ROGTEC Magazine - Russian Oil & Gas Technologies - News, Reviews & Articles

ROGTEC Magazine - Russian Oil & Gas Technologies - News, Reviews & Articles

Wednesday, April 2nd, 2014

Bashneft: Yearly Figures EBITDA up by 3.6%

Bashneft Group, which comprises JSOC Bashneft, its subsidiaries and affiliates, has released its audited consolidated financial statements for the fourth quarter and the twelve months ended December 31, 2013 prepared in accordance with International Financial Reporting Standards (IFRS). In 2013, the Group’s revenue from sales increased by 5.8% year-on-year to RUB 563,296 million. Adjusted EBITDA increased by 3.6% to RUB 103,972 million. This growth was primarily driven by increased production of hydrocarbons and exports of petroleum products, as well as growing product sales in premium market segments.

‘Last year the Company enjoyed remarkable success in terms of operating and financial performance,’ commented Bashneft’s President Alexander Korsik. ‘The Company achieved the strongest production growth in the oil industry by boosting production in its traditional operating regions and also through the commissioning of the Trebs and Titov fields in the Nenets Autonomous District. An increase in operating cash flow in 2013 enabled us to pay the largest interim dividends in Bashneft’s history and to continue upgrading our refineries and retail network. We also made major efforts to divest non-core assets and streamline our corporate structure through the reorganization of Sistema-Invest.’

In 2013, net income attributable to shareholders of the parent company totalled RUB 46,170 million, which is 11.7% less than in 2012. The reduction in net income was related to impairment of the Group’s financial investments in OJSC Belkamneft. On September 30, 2013, JSOC Bashneft sold its stake in the share capital of OJSC Belkamneft (38.46%) to a group of private investors for RUB 6,469 million.

In the fourth quarter of 2013, the Group’s revenue from sales declined by 6.6% quarter-on-quarter to RUB 146,242 million. In the fourth quarter of 2013, adjusted EBITDA amounted to RUB 26,991 million, which is 17.8% lower than in the third quarter of 2013. In the fourth quarter of 2013, net income attributable to shareholders of the parent company totalled RUB 13,628 million, which is 84.5% higher than in the third quarter of 2013; this was related to a low base effect due to the impairment mentioned above.

In 2013, the Group’s operating cash flow increased by 16.2% year-on-year to RUB 82,693 million. This enabled the Group to reduce its total debt in the form of short-term and long-term borrowings by 17.6% to RUB 90,816 million as of December 31, 2013. In 2013, Bashneft’s capital expenditure amounted to RUB 30,441 million, which is slightly (1.1%) less than the previous year.

In 2013, Bashneft achieved the strongest production growth in the Russian oil industry, increasing its average daily oil production by 4.4% year-on-year to 321.5 kbpd. In the fourth quarter of 2013, the Company’s average daily oil production reached its highest level since 1995, and totalled 331.1 kbpd. In 2013, oil production at Bashneft’s fields totalled 16,073 thousand tonnes (117,333 thousand barrels), which is 4.1% more than in 2012.

More than half (54%) of the increase in oil production in 2013 in traditional oil-producing regions was related to highly efficient geological and engineering operations and the use of state-of-the-art technology. Another factor that contributed greatly to Bashneft’s production growth in 2013 consisted in commissioning of the Trebs and Titov fields in the Nenets Autonomous District.

Bashneft’s refining complex in Ufa processed 21,399 thousand tonnes (156,213 thousand barrels) of oil, which is 3% more than in 2012. In 2013, refining depth at Bashneft’s refineries averaged 84.7%, which is comparable to the level reached in 2012. During the same period, the share of light products increased to 60.4% from 59.7% a year earlier.

Revised data show that the average Nelson Index increased from 8.55 to 8.83 after sulphuric acid alkylation and sulphuric acid regeneration units were put into operation at the Bashneft-Novoil branch. Upgrades to a hydrocracker and a delayed coker at the Bashneft-Ufaneftekhim enanbled increased capacity and also played a role in improving Nelson Index for the Company.

Sales of petroleum products and petrochemicals added 2.9% and reached 19,816 thousand tonnes in 2013. As part of its strategy for developing its marketing channels in order to supply products to consumers, Bashneft continued to increase its share in the retail and small wholesale segment. Thus, in 2013 the Company boosted its retail sales of petroleum products by 2.8% to 1,402 thousand tonnes, while revenue from retail sales rose by 11.5%.

Wednesday, April 2nd, 2014

Rosneft’s Yurubcheno-Tokhomskoye Oilfield in Eastern Siberia Delayed to 2017

Rosneft plans to start production at its Yurubcheno-Tokhomskoye oilfield in eastern Siberia in 2017, the company said on Tuesday, another delay for a field key to Russia’s efforts to at least keep oil production at current levels.

Rosneft, Russia’s biggest oil company and the world’s largest listed producer by output, said Yurubcheno-Tokhomskoye will reach a production plateau of up to 5 million tonnes a year (100,000 barrels per day) in 2019.

In 2012, Rosneft CEO Igor Sechin told investors in London that the field was due to start production in 2016, with the same plateau mentioned on Tuesday.

Previous management at Rosneft, where Sechin took over in 2012, had planned to start production in 2013 with the plateau of up to 10 million tonnes a year.

Rosneft did not explain the change in launch time or adjusted production figures on Tuesday but said that in the future, the field could produce up to 7.3 million tonnes a year (150,000 bpd). It gave no gave no time frame.

The field is to supply Asian markets via the East Siberia-Pacific Ocean pipeline and feed the yet-to-be-built VNHK petrochemical plant in Russia’s Far East, it said.

Rosneft is preparing to more than double oil exports to China to over 1 million bpd, seeking to secure market share and billions of dollars in pre-payments.

However, Russian pipeline monopoly Transneft and some analysts question whether Rosneft has the oil in the ground to honour its supply commitments. Rosneft has said it will honour all obligations.

Russia is now pumping over 10 million bpd, still the world’s highest, but the bulk of production comes from western Siberian deposits which are depleting. (Reporting by Katya Golubkova; Editing by Steve Gutterman and William Hardy)

Wednesday, April 2nd, 2014

Rosneft Acquires Orenburg Drilling Company

Rosneft completed acquisition of 100% share in Orenburg Drilling Company from VTB-Leasing Group.

Acquisition of Orenburg Drilling Company is the key aspect of the program aimed at the re-equipment of Rosneft’s fleet of drilling units and implementation of the policy of the group for internal service share increase. Acquisition of Orenburg Drilling Company will provide most important regions of the Company’s activities with drilling operations subject to maximum pricing efficiency.

“The Orenburg Drilling Company fleet of drilling units is one of the most modern in terms of technology and average age of the drilling units. As a result of the transaction, Rosneft’s internal service share will increase enough to considerably improve efficiency of drilling projects implementation at the Company’s greenfields and brownfields, in particular by means of cost control at each stage of wells construction. Rosneft plans not only to concentrate on domestic drilling needs, but to carry on rendering services to third-party customers, contributing to oil production efficiency improvement,” First Vice President of Rosneft Eric Liron commented on the transaction.


