This spring Salym Petroleum Development (SPD), a joint venture between Gazprom Neft and Shell, launched an ASP mixing plant on the West Salym field in Yugra. This is the key facility of Russia’s first, and so far only, pilot enhanced oil recovery project based on chemical flooding by injection of the three-component mixture made of alkali, surfactant, and polymer. This method, on the one hand, makes it possible to produce up to 30% of oil remaining in the formation after conventional waterflood; on the other hand, incentives are required for it.
In case everything is successful, the company can start full-scale application of the new technology after 2023, and additionally produce with its help up to 3 million tons of oil a year on the Salym group of oilfields. Meanwhile, proliferation of this method to other oilfields in the KHMAO, as estimated by experts, promises the region 2.4 billion tons of ‘black gold’ within 15 years.
Two years ago Oil&Gas Vertical Magazine (NGV) has already highlighted ASP technology (see NGV #10'14); however, the situation in the industry and in the economy as a whole was substantially different as compared to that of today. Yakov VOLOKITIN, SPD Petroleum Engineering Manager and Head of New Technologies, speaks about the start of practical implementation of the plans announced long ago, and whether it makes sense to use the costly technology given the current oil prices.
Ed.: Yakov, in which manner can ASP substantially enhance oil recovery ratio?
Y.V.: This is the case of a radically new technique of formation stimulation. Injection of the three-component solution, firstly, substantially improves the displacement capacity of the injected fluid, and secondly, makes it possible to mobilize the oil remaining from waterflood by way of reducing interfacial tension between oil and water. Thanks to the synergy between these chemical & physical processes, substantial volumes of additional production can be obtained.
Ed.: The oil recovery enhancement problem is relevant to all West Siberian oilfields in advanced development phases. Why exactly was the Salym group chosen for the pilot project?
Y.V.: It is worth recalling that the interest for tertiary EOR methods started to appear in the USSR as early as in 1980s. Subsequently, this interest, both in our country and overseas, faded away for some time since the oil industry made a technological breakthrough in other areas - 3D seismic, horizontal drilling, single- and multi-stage fraccing. This made it possible to grow production in Western Siberia by extensive methods. However, these methods gradually run dry: it’s getting more and more difficult to extract something of value from conventional deposits using them.
In the West they started thinking about creation of the next technology which would make it possible to radically enhance efficiency of development of existing fields. Projects started to appear, originally pilots, based on tertiary chemical enhance oil recovery methods.
Shell was one of the first to have started applying ASP technology on its fields. Its Salym project was among the polygons for testing the new technology. The company currently has two more similar projects outside Russia – in Malaysia and Oman.
Gazprom Neft, which has become Shell’s partner in the Salym project in the end of the 2000s after acquisition of a 50% share in SPD, entirely supported transfer of the innovative method to the Russian soil. In the autumn of 2012 shareholders made an investment decision on the pilot project.
Ed.: Was it difficult to prepare? In fact, there have never been any cases of application of this method in Russia so far…
Y.V.: From the very beginning there has been a complete mutual understanding on this issue between shareholders. One can say that for Gazprom Neft, with its main producing assets in Western Siberia, ASP method is strategically even more significant than for Shell which operates in regions with various production conditions. In this sense Shell is the optimal partner – among other matters, it has proprietary expert assessment, laboratory scientific & technical centre in the Hague, which not all Western companies can boast by far.
Ed.: Do you feel difficulties due to not very favourable economic and geopolitical situation – for instance, with shipments from overseas?
Y.V.: No, all the volumes of materials required for the pilot project have already been purchased. Sometimes there occurs an urgent need for spare parts for the equipment; however, there appear to be no problems with this either.
Ed.: Does the start-up of the component mixing plant mean that injection of the solution into the formation has already begun?
Y.V.: Exactly so. The work is currently being carried out on the West Salym field only – its formations are optimal for ASP technology in terms of their properties; furthermore, this field accumulates two-thirds of the company’s reserves. Once we confirm the efficiency of this method we will approach other SPD’s oilfields – Upper Salym and Vadelyp.
Ed.: What results do you expect from the pilot project?
