Tight Oil Developments in Russia: Part 2
James Henderson
The Oxford Institute for Energy Studies
Click here to read part 1
3. Corporate Activity in Russia’s Tight Oil Reservoirs
Rosneft
As befits Russia’s National Oil Company, Rosneft has taken the leading role in the development of the country’s tight oil reserves, in particular since the announcement of its joint venture with ExxonMobil in 2011. Initially the most significant part of this joint venture appeared to be the exploration of Russia’s Arctic offshore regions, in particular the South Kara Sea, but when the companies confirmed their joint plans in June 2012 it became clear that the near term benefits would most likely be seen in the development of Rosneft’s extensive Bazhenov and Achimov resources, including tight oil and shale oil reservoirs. The companies’ plans will focus on a pilot project covering 23 licences with an area of over 10,000 km2 and will include the drilling of new vertical and horizontal wells in addition to the deepening of existing wells and the revival of idle wells. The latest fracking technology will then be applied to the formations during a trial period covering 2013–2015, after which an assessment will be made about a broader potential development scheme. Rosneft also has a second international partnership for its shale resources, since it will work with Statoil in the Samara region to explore the Domanic formations in twelve of its licences. As in the case of the ExxonMobil JV Statoil will be providing financial support and technical expertise in co-operation with Rosneft’s domestic employees in the region.
Rosneft has provided a number of estimates of its tight oil potential, including an assessment in Spring 2012 that its Bazhenov and tight oil resources amounted to 18 billion barrels, followed by a lower 5.8 billion barrel estimate at an investor presentation in October 2012, which was then increased to 10.3 billion barrels of ‘hard-to-recover’ resources stated at a roundtable for analysts in Moscow in May 2013. This disparity in estimates reflects not only the varying definitions of shale, unconventional, ‘hard-to-recover’ and tight oil reserves and resources mentioned above but also the fact that the application of the new technology being introduced by ExxonMobil is at a very early stage. As a result, another Rosneft estimate that production from its unconventional resources could reach 300 kbpd by 2020 must also be viewed with some caution.
Nevertheless, Rosneft does have some experience of its own in exploring for and developing tight oil resources, having undertaken an initial project to produce oil from the less permeable reservoirs at the Salym suite of fields via its Yuganskneftegas subsidiary. Its results were not particularly positive, although it did manage to establish that flow rates of 10 tonnes per day (c.75 bpd) could be sustained over several decades from vertical wells drilled into the Bazhenov and Abalak formations. This level of production, however, and the very low overall recovery rate of 7 per cent, would not make such a development economic on a widescale basis, hence the need for the more modern techniques planned to be used in the JV with ExxonMobil.
Surgutneftegas
Development of the tight oil resources around the Salym field has also been a focus for Surgutneftegas, and indeed the company has the longest history of any Russian company in the search for an economic way to develop ‘hard-to-recover’ oil. Over the past 30 years Surgutneftegas has drilled more than 600 wells into the Bazhenov formation on its licences, but the mixed results again highlight the difficulties in developing the resource successfully. 37 per cent of the company’s wells have been dry, demonstrating the problems with understanding the properties of a reservoir which is not homogenous, although more encouragingly the 63 per cent of wells that have been successful have flowed up to a maximum of 300 tonnes per day (c.2,200 bpd). Over the life of its operations to date Surgutneftegas has produced almost 9 million barrels of Bazhenov oil, and although this equates to a rather low average of 800 bpd over the entire 30 year period the company estimates that it should be able to recover a further 30 million barrels during the next two decades. Given the somewhat conservative outlook that it adopts towards international co-operation and partnership it seems unlikely that Surgutneftegas will be at the forefront of Russia’s shale oil developments but will rather be a secondary player as it continues to develop its own technical solutions to the development of tight oil reservoirs.
Gazprom Neft
Gazprom Neft, on the other hand, is taking a more proactive approach and has two tight oil projects underway while also planning to further develop its exposure to shale and tight oil reservoirs through the purchase of additional licences. Shell is the company’s core partner in its first tight oil project, which is exploring the development of resources in the license area that contains existing conventional production from the Upper Salym field as part of the SPD 50:50 joint venture between the two companies. The JV partners have put together a plan for the implementation of an $80mm pilot project at the North Salym field, which contains deposits in the Bazhenov shale layer, and the intention is to further expand the JV in order to bid for new licences in the Khanty-Mansiisk region as part of a four year plan to bring major shale deposits into production in the region. Indeed Gazprom Neft has set out initial targets for the JV to commence production in 2015 before reaching peak output of 35 kbpd by 2024 and to ultimately exploit up to 650 mm barrels of reserves.