Wednesday, April 2nd, 2014

Roxi Petroleum: BNG and Galaz Progressing Well

Roxi, the Central Asian oil and gas company with a focus on Kazakhstan, is pleased to update the market with operational progress at its BNG and Galaz assets.


The BNG Contract Area is located in the west of Kazakhstan 40 kilometres southeast of Tengiz on the edge of the Mangistau Oblast, covering an area of 1,561 square kilometres of which 1,376 square kilometres has 3D seismic coverage acquired in 2009 and 2010. Roxi resumed full operational control of BNG Ltd LLP in 2011.

Deep well

Drilling at Roxi first deep well A5 has reached a depth of 3,892 meters.

The Total Depth of the well is 4,750 meters. From 3,600 meters drilling has been through alternative layers of clay and salt. The salt layer proper commenced around the 3,800 meter level and continues for some 250 meters. Below the salt layer we expect to find a gas cap and beyond that we will enter our target source rock.

Provided it is not affected by water we would expect to drill through to the bottom of the salt layer in the next two weeks and to reach total depth by the end of April when following the installation of casing testing would commence.

Shallow wells

We continue to enjoy success with our shallow wells at BNG. Wells 805, 54 and 807 are producing at an aggregate rate of 450 bopd (262 bopd net to Roxi). Well 806 has been completed and is moving directly to long term testing at three separate intervals in the next few days.

At Well 143 testing has commenced after five levels were perforated. Should Well 143 test positively Roxi believes the area from which oil can be produced from these horizons would be materially extended.


The Galaz block is located in the Kyzylorda Oblast in central Kazakhstan. The Contract Area was extended on 10 January 2011 to 179 square kilometres and now includes significant exploration upside on the east side of the Karatau fault system, as well as the NW Konys development.

Existing production

Wells NK-3, NK-5, NK-7 and NK-8 continue to produce at the rate of 1,080 bopd (371 net to Roxi)  Work continues to bring Well NK-12 back into production. NK-14 has reached its total depth of 1,501 meters without incident and has been perforated at three separate intervals. The lower and middle levels have tested for water. The result of testing on the upper interval is expected to be known in the next week or so.  Well NK24 has been spudded and has reached its total depth of 1,600 meters without incident. The well is targeting targeting Jurassic and Cretaceous reservoirs and the plan is to test two intervals before the end of April.

Clive Carver, Chairman commented  ”We continue to be pleased with the results from our shallow wells at both BNG and Galaz. The wait for news of the outcome of the deep drilling at BNG will not now be long and we hope the results will provide a major boost for the Company.”

Wednesday, April 2nd, 2014

Max Petroleum: Final Sagiz West Well Strikes 24m of Pay

Max Petroleum Plc, an oil and gas company focused on Kazakhstan, is pleased to announce successful drilling results of the final well in the current appraisal drilling programme in the Sagiz West Field.

The SAGW-7 appraisal well has reached a depth of 1,438 metres with electric logs indicating 24 metres of net pay in four Triassic reservoirs over a 117 metre gross interval at vertical depths between 1,172 and 1,289 metres, including 19 metres of net oil pay in three upper reservoirs and five metres of net gas pay in one lower reservoir. Reservoir quality is excellent with porosities ranging from 15% to 27%. The Company is setting production casing in the well and will begin testing SAGW-7 as soon as practicable.

The Zhanros ZJ-30 rig will next move to drill the KZIE-5 well, an appraisal well in the East Kyzylzhar I Field designed to evaluate several Jurassic reservoirs based on the Company’s detailed technical analysis of additional 3D seismic data acquired over the field in in 2013.

Wednesday, April 2nd, 2014

Max Petroleum: Kenneth Hopkins Appointed Chief Operating Officer

Max Petroleum Plc, an oil and gas company focused on Kazakhstan, announces further details of previously announced cost cutting initiatives along with related management changes.

Appointment of New Chief Operating Officer

The Company is pleased to announce the appointment of Kenneth Hopkins as the Company’s Chief Operating Officer. Mr. Hopkins will continue to serve as General Director of the Company’s operations in Kazakhstan, a position he has held since May 2013. Richard Hook, Mr. Hopkins predecessor as Chief Operating Officer, will become a consultant to the Company.

Mr. Hopkins is a 21 year resident of Kazakhstan and has held numerous senior management and executive positions with various companies during his largely international oil and gas career, including for Oryx Energy (Chief Geologist for Kazakhstan operations and technical and operating committee member on the East Timor Sea Bayu-Undan gas condensate project), for Orient Petroleum Ltd. Kazakhstan in partnership with PetroKazakhstan (Senior Vice President), for Aral Petroleum Capital LLP (Exploration Director) and for International Petroleum Limited (Kazakhstan Country Manager). Mr. Hopkins holds a Bachelor of Science degree in Marine Sciences and a Master of Science degree in Geology from Texas A&M University and is a certified petroleum geologist with 32 years of experience in the oil and gas industry.

Other Senior Management Changes

As part of the process of streamlining of the finance function across the Company, Ms. Gulmira Suleimen has been promoted to Finance Director of Samek International LLP (“Samek”), the Company’s operating subsidiary in Kazakhstan, replacing Andrew Large in that capacity, and Kevin Clark, the Company’s financial controller, has replaced Geoff Stone as the Company’s Chief Accounting Officer and has assumed the role of Company Secretary.  Ms. Suleimen previously served as Samek’s Chief Accountant, a position she has held since October 2007, and Mr. Clark has served as the Company’s financial controller since May 2009.

Other initiatives

The Company also plans to close its Houston office during 2014 and is implementing further cost savings initiatives in both London and in Kazakhstan.

Robert Holland and James Jeffs, Co-Chairmen of the Company, commented:

Kenny is an experienced and effective leader and has done an outstanding job for Max Petroleum, especially in the areas of operating efficiencies and cost savings. His promotion reflects the transition of the Company’s focus to appraisal and production. We are grateful for Richard’s many contributions and that he has agreed to continue to fulfil an important role assisting us with our remaining exploration, appraisal and other activities. We also want to thank Andrew Large and Geoff Stone for their past contributions to the Company over the years and wish them well in their future endeavours.” 

Tuesday, April 1st, 2014

Closure Interview: Yuri Parnivoda, General Director Russia, Drillmec

Yuri Parnivoda,  General Director Russia, Drillmec

Please describe your position and role within the company

As General Director, I manage the company in accordance with the internal company documents & charter, and of course within the current legislation of the government of the Russian Federation. I oversee all financial and professional activity of the company, with my main focus being business development and brand awareness for equipment and aftermarket sales in Russia and the CIS

Drillmec is seen as a leader in supply of advanced rigs and drilling technology – but how is business for you in Russia? How do you see it developing over the coming years?