Y.V.: We are not speaking of profits and substantial production volumes; the exploration wells drilled – a total of seven – will then be suspended. It is important to understand now how many tons of additional oil can be produced per each ton of the solution injected. Our prime objective is to remove process risks and prove that realistic volumes of oil can be produced from a 98% watercut formation. We expect to obtain the first results by the end of the year.
The main difficulty is to assure that in the course of injection into the formation the ‘cocktail’, as we call it, does not disintegrate, remains stable for several months at the temperature of 90 degrees and pressure of 200 atmospheres, and all of its components work consistently. This is what success of the entire project depends on.
Ed.: By how much is ASP technology more expensive than conventional waterflood?
Y.V.: Twice as expensive. Therefore, without tax incentives this technology is economically unfeasible. Ministry of Energy and Ministry of Finance with which we negotiate have not promised anything so far. Meanwhile, the timing is getting tighter - at the end of the year we would like to start preparing for the full-scale development of the method. At the National Oil & Gas Forum in April Alexey Govzich, SPD CEO, presented the structure of the incentive which, as we believe, makes it possible to minimize the risks of the government. We offer several options including the financial result tax or reduction of the MRET rate for application of tertiary methods.
Ed.: If you obtain the incentives, will the full-scale project pay back given the current oil prices?
Y.V.: It will. Cost of production with ASP application in Western Siberia is about $25/bbl. Anything above this level adds value. Our calculations show that with the oil price of $45-50 the technology will work successfully and bring hundreds of millions of profit both for the company and the government, as opposed, for instance, to shale production.
Ed.: What about timing?
Y.V.: In case the pilot proves successful and we get help from the government, in 2018 we make the investment decision, starting 2020 build the infrastructure – highly efficient mixing and injection plants, additional wells, pipelines, and two more years later we start producing. The technology can further be replicated on other West Siberian fields as well, first and foremost on Gazprom Neft’s oilfields, of course. It produces 35 million tons a year in this region, and will have acquired a valuable experience of working with ASP by then.
Ed.: You currently purchase surfactant in the USA, polymer in France. They speak a lot about import substitution now. Can production of these items be developed in Russia?
Y.V.: There exist specific plans to this end now. SNF build a water treatment polymer production plant in Saratov. We plan to purchase part of the product from them, this is quite sufficient. Surfactant must also be produced in our country. We need 20 to 50 thousand tons of surfactant a year. Importing such volumes from abroad is complicated and expensive; moreover, due to specific features of preparation it is desirable to produce this item as close to the field as possible. In order to produce the required volumes, one or two plants are required, costing at least $100 million each.
There are a number of companies which are ready to build them. We negotiate with three potential vendors, both completely Russian and JVs. The difficulty is that, in order to justify the investment project, they need a contract for specific deliveries. We cannot guarantee them, though, until the issue of incentives has been resolved. All in all, according to the calculations, transition to the chemicals of Russian origin can reduce the project’s operating expenses by 20-30%, exclusive of the logistical costs reduction.
Ed.: The peak of production on the Salym group of fields – 8.4 million tons – was reached in 2011, then production started to decline. It was reported that SPD’s goal is not only to stabilize production but also to proceed to growth. Is it realistic to achieve this goals under the current conditions, not so easy for the industry?
Y.V.: Quite. We have already turned the decline around: last year we produced 6.1 million tons; the plan for this year is 6.145 million. We intend to maintain this level until 2020, and without applying ASP at that. In the near term we make an emphasis on new WE and WI technologies, which is actively practiced by Gazprom Neft’s oilfields now. We have mastered sidetracking which has never been applied before; this year we will drill two multi-stage frac wells.
Another reserve is the development of hard-to-recover reserves, first of all low permeability Achimov formation, for which we start preparing a pilot project, plus active exploration. Last year the company has identified 23 areas for fraccing with potential reserves of 20 million tons of oil.
Besides, the two exploration wells drilled in 2015 have proven fairly successful: the first one, stand-alone, has detected an oil-bearing section which we are going to spud next year; the second deep well for the Tyumen formation has detected a light-oil section.Back to