In addition to its partnership with Shell, Gazprom Neft is also undertaking a project to review and potentially exploit the Palyanovskaya zone in the Bazhenov layer of the giant Krasnoleninsoye field. In August 2013 the company announced that that it would begin a four well pilot project by the end of 2013, with a plan to drill inclined wells into the tight oil layers over the next 18 months before deciding if a commercial development of the resource is possible. Gazprom Neft is well-placed to make this assessment as it has already brought 60 million barrels of tight oil into production from beneath existing fields in 2012 and plans to bring five more tight oil plays to the development phase from 2013. It also has extensive experience of using horizontal wells and hydro-fracking at its conventional fields in West Siberia, with plans to drill 120 horizontal wells and to conduct 90 multi-phase hydro-fracs in 2013. As a result it should be in a good position to deploy these skills in lower horizons, although the company has warned that a shortage of technical resources in Russia could be a limiting factor in the full exploitation of the Bazhenov resource.
LUKOIL
LUKOIL has been expressing its enthusiasm for tight and shale oil resources for the past two years, with company vice president Leonid Fedun describing it as ‘our Bakken’ and stating that ‘we have the reserves, and sooner or later we will get them out’. Indeed LUKOIL has already begun to exploit the deeper and less permeable resources below its existing fields in West Siberia, noting in its 2013 Databook that it is increasing output at the Vostochno Perevalnoye and Potochnoye fields using multi-zone fracturing of horizontal wells to exploit the Achimov deposits in its licences. Although neither field is large (they have a combined proved reserve base of c.350 million barrels) the techniques being used there have helped to reverse production declines and that will also be applicable as the company moves to develop other tight oil reservoirs, including the Bazhenov, at current and new licences. In 2012 the company acquired the licences to the Imilorsky deposits in the Khanty Mansiisk region, which contain significant tight oil resources, and has also announced during a recent conference call that it is looking to acquire one or two more ‘hard-to-recover’ assets in the near future in order to take advantage of the improved economics for such reserves.
LUKOIL also owns a 100 per cent subsidiary RITEK which has for some time been specialising in the recovery of ‘hard-to-develop’ reserves. Indeed the company, whose acronym stands for Russian Innovative Fuel Energy Company, is currently pioneering the development of Bazhenov shale reserves using a combination of horizontal drilling, hydro-fracking and thermal gas treatment technology. Two pilot projects, at the Galyanovskoye and Sredne-Nazymskoye fields, are currently investigating whether thermal gas treatment can help to improve the feasibility of producing shale oil by heating it up and allowing it to flow more easily through low permeability reservoirs, using techniques similar to those seen in the development of Canadian bitumen reserves. Although the trials are at an early stage it is hoped that the combination of heating and fracking could allow a much broader development of shale reservoirs throughout the LUKOIL portfolio.
TNK-BP
Although TNK-BP is now owned by Rosneft and no longer reports its activities separately, the company’s tight oil development plans before the takeover included seven pilot projects in West Siberia with a resource estimate of approximately 4.5 billion barrels. Indeed the company has been quoted as stating that it has almost 7.5 billion barrels of tight oil resources in West Siberia alone, with more than 20 billion barrels of total ‘difficult-to-recover’ resources overall. A number of the pilot projects are aimed at the development of new reservoirs at existing fields, with the North Khokhryakovskoye field being a good example. Current production from the conventional layers of the field is 1,600 barrels per day and the company aims to double this figure in 2013 by exploiting the 350 mm barrels of tight oil reserves at the field using the standard techniques of horizontal drilling and multi-stage fracking. Although the production numbers are relatively small, the project will provide an indicator of the best methods to be used in the company’s tight reservoirs, and up to $100 million will be spent in 2013 to further the company’s understanding across all of its seven projects. A similar pilot will be conducted at the Ryabchik field on the borders of the giant Samotlor development, where almost 800 mm barrels of tight oil is believed to have development potential, while the company’s subsidiary Varyeganneftegaz plans to carry out a further three projects in partnership with Schlumberger in order to exploit the 2 billion barrels of ‘hard-to-recover’ reserves that it has on its books.