Drillmec is an international leader in the design, manufacture and distribution of drilling and workover rigs for onshore and offshore applications as well as a wide range of drilling equipment. The results achieved in over ten of years of international experience have been recognized by customers worldwide and stem from our commitment to continuous improvement through the pursuit of high quality, a strong focus on human resources and emphatic efficiency throughout the whole process. We are expecting the Russian drilling industry to increase rapidly in the coming years, and in turn we are increasing our presence in the market. As an example of this, the quantity of Drillmec top drives being used in Russia has tripled over the last 3 years.

With Drillmec not only competing with Russian rig manufacturers, but also with Chinese, European and North American companies – why should Drillmec be considered by drilling contractors when buying new rigs?

Whether looking at on or offshore drilling, we at Drillmec are the experts that help our customers continually raise their performance through our proven technical expertise, global aftermarket network and trusted quality. Our engineers apply years of experience to deliver the best solutions based on material selection, service application and functioning criteria.

Our service offering includes design, manufacturing, commissioning and aftersales service for conventional and hydraulic land rigs, mobile and workover drilling rigs, offshore units and drilling equipment.

Since its establishment, Drillmec has applied itself to putting forward innovative proposals that add real value to projects by reducing the cost of drilling operations in oil & gas fields. We can also provide our customers with complete rig certification in accordance with API and DNV specifications. Our knowledge of drilling operations is our biggest asset and works to our clients’ advantage. We are proud of the reputation we have built in combining the expertise of an oil company, drilling contractor and manufacturer in order to tailor a fit-for-purpose drilling rig

Drillmec have recently supplied rigs to be used offshore Caspian. What technologies do you have for offshore drilling?

Drillmec provides a complete range of offshore drilling equipment packages to the drilling industry, using innovative engineering, high quality standards and a knowledgeable staff base, to ensure we cover all of our client’s needs. Drillmec manufactures derricks and masts for all applications, and, in addition, packages can be furnished with top drives, motion compensators, racking system, pipe handlers, catwalk machines, elevators, top mounted flares and all derrick related equipment for complete packages.

In addition to complete drilling packages, Drillmec offers a comprehensive line of offshore equipment for platforms, barges, semi-submersibles and drill ships that can handle a wide range of E&P and production requirements. From the drill floor to the top drive, Drillmec supplies mud systems, control rooms, derricks, pipe handling systems, catwalk machines, power tongs, and rotary tables with all the power you need. Drawworks packages up to 4,500 hp, mud pumps up to 2,200 hp and fully automated hydraulic rigs up to 600 metric tons (1,320,000 lbs) pulling capacity are available. Also offered are skidding systems, and bulk storage and transportation systems.

We are hearing a lot about the upcoming development of the regions unconventional fields. What rig solutions do you have suitable for drilling these fields?

The best choice for accurate directional drilling is our HH automated hydraulic rigs. The unusual characteristics of the HH Rig design make their shape far different from that of a conventional rig. The “HH” Rigs were designed to achieve high levels of safety and outstanding performance. They integrate various hydraulic equipment in a drilling process that is largely automated and has all drilling functions centrally controlled from a comfortable and air conditioned driller’s cabin.

The most evident characteristic of the HH Rigs is the self-erecting hydraulic telescopic mast, made of one powerful hydraulic cylinder. The mast has an integrated hydraulic top drive built in. It is a self-standing telescopic mast with reduced height, suitable to handle range 3 “supersingles” drill pipes.

The drilling parameters are controlled by the driller from a control panel in the doghouse; this allows automatic drilling even with a preset wob and rpm. Predetermined limits of over-pull can also be set. Such features coupled with the back reaming allowed by the top drive, considerably reduce the risk of stuck pipes.

The overall dimensions of the “HH” Rigs are much smaller than the conventional rigs of corresponding power. All the major rig modules are permanently mounted on semi-trailers and are self-erecting for fast and safe moving between locations. Much less loads than those of a comparable conventional rig are needed for moving.

On an “HH” Rig, with a smaller crew and most part of the routine activities made by automatic or remotely controlled equipment and an unmanned rig floor, the possibility of casualties is reduced. The very small number of recorded accidents, even if of very limited importance, clearly shows that the activity on the “HH” Rigs is always done at the highest possible level of safety for the entire crew.

Gazprom drilling rig

The automated systems, the central control and the reduced number of people, allow for an easier and more effective handling of the rig, with very beneficial effects on the overall performance and costs.

The emphasis on safety of the unique design of the “HH” Rigs, is achieved mostly by an extensive automation of a large number of their components. It can be enhanced further to reach full automation and to cancel almost entirely the manual work on the rig floor. It appears the right way to finally reach “zero accident” in the land drilling industry.

Tell us a recent success story, about a drilling contractor using a Drillmec rig.

Particularly in Russia, our equipment is used by the following key clients -
1.    Rosneft uses Drillmec MR8000 and hydraulic top drive HTD 250.
2.    Gazprom affiliates started using HH -150 FA and HH-200 FA, eliminating the presence of workers on drill flow. Besides this, HH rig has no monkey board. This is the first fact in our Client’s history, that improves safety on the field with H2S factor;
3.    Lukoil – Offshore drilling equipment package Drillmec 2000HP for LSP-1 project of the V. Filanovskiy oilfield;
4.    Weatherford Drilling had established the record in drilling operations in Russia using Drillmec MR8000 drilling rigs and HTD 250 and HTD 200 hydraulic top drives. Many Drillmec HTD 200 top drives have also been adopted in Russia and are being used on drilling rigs manufactured in China for Weatherford drilling
5.    UsinskGeoNeft – Hydraulic top drives HTD 350;
6.    Integra Drilling uses Drillmec MR7000 mobile drilling rigs and HTD 250 hydraulic top drives.

Finally, what is your forecast for the regions drilling sector in the coming years?

We have invested a lot to ensure that our technologies are adapted to the current requirements of our customers in Russia. We hope that this will continue to satisfy the requirements of drilling companies in Russia.

Tuesday, April 1st, 2014

Costs are Holding our Industry Back… Again!

Screen Shot 2014-04-01 at 14.19.35

David Bamford, Petromall

This oil & gas industry of ours goes through cycles, tied by elastic to the price of oil and gas. On the back of the decade long rise in oil prices and the corresponding boom in exploration and production activity, costs have escalated – exponentiated some would say – and as a consequence investors can now see that many oil and gas companies are delivering poor returns.

Escalating costs are compounding the other problems experienced by exploration and production companies – disappointing exploration results, delays and cost over-runs in development projects, missed production targets.

Thus we are now entering yet again that phase of the cycle in which companies ‘go to town’ on costs: if this period is anything like previous episodes, we will see both manpower reductions, project cancellations and consolidation.

