There is no alternative to the alternative

Interview with Alexei Vashkevich, head of the Gazprom Neft Directorate of Geological Exploration and Resource Base Development
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Alexei Vashkevich

With a significant amount of tight reserves on its books, Gazprom Neft has become one of the first Russian companies to begin shale oil projects in Russia.

Russia has immense reserves of hydrocarbons concentrated in the Bazhenov suite, but the profitable development of those resources requires investment, technologies, and support from the state. Alexei Vashkevich, head of the Gazprom Neft Directorate of Geological Exploration and Resource Base Development, told Yekaterina Maikova about the company’s new projects for the development of tight and unconventional reserves and about challenges it faces.

— Alexei Aleksandrovich, please tell us about the company’s strategy for the exploration and development of tight and unconventional hydrocarbon reserves.

— Gazprom Neft’s recently updated 2025 development strategy is designed to keep production on the level of 100 million tons of oil equivalent and to maintain sufficient reserves to support such production levels during the next twenty years. This will require an increase of our resource base, which currently consists of 2 billion tons of oil equivalent of category 2P reserves, by an additional 1.2-1.7 billion tons of oil equivalent. Those additional reserves are to be obtained at least in part by bringing tight and unconventional reserves into development. The company plans to bring into development approximately 60 million tons of additional category 2P reserves by 2015, and then to raise that figure to 300 million tons by 2020.

— What exactly do you consider to be tight reserves?

— We often ask ourselves how we are to classify tight reserves. As a result, we divided those resources into two key clusters. The first includes reserves that are literally difficult to extract from the subsoil. That means those reserves that are located in formations that are well understood as regards geology and development technologies. Such reserves are classical in terms of deposit formation, but they are tight reserves because of their reservoir properties, the thicknesses of their pay zones, and the gas content in the upper part of the deposit. The main tight reserves we are looking at are partly the Achimov and the Tyumen suite, they amount to over 500 million tons of recoverable reserves, or approximately 40 percent of the company’s category ABC1 resource base. We define the second cluster as consisting of the so-called unconventional reserves that we identify based on the history of oil genesis. These reserves essentially consist of oil source rock, including the Bazhenov-Abalak suite as well as deposits whose geological structure we are just beginning to understand, for example, Paleozoic deposits. There are estimates of the unconventional reserves resource potential that differ from one another by a factor of several times. The estimate that one commonly hears is 100 billion tons of oil equivalent across Russia. Furthermore, a significant part of those reserves, approximately 20-30 billion tons of oil equivalent, is concentrated in Khanty-Mansi Autonomous Okrug-Yugra. According to our estimates, a quantity of those reserves in Khanty-Mansi Autonomous Okrug-Yugra amounting to about 8-10 billion tons of oil equivalent has yet to be divided into license areas, while the rest of the region’s unconventional resources are located in areas being developed by various companies.

— How does the company approach technologies for developing tight reserves and unconventional reserves? How similar are the approaches?

— It is impossible to bring tight reserves into development effectively without thorough research efforts. Therefore, working jointly with Gazpromneft Research Center, we created a project office on the basis of our subsidiary Gazpromneft-Khantos which is tasked to study international experience in developing tight reserves, test it in Russian conditions, run pilot projects, and analyze the results. The work is going full speed ahead. We understand tight reserves geologically, and that’s why our main challenge is to develop technologies, use special modeling tools, and work together with leading oilfield services companies.

The range of approaches we apply includes horizontal drilling with multistage hydraulic fracturing and the use of polymer waterflooding and surfactants for the purpose of producing from previously undeveloped zones. Last year, we drilled 68 horizontal wells in tight reserves areas, nineteen of which were hydrofracked using multiple fracking technique (two to six stages).

In 2013, we are planning to drill 120 wells, 70 of which will involve multistage hydrofracking. We will also increase the number of stages.

— The plans look impressive, but the number of hydrofracking stages and the length of a horizontal well section are hardly a panacea. . .

— Yes, of course, these things are not ends in themselves. And although we are already able to do eight hydrofracking operations in a single horizontal well section, it’s driven primarily by economics. Our experience has shown that three or four hydrofracking stages are frequently enough for effective development. Western companies know how to conduct up to forty hydrofracking stages. They apply that technology, for example, at the Bakken shale formation in America, but on the average they perform only about twenty stages. There are detailed engineering formulas that make it possible to estimate the economics of a given number of hydrofracking stages. There is a similar situation with the length of the horizontal section. In some wells, it’s 500 meters long; it’s 700 meters in others; and it’s 3000 meters in the Bakken formation.