Partnership has also been a theme in TNK-BP’s other two pilot projects, with the company working alongside Halliburton to exploit the Yem Yegovskoye field, another asset that is part of the huge Krasnoleninsky group of fields. TNK-BP’s share is estimated to contain around 750 mm barrels of light, tight oil, and Halliburton has taken on a risk contract to use its drilling and fracking technology to improve field performance, receiving bonus payments for beating specified operational targets. Prior to its takeover by Rosneft the company was looking to sign a similar deal to undertake its final pilot project at the Van Yogan field, with one of the company’s Deputy General Directors pointing out that the need for foreign contractors was based on the fact that ‘I think that in order to find some kind of efficient technology, we need to solve a whole lot of complex issues. Here we need quality well drilling and new completion methods, and it is precisely foreign service companies that have achieved success in these matters.’
Small Company Activity
Aside from the large vertically integrated Russian oil companies and their foreign partners there are also a few small oil companies that are starting to investigate the country’s unconventional oil potential. Ruspetro is an independent company quoted on the London Stock Exchange that is primarily focused on the production of tight oil reserves in West Siberia. It operates licences in the Krasnoleninsky area, where it has gained access to licences covering 1,234 km2 of acreage with Bazhenov potential, and it has commenced initial exploratory work on these deeper reservoirs that are located below fields that already contain the company’s 1.8 billion of proved and probable reserves. Meanwhile in the Tomsk region of Siberia Imperial Energy, a company now 100 per cent owned by Indian National Oil Company ONGC, is also looking to exploit the shale and tight oil reserves in its licences in order to offset steep declines in production over the past two years. The company believes that it may have up to 2.1 billion barrels of tight oil resources in its portfolio, and it is planning to start pilot projects in 2013 to investigate how much might be recoverable. However, Imperial is seeking a strong partner to bring the technical expertise and the financing that it will require to fully appraise and develop its potential reserves, and although there has apparently been some interest from potential partners no deal has been struck to date. Also operating two licences in the Tomsk region, Petroneft is another small company that has begun production from traditional reservoirs but has also identified potential resources in the Bazhenov shale layers below its existing fields. The company has yet to undertake any significant appraisal work, but provides another example of potential upside from the deeper unconventional layers in West Siberia.
4. Achieving the Commercial Development of Russia’s Tight Oil Resources
It is clear from the descriptions above that although corporate enthusiasm for exploration of Russia’s unconventional resources is rising, and is also starting to involve international companies, most of the activity concerns pilot projects to assess the size of the resource and the commercial realities of its extraction. First results appear to have confirmed the geological uncertainties mentioned earlier, with initial flow rates from wells varying from 75 bpd day to 2,000 bpd, and in some extraordinary circumstances to 7,000 bpd. They also confirmed the well-known shale phenomenon of rapid production decline from individual wells, with output in year 2 being on average only 30 per cent of year 1 production, and year 3 output falling to only 20 per cent of the initial flow rates before a long decline output tail (see Figure 4 for a typical production profile). The greater risk that this has generated has been further compounded by the higher cost of drilling the necessary horizontal wells to a greater depth than has historically been associated with oil field development in Russia. While an average vertical well into a conventional West Siberian oil field might cost $1–2 million, a horizontal well into the deeper Bazhenov layer is more likely to cost in the region of $8–10 million, with some drilling companies estimating a possible cost as high as $15 million for more complex wells. By comparison US company Hess has reported that its average cost for drilling and completion of a well into the Bakken shale in North Dakota is now $8.6 million, while Marathon Oil reported that its average well cost into the Eagle Ford shale was in the region of $8–8.5 million in the fourth quarter of 2012. In Russia some companies have mentioned much lower drilling costs, with Rosneft citing a figure of $5 million per well, but it seems very unlikely that the average cost for the drilling and full completion of a well would be lower than in the very competitive US market.