The UKCS and NOCS as an Example
In the UKCS and NOCS, escalating costs are already leading to delayed or cancelled projects due to poor economics, both for new developments and in-field projects. A further consequence is that decommissioning, and the associated costs, looms larger on the radar screen, leading to even more rapidly declining infrastructure.

Evidence for this can be assembled simply by collecting some news clippings from the last 3 or 4 months:
»     Kristin Gas Export (NOCS; Statoil)
– Project terminated………“unsustainable project economics”
»     Rosebank (WoS, UKCS; Chevron)
– Doubts…..“does not currently offer an economic value proposition that justifies proceeding with an investment of this magnitude”
»     Bressay (NNS, UKCS; Statoil)
– “re-evaluating”….“delay”….“alternative development         options”
»     Recent NPD commentary on NOCS:
– Johan Castberg (Barents Sea; Statoil); Linnorn (Norwegian Sea; Shell); Tresakk (North Sea; Shell)….all delayed…”gas prices, costs, lack of infrastructure”
– “pretty much all of the projects in the Barents Sea are in danger”

The simple cartoon on the next page is an attempt to generalise the value evolution of a basin:
The key points are:
1.    The big simple fields are discovered and developed first, value rises rapidly, cost/boe stay low.
2.    Progressively fields get smaller, deeper, more complex, contain more difficult fluids, costs/boe rise.
3.    Eventually value is being destroyed.

It is exactly this logic that persuades big companies to leave a Maturing region and seek new Frontiers.

Without an urgent response, first the UKCS and later the NOCS are at risk of living out this cartoon.

To dig further into this, I have begun to assemble a small data base of NW Europe projects and some West African examples to compare them with.

The table below illustrates some of the data:

David Bamford table 1

Fields in Red are under threat or delayed; those in Orange are going ahead but not yet producing; those in Black are producing.

I have found it necessary to get away from published economics as these are based on all sorts of typically beneficial assumptions meaning that parameters such as NPV and RoR cannot be compared. What can be compared and what I show for each project are the reported cost in $bn, the reserves these dollars are being spent on, and the target or ‘nameplate’ production level.

David Bamford pic 1

David Bamford Pic 2

It’s a little difficult to make sense of these numbers in tabular form but I find this simple crossplot quite helpful:

The horizontal axis relates to the reserves – S per boe.
The vertical axis relates to production – $ per produced barrel per day.

What quickly becomes apparent is that Frontier, larger, projects plot in the Green area; smaller, more complex, perhaps heavy oil, projects in the UKCS and NOCS plot in the Red or just in Orange.

Interestingly, a big North Sea project – Clair Ridge with over 600 million barrels under the control of a single Operating Group and with the diligent application of technology – plots pretty well on the cross in the middle of the plot.

Also interestingly, note that if the actual spend for the Angola PSVM project is used instead of the projected spend, this moves from the comfort of the middle of the Green zone to being pretty well on the cross in the middle of the plot too!

What Conclusion Do I Draw?
I suggest that the UKCS and NOCS have a serious problem with escalating costs.

However, I believe that these areas can continue to compete with Frontier areas but two things are needed, namely Consolidation and Technology:
»     Consolidation
– To assemble reserves, whether in new or old discoveries, or in producing fields, into bigger agglomerations under a single ‘regional’ operating entity so as to enable the ”hub and spoke concept”.
»     Technology
– To dramatically reduce the number of wells needed to develop a field or part of a field.
– To monitor hydrocarbon production and detect where there are untapped reserves.

I believe the situation is urgent, requiring a rapid response from governments and industry.

Tuesday, April 1st, 2014

VNIIGAZ Offshore Hazards: Assessing the Impact of Icebergs on Offshore Production Platforms

Screen Shot 2014-04-01 at 14.05.25

Dmitry A. Onishchenko (Gazprom VNIIGAZ LLC)

Resolving the challenge of developing Russia’s offshore oil and gas resources, those on Arctic shelf being first and foremost, requires much scientific research, both theoretical and practical. One of the main challenges is attempting to calculate the ice loads that can hit offshore platforms which is still critical for developing most fields in Russia’s Arctic shelf. The correct estimation of the ice loads that are likely to be encountered is key – overestimation of the loads will result in higher capital expenditure, while underestimation will increase the risk of damage or even destruction during operation. As with other loads caused by natural factors, ice loads can vary enormously, and this is why calculating ice load values must be done within the probabilistic framework. One of the current challenges facing the industry is the construction of offshore platforms for a number of promising fields based in a number of Russia’s northern seas, including the Barents and Kara Seas.

Using current data, the study proposes a physical and mathematical model which allows various iceberg hazard indicators to be analyzed. These include the probability of an iceberg/platform collision during a given timeframe, the probability distribution of the iceberg’s kinetic energy on collision, etc.

Requirements are established for the initial data required for corresponding calculations. The paper discusses the results obtained and the possibility of their use in practical design work.

1 Factors behind the probabilistic nature of an ice load
The ice load on offshore platforms arise when the platform is affected by moving ice cover, generally of spatially inhomogeneous nature and consisting of various types of ice formations (e.g. level ice, rafted ice, ridged ice, icebergs etc)  – the full list can be found in World meteorological organization’s sea ice nomenclature [1]). Ice breaks as it advances and comes in contact with the platform and, in turn, creates pressure on the platform’s hull. Therefore, the ice load on an offshore platform is governed by two separate destruction processes – local ones that take place during ice/platform contact, and the global processes which complement the destruction of the ice cover or its individual elements forming part of that cover on the whole (generally expressed as ice cracking). We should note that in almost all cases, an iceberg-to-platform collision will result in the local destruction of ice.

The total ice load on the entire platform (it is often referred to as global load) is a function of time which can, generally, vary significantly. Because of this variation, it is important to examine ice loads as random processes. There are a large number of parameters to take into account, including those that determine the ice regime  in the area near the platform, while others do “manage” the interaction of ice cover with the platform.

Listed below are some of the parameters which determine the nature of an ice load. These parameters in particular determine the variability of the ice cover:
»     large number of ice formations (first year and multi-year level ice, ridges, icebergs etc);
»     thickness, morphometric composition, spatial boundaries of ice formations;
»     ice drifting at various velocities;
»     velocity and temperature during the contact with the structure;
»     frequency of certain ice formations shapes;

These parameters in particular determine the destruction of the ice cover:
»     local ice strength;
»     large number of destruction patterns (shearing, crushing, bending, stability loss, cracking, piling-up and etc.);
»     few interaction scenarios (impact, pile-up, freeze-up and etc.).

The above parameters are random values, based either on observations or mathematical modeling. For many of the listed parameters, however, the observation ranges are short, and may contain errors (as compared against “true” distributions which are apparently, unknown). Moreover, due to the internal heterogeneous properties of ice, its load, even for the same formation (e.g. level ice) with spatially invariable “external” parameters is of course random.

