With oil and gas exploration activity at a record low, the number of successful new-field wildcats that completed drilling during 2017 was just over 200, similar to 2016 but down from over 400 in 2014. Offshore West Africa reflected the downturn with only four new discoveries made compared to 16 in 2014. Three of these came in Senegal and the Yakaar 1 deepwater gas discovery heads up the 2017 top ten after operator Kosmos reported 45m of net pay in Lower Cenomanian sandstones giving estimates of approximately 15 Tcfg Pmean resources.
Top 10 discovery wells drilled during 2017 (excludes Former Soviet Union and non-frontier areas of United States and Canada)
Latin America dominated 2017 in terms of discovery size, holding six of the top ten wells. ExxonMobil’s Stabroek Block offshore Guyana saw over a billion barrels of recoverable reserves added through the Payara, Snoek and Turbot oil discoveries made in deepwater clastics. Two significant discoveries were made in Mexico, both holding between one and two billion barrels of oil equivalent in place. Operator Talos Energy encountered 170m-200m of net oil pay in Upper Miocene sandstones of the Zama 1 well offshore in the Salina del Istmo Basin while onshore in the Veracruz Basin Pemex reported the Ixachi 1 gas and condensate well as the largest onshore discovery in 15 years. A significant Atlantic Margin offshore gas discovery was made by BP Trinidad in the Savannah 1 well while Anadarko’s Gorgon 1 discovery offshore Colombia may also prove sizeable with the operator reporting 80-110m of net gas pay.
In the Colville Basin on Alaska’s North Slope, Armstrong Energy made a major onshore light oil discovery with the Horseshoe 1 & 1A wells encountering 45m and 30m of net pay in the Cretaceous Nanushuk Formation. The Armstrong/Repsol partnership estimate contingent resources of approximately 1.2 billion barrels in the Nanushuk play.
2017 discoveries by resource size
In South East Asia there were 18 discoveries recorded during 2017 with the largest, in excess of 100 MMboe, in Indonesia and Myanmar. Pertamina discovered oil and gas in the Parang 1 well in the Tarakan Basin, offshore Kalimantan, with post-drill estimates of 121 MMbo plus 851.1 Bcfg Pmean recoverable resources after targeting Miocene and Pliocene sandstones. In Myanmar’s Rakhine Offshore Basin the MPRL/Woodside partnership drilled the Pyi Thit 1 deepwater new-field wildcat and encountered 36m net gas pay in the objective reservoir which tested at a rate of more than 50 MMcfg/d.
The largest Middle East discovery reported during 2017 came from Lukoil’s Eridu 1 new-field wildcat drilled onshore in the Mesopotamian Basin of southern Iraq. Drilling was completed in December 2016 and during February the partnership with INPEX Corp confirmed it had discovered sweet oil in the Cretaceous Mishrif Formation and recorded a flow rate of more than 6,300 bo/d. It was followed up with two successful appraisal wells with the company anticipating recoverable reserves in excess of one billion barrels.
Northwest Europe saw an upturn in exploration drilling during the summer of 2017 but it still remained low overall for the year and only 13 discoveries were reported, all generally under 100 MMboe. Offshore Norway Statoil and Lundin recorded discoveries in the Barents Sea and Statoil was also successful on the Verbier prospect in the United Kingdom’s Moray Firth Basin. Offshore Netherlands Oranje-Nassau and partners Hansa Hydrocarbons reported that the Ruby new-field wildcat was a significant discovery after testing a Permian Rotliegendes sandstone reservoir at a rate of 53MMcfg/d.
January 2018 commenced with ExxonMobil announcing another potentially significant discovery on Stabroek. Ranger 1, which is the sixth discovery on the block, encountered 70m of high quality oil-bearing carbonates 100km north of the original Liza 1 well and opening a new play.
ExxonMobil’s Stabroek Block, offshore Guyana
In a press release dated 26 December 2017, Permanent Court of Arbitration on behalf of the Conciliation Commission conducting arbitration into the defining of a maritime boundary between Timor Leste and Australia, said that the two countries and the Greater Sunrise Joint Venture (GSJV) had agreed the signature of a maritime boundary treaty in early March 2018.
On 30 August 2017, the governments of Timor Leste and Australia reached agreement on a Comprehensive Package Agreement regarding maritime boundaries in the Timor Sea. This agreement was formalised into a draft treaty and initialled by each government in October 2017 in The Hague.