Source: Author’s estimates based on company data. In light of these high well costs, variable flow rates and sharp decline rates that are so different from the traditional Russian oil field model, the economics of developing tight oil from the Bazhenov shale reservoirs require a tax system that allows swift cost recovery. The current Russian system, however, has been created for an industry largely producing from existing fields with low capital expenditure requirements. It is based on a revenue-based royalty (Mineral Extraction Tax or MET for short) and export tax regime that is applied to every barrel equally, from first production to final depletion, making no allowance for profitability. As a result, it has historically been very difficult to justify the commercial development of unconventional oil in Russia, especially as the effective tax rate at a $100 per barrel oil price has been around 60 per cent, assuming that 45 per cent of production is exported and 55 per cent sold domestically. For example, the author estimates that a Bazhenov well with a cost of $9 million and an initial flow rate of 50 tonnes per day (370 bpd) would have an IRR of minus 5% at an oil price of $100 per barrel under the tax system prevailing in the first half of 2013. Indeed it would need an export oil price of well over $200 per barrel to achieve a 15 per cent hurdle rate (assuming that 45 per cent of the oil is exported).
As a result, a lengthy discussion has been continuing between the oil industry and the Russian government concerning either the introduction of a profit based tax system or a reduction in the current rates of MET and/or export tax. This has resulted in the passing at first reading of a bill that will significantly reduce, and in some cases remove, the MET royalty tax from tight oil developments. The bill, which attempts to give tax breaks to a broad range of ‘hard-to-recover’ oil, essentially differentiates between reservoirs according to their permeability, the extent of field depletion and the size of the oil-filled formation. Various co-efficients are then applied to reduce the level of MET, with for example oil produced from layers with very low permeability and no thicker than 10 metres being given a co-efficient of 0.2 (that is, they pay 20 per cent of the current MET rate), while similar reservoirs with a thickness more than 10 metres will have a co-efficient of 0.4. The deep Tyumen deposits mentioned above will have a co-efficient of 0.8, meaning that there will not be much tax relief for any oil produced, but the shale layers in the Bazhenov and its associated Abalak, Khadum and Domanik reservoirs will have a co-efficient of zero, meaning that they will incur no MET for a period of 180 tax periods (equivalent to 15 years).
The immediate impact of this tax change on a standard shale well producing 50 tonnes per day and costing $9 million is impressive, but not completely persuasive. The IRR is increases from minus 5 per cent to plus 7 per cent, but with most companies setting their hurdle rate in the range 15–20 per cent this would still not be enough to justify investment. This highlights the key problem with the MET tax break, namely that it continues to apply the same break to all wells irrespective of cost or initial output, without regard to profitability. In essence, this is the same problem being faced by the Russian oil industry as a whole, except it is magnified because of the high costs involved and the huge range of uncertainty around many of the basic assumptions in the economic calculations. Figure 5 demonstrates the dramatic differences in the economic results between various well cost and initial output assumptions and underlines the continuing issue for all oil companies looking to develop Russian unconventional oil resources.
As can be seen, a well with an initial output of 50 tonnes per day and a cost of $9 mm has an IRR of 7 per cent, but the same well producing 75 tonnes per day has an IRR of 24 per cent, and at 100 tonnes per day the IRR leaps to 44 per cent. Similarly a 50 tonne per day well has an IRR of 16 per cent at a $7 mm well cost but only 2 per cent at an $11mm cost. Although it might not seem surprising that a 50 per cent increase in output should produce a large increase in IRR, the key point here is that well output of 75 or 100 tonnes per day is well within the parameters of likely outcomes, but 25 tonnes per day is also perfectly possible, at which point the IRR barely gets above zero even if the well cost falls to $5 mm. Furthermore, these economics only take into account the cost of successful well development and make no allowance for the cost of the possible 35 per cent of wells that could be dry or non-commercial. Even if this ‘dry-hole’ percentage is reduced to 25 per cent or even 20 per cent the impact of the additional cost of one ineffective well in five would effectively add more than $2mm to the cost of each producing well, and as Figure 4 shows this could easily tip even a 75 tonne per day well into marginal economic territory.