2 “Probabilistic” and “deterministic” design method
The random nature of ice loads is nothing new – it is normal for all loads caused by natural factors such as wind, wave, snow etc. Engineers have long mastered random loads: so called representative and design load values are used for design purposes along with representative and design values of the strength of structural material and soil. Design criteria for limit state methods are generally expressed as

Qd ≤ Rd,                (1)

where Qd is a design value of the force factor such as force, bending moment, stress in a given element of the structure under design (or “action effect” using the new terminology [2], which is calculated for a given combination of applied loads;

Rd is a design value of bearing capacity for an element, usually calculated through strength properties of the soil or a material. (We should note that in regulatory documentation equations such as (1) are usually seen in modified form with additional multipliers. This doesn’t affect subsequent analysis in any meaningful manner, thus for the purpose of simplicity we shall use this imprecise equation (1) for the design criteria.

In turn, design values are determined based on representative values Q0,R0:

Qd = γf Q0,  Rd = R0/γm,         (2)

where γf and γm are so called partial safety factors (for load and for material, correspondingly).

We should note that all listed values are deterministic, thus for conventional design work, the random factor is effectively excluded: it only appears in the determination of representative (or, directly design) strength and load values. From now on, we only discuss action effects and corresponding loads. The representative value of ice load on the structure (which is random as we have stated) is generally accepted at a value with predetermined recurrence period T. Recurrence period values vary for different load types. Thus, present day regulatory norms [3], recommend T = 100 years for principal load combinations and T ~ 103…104 years for extraordinary combinations.

Thus, according to its definition, the representative load value expressed as qα, is determined as a value that can be exceeded during a given (arbitrary chosen) year with a probability of α=1⁄T, which can be expressed in the following equation:

Pr{Q>qα at least once a year}=α,        (3)

where Pr{A} stands for the probability of a random event A. Value α is called accumulated probability or occurrence; it is often expressed as a percentage value. We should note that α = 0,01, or 1 %, for recurrence period T = 100 years. Sometimes condition (3) is better expressed as

Pr{Qmax>qα }=α,                (4)

where Qmax is annual maximum of ice load.

Considering that ice load may occur under the influence of various ice formations (level ice, rafted ice, ridges, icebergs etc), thus equations (3) and (4) are normally written separately for different types of ice formations. That is why a few representative ice load values are used in design work corresponding to various design situations – action from level ice, rifted ice, ridges, icebergs etc.

Now let’s introduce cumulative distribution function for Qmax value and denote it as FQ (x), so the equation (4) can be turned into:

FQ (qα )=1-α.                (5)

On the front, equation (5) seems very simple. A closer look, however, reveals that finding function FQ (x) is not at all a trivial task: it depends (and often in a very complicated way) on distribution functions of all values influencing the load as well as on geometrical properties of the structure under design. To illustrate the associated challenges we should mention that a different approach than equation (4) is used to determine representative load values for other natural load types such as wave loads or current loads, specifically:

Q0=Q(ω1,ω2, …),                (6)

where ω1,ω2, … is a set of design parameters values for a design situation, and Q(x1,x2, …) is the so called load formula. In cases of wave load for example, the set of parameters includes wave height of certain occurrence along with associated period and average wave length value. In cases of current, governing parameter is the current velocity of certain occurrence. It could also be noted that Russian codes up until recent times used a similar approach for estimating events of level ice impacts; governing parameters for this are representative ice thickness (at 1% occurrence) and the design ice strength. Note that Q(x1,x2, …) are regular deterministic functions explicitly stated in corresponding structural codes.

Thus, design value for ice load in case with level ice, uses the following equation

Q0=mkb kV Rc Dhd,            (7)

where hd is the design ice thickness at the platform location, Rc is the design compression resistance (strength) for ice, D – width of the structure affected by ice, kb, kV and m are some constants that only depend on structure geometry and hd.

It is crucially important that representative value Q0 has no (at least no explicitly stated) occurrence value assigned (this is why we use distinctly different symbols for related values of Q0 and qα), while occurrence requirements are applied to the parameters of “impacting” natural objects: wave height, current velocity, level ice thickness etc. This approach makes it possible to make a clear distinction between the stage of design preparation when design parameters of “impacting” natural objects are defined (this is traditionally done by specialized engineering research organizations) and the design stage of a project itself, when the engineer’s task is to ensure the accuracy of inequalities such as (1) with consideration of (2) and (7) by proper selection of suitable structural design and materials.

When we look at a “probabilistic approach to design work”, illustrated by equation (4), this effectively creates a catch twenty two situation: the design (development of construction solutions) can’t be performed until probability distributions FQ(x) are known for all estimated events, while these distributions can’t be calculated until structural design is available. Moreover, this challenge requires the surveyors to build probability distribution functions for all variables and factors affecting the loads (a large but incomplete number of which are listed above), whereas the conventional approach only envisages the determination of corresponding representative values at the survey stage. The former requires a significantly larger volume of observational data. This raises the following question – in this catch 22 situation, who is responsible for the adequacy of required probability distributions which must be known even to their tail values, including those for α reaching
10-3…10-4, and even up to 10-5?

The RF Government is active in updating its regulatory construction framework, including that for the design of offshore oil and gas facilities. With that, new or updated regulatory documents enforce the probabilistic approach for design criteria as in equation (4) (see e.g. [4]). Unfortunately, the authors of these documents fail to consider that the probabilistic design approach requires a) enormous volumes of initial data (unobtainable through conventional engineering research; especially considering that regulatory norms for design engineering surveys do not include any such new “probabilistic” requirements) and b) subsequent laborious work on constructing probabilistic load distribution functions FQ (x). This makes it hard to expect actual adherence to the requirements of probabilistic criteria such as (4) in design of offshore platforms. There is the hazard that even if these are performed practically, it would only be formal: using some surrogate distributions FQ (x), the reliability of which is next to impossible to substantiate. This, in turn, may negatively impact the reliability of the designed facility.

3 Requirements for iceberg impact design load
The assertions above are not to say that probabilistic methods have no place in design work: they are only to state the necessity a clear understanding of which issues can better be resolved by applying probability theory for developing specific design solutions.

One such issue is the assessment of iceberg hazards for platforms located in offshore areas where icebergs drifts are probable. For the purposes of design, iceberg to platform collision should be considered as a special load. Below we list the examples of constructing a probabilistic model which enables us to form “a hazard” and the estimation of corresponding quantitative indicators. Some studies on this matter use the term “risk”. Formally, it includes assessment of unfavorable consequences along with determination of probability for unfavorable events. Because this paper does not describe the consequences of a possible iceberg collision, we shall not use the term “risk”.

Some iceberg hazard parameters are:
»     probability of iceberg to platform collision during a one year period;
»     probability of collision during one a year period for an iceberg with dimensions and mass exceeding an established value;
»     probability of collision during a one year period for an iceberg with kinetic energy value above the established;
»     probability of collision for an iceberg approaching the platform from distance L;
»     probability of collision during one year period with global load on the platform below the established value and etc.