Timor Leste Maritime boundary
In broad terms, the draft treaty delimits the maritime boundary between Timor Leste and Australia in the Timor Sea and establishes a Special Regime for the area comprising the Greater Sunrise Complex (GSC). The draft treaty also establishes revenue sharing arrangements where the shares of upstream revenue allocated to each country will differ depending on downstream benefits associated with the different development concepts for the GSC.
The GSJV operates the GSC which currently straddles the Australia and Joint Petroleum Development Area (JPDA) boundary in the ratio 79.9:20.1 in favour of Australia. The GSC includes the Sunrise, Sunset and Troubadour Fields. Sunrise was discovered in 1974 which means the discovery and associated fields have been stranded for some 40 years. In 2010, the GSC total contingent resource was independently certified to be 5.13 trillion cubic feet of dry gas and 225.9 million barrels of condensate. The GSC joint venture comprises: Woodside (operator 33.44%), ConocoPhillips (30%), Shell (26.56%), and Osaka Gas (10%).
Those of us who have focused our professional skills on domestic US oil and gas exploration and production sometimes lose sight of how actively international oil and gas concessions/properties/interest are trading hands.
Below is a quick collage of international assets transactions
Collage of international assets transactions
Since 1/1/2013 there have been 8677 asset transactions worldwide in which a working interest/participation did/would have changed hands. Since only 6% of these were cancelled, it’s fair to assume that the international oil and gas asset
market is active and reasonably healthy.
With about 6 more weeks left in this year, with no new deals 2017 will close out at the second highest level of ownership deal flow (transactions + pending deals) since 2013.
Graph of international asset transactions by year
We would expect the pace of international asset transactions to maintain this momentum as oil and gas pricing stays relatively stable (or increases) and especially if petroleum ministries (national and provincial) begin to incentivize investment of exploration and development CAPEX.
The largest transaction by acreage amount was Petronas’ 5/20/2014 purchase of STR Projetos e Participacoes Ltda’ 37.5% interest in lightly drilled Blocks 9 and 11… located NNW of Malakal and including Khartoum.., South Sudan [total acreage =68.8 million acres, or a piece of land measuring about 330 x 330 miles.
That’s a big chunk of territory.
Map of Petronas’ interest in Blocks 9 and 11
For perspective, this block of acreage would contain the entirety of the Permian Basin.
Map of the Permian for comparison
This transaction dwarfs any of the other 26 Petronas interest purchases ….they
must have seen a lot of East African Rift potential here, since only 6 wells have been drilled in the blocks, all of them are dry holes, and just one well had oil shows.
More recently, INEOS was very active in 2017, transacting for approximately 740,000 acres of mostly gas/gas & oil reserves.
Map of INEOS activity 1
Map of INEOS activity 2
INEOS’ gross 3,878,000 acre position (all years) is all European and is highly concentrated in the UK, and represents participation interests ranging from 10% to 50%. About 2/3 of the acquired interests are offshore,
Chart of INEOS acreage by country
There appears to be little correlation between acreage block size and % interest purchased, so it looks like INEOS is making very focused acquisitions.
Chart comparing Interest Purchased to Area ONSHORE
Chart comparing Interest Purchased to Area OFFSHORE
Our International subscribers can use all the information in Asset Allocations to
determine the patterns of buyers and sellers, and use the Block Card to assess
where buyers and sellers have other country assets that you should know about.
Example of a Block Card in the DI International Web App
The North West Europe region saw a bumper summer of exploration and appraisal drilling in 2017, with activity back up to a comparable level as prior to the oil price crash at the end of 2014 (see chart below). A combination of oil price recovery to above $50 per barrel and significantly cheaper rig rates — half of 2014 day rates — has prompted operating companies to drill, augmented by the favourable weather conditions during summer.
Figure 1. NW Europe exploration well spuds by quarter
UK takes lead with improving economic conditions
Drill-ready prospects that have been on hold for a couple years, and would likely have been drilled sooner in more favourable economic conditions, finally received approval and moved ahead quickly. A revitalised UK government body under the Oil and Gas Authority (previously under DECC) is arguably another factor. In the UK, a few companies had multiple prospects drilled: Statoil’s drilling campaign saw successful yet uncommercial oil at Mariner Segment 9, their Jock Scott prospect failed to encounter reservoir, and the Verbier updip sidetrack found oil at the second attempt, after an initial unsuccessful well; CNOOC Limited subsidiary Nexen operated two HPHT 150-days plus new field wildcats, with Craster still ongoing, whilst the earlier Glengorm well proved to be a non-starter; Summit Petroleum drilled the Ranger prospect and appraised Avalon; and BP’s Capercaillie prospect was drilled, while the Achmelvich wildcat still ongoing. Other spuds of note include UK onshore Cuadrilla’s shale gas exploration Preston New Road currently ongoing, after a difficult route through the planning procedure, and expected to be hydraulically fracked and flow tested at the end of the year.