With the average well in the Bazhenov having an initial flow rate of 50 tonnes per day , however, it is not surprising that a number of companies are continuing to press for further tax breaks, including a reduction in the rate of export tax, from the Russian government. At present such a move is not under consideration, in particular because the impact on an already stretched Russian budget that relies heavily on oil export taxes would be too significant for the Ministry of Finance to countenance. As a result, although the current MET exemption is certainly a positive step towards the development of Russia’s shale and tight oil resources it may not be enough to encourage the full scale exploitation of the resource in the short term. A key indicator of the suitability of the tax regime is likely to emerge only after the completion of the Rosneft/ExxonMobil pilot project in 2015, as this will provide some more accurate estimates for the key production and cost parameters for the economic calculations and ExxonMobil would be very unlikely to underwrite further significant expenditure unless this was accommodated within a suitable tax environment.
5. A Practical Issue – The Availability of Sufficient Drilling Equipment
The issues of geology and taxation will clearly be critical to the development of Russia’s tight oil reserves, but a further complication could also emerge in the service industry, where the provision of sufficient equipment to meet aggressive development and production objectives could be a significant problem. According to data provided by REnergyCo, who produce monthly rig statistics for Russia, the total current fleet of rigs working in the country has varied between 717 in February and 978 in June 2013, and data from the Russian drilling company Eurasia Drilling would suggest that around 17 per cent of these would be powerful enough (1500 horse power or above) to drill the deep horizontal wells that are needed in the Achimov, Bazhenov and Tyumen reservoirs (see Figure 6). As a result we can deduce that there are approximately 150–175 heavy rigs active in Russia at present, but it would also seem logical to conclude that they are all already active drilling the 800 horizontal wells that were completed in Russia in 2012 on existing fields, particularly in Timan Pechora and West Siberia. As a result, it would seem to be safe to conclude that, although some old rigs will be freed up to work on unconventional reservoirs, it is likely that the majority of the rigs needed to develop Russia’s tight oil reservoirs will need to be built over the next few years. Indeed rig manufacturers are already anticipating a multi-billion dollar bonanza as a result of this increased activity.
A relatively simplistic analysis would appear to support this conclusion. If we assume, for the sake of argument, that all rigs required to carry out deep unconventional drilling will need to be new and that the Ministry of Natural Resources target of 1 mmbpd of production must be met in 10 years, then using standard assumptions for initial well output, decline rate and wells drilled per rig per year then we can estimate the number of rigs required. We assume that the initial well production will be 50 tonnes per day and will decline as shown in Figure 3 above, and on this basis the number of wells required to reach output of 1mmbpd will peak at 1800 in year 10 of a full development programme (see Figure 7). In terms of the number of rigs needed to meet this drilling programme, we assume that each well will take 35 days to drill (compared to around 26 days for Bakken wells in the USA) and that there will also be time needed for movement between well sites and fields, which will probably be considerable. Eurasia Drilling estimates that it would take on average 45 days to move a rig from one field to another, but as it is likely that multiple wells will be drilled from the same site before any movement we have reduced this ‘down-time’ to an average of 25 days, in which case the implication is that each rig would be able to drill, on average, 6.1 wells per annum. This would imply that at the peak level of activity 220 rigs would need to be active drilling new wells to maintain output at or just above 1 mmbpd, and if one then includes a 25% contingency to allow for rig downtime and maintenance one can estimate that up to 275 new rigs might need to be constructed over the next 10 years to meet an aggressive Russian unconventional oil production target. In terms of a comparison with the US, around 180 rigs were active in North Dakota and Montana in August 2013 according to the Baker Hughes rig count statistics, supporting production of 700,000 bpd, implying production per rig of 3,900 bpd, while our Russian assumptions suggest that 275 rigs will be needed to sustain 1 mmbpd, or 3,600 bpd per rig. Given the difficulties of the Russian environment and the developing nature of the services industry there, this difference in efficiency would seem to be reasonable and provides some confidence in our estimate.
The key question, of course, is whether this number of rigs can be built within the given 10 year timescale. Even if the forecast outlined above is only directionally correct, achieving 1 mmbpd of tight oil output would require a tripling of Russia’s heavy oil rig fleet, and with the individual cost of new heavy rigs estimated in a wide range of $10-60mm the total bill could reach as much as $15 billion, or around $1.5 billion per annum over 10 years. By comparison, Eurasia Drilling, which accounted for 29 per cent of all onshore drilling in 2012 (see Figure 8) had a total capital expenditure for the year of $600 mm. Extrapolating this to create an approximation for the drilling industry as a whole, we can surmise that total OFS drilling capital expenditure might have totalled $2 billion in 2012, meaning that our estimate of the potential annual requirement for unconventional drilling alone would account for 75% of this if the Ministry of Natural Resources target is to be met.