We should note that the probability of an iceberg collision (to be more precise, the assessment of probability calculated based on available statistical data using one or another probability model) can’t by itself be considered as a comprehensive data set required to complete a platform design. Actually, if only small icebergs or their bergy bits reach the offshore field, then the corresponding design situation apparently won’t be crucial for the design, while should there exist a probability of an even rare occurrence of large iceberg collisions, it has to be taken into account. Thus, one of possible formalization options envisages the requirement of calculating such parameters is the probability for the platform with known shape and size to be impacted by an iceberg  with kinetic energy above an established value for a given time period [5].

The general design criteria require the platform to maintaining its bearing capacity under the influence of certain design loads. Let us examine this issue in relation to the load on a possible iceberg to platform collision. The first thing to mention is that an estimated iceberg collision is rare [6]. This means that the actual structure built to serve for a period of 25-50 years (in most cases) will almost never experience an iceberg collision. Still, the collision probability does not equal zero. To this extent, one known “onshore” analogue is the seismic load.

“Probabilistic” design corresponds to the latter of the listed iceberg hazard factors. The resulting load for an iceberg to platform collision will significantly depend on the local shape of the iceberg surface coming into contact with the
platform hull.

Resolving the task of calculating estimated load qalpha from an iceberg collision (at α~10-4…10-5 ) includes a number of interrelated factors. The necessary input data can provisionally be divided in 3 large units.

Unit I1: statistical data on iceberg observations, their shapes and sizes near the platform location. With that, due to the rare occurrence of such events, statistically solid data would require very long observation data sets; it is apparent that a standard 5-year survey cycle by itself won’t provide the required volumes of information, and therefore archive data analysis is required. For example, corresponding databases were created in Canada for the Grand Banks of Newfoundland and in Russia for the Barents Sea ([7,8]).

Unit I2: The physical and mechanical model of an iceberg to platform collision, which includes ice destruction patterns near the impact area and describes an iceberg’s dynamic behavior during the collision. A number of such models was developed (see e.g. [9-11]). However, a few problems remain somewhat unresolved. In particular, there are challenges related to modeling the dependency of the collision area based on the penetration depth of the collision, which largely determines the intensity of the impact to the platform (an example of resolving such task can be found in [12]), along with consideration of hydrodynamic effects occurring when two massive bodies (iceberg and platform) come close to each other.

Unit I3: iceberg drift model (e.g. rectilinear or chaotic) near the platform location. Main “moving” factors are near-surface currents, winds and, possibly, ice cover. Because the iceberg trajectory observations data are insufficient to obtain reliable statistical conclusions on spatial and time parameters of iceberg trajectories, developing adequate and efficient “atmosphere-ice-ocean” models would assist in finding a solution for this task.

In general cases, the equation required to find design value qalpha with consideration of (6) can be expanded to

Pr{maxQ (ω(i))>qα }=α,            (8)

where ω(i) = (ω1(i), ω2(i) ) is the aggregate of all random parameters influencing the ice load (for an iceberg, that would be its velocity at collision, its mass and inertia moments ice strength and surface shape at the zone of contact and etc. – these parameters appear in units I1 and I2); i = 1,…, N are all iceberg interactions on a platform during one year period (usually N being the number of collisions is random and the case of N = 0 is not excluded; pertaining to unit I3), and

Q = Q(ω)                 (9)

is the iceberg load formula used to calculate maximum load for a specific single collision event with prescribed values of random parameters ω (unit I2).

Various approaches can be used to model iceberg hazards [3, 5,12-16]. Most of these use the Monte Carlo statistical method. Below is a modification of an approach developed by the pioneering works of Canadian specialists [5,6], which make it possible to obtain estimated correlations in any analytical form. Another example of implementing a modified approach for a population of ice flows affecting the platform can be found in article [17].

End of Part 1

List of literature
1.    WMO sea ice nomenclature. WMO/OMM/ВМО – No. 259. Amendment No. 5 (2004). [Digital resource] URL: (as displayed on 15.11.2013)
2.    GOST R 54257-2010 Reliability of structures and foundations in construction. Principal provisions and requirements.
3.    ISO 19906:2010 Petroleum and natural gas industries – Arctic offshore structures
4.    SP 38.13330.2012 Loads and impacts on hydrotechnical facilities (from waves, ice and vessels) (updated version of SNiP 2.06.04-82*).
5.    Dunwoody A.B. The design ice island for impact against an offshore structure. Proc. 15th Offshore Technology Conference, Houston, USA, 1983, p. 325–332.
6.    S471-04 General requirements, design criteria, the environment, and loads. CSA, 2004.
7.    Verbit S., Comfort G., Timco G. Development of a database for iceberg sightings off Canada’s east coast. Proc. 18th Int. Symposium on Ice, IAHR’06, Sapporo, Japan, 2006. Vol. 2, pp. 89–96.
8.    Naumov A.K., Zubakin G.K., Gudoshnikov Yu.P., Buzin I.V., Skutin A.A. Ice and icebergs near Shtokman gas condensate field. Works for international conference “Developing Russian sea shelves” (RAO-03), St. Petersburg, Sept. 16–19, 2003, pp. 337–342.
9.    Vershinin S.A., Nagrelli V.E., Yermakov S.V., Onishchenko D.A. Impact interaction of iceberg and ice-resistant offshore platform for the Shtockmanovskoye field. Proc. First Int. Conf. on Development of the Russian Arctic Offshore, St.Petersburg, Russia, 1993, pp. 192–196.
10. Matskevitch D.G. Eccentric impact of an ice feature: linearized model. Cold Region Science and Technology, Vol. 25 (1997), pp. 159–171.
11. Matskevitch D.G. Eccentric impact of an ice feature: non-linear model. Cold Region Science and Technology, Vol. 26 (1997), pp. 55–66.
12. Fuglem M., Muggeridge K., Jordaan I. Design load calculations for iceberg impacts. Int. J. Offshore and Polar Engineering, Vol. 9. No. 4 (1999), pp. 298–306.
13. Nevel D. Ice force probability issues. Proc. IAHR Ice Symposium, Banff, Canada, 1992, pp. 1497–1506.
14. Korsnes R., Moe G. Approaches to find iceberg collision risks for fixed offshore platforms. Int. J. Offshore and Polar Engineering, Vol. 4. No. 1 (1994), pp. 48–52.
15. Fuglem M., Jordaan I., Crocker G. Iceberg-structure interaction probabilities for design. Can. J. Civ. Eng., Vol. 23 (1996), pp. 231–241.
16. Naumov A.K. Distribution of icebergs near Shtokman gas condensate field and assessment of iceberg to platform collisions. Lib.: Complex research for ice and hydrometeorological events and processes near the Arctic shelf. Works of AARI, v. 449, St. Petersburg, 2004, pp. 140–152.
17. Onishchenko D.A. Probabilistic modeling as a tool to determine estimated ice loads in arctic shelf environment. Science and technology for the gas industry, №1 (2006), pp. 62–80.

