Fields of dreams

Interview with director for new upstream projects, Denis Sugaipov
Argus FSU Energy

Denis Sugaipov

Gazpromneft is in the middle of major new upstream projects in Russia and Iraq, which should help it meet its 2020 production goal of 2mn b/d of oil equivalent. Director for new upstream projects, Denis Sugaipov, outlined the firm’s plans for the Novoportovskoye field and other greenfield projects in a recent interview with Argus

— Which of Gazpromneft’s new upstream projects are the priorities for
this year?

— Number one is the Prirazlomnoye project, where drilling and production is expected to begin this year. After this, it is infrastructure commissioning and first crude production at the Badra project in Iraq, and then our northern projects — Novoportovskoye and Messoyakh. It is important for us to maintain momentum at Novoportovskoye and to build infrastructure for the central oil gathering station and the pipeline to the crude delivery and acceptance point on cape Kamenny according to schedule, as well as to maintain momentum on design and survey work, and on buying equipment for the crude transfer terminal (FSUE, 16 May, p1).

— What work is scheduled for the Novoportovskoye field this year, and what investment is allocated for it?

— We plan to invest Rbs12bn-15bn ($375mn-470mn) at Novoportovskoye this year, including the following sub-projects — hydraulic fracturing at exploration wells, as well as on vertical and horizontal wells drilled last year, to test this technology on the field’s Jurassic layers. We performed four hydraulic fracturing jobs in the winter when the winter road was open, and they confirmed Jurassic layer productivity. Well flow rates are 60-300 t/d (438-2,190 b/d), and we performed multi-stage fracturing on one horizontal well. This technology is the most promising for developing Jurassic layers, and it maximised our flow rate growth. We will drill three horizontal wells this year, work on infrastructure construction and continue working on infrastructure design and engineering within the framework of full field development. We plan to select the final concept before the end of 2013.

— Do you mainly plan to drill horizontal wells?

— Horizontal wells, combined with hydraulic fracturing, demonstrated the best efficiency, but we will continue pilot works, including vertical well fracturing. We will select the most efficient technology in the final phase.

— What is the quality of the crude produced, and what crude quality do you expect from Novoportovskoye?

— We understand that it will be light, high-paraffin crude. Light crude offers good netbacks, provided we use our own resources for transportation and sale — without blending with other grades in the transportation system — but high paraffin content will involve additional development costs. To prevent crude from freezing in pipelines, in the gathering system and in the crude storage system, it needs to be heated at all times.

— What production profile do you expect?

— The Novoportovskoye development plan is based on reserves estimates of 230mn t (1.68bn bl) of crude and 260bn m³ of gas. The field is well explored and all reserves are confirmed. But we have identified two project phases within the concept. The first phase is based on reserves in the southern part of the field, where we propose drilling about 240 wells from 14 wellpads. The southern part of the field alone is capable of peak production of up to 5mn t/yr (100,000 b/d). The second development phase covers the northern part of the field, where we will have 12 wellpads and 132 wells. Crude production in this phase will peak at 3mn t/yr.

As of today, we have two scenarios for how to develop these phases — a two-phase scenario, and a scenario with a delayed second phase. Under the first scenario, we would reach a crude production plateau of 8mn t/yr. With the other scenario, we would maintain a production plateau of 5mn t/yr for a longer period, which means we could save on crude tankers and infrastructure capacity. We are developing project documentation for the first phase, while a decision on the second phase will be made later, upon completion of all necessary pilot work. The gas production plateau is expected to be about 8bn m³/d for a quite extended period of time.

In 2011, we had trial tanker pilotage using an icebreaker and we confirmed navigation feasibility in the area close to cape Kamenny. Last year, we signed an engineering, procurement and construction contract for a crude export terminal a few kilometres offshore. The feasibility study is completed and we have started design and survey works, as well as equipment procurement.

— You made a trial shipment from Novoportovskoye by road and rail earlier this year, and there are reports that you may try to send another 70,000-80,000t as seaborne exports this year. Is this correct?

— The scheme by road and rail proved successful and it will be used in winter 2013-14 and winter 2014-15, and maybe in winter 2015-16, until the terminal is launched. At the same time, we are also considering the second option, but we need infrastructure for crude transportation to cape Kamenny to implement this. This is being built and the scheme may launch in 2013 or 2014. But we need a pipeline and a delivery and acceptance point to supply crude to shore, and these facilities are being built. As soon as the infrastructure launches, we will start using this scheme, but we will carefully evaluate all possible environmental risks.