Of course it must be acknowledged that all these calculations are highly theoretical at present, but they do at least highlight the very real potential of an OFS industry capacity constraint over the next decade in Russia. Indeed, even short term forecasts of likely drilling activity underline the tremendous growth that is likely to occur as more intensive and deeper exploration and development activities proceed. Figure 9 shows an industry forecast for the increasing drilling volumes and the growing prevalence of horizontal drilling in Russia to underline the point.
One final point about the investment required in Russia’s oilfield services industry is that there may be a significant risk of delay in spending while oil companies establish the true potential of the resource base. Oilfield service companies will not invest in the drilling capacity to service an industry producing 1mmbpd until they know that this potential can be reached and therefore that their new rigs will be able to make a reasonable rate of return over the medium to long term. An outcome that saw either production targets being missed or production peaking at 1mmbpd but then going into rapid decline could spell disaster for service companies, and as a result they will be likely to invest cautiously as they see the unconventional industry in Russia grow. By default this is likely to temper the growth in production in the short term, meaning that more aggressive output targets are unlikely to be met.
6. Other issues
Aside from the major issues of the economic viability of unconventional oil development in Russia and the availability of sufficient oil service capacity, there are a number of other questions that will need to be answered before companies make significant investment decisions.
Law on Strategic Reserves: One legislative issue, at least for foreign companies, concerns the Law on Strategic Reserves which was introduced as an amendment to the Subsoil Law in May 2008, and which limits foreign involvement in fields with reserves above a certain size, namely 70 million tonnes (c.500 million barrels) for oil and 50bcm (c.1.75 Tcf) for gas. Any fields larger than this, or located offshore, must have a Russian company as a majority shareholder. However, because shale oil resources are much more complicated to define in compartmentalised blocks compared to conventional fields, which generally have a defined areal extent and depth below a trap of some kind, the Russian authorities may struggle to define accurately whether a particular company owns a strategic resource or not. This could in future create problems for any foreign company that might start as a majority shareholder in a license area only to find that its position is illegal. At present this potential problem is being resolved through the formation of JVs between Russian companies with a 51 per cent stake and foreign companies with a 49 per cent stake, but if the industry is to develop in a rapid and competitive fashion the issue of strategic reserves may need to be addressed in order to encourage a broader sweep of company involvement in unconventional oil development.
Corporate landscape: This raises a second more subjective question about the corporate environment needed to catalyse successful development of unconventional reserves. The Unconventional Gas Centre in North Dakota lists 89 companies that operate in the Bakken shale area of the US alone, and it is this diversity of corporate involvement as well as the small and adaptive nature of many of the companies that has been at the heart of the success of the unconventional oil and gas industry in that country. The largest producers from the Bakken shale in 2012 were Whiting Petroleum and Hess, and although these are not small companies, with market capitalisations of $6.2 billion and $26.5 billion respectively, they are not the multinational IOCs that were actually quite slow to enter the US unconventional industry. As described by one industry participant ‘the big international oil companies are good at being able to plan ahead… have multi-year timeframes and can execute very complex projects. But all these things become weaknesses when you are working in shale plays. You need to revisit your planning according to what you learn about the reservoir, or the market. And that adaptive planning is what the smaller companies are good at.’ Indeed one Chevron employee openly commented that ‘we’re going to do it [shale oil development] right, [but] it will probably take us a little longer than some others.’
The corporate landscape in Russia is in sharp contrast to the dynamic smaller company model in the US, with a few large companies leading the way, dominated by the country’s NOC Rosneft. A partnership model with large IOCs has been developed in order to introduce international technology and experience, but one conclusion from the Chevron experience might be that progress is likely to be methodical rather than rapid. It is too early to draw any conclusions yet as to whether the Russian model will ultimately be more or less successful than the US model, as the IOC/NOC partnership concept is itself at an early stage of development. All that can be said is that it is different and so inherently carries the risk of becoming a longer term rather than a shorter term project, with large companies having a broader focus of interests and concerns to act as potential distractions than the smaller and more entrepreneurial concerns that have been at the forefront of shale oil developments in the US.