Tuesday, April 1st, 2014

Tight Oil Developments in Russia

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James Henderson : The Oxford Institute for Energy Studies
Part 1

Production of unconventional oil has transformed the US energy landscape, creating the potential for that country to reduce its reliance on oil imports and to contribute to the possibility of North America’s becoming energy independent by the end of this decade. As Fattouh and Sen point out, however, in their recent OIES Comment, despite the forecasts of many commentators that this would cause a revolution in oil supply and prices, the impact on the global energy market has in fact been somewhat less dramatic than expected. This working paper aims to take a similarly realistic view of the potential for tight oil production in Russia, something which has been highlighted by the recent study of global shale oil and gas resources undertaken by the EIA, which named Russia as the possessor of the world’s largest shale oil reserves.

The main focus of attention has been on the Bazhenov shale which lies beneath Russia’s main producing reservoirs in West Siberia and is indeed the source rock for many of the giant fields that have been at the core of the country’s oil output, which is now running at approximately 10.5 mmbpd. Rosneft, LUKOIL, Gazprom Neft and others have highlighted the potential for the Bazhenov and Russia’s other tight oil reservoirs to help achieve the government’s objective of maintaining overall production at current levels in the face of the natural decline in many of the country’s older fields. Joint ventures with ExxonMobil, Statoil and Shell have started to introduce international expertise and technology, and the future output from Russia’s tight oil reservoirs has been estimated by the Ministry of Natural Resources at up to 1 mmbpd by 2025.

The exploitation of this underdeveloped resource, however, is at a very early stage and a number of issues have already emerged. The geology of many of the reservoirs seems very heterogeneous, with markedly different well results being produced only kilometres apart. Well costs are high and, in common with most shale reservoirs, decline rates are rapid, meaning that costs need to be recovered early in the production cycle if an economic return is to be made. The current tax system in Russia, however, does not anticipate this type of well performance, being focussed on revenues rather than profits, and tax rates are also very high. Although reductions on specific taxes have now been introduced, they may not be enough to encourage wide-scale investment. Furthermore, it is not just oil company investment that is required but also significant expenditure by oil service companies on new rigs and fracking equipment, a lack of which could easily delay the achievement of production targets.

As a result, this paper aims to address these and other issues in order to assess the potential progress in the development of Russia’s tight oil reserves. Section 1 provides some initial context of the potential importance of unconventional oil in Russia as a means of alleviating the declining production of existing West Siberian assets and as a bridge towards the longer term development of areas such as the Arctic offshore. Section 2 then outlines a definition of what is described in Russia as ‘hard-to-recover’ oil, differentiating between shale reservoirs such as the Bazhenov and other tight oil reservoirs such as the Achimov and Tyumen formations which are often found in the deeper layers of existing fields. Section 3 then reviews corporate activity in the sector to date, highlighting in particular the new joint ventures formed by Rosneft, the development work carried out by Gazprom Neft and Shell in the Salym area and the new focus of LUKOIL on its deeper and tighter oil assets.

Section 4 then moves on to a discussion of the commercialisation of Russia’s tight oil resources, and in particular highlights the tax concessions that have already been granted for ‘hard-to-recover’ oil, while also discussing further changes that may be needed to catalyse full scale development in projects with a very different cash-flow profile to traditional Russian oil fields. Section 5 addresses another key issue for the industry, namely the availability of rigs of high enough quality and power to drill the numerous horizontal wells that will be needed if 1 mmbpd of production is to be achieved. It concludes that not only will it be difficult to build enough new rigs, but also that the oil service industry may well be reticent to invest heavily until it more fully understands what the future of the unconventional oil industry in Russia may be. Section 6 then reviews a number of other issues that could hinder development of tight oil in Russia such as a corporate landscape dominated by a few large players, the Law of Strategic Reserves, the Licensing Laws and Environmental and Water issues. Section 7 then offers some conclusions which suggest that, although the potential for a significant increase in unconventional oil production in Russia certainly exists, the achievement of the aggressive Ministry of Natural Resources target is likely to take longer than anticipated.

1. Unconventional Oil in the Context of Russia’s Energy Strategy
The Russian government’s Energy Strategy to 2030 indicates that it is keen to maintain the country’s oil production at or above the level of 10.4 mmbpd seen in 2012, and the outlook for 2013–2015 remains quite positive as new fields are set to be brought onstream and existing developments arrive at peak output. A number of domestic and international commentators are now, however, forecasting that Russian oil production could be close to its peak, with the inevitable decline of Soviet era fields prompting an overall fall in output by 2020. Figure 1 and Table 1 show two Russian government targets, contained in the Energy Strategy to 2030 and the Geology Development Strategy, both of which see a gradual rise in output towards 10.7 mmbpd by 2030, but the more independent forecasts also shown suggest that these targets may be rather optimistic. The most radical low case scenario, produced for the Government Energy Commission in 2011, shows a collapse in oil output to below 5 mmbpd by 2030 if the current tax and regulatory conditions in the Russian oil sector are not changed. Even the less pessimistic forecasts, which anticipate some government reaction in terms of tax breaks and other encouragement of investment, see production falling to a range of 7–9 mmbpd. Only one forecast, that from the US Energy Information Administration, sees production exceeding the Russian government targets.

Oxford Institute Fig 1
Oxford Institute Table 1

The debate about the exact extent of any possible decline has largely focused on whether the Russian government will provide sufficient tax incentives to encourage the development of fields in new regions of Russia such as East Siberia and the Offshore, with a particular recent focus on the Arctic following the announcement of Rosneft’s joint ventures with ExxonMobil, Statoil and ENI. It has become increasingly clear, however, that the likely start date for any production from this region will not be until well into the next decade, given that the first exploration well is not due to be drilled until 2014 and the subsequent appraisal and development of any discovery would be likely to take at least a decade. Indeed some Russian oil industry players remain sceptical about the economics of any major developments in the Far North. In 2013 LUKOIL’s Leonid Fedun was quoted as stating that ‘if someone asked me to invest money in Arctic exploration and development, I wouldn’t give a kopeck. We have many more investment opportunities that carry less risk.’