— What other technologies are you using for tight reserves?

— At the same time as we’re developing multistage hydraulic fracturing, we’re also developing our competence in drilling multiple-borehole horizontal wells. The rationale behind this is cost-cutting.

We now already have experience in drilling four-borehole horizontal wells. The company drilled a total of five wells in 2012 with a multiple borehole structure, and this year we intend to drill eighteen such wells with an average of three or four boreholes each. It is very important for us at present to raise production while ensuring that it is economically feasible to use such technologies and obtain high initial flow rates.

What makes tight and unconventional reserves so peculiar, is that they are long life reserves. While a traditional field’s life is 20 to 30 years on the average, the life of a tight reserves field may exceed 50 years.

— Is the company getting foreign contractors involved in such operations?

— As for the actual drilling of the wells, Russian contractors are no less qualified for that than foreign ones, and on certain issues they are better. Besides, Russian contractors are cheaper. At the same time, foreign oilfield services companies, despite their higher costs, still continue to outperform Russian players when it comes to conducting downhole operations.

— As part of its tight reserves program, Gazprom Neft is continuing geological exploration of the Chona group fields in Eastern Siberia. You are cooperating with the Japanese company JOGMEC in the geological study of the Ignyalinsky area, one of the three areas of the Chona group. What are the results of the work?

— We are content with the way our partnership is developing. This project is going very smoothly. JOGMEC is a worthy partner both for its functional discipline and for its technical expertise. We have completely finished seismic surveys of the Ignyalinsky area, including 3D coverage of over 350-square-kilometers. We have spudded two wells, and will drill two more next year. We and JOGMEC are supposed to make the decision to proceed to the second phase of the project before the end of 2014.

In other areas of the Chona project, including the Vakunaika and Tympuchikan areas where we are operating independently, we are also continuing geological exploration, and are testing previously plugged and abandoned wells.

In the Vakunaika and Tympuchikan areas, we have conducted high-resolution seismic surveys over a 350-square-kilometer territory using the innovative and unique UniQ method. This was the first time that technology was used in Russia. We have now begun processing the data obtained with the assistance of Schlumberger specialists. At the same time, we are preparing for the next field season. Our company must go through approximately 1200 square kilometers of seismic surveying here, and we are considering different ways of optimizing our work, including the reduction of the survey duration from three to two years. It will take additional investment to develop tight and unconventional reserves.

— How do you assess the taxation climate interms of developing that kind of reserves?

— It is practically impossible to develop tight and unconventional reserves using old methods. Furthermore, while an ordinary well costs about 50-60 million rubles, a well for developing tight reserves costs 100-120 million rubles. That’s how much it costs to drill a horizontal well with four or five hydrofracking stages. On top of that, operating and maintaining such wells will also be more expensive.

All of this has to be taken into consideration in drafting a system of tax exemptions for tight reserves developers. We have a good understanding of how much it will cost to efficiently recover tight reserve deposits that we believe are worth developing. And we are currently trying to explain that in order to bring into production 50-100 million tons of oil equivalent of additional reserves, we need certain tax incentives that make it economically feasible to develop those deposits. The main tool is the exemptions from the mineral extraction tax with account for a field’s properties of permeability, degree of depletion, and viscosity.

We are currently awaiting the passage of a law prepared by the Ministry of Finance pursuant to Russian government decree number 700-r which is necessary to set the conditions for the economically efficient development of tight oil reserves. The draft law provides for differentiated mineral extraction tax rates depending on reservoir permeability, the field’s degree of depletion, and the size of the oil-bearing stratum. Furthermore, that decree will assign the unconventional oil reserves of the Bazhenov, Abalak, and Domanikov productive deposits to a separate category. Let’s talk about the second reserve cluster.

— In your opinion, is it accurate to refer to the Bazhenov suite with such a popular term as “shale oil”?

