Since the beginning of the year, the fee for flaring associated gas has gone up sharply. On November 8, the Russian Government passed a resolution approving the method of calculating pollution fees for those who flare associated gas. This will establish a coefficient of 12 to be used in the formula for calculating payments in 2013. That coefficient will rise to 25 in 2014. At present, a coefficient of 4.5 is used. The maximum acceptable level of associated gas flaring remains, as previously, 5 percent of the total volume of associated gas produced.
Furthermore, according to the new document, the integrated index for flaring of associated gas is calculated using either an aggregation method for subsoil users belonging to a larger group or using a differentiation method for an individual subsoil user for all of the subsoil sites over which that user has usage rights.
According to Anton GLADCHENKO, head of Gazprom Neft’s Gas and Power Engineering Directorate, the new rules, for which oil companies had waited for two years, will change the utilization practices by making them more predictable. This also applies to the development of new fields, with its grace period for associated gas utilization.
— Anton Viktorovich, what do you think about the new utilization rules?
— On the one hand, the new procedure does increase penalties by several times. On the other hand, the government is motivating subsoil users to invest in projects to make the utilization of associated gas more efficient, by subtracting the project expenses from emissions fees.
Furthermore, the new document allows us to keep track of the gas utilization across the company, and gives a grace period for new fields, or “green fields”, where the requirements to utilize 95 percent of the associated gas produced will not apply during the initial stage. Oil companies had been waiting for the new regulatory document for two years.
However, in my opinion, it will take a couple of years of using the new tools before companies and regulators can say how good they are.
Starting next year, penalties will rise sharply, that’s why it’s important to make sure the new regulatory mechanisms work properly. We are concerned because the transitional period didn’t go too well in 2012, when the 2009 procedure was still in effect. The procedure was flawed from the very beginning. For example, there were various ways in which penalties could be calculated, various ways to apply penalty factors for emissions in excess of the established limits, etc.
Each company ended up counting things in its own way. Each had its own vision and its own reading. As a result, everyone in the end got completely different numbers.
— According to Alexander Dyukov, Gazprom Neft will pay a total of 800 million rubles in penalties for wasting associated gas in 2012, as compared to 30 million rubles paid in penalties the previous year. How will the situation change next year?
— Over the last three years, the associated gas utilization rate at our company has been growing by an average of 5 percent per year. But in 2013 we expect this indicator to grow by as much as 15 percent from the 2012 level.
This is due to the fact that we are completing basic facilities at two key sites, Yuzhno-Priobsky Project and Phase 1 of the Noyabrsk Integrated Project. This will bring the Gazprom Neft’s annual associated gas utilization rate to about 80 percent.
At the Yuzhno-Priobskaya license area, where we are currently producing 12 million tons of oil per year, we have built a gas gathering system, and are currently completing construction of an export line jointly with SIBUR. A gas pipeline to the Yuganskneftegaz network is already in place, and a compressor station will be commissioned in 2013.
We are also implementing jointly with SIBUR Phase 1 of the Noyabrsk Integrated Project, which includes five fields in the Vyngapur group. We are not doing this as a joint venture, but under a long-term contract for gas supply and processing. We will finish our part of the work by the end of 2012. We have already revamped and built 111 kilometers of pipelines, and are finishing construction of four vacuum compressor stations required to ship low-pressure gas.
At the same time, SIBUR has increased the Vyngapur Gas Processing Plant capacity, which enabled us to increase utilization by 1 billion cubic meters of gas per year. We can increase those numbers even further in the future.
Besides, we are building an additional gas module as part of Phase 1 of the Noyabrsk Integrated Project . An ambitious drilling program is currently under way at the Yety-Purovskoye field. And we are designing a compressor station for that program so that in the future the field will not end up getting locked down and so that the gas gathering and export system can handle the volumes that we plan to produce there. The investment project has already been approved, and we are selecting the main equipment.
We are also running a number of associated gas utilization projects in Tomsk Oblast, where we have several small assets. In December 2011 we commissioned a new gas pipeline for transmitting gas from Shinginskoye field to Luginetskaya compressor station.
In total, our company’s associated gas utilization program can be valued at $1 billion. And it only covers the ongoing or planned projects in the developing fields, not counting green fields. Half of this amount has already been allocated, and another
— How is your company addressing the associated gas utilization problem at small and remote fields?
— We have several problematic assets for which a decision is yet to be made. The situation is that investing in the gas utilization at those fields makes these projects unfeasible.
A telling example is Urmanskoye field in Tomsk Oblast, where all the associated gas is flared. It’s a field with dropping production located hundreds of kilometers from infrastructure and markets for the products of gas processing, and there’s not enough associated gas to justify, in any way, investing in the construction of a gas gathering and transmission system or a gas injection system.
This also relates to Phase 2 of the Noyabrsk Integrated Project. There are several small fields located
But investing in the utilization of associated gas will practically kill the expedience of developing those reserves. We would have to build up to 200 kilometers of gas pipeline and an expensive compressor station. That is, depending on the scenario, we would have to invest
It makes more sense for the company to stop producing oil than to utilize associated gas. But stopping production is a drastic measure, because we as yet have made no investment decision on those fields. It will be made after we get the results of the geological exploration program planned for that group for the next few years.