One of the specific investment opportunities to which Mr Fedun is referring, and into which his company is currently investing significant funds, is the exploitation of Russia’s unconventional oil resources. Although the development of what is often referred to in Russia as ‘hard-to-recover’ oil is not a new topic, with the discovery of shale oil in Russia dating back as far as 1967, it has become much more interesting following the improvements in the technology for the extraction of shale oil and gas developed in the US over the past decade. Indeed the other main focus of Rosneft’s JVs with both ExxonMobil and Statoil is the application of new technology on the company’s tight oil reserves in West Siberia and European Russia, and a number of recent estimates suggest that the resource base to be exploited across Russia is enormous, although uncertain. The level of this uncertainty is captured in the wide spread of high and low estimates: total tight oil reserves in Russia have been put in the range of 15 billion to 1.05 trillion barrels. Even individual companies have very broad assessments of their own resources, with Rosneft quoting numbers in the range 6–18 billion barrels and TNK-BP offering forecasts of between 4 and 19 billion barrels. Given that Russia’s total proved reserves are estimated at 87 billion barrels it is clear that even numbers at the lower end of the range would be significant additions to the country’s oil reserve base. This potential was further confirmed by a recent assessment of global shale resources by the US Energy Information Administration which calculated that Russia has the world’s largest shale oil resources with a total of 75 billion technically recoverable barrels.

2. Defining Unconventional Oil in Russia
Before progressing from these resource numbers to potential production estimates it is important to emphasize that the definitions of unconventional reserves in Russia are somewhat blurred in a multitude of terms used to describe the hydrocarbons being explored by various companies. The broadest definition is ‘hard-to-recover’ oil, and this is often used by companies looking for a catch-all to describe reserves that need tax breaks from the government to encourage investment. ‘Hard-to-recover’ reserves include shale resources, such as those found in the often-cited Bazhenov geological layer, but also include bitumen, a very viscous crude that is extracted from shallower reservoirs using mining or steam heating techniques, as well as oil that comes from conventional reservoirs that happen to have low permeability and/or porosity. Indeed this breadth of definitions is one reason why the Russian government has been relatively slow to introduce tax breaks for the oil industry, for fear that companies would use ‘creative reserve auditing’ to bring as much of their production as possible into the ‘hard-to-recover’ category.

Narrowing the definition to more traditional unconventional shale and shale-like reserves, the US EIA tight oil resource estimate for Russia specifically includes only the Bazhenov layer. This layer is highly significant as it is believed to cover the entire 2.6 million km2 area of the West Siberian basin and to act as the source rock for 85 per cent of the conventional oil fields located there. The Bazhenov is located at a depth of 2,700–3,100 metres in the Upper Jurassic rock strata (see Figure 2), and has a permeability of less than one millidarcy with a porosity of between 2 and 6 per cent and a reservoir thickness of 20–30 metres, making it comparable to the Eagle Ford and Bakken shale formations in the USA. As with many tight reservoirs the oil tends to be light (34–43 degrees API, with an average of 38 degrees compared to the Urals blend figure of 32–33 degrees) and has a relatively low sulphur content of 0.6%. As a result it can flow quite freely once the tight sandstone reservoirs have been accessed through horizontal wells and broken open using multi-stage fracking techniques.

Oxford Institiue Fig 2

The Bazhenov, however, is not the only new tight oil play in Russia, as similar types of resources are also found in two other layers, the Achimov and the Tyumen, that have not been included in the US EIA analysis because of a lack of available data. Nevertheless, they are very much part of the tight oil development work that a number of companies in Russia are currently undertaking and are certainly included in any definition of ‘hard-to-recover’ oil. The Achimov layer is generally located just above the Bazhenov at a depth of 2,500–3,200 metres (see Figure 2), with the oil trapped in tight sandstones confined by shale. The reservoirs tend to be of average porosity but low permeability, but nevertheless have a tendency to have better flow rates and lifetime production than the Bazhenov layer. A number of gas condensate fields have already been developed from this rock layer, including by the Gazprom/Wintershall JV Achimgaz, and the shallower depth of the reservoirs means that they tend to be cheaper and easier to operate than their deeper counterparts. In contrast the Tyumen layer, which covers the same geographic area as the Bazhenov but at a lower depth of 2,800 to 3,200 metres, tends to contain narrower reservoirs with mixed permeability, making it a more difficult target for drilling and generally more expensive to develop. Nevertheless, a number of companies, including LUKOIL and TNK-BP, have been exploring the potential of this reservoir below existing conventional fields and see it as another potential boost to overall production capacity.

The geographical extent of these three tight oil reservoirs and the large resource estimates associated with just one of them (the Bazhenov) have encouraged the Russian government and oil industry to believe that the development of unconventional oil in Russia could be the short-to-medium term solution to the risk of a potential production decline. Indeed a number of corporate and ministry production forecasts have been made that suggest the possibility of significant output being achieved by the end of this decade. Rosneft has tentatively estimated that it could be producing 300,000 bpd of unconventional oil by 2020, while TNK-BP has more cautiously forecast output of 50,000 bpd on the same timescale and Gazprom Neft has suggested that it could produce a similar amount. More optimistic overall forecasts have emanated from the Russian Energy Ministry and the Ministry of Natural Resources, and as shown in Figure 3 the latter suggests that total tight oil production in Russia might exceed 1 million bpd by 2025 and reach 1.7 million bpd by 2030. The uncertainty surrounding the development of this new resource, however, is underlined by the fact that the Energy Ministry forecast, although positive, is much lower at only 440,000 bpd by 2020 before declining to 400,000 bpd by 2025.

Oxford Institute Fig 3

This uncertainty reflects difficulties in a number of areas, including licensing, levels of taxation, definition of strategic resources, environmental legislation, availability of sufficient oil service equipment and a lack of variety in the companies developing the resources, but at the most basic level the issue of geology remains the primary concern at present. On the positive side, it is asserted by a group of scientists led by Ivan Nesterov at the Russian Academy of Sciences that the high oil saturation across the key Bazhenov shale layer means that oil can be produced commercially at any point across its geography. Other specialists such as Valeriy Soloviev, Chief Expert of Gazprom Neft’s Research and Technical Center (NTC), are also positive and believe that ‘taking into account the potential resources of the Bazhenov formation, it is a great candidate for further exploration and development’.

An alternative view is presented by scientists such as Vladimir Teploukhov, Head of the Logging Data Interpretation Department at NTC, who stresses that ‘the Bazhenov formation stores too many surprises, and the surprises are still there despite decades of research. The main challenge for geologists and development engineers is how to accurately pinpoint recoverable reserves and the areas of their concentration. The volume of effective oil-saturated pore space of the Bazhenov formation has not been identified with the desired precision. Data on permeability and porosity of the Bazhenov rocks are insufficient. In addition, the characteristics may vary enormously in different locations. Sometimes even neighbouring wells produce completely different data. For as long as these issues remain unanswered, the development of the reserves continues to be too risky’.

It is clear, then, that despite the huge resource potential of the Bazhenov and associated tight oil strata in Russia, the geology is yet to be fully understood, and it is this fact that has heightened calls for increased government support for companies which are preparing to investigate the possibilities for commercial production. Before discussing what levels of government support may be needed, as well as what other issues may need to be resolved, it is worth first reviewing the major corporate activity to date in order to assess how companies currently view unconventional oil prospects in Russia.

In the next excerpt, we will focus on the major companies involved in unconventional oil and gas production in Russia.

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