— The term “shale oil” has a clear definition. People frequently confuse “shale oil” with “oil shale.” Practically all of the oil in Western Siberia was created within a single stratum. That is, all the liquid hydrocarbons that we are extracting from various horizons, including the oil of the Bazhenov-Abalak complex, came into being within a single geological suite. Subsequently, by means of structural and nonstructural damage, the hydrocarbons migrated into more highly-situated layers. Essentially, this is what the main definition is about: the oil that remains in the source rock from which we are trying to extract it is what you call shale oil.

When oil is found in other horizons with similar reservoir properties (i.e. low permeability) and content (e.g. argillites and argillaceous shale), you call it oil shale. These are the same kind of classic deposits, but with reduced reservoir properties. For example, the Achimov suite consists of that type of resources.

— How do the petrophysical properties of American shale oil fields, which predominantly consist of argillaceous shale, compare with the Bazhenov suite, which is mostly carbonate?

— The petrophysical and granulometric properties of the clays or so-called shales vary from deposit to deposit. Even among the American shale oil formations, for example the Bakken and Eagle Ford shales, the content is completely different. That’s why, when we say “Bazhenov,” you have to understand that it’s just one of the kinds of shale.

— In that case, which American formation is closest to the Bazhenov suite?

— That’s a very tough question. The content of shale is defined by a combination of 10-15 parameters. Therefore, even minor differences of 1-2 percent in one parameter lead to changes in the proportions of the next parameter, the next one after that, etc., and ultimately the composition of the shale turns out to be completely different. Thus, each formation is unique, and that fact is reflected in the technological approaches to developing the formations, and in particular in the planning of hydrofracking operations.

— What are the peculiarities of developing shale fields?

— The keys to developing unconventional reserves are the structure of the regional model, competent estimation of oil location, choosing the proper spot for drilling the well, and identifying the optimal technologies. Geomechanical and thermal modeling play a very important role. Natural microfissures form and widen within rock as a result of thermobaric processes, and those fissures are the conductors of hydrocarbons. Thermal modeling makes it possible to predict where such generation zones can be found. In other words, we can find a good deposit with a high hydrocarbon content, but since the processes by which kerogen is synthesized into light hydrocarbons and the processes by which fissures and radiolarite interlayers form and expand have yet to occur, it would be physically impossible to extract those hydrocarbons. That’s why it’s so important to find the proper drilling point.

Gazprom Neft has been able to successfully meet that challenge by drilling the first directionally-drilled exploration well on the Bazhenov-Abalak horizon of the Palianovskaya area in Krasnoleninskoye field in Khanty-Mansi Autonomous Okrug-Yugra and obtaining a flow of a gas-oil mixture without hydrofracking. The flow rate of that well today is 80 tons of oil per day. And we understand that if we drill a second well, say, one kilometer away from the first one, then we will get a completely different picture. When you’re developing shale complexes, scale is extremely significant and is measured not in the tens of kilometers, but frequently in the hundreds of meters. That is why detailed geological modeling that includes high-density 3D seismic surveying and the use of innovative methods of interpretation makes it possible to see clearly the geological structure of deposits.

By combining those data with geochemical, thermal, and sedimentation models, it is possible to estimate the location of the points that we see as our targets.

— Please tell us about the ongoing unconventional reserves projects run by Gazprom Neft.

— Besides the one well in Palianovskaya area that I mentioned above, we are now developing a strategy for the further development of that field. We are planning to drill fourteen wells by 2015, including five horizontal wells with multistage hydraulic fracturing. Yet another project for the study of the shale oil production potential is underway as part of a joint venture with Shell called SalymPetroleum Development (SPD). One of the targets is preparing of the Bazhenov reserves at Verkhnesalymskoye oilfield in Khanty-Mansi Autonomous Okrug-Yugra for commercial development.

As for unconventional reserves, I must mention the Paleozoic reserves that we are currently working on. At present, we are conducting pilot work on the Paleozoic deposits at Archinskoye field in Tomsk Oblast. The program involves drilling three wells in 2013 and seven oils in 2014 and 2015. At this stage, the main task for us is to confirm our geological model of the deposits and determine the most efficient development methods.

— What are the nearest-term plans for development of the Bazhenov suite?