Figure 2. Summer 2017 spuds
Norway had the usual spread of drilling in the North, Norwegian and the Barents Seas, which included Barents Sea Wisting and Alta appraisal wells, and Statoil’s multi-billion- barrel Korpfjell prospect 37km from the Norway/Russia border, that which proved to hold less than 0.5 Tcfg. Statoil also drilled Gemini N, Kayak, and Blåmann, proving successful discoveries in the Barents Sea but not resulting in standalone field developments. Ireland saw its first exploration well drilled since 2015, but the highly anticipated Druid/Drombeg well, targeting nearly 5 Bbo, ultimately disappointed operator Providence Resources and partners.
Perhaps the surprise package was notable success in the Netherlands where Oranje-Nassau Energie made a significant gas discovery at Ruby on the Dutch-German offshore border, and Vermillion drilled two onshore gas discoveries, Nieuwehorne-2 and Eesveen-2.
Whether this indicates the end of the decline for exploration and appraisal as a result of the downturn in North West Europe remains uncertain, however planned well numbers suggest a similar number of Q4 wells as the past few years, and that the summer of 2017 was a blip. Norway, UK and Denmark all have firm commitment wells due in the coming years and healthy award numbers in recent bid rounds for exploration acreage. Statoil has a second commitment well on the Korpfjell licence and reports five exploration wells planned for 2018 in the Barents Sea. The summer of 2017 suggests there is an appetite to drill under the right conditions and the summer of 2018 may see a similar quantity of wells being drilled.
The East Coast Gas Market is finely balanced with current conventional and coalbed methane resources stretched to both supply LNG export markets and meet domestic demand. While this situation has developed into a political issue for federal and state governments, exploration companies have been identifying and investigating the potential of Palaeozoic shale gas in the Northern Territory of Australia. It is still early days, but with the advent of the Northern Gas Pipeline linking eastern states with the Northern Territory, any gas reserves commercialised from the Palaeozoic shales could contribute to the future supply of the East Coast Gas Market.
The Australian Gas Market
There are three main domestic gas markets in Australia: the East Coast Gas Market (ECGM) — supplied from Bass Strait and Cooper Basin fields, the West Coast Gas Market (WCGM)— supplied from North West Shelf fields, and the Northern Territory Gas Market (NTGM)— supplied from Amadeus Basin fields.
The ECGM includes the states of New South Wales, South Australia, Victoria, Tasmania, and Queensland, and is largely isolated from the WCGM and NTGM. In 2015, the Australian Competition and Consumer Commission (ACCC) documented that the available gas productivity would be enough to supply the ECGM demand forecast for 2018 (subject to the timely development of reserves and demand changes). Since then, the ACCC has released an updated Interim Report revising its outlook for 2018, and instead forecasts a shortage of between 55-108 petajoules (PJ) of gas.
This shortage has led to domestic gas users facing high prices (ranging between US$10-16 per gigajoule in H1 2017) and increased uncertainty, as suppliers are becoming less willing to enter into long-term contracts. Many industries (including chemical and alumina production) have been affected, and some have even started deferring contract negotiations in the hope that better conditions return.
The Australian Energy Market Operator has estimated that the total domestic demand forecast for 2018 is between 1,956 and 2,009 PJ. The ACCC has estimated that more than 60% of this is attributable to exports from three LNG projects in Queensland, which are: the Australia Pacific LNG project (capacity of 9 million tonnes of LNG per year (MMt/y)), the Queensland Curtis LNG project (total capacity of 8.5 MMt/y) and the Gladstone LNG project (full capacity of 7.8 MMt/y).
With the LNG projects able to export a significant amount of gas produced from a large portion of the available 2P reserves (approximately 60%— mostly coalbed methane), the federal government recognised the need to ensure security of supply to domestic users. To address this, on 1 July 2017 the government implemented the Australian Domestic Gas Security Mechanism (ADGSM), which allows export controls to be placed on the industry depending on the domestic market forecast. If a gas shortfall is predicted, a limit preventing LNG exporters drawing too much gas from the domestic market is invoked. Gas producers have also showed alignment with the federal government by guaranteeing that they would meet forecast domestic demand for 2018 and for years beyond. However, despite these assurances, it is believed no formal agreements have been signed that cement this guarantee.
