukoil has also identified the Flora prospect on E X-30 Trident. TPAO has an exploration well planned for 2018 on Turkish block D24, 120km SE of Rubin and Shell was awarded the 1-14 Han Kubrat licence south of Han Asparuh in 2016 completing a 5,125 sq km3D seismic survey in February 2017.
Following poor success across Europe, including Poland, Ukraine, France, the Netherlands, and Denmark, the UK now remains the last candidate province for European shale gas and oil in the near term. And a fracking moratorium in Scotland has further reduced that to England & Wales. The British government is in favour of developing the resource and opened up significant acreage in the 14th Onshore Round. Nonetheless, some resistance remains.
Meanwhile, North Sea production has been waning and the current deficit amounts to around 1 trillion cubic feet (Tcf) per annum, with the figure set to double over the next 20 years. 1/3 of gas imports come from either Russian fields or LNG supplies of mixed provenance. And with ‘Brexit’ looming, it will be vital for the UK economy to secure long term, reliable energy.
Figure 1. Falling North Sea gas production could create a huge energy deficit
The British Geological Survey has estimated around 1300 Tcf GIIP (P50) for the Bowland Shale in Northern England and 4.4 Billion barrels (Bbbl) OIIP for the southern Weald Basin. A further 80 Tcf GIIP and 6 Bbbls OIIP (P50) have been inferred for the Scottish Midland Valley but – due to the fracking restrictions – this basin is off-limits for the foreseeable future. Smaller CBM potential has also been identified within a number of coal measures in Wales and the English midlands.
Figure 2. UK shale gas licences and key shale plays
The recent news that Third Energy will be allowed to frack an existing well at Kirby Misperton in North Yorkshire has been met with cautious optimism. The upstream operators and investors are generally cheered by the progress but are keeping their expectations in check for a few reasons, not least being that both regulatory process and limited onshore drilling capacity suggest it will still be only a handful of wells per year for the near term. Looking ahead, here are the likely main players:
- INEOS holds 35% of the net licensed acreage and has promised to drill up to 30 shale wells – the first planning application went in at the beginning of 2017. INEOS owns Grangemouth refinery in Scotland and is keen to identify domestic condensate feedstock sources;
- Cuadrilla has begun site preparations at Preston New Road in Lancashire, but will not drill until Q2. The company faced significant local opposition but has obtained permission to drill up to four wells at the site following Central Government intervention, and may still get consent to drill four more at the nearby Rosacre Wood site;
- IGas has some investor issues at the moment which are likely to hamper any aggressive push on their unconventional assets although they do have a pending application alongside Egdon Resources;
- Egdon is mainly focussed on its conventional assets in the near term;
- ENGIE, Total, Centrica have taken up substantial acreage but have been more reserved in their approach with Total and Centrica content to participate rather than operate;
- UK Oil & Gas is focused on the Horse Hill tight reservoir discovery near Gatwick but has some prospective shale acreage in the Weald Basin;
- A number of other significant players – including Horizon Energy Partners and Hutton Energy – are keeping cards close to their chest for the time being.
Over 12,300 sq km of prospective acreage has been licensed to 24 companies.
Figure 3. UK shale acreage holders (net sq km)
To date only Cuadrilla has actively drilled for shale gas, with six wells (including two sidetracks) in Lancashire during 2010 – 2012. Only one of these was fracked – Preese Hall 1 – but seismic activity was detected during testing and led to suspension of operations. A number of earlier wells intercepted the shale horizons and have contributed to preliminary play mapping.
Nonetheless, even if INEOS, Cuadrilla, and the other companies successfully drill their 14th Round commitments, there will still only be around 50 exploration shale wells. Compare this to 74 in Poland (far less the thousands in the US) and it becomes obvious that the UK will need to be fortunate to gather substantial data. This links with the energy supply perspective that unconventional reservoirs are not expected to become a significant part of the domestic energy mix in the near to medium term. Longer term/industrial development of shale is of course highly reliant on adequate data gathering and a consistent investment environment – it’s still too early to make a call on either. The Horse Hill oil discovery does provide some potential relief as successful development of this tight reservoir may stimulate onshore E&P.
In terms of shale play development, there is a long way to go but Third Energy’s planned frack at Kirby Misperton and Cuadrilla’s expected spud in Q2 lie on the immediate horizon, with INEOS and possibly IGas to join the party later in the year. This hardly amounts to exciting times for the UK sector, but at least it is encouraging that there will soon be some real data and results to work with, and hopefully the foundations will be set for a more vibrant industry in the medium term.
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