— We never looked at the Bazhenov suite as a target site for licensing before. The reserves that Gazprom Neft has in Khanty-Mansi Autonomous Okrug-Yugra came to the company a s a legacy along with traditional fields. And now in keeping with Gazprom Neft’s new focus on partnering with Shell, we are planning to apply for licenses for the geological study in Khanty-Mansi Autonomous Okrug-Yugra this year. And we’re planning to bring the initial Bazhenov suite sites into development in 2015-2016. We believe that the shale oil resource base in Khanty-Mansi Autonomous Okrug-Yugra, which has yet to be divided into license areas, may comprise 8-10 billion tons, of which there are approximately 300 million tons of recoverable reserves that are target reserves for us. Our analysis says that the joint venture may eventually reach a peak production level of 5 million tons of shale oil per year. The advantages of working in Khanty-Mansi Autonomous Okrug-Yugra are obvious. It’s a region with a developed infrastructure, and our knowledge and understanding of its geology are pretty good. All of this will have a positive effect on project efficiency. And if the state will incentivize the development of unconventional reserves through certain tax exemptions, then it will be only three or four years until the first projects will launch.

— According to the American experience, peak production is reached very quickly at shale oilfields, after which flow rates fall sharply. Are you afraid that something similar may happen at your production sites?

— That performance pattern can be explained by physical processes that take place at such fields, and this factor needs to be taken into consideration. That is why, for example, the economy of a well at Bakken is arranged so that it will pay for itself during the first 2-3 years of operation, because flow rates will then begin to fall. At the same time, the duration of development of such fields is significantly greater than at traditional fields.

— Let’s talk about global issues. What do you think the development of unconventional oil reserves in Russia will look like in the near future?

— Speaking of the prospects for development of the Russian raw mineral materials complex during the next two decades, we can predict that approximately 45-50 percent of the oil will be produced at the fields that were already commissioned. There have been predictions that approximately another 30 percent will be produced on the Arctic Sea shelf, but that goal appears rather ambitious for the time being. So, in my view, there are no serious alternatives to developing unconventional reserves.

Since over 90 percent of the traditional reserves have already been divided into license areas, most of the increment in the country’s mineral resources today occurs due to the additional exploration of fields that have already been discovered, production drilling, and the re-estimation of reserves. Any oil company is concerned with the issues of replenishing its resource base. Therefore, one way or another, we eventually come to the conclusion that without bringing unconventional reserves into production, it will be difficult to maintain and build up production.

— In your opinion, how promising is the direction of developing gas hydrates?

— If we can learn how to develop gas hydrates efficiently and profitably, then we can simply set aside everything else. The total liquid hydrocarbon resource base in the entire world is estimated at around 2-3 trillion tons of oil equivalent. At the same time, the gas hydrate potential, according to various estimates, is approximately 15 trillion tons of oil equivalent. That means practically unlimited possibilities. But so far, nobody has gained any serious experience in developing gas hydrates. There have only been sporadic pilot projects. This all has a simple explanation: as long as cheaper methods for extracting hydrocarbons exist, nobody will begin producing gas hydrates.

— What are Gazprom Neft’s plans to tale part in tight and unconventional reserves projects abroad?

— We are currently studying the market situation within and outside Russia’s borders. Most importantly, participating in such projects will allow us to acquire new competencies that we would be able to quickly study, master, and adapt to our own projects in Russia.

— Speaking about such tight reserves projects as the development of the Arctic shelf, where Gazprom Neft is a project operator, what are the prospects for those projects?

— At present, the company is running two projects on the Arctic Sea shelf: Prirazlomnoye and Dolginskoye fields. We are conducting geological exploration at Dolginskoye field, where Gazprom Neft is the project operator. We plan to drill one exploration well there this year. We will drill another well there in 2014. Based on the information we obtain, we will be able to make the decision to transition the field into the development stage. We need to estimate investment volumes and the building of required infrastructure. At present, we have contracted a drilling platform and support ships, and we very recently chose a contractor for integrated services management. We have already obtained an approval from the environmental expert review board for the operations, and we expect to receive a permit for well drilling. We plan to begin drilling operations in summer 2013. We have selected three trial sites. Water depth at the field is 30-50 meters, and well depth is 3200 meters. How long it will take us to complete the work depends on ice conditions, but usually this area of the Pechora Sea freezes up in October. Our objective is not only to drill a well, but to test it too. That will enable us to obtain the maximum quantity of geological information.