In addition to the large volume of gas consumed by the LNG projects, the ACCC has recognised two issues limiting the supply side of the balance. The first is the decline in production. The Gippsland Basin currently produces the highest volume of gas, equating to 330 PJ, however this is expected to fall to 244 PJ in 2018, as traditional sources continue to be depleted and final investment decisions are deferred, for example as in Shell’s Arrow gas project.
The second issue is legislative. To date four states: New South Wales, Northern Territory, Tasmania, and Victoria have introduced moratoriums and bans on hydraulic fracture stimulation. These bans have prohibited companies exploring for and developing unconventional resources, which could potentially have a large, positive impact on the supply side of the balance. Through a change of government, the Northern Territory is the most recent state to introduce the restricting regulations.
Northern Territory Palaeozoic Shales
There are seven basins and major sub-basins in the Northern Territory. The Amadeus, Beetaloo, and McArthur basins have historically had the highest level of exploration activity. However, since 2015 only 11 wells have been drilled (all in the Beetaloo, and Georgina basins), by Santos, Origin Energy, and Pangaea. Exploration results from these wells have been mixed, however Origin’s 2015-2016 four-well campaign in the Beetaloo Basin has emerged as one of the most positive.
Figure 1: The basins of Northern Territory, Australia
During the campaign, Origin drilled three wells (Amungee Northwest 1, Kalala South 1 and Beetaloo West 1) that have supported the presence of a laterally continuous, organic-rich source rock of Proterozoic age called the Velkerri Formation. Further analysis has indicated that the middle section (the B Shale) of this formation has excellent source-rock quality, with gas-filled porosity in the range of 3-5%, and geomechanical properties conducive for hydraulic fracture stimulation.
Later in 2016, the Amungee Northwest 1H well was spudded to begin a multistage fracture stimulation test, targeting the B Shale over a 1,000m horizontal section. The average production rate during the 57-day extended test was 1.1 million cubic feet of gas per day (MMcfg/d). Following this, Origin made a preliminary estimate of petroleum-in-place for the Velkerri B Shale Gas Pool, estimating that its acreage potentially held a gross original gas in-place volume of 496 trillion cubic feet of gas (Tcfg) and technically recoverable resources of 85 Tcfg (representing a 16% recovery/utilisation factor).
Figure 2: Origin Energy’s Beetaloo acreage with 2015-2016 well campaign
Potential Economic Impact
Further work in Origin’s campaign has stalled following a moratorium on fracking introduced on 14 September 2016 by the newly elected Labour party. Simultaneous to the moratorium, the party also commissioned a Scientific Inquiry into Hydraulic Fracturing in the Northern Territory. As part of this ongoing investigation, Origin illustrated that a large-scale project could potentially provide 400-500 terajoules of gas per day to the ECGM, based on a 400-500 well project spanning 20 years.
Further analysis in this example suggests that this could represent a life-cycle capital cost of greater than A$5.5 billion (~US$4.3 billion), based on an assumption of an average well cost of A$12 million (~US$9.4 million) and plant costs of A$5 million (~US$3.9 million) per annual PJ of capacity. Further to the additional long-term gas supply, the federal government and Northern Land Council would also benefit from revenues raised by royalties levied on production (which could be up to 12% and 1% respectively), and taxes including the Petroleum Resources Rent Tax, which is set at a rate of 40%, and the Corporation Tax, which ranges between 28.5% and 30%.
Origin’s exploration campaign is still in its infancy but has highlighted the possibility of significant unconventional potential in the Beetaloo Basin and perhaps beyond. This is further mirrored by other exploration companies and the US Energy Information Administration, which have suggested that the Velkerri shales may extend into the McArthur Basin, and that the technically recoverable shale resources in Australia could potentially be >400 Tcfg.
A resource this large is difficult to overlook, and with the Northern Gas Pipeline (scheduled for completion in late 2018) providing a possible transport route to the ECGM, it seems unlikely that these resources will remain undeveloped indefinitely. However, with the moratoriums and bans on fracking currently in place, and the long lead time from exploration to production, it seems remote that any progress made will remedy the forecasted gas shortage in 2018. The federal government has recognised that this legislation is exacerbating the current ECGM situation and is considering imposing penalties on states (through the redistribution of Goods & Services Tax receipts) that do not favour approving development plans based on an individual project basis.
Additionally, the federal government is also reviewing royalty options for landowners to incentivise exploration. A lifting of the moratoriums and bans may also help to boost the declining gas supply by increasing the number of final investment decisions taken, however this is also a function of the oil price, which is currently stunting the economic viability of some projects. To fully re-balance the market, the government also needs to address issues on the demand side. To achieve this, it may impose export limits on the three LNG projects, however this has been deemed as a temporary measure.
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.