Licensing: The relatively tight nature of Russia’s corporate landscape is also exacerbated by the licensing regime for tight and unconventional oil, which tends to favour larger companies. Much of the Bazhenov shale reservoir lies below existing licenses and fields in West Siberia and, as has been mentioned above, is the main source rock for oil in the region. In some instances the licenses for shallower reservoirs also extend down to the deeper shale layers, and so the large companies which dominate Russian production have extensive Bazhenov exposure by default. Even if the current licenses do not currently extend down to the Bazhenov, however, it is expected that companies owning the shallower licenses will be able to extend their exploration to the deeper horizons as a matter of course. As far as new licenses are concerned, Gazprom Neft has identified acreage containing a potential 8-10 billion tons (60–75 billion barrels) of resources that has yet to be allocated in the Khanty-Mansiisk region alone, so the possibility of new entrants arriving still remains. Given the current government preference towards state-controlled institutions, however, highlighted by a recent Fitch ratings agency report, and the implications of the Law on Strategic Reserves discussed above, it would seem likely that the majority of this new acreage will go to the same group of companies that currently dominate the industry.
Environment and water issues: Russia’s huge geographical expanse means that it is unlikely to be troubled by the environmental concerns that are currently facing more densely populated countries where lobby groups are raising concerns about the possible impact of fracking on supplies of potable water and the risk of seismic disturbances. Nevertheless, Russia does have some strict environmental laws that can impose severe fines on companies that cause damage through leaks or harmful waste disposal, and it is currently unclear whether these might need to be adapted further to account for the increased activity that would result from significant horizontal drilling and well fracking involved in the development of tight and shale resources. Given that activity on tight reservoirs using these techniques has been underway for some years under current legislation one might assume that this will remain the situation if drilling for unconventional resources expands. Given the difficult terrain in Siberia, however, combined with the extreme weather conditions, which means that the landscape changes from a frozen wasteland in winter to boggy marshes in summer, it would not be surprising if the Russian authorities decided that new legislation is required to manage a different type of development activity that involves high levels of liquid injection and the need to deal with the return of at least 15 per cent of injected water to the surface. Any examination of this issue could clearly take some time and cause delays to operational activity.
One of the other main environmental issues may also concern the use of water. Although there would seem to be little risk of drought in Siberia, the fact that temperatures remain below zero for a significant part of the year means that the issue of water provision could be a significant one. This may require state approval for a broader network of heated pipelines to manage winter water supply, the expansion of road transport fleets and storage facilities to cater for water provision at different times of the year and an adaptation of the rules for water extraction and injection that are currently managed by the Ministry of Natural Resources. None of these issues are insurmountable, of course, but could nevertheless lengthen the process of moving from the exploration to full development of Russia’s unconventional resources.
Manpower requirements: A final, and much more subjective, question concerns the availability of sufficient skilled labour in Russia’s oil heartland to meet the requirements of the much more intensive work required to exploit unconventional oil and gas. While it is impossible to be definitive at this early stage of the resource development, the development of the Bakken resource in the US is estimated to be creating 65,000 new industry-related jobs, and the boom in oil production in North Dakota is causing a shortage of manpower and facilities. As one industry participant described the situation – ‘we need help, we need manpower and we need intelligence.’ In Russia much of the country’s skilled oil industry workforce is already heavily engaged in stemming the decline of the country’s existing assets and indeed the economy as a whole could be facing labour shortages as the population declines, with the consequence that if a dramatic increase in drilling is required to accelerate unconventional output then it is likely that significant additional manpower will be required that cannot just be shifted from existing fields. Of course foreign company participation can alleviate this problem to an extent, but nevertheless there must be some question about the availability of skilled human resources in West Siberia to meet future industry needs.