I think that a new government resolution will allow us to wait for the geological exploration results, since it allows for levels of associated gas flaring to be counted for the company as a whole rather than for individual fields.
— How do you plan to use associated gas at the new fields, Messoyakha and Novoport? What economic and technological scenarios for the efficient utilization of associated gas have been made for those projects?
— First of all, the remoteness of these fields from gas infrastructure and markets explains the need for a gas module. Secondly, it’s connected with particular aspects of the gas component. Those fields have large gas reserves, both of them are likely to have gas breakthroughs during oil production, and those breakthroughs are likely to be significantly large. We are working out two options in parallel. The base option is to inject the gas into the reservoir, and the alternative option is to export the gas elsewhere.
The latter option is more complicated, because gas will not only have to be produced, conditioned, and shipped. It also will have to be sold. That is, we’ll need long-term supply contracts for the gas. By the end of 2013 the gas module concept will be determined, and accordingly gas injection facilities should be commissioned by the time those fields enter the commercial development stage.
The company’s position is that gas utilization facilities should be commissioned at the same time as the facilities for commercial development of new fields. I emphasize the word “commercial” here because we’ll be running pilot projects at the Messoyakha group and Novoport field during the next few years.
— Associated gas utilization projects come with an impressive price tag and a long payback period. How efficient are such projects at your fields? Is there any way of cutting the costs?
— Associated petroleum gas is a complicated product that does not keep well. That has a serious effect on the CAPEX of gas infrastructure facilities, and likewise on the commercial side of such projects.
As I said, that not only are gas utilization projects incapable of justifying their own costs for the problematic assets in the Noyabrsk region; they can kill the entire project.
In my view, we need a high-quality economic expert review to be conducted before the field development plan is signed. And if it shows that the best associated gas utilization option leads to an overall negative economic result, then the government will have to decide either to allow a gas utilization rate lower than 95 percent for that field or accept that it doesn’t make economic sense to develop the field under current conditions and postpone its development and thereby naturally lose the economic advantage for the industry and for the state.
Projects like Phase 1 of the Noyabrsk Integrated Project, which is economically attractive both for Gazprom Neft and for SIBUR, are a different story. The two companies have come to an agreement, concluded a long-term contract, made all of the investments in a timely manner, practically simultaneous commissioned their facilities, and as a result, gas has gone into processing at a rate of approximately 1 billion cubic meters per year.
It’s also possible to reduce the CAPEX by joining with other subsoil users. When we study the gas utilization options, we always try to understand whether we could get a synergistic effect through building a common gathering, transmission, compression and processing system together with other companies.
For example, we have several crossovers with TNK-BP both within the zone of our current assets and in the zone of major new projects such as Messoyakha, and we are looking at sharing gas utilization projects with them. There is also a potential and a need to talk with Rosneft.
However, I would not exaggerate the scale and possibilities for cooperation with other companies for associated gas projects. Distances as little as
— Are you looking at any gas power generation projects?
— In 2010 and 2011 we brought on-stream two lines of a gas turbine power plant with a total capacity of 96 megawatts in the southern part of Priobskoye field. That plant fully meets the power demand of such a gigantic field. There is also a number of small gas engine power plants scattered across our remote fields in Tomsk Oblast, the Noyabrsk region, and Khanty-Mansi Autonomous Okrug.
Many companies, including TNK-BP, LUKOIL, and Surgutneftegas, have a quite broad portfolio of projects for their own power generation which on the average covers
The thing is that in 2011 the so-called cost curve for the building of our own power generation capacity turned out to be lower than the cost curve for using external power. Many companies, including oil companies and metallurgical companies, were seriously worried by that and forced through electric power generation projects. However, the situation has changed somewhat since then. That’s why, before we undertake any major gas power generation projects, we are trying first to answer the question: what makes better sense in the long term, building some generation capacity of our own or buying electricity from the external grid.
But where there is an electric power shortage or no alternatives for the use of associated gas, we are actively building our own power stations. Each major project such as Novoport, Messoyakha, Kuyumba, and the Chona project will definitely have its own standalone gas turbine power plant.
— Gazprom Neft began producing gas just last year. Why did you get involved in this business, and do you plan to develop it further?
— Within the Gazprom Group of companies, our specialty is the development of liquid hydrocarbons. But a number of our fields, including Novoport, are oil and gas condensate fields. And we cannot develop the reserves of the oil fringe there in an economically efficient way without gas breakthroughs. Therefore, whether we want it or not, the company is building up its gas production too, bearing in mind the peculiar features of the reserves.
At present, we have two gas fields within Muravlenko and Novogodneye fields in the Noyabrsk region. The oil economics of those assets is rather weak. The fields are in the late stage of development. But there are gas reserves there, too, and we have found a simple and economically efficient solution: producing gas and delivering it to the nearby infrastructure of Gazprom Dobycha Noyabrsk. In doing this we use practically the same equipment and personnel that we use for oil production.
The project is interesting both for Gazprom, which gets to fill up its underutilized facilities and obtains gas for its system, and for us, since we can economically extend the life of those fields.
In the future we will also have to be involved in gas development, since most of the reserves and resources of the new Gazprom Neft projects are at oil and gas condensate fields. That’s why we will continue looking at potential development of both oil and gas reservoirs simultaneously, which will let us achieve economic synergy.