— What are the biggest challenges at your other northern project, Messoyakh?

— Messoyakh has not been developed to date because of highviscosity — 120-140 millipoise — crude reserves in the Pokurian suite. High-viscosity crudes are difficult to produce, and the recovery factor is rather low. But the pilot development plan scheduled in 2011 and partly implemented in 2012 demonstrated that full-scale economic field development is feasible.

The budget for this year is Rbs7bn-8bn and it will be invested in pilot wellpad 4, where six wells will be drilled, including four horizontal and one water injection well. 3D seismic covering 400km³ was performed last winter and five exploration wells are being drilled, which will be tested this year.

We will also focus on design and survey work this year to develop top-priority infrastructure facilities. These will include a central gathering station in the eastern area of the field, a 105km oil pipeline to the Zapolyarye-Purpe line, and a crude delivery and acceptance point close to the area where crude is delivered to the Zapolyarye-Purpe pipeline. Pilot drilling of horizontal wells confirmed initial flow rates. Wellpad 1’s rate was 50-200 t/d, while wellpad 2 flowed at 30-70 t/d.

— What production techniques will be used for Messoyakh’s high-viscosity crude?

Centrifugal pumps. This is a well-proven method. These pumps can produce high-viscosity crude and lift it to the surface. When lifted, crude behaves well enough in surface conditions, it does not freeze even in winter, and we can deliver it to the pipeline. The main issues will be crude, water and gas filtration in the formation, as well as waterflooding, formation maintenance and waterflood displacement.

— Following Rosneft’s takeover of TNK-BP, have you already started working with Rosneft on the project? And do you think that the start-up date for Messoyakh may change?

— We have not noticed any changes, largely because the people have obviously remained the same. The scope of exploration for 2014 is already agreed upon with Rosneft. As for date changes, this does not really depend on the owner. Our company, just like TNK-BP and Rosneft, has a commitment to Transneft to fill the Zapolyarye-Purpe pipeline by 2016. Our commitment from the Messoyakh project is 8mn t/yr. We do not see any circumstances which could prevent us from complying with these commitments, because the field has high reserves and we have high well flow rates.

— What production level is scheduled for 2016? When do you think you can reach the 8mn t/yr that you have committed to Transneft?

— We will be producing 8mn t/yr by 2020 and we will be happy to produce 1mn t in 2016. But at the same time, we are considering options that can help us fill the pipeline faster — that is, by increasing production.

— Are government tax incentives for projects such as Messoyakh sufficient to allow final investment decisions to be made?

— For fields in the northern part of the Yamal-Nenets autonomous district, such as Novoportovskoye and Messoyakh, yes, the export tax incentives will enable us to develop these fields on a cost-effective basis.

— Gazpromneft’s other important new production centre is Orenburg. What works is being undertake there this year and what are your production expectations?

— This year, we are developing four licence areas — the eastern area, the biggest within the Orenburg gas condensate field; the Tsarichanskoye field; the Kapitonovskoye and the Baleikinskoye fields. All the fields are at different phases of geological survey and readiness for development. Overall production performance in the region will reach 2.9mn t of oil equivalent (toe) (21.2mn bl of oil equivalent) in 2013. Investments will amount to Rbs15bn-17bn and will primarily be used to expand the drilling programme in the eastern area of the Orenburg field, where we plan to drill about 65 horizontal wells. As for the Orenburg hub production outlook, we expect output to peak at 7mn toe/yr by 2016-17. And investment will amount to Rbs100bn in the next five years.

— What is the expected production level in Iraq, where output is supposed to begin by the end of this year?

— We are focused mainly on infrastructure at the Iraqi project [the Badra field]. We are building crude gathering, treatment and transportation systems within the framework of several engineering, procurement and construction contracts for field infrastructure — including a central crude gathering facility and a 160km pipeline to the Garraf field. We plan to commission the main facilities and to deliver crude to the pipeline by the end of this year. Investment by all project members in field development is about $1bn in 2013, and our share is $350mn-370mn.

We have also started testing the Badra 4 well. The flow rate was more than 2,000 b/d from the lower interval, which was thought to be unpromising. We will be testing three more wells, compared with the one we have tested so far, and we hope that the combined flow rate from these will exceed 10,000 b/d.

— Lukoil, which also has Iraqi projects, often complains that the decision-making process and approval of selected bidders take a lot of time. Have you faced similar problems?

— We have also incurred certain losses in terms of contract approvals. In particular, it took us over six months to obtain approval for construction of gas infrastructure with [South Korea’s] Samsung.