7. Conclusions
Russia’s traditional oilfields in West Siberia are in decline and the Russia government and its oil companies are therefore faced with some stark choices if they wish to retain the country’s oil production above 10 mmbpd. Much excitement has been generated by the huge exploration potential of the country’s offshore basins, with joint ventures being formed between Rosneft and various IOCs to exploit licenses in the South Kara, Barents and Black Seas and with tax incentives being provided by the Russian administration to encourage investment. A separate element of these joint ventures has also been the exploitation of Russia’s tight and shale oil resources, which could in fact produce a more rapid result in terms of production to replace any decline from current fields. Indeed, with the USGS estimating that Russia is the largest holder of shale oil resources in the world, with 75 billion barrels of potentially recoverable resources, it would seem that the opportunity is huge, and the Russian Ministry of Natural Resources has set a target of 1 mmbpd of production from this resource base by 2025.
This enthusiasm, however, needs to be tempered because of a number of issues that will need to be faced if successful development of Russia’s unconventional oil is to be achieved. The country’s most extensive shale oil, in the Bazhenov reservoir, has been likened to the Bakken resources in North Dakota which are currently producing over 700,000 bpd, but the differences between the two areas are as interesting as the similarities. A detailed geological assessment of the more than 2 million km2 of Bazhenov reservoir has yet to be completed, but even the early seismic and drilling results suggest a significant heterogeneity across even short distances, with starkly different initial flow rates and decline curves from wells only a few kilometres apart. Furthermore, there is a large difference in well drilling cost estimates that again suggests a wide variety of operating conditions, increasing the risks for operators.
In these circumstances a tax regime that focuses on royalty payments per barrel of oil produced or exported without regard for cost recovery is always going to make it difficult for oil companies to generate commercial returns from their investments. The Russian government has started to appreciate this fact, and recent legislation has offered a scale of MET royalty payments according to the difficulty of extraction, but as our analysis has shown even this may not be enough to encourage wide-scale investment. Reductions in export tax rates may also be required, but a more rational long-term approach would be a restructuring of the regulatory system to focus on taxing profits rather than revenues. The Russian administration is reluctant to do this for fear that ‘creative oil company accounting’ will result in the majority of oil production being classified as ‘hard-to-recover’, with a consequent loss in tax revenue, but it may be the case that the need to incentivise the development of Russia’s unconventional resources can provide an additional spur to action on a profit-tax regime for the Russian oil industry.
Another key question for the development of Russia’s shale and tight oil resources will be the expansion of the oil service industry. The number of heavy oil rigs, which are capable of drilling the deep horizontal wells needed to exploit the Bazhenov reservoirs, will need to triple if the Ministry of Resources target is to be met, raising a question about the ability of the oil service industry to meet the possible $15 billion expenditure requirement. Furthermore, the industry will also have to expand its ownership of fracking equipment and other operational items, and this will put pressure both on its ability to finance so much purchasing in a relatively short period of time and its willingness to take the risk of investing in what remains an uncertain resource base.
The other key issue which faces the Russian oil industry as it seeks to develop its unconventional resources is the overall corporate landscape of the sector. In North Dakota alone 89 small and medium-sized companies are involved in developing the Bakken shale, while in Russia four large and vertically integrated companies (now that Rosneft owns TNK-BP) are heading the drive to develop the Bazhenov reservoirs in co-operation with their new international partners. It is too early to say whether the new NOC-IOC partnership model that is becoming prevalent in Russia will be successful in developing the country’s tight and shale oil resources. The suspicion must be, however, that companies with a broad sweep of domestic and international interests will be less likely to focus on the swift resolution of the many problems that are sure to be faced than the very entrepreneurial entities that are prevalent in the US unconventional sector.
Overall, then, although Russia undoubtedly contains huge potential for the development of unconventional oil resources, it would seem unlikely that the aggressive Ministry of Natural Resources target will be met. We will know much more about the geological and commercial issues that the industry faces once the Rosneft-ExxonMobil pilot project is competed in 2015, but the suspicion is that the Russian government may need to show even more flexibility in its tax arrangements in order to encourage full scale development of the Bazhenov shale. On a positive note, this could produce the ultimate catalyst towards a full revision of the oil tax system towards a profit-based model, in order to ensure that production remains above 10 mmbpd. A less encouraging development would see continued concerns about a short-term loss of tax revenue leading to a continuation of the status quo with ad hoc adjustments, thus undermining the development of the industry and preventing even the more conservative Ministry of Energy targets for shale and tight oil production being met.
