Mikhail Chertenkov, Deputy CEO of Field Development Technology, Lukoil-Engineering

Q&A to discuss heavy oil production and some of the challenges of working in harsh environments.

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The Yarega heavy oil field is an example of Russia’s technical advancements in heavy oil and bitumen production. Describe the technologies deployed in the field and their effects on production.

Due to the requirements for high oil production rates and final oil recovery factors, we applied a counterflow steam-assisted gravity drainage (SAGD) technology in Yarega, which resulted in even reservoir coverage by thermal exposure, higher oil production rates, and lower steam/oil ratio values. Modeling results also had shown higher expected final oil recovery factors.

A surface/underground thermal oil mining field development method is in common use in the Yarega field. The oil production performance indices of the oil mining method were significantly improved by the following measures:

  • The lengths of horizontal wells drilled from underground mines were tripled due to new directional drilling systems, thus oil rates from new wells were increased.
  • An upgrade of a surface steam generation unit raised the steam pumping pressure.

By implementing counterflow SAGD technology, we increased horizontal well length, reduced operational expenses, eliminated adverse working conditions from the processes, and significantly improved workplace health and safety protection. The counterflow SAGD also allowed us to develop new areas in the Yarega field that were not prepared by functioning mines.
What are the benefits of using thermal production technologies?

In the Yarega field, there is no alternative to thermal methods for oil production. The majority of the nonthermal development technologies for heavy oil fields are known to be economically inefficient. Lukoil is working on improving thermal methods for production in its heavy oil fields. We have set a goal to increase oil production rates by 40% and final recovery factors by 10% by developing the currently employed methods and applying new approaches and technologies in pilot project programs.

What are the lessons learned in using vertical drilling rigs and rack-type rigs at the field?

The main issues associated with drilling from traditional vertical rigs were a result of the high dogleg severity associated with the reservoir’s shallow depth (200 m to 220 m in total vertical depth). Among the challenges faced were low penetration rates because of insufficient weight on bit owing to buckling and the inadequate weight of the bottomhole assembly and drillstring. Another issue was the inability to reach target depth with casing because of the rig’s low weight, friction, and an inability to push down casing from the surface.

The use of a slant drilling rig resolved these issues. However, we had to use slant workover rigs later on.

In oil mining, the horizontal drilling technology has been changed several times in Yarega. Before 2011, horizontal well lengths did not exceed 300 m because of technical constraints and wells were drilled “blindly.” Starting in 2011, we increased horizontal well lengths up to 800 m with the application of new mining drilling systems. In addition, measurement-while-­drilling technology allowed us to maximize the length of reservoir contact. As a result, oil production rates increased significantly and operating expenses decreased.

How can intelligent well technology increase heavy oil production?

The key factor in successful SAGD project implementation is to provide sufficient steam quality supported with instrumental daily control and reservoir heating monitoring along the horizontal well lengths.

The steam dryness factor, pressure, and temperature are monitored online from the steam generation facility to the wellheads on Yarega field. To control reservoir heating along a production well’s length, fiber-optic systems are mounted behind casing on screens in the horizontal parts of the well. In steam-injection wells, fiber-optic systems are mounted on tubing.

Fiber-optic sensors provide reservoir temperature profile data to allow on-time decision making for steam chamber expansion control (by steam pumping rate), mode adjustment for electrical submersible pumps, maintenance of the pumping/production ratio to achieve optimal subcooling, and engineering and remedial operations based on well integrity monitoring.

Given the harsh environments such as those in the Caspian region, what are the challenges when deploying new technologies?

Lukoil assets include heavy oil reserves at depths greater than 1.5 km. The company is working on issues related to steam delivery without large heat losses to such depths.

We have also successfully developed tight-rock carbonate reservoirs at depths to 4 km. We revised the field development approach, rejected vertical well drilling, and switched to horizontal well drilling with multistage fracturing. The development of the multistage fracturing technology required the use of high-powered fracturing equipment to generate higher pumping pressures compared with those that are commonly used on Russian oil fields. It also required the use of weighted fracturing fluids to eliminate formation damage. These solutions are used today in our regular operations on a large scale.

We are getting ready to start drilling in the Filanovskogo (Filanovsky) field in the Caspian Sea where we will implement extended reach drilling technology and a remotely operated and self-acting inflow control completion system.

As part of the improvements in reservoir management processes, there is progress in deploying fiber-optic monitoring systems and inflow indication chemical tracers that are placed either under the completion or in fracturing fluid.

What are the technology trends anticipated in the next 5 years?

Current oil and gas reserves developed by Lukoil can be characterized by thin pays, low permeability and tight reservoirs, and oil rims. In these reservoirs, multilateral wells are required, including some with multistage fracturing. Therefore, we expect more exploration of these technologies in the next couple of years. So far, the company has drilled approximately 100 multilateral wells with continual improvement in the technology.

For Further Reading

SPE 171275 Improvement of Drilling Technology for the Yarega Heavy Oil Field Development by SAGD Method With Counter-Producing and Injecting Wells by D.S. Loparev and M.V. Chertenkov, Lukoil-Engineering; G.V. Buslaev, USTU Oil and Gas R&D Institute; et al.

Mikhail Chertenkov, SPE, is the deputy chief executive officer of field development technology at Lukoil-Engineering. His areas of scientific interest include improvement in the processes for development of heavy oil fields and new technologies. Chertenkov holds a degree in geology and prospecting of oil and gas fields from the Tomsk Polytechnic University in Russia. He was a program committee cochair at the SPE Russian Petroleum Technology Conference in Moscow in October.