Chris West is the Development Manager for the Heavy Oil Program for BP Alaska. Based in Anchorage, he is responsible for heavy oil development through application of technologies not previously employed in Alaska. He has been with BP for 26 years, working in the Gulf of Mexico, as well as Alaska. Prior to joining BP, West was with Shell UK in Aberdeen, Scotland. Chris has a B.Sc. in Geology from the University of London and is an AAPG Certified Geologist.

A 5-Year Research and Development Program

BP is currently performing a pilot project to evaluate the applicability in Alaska of cold heavy oil production with sand (CHOPS) and other cold recovery operations that are widely and successfully used in Canada. This project is part of a 5-year technology research and development program to evaluate and assess heavy oil production options in the area. The current pilot will duplicate, as closely as possible, the drilling profile, completions equipment and recovery process of a typical Canadian CHOPS well.

BP has, to date, already produced about 50 million barrels of heavy oil in Alaska, including from the Shrader Bluff and West Sak reservoirs. Production here is mostly from multilateral wells; up to five laterals per well, each up to 2 km long. Most existing production is of oil with sufficiently low viscosity that the reservoirs can be produced with the assistance of waterflood.

The Ugnu Formation

The pilot project is targeting the Ugnu formation, which is younger than the producing reservoirs at Shrader Bluff and West Sak. The Ugnu formation is estimated to contain 20 billion bbl of oil equivalent, about 25% of which is at the Milne Point unit on the North Slope. Milne Point was selected as the location for the first trial and its oil (14° API) is more mobile than in some other areas. The oil is, however, thought to be beyond the limit for waterflood—water may bypass the oil—so an alternative strategy is required. 

CHOPS was selected for the 3,700 ft Ugnu pilot well because the reservoirs are much deeper than those in Canada, where SAGD wells are typically 400–1,200 ft. Steam is difficult to apply at such depths, except perhaps for a very high pressure thermal solution.

The Ugnu formation has up to six reservoir intervals. The reservoir sands are highly compartmentalized with much faulting, leading to multiple local oil/water contacts (OWCs). The current pilot project, targeting the Lower Ugnu, is testing one of the deepest reservoir intervals. The first well—the first ever CHOPS well in the Ugnu—was drilled in 2007. First production is expected in late 2008. If the initial tests are successful, shallower zones may be tested.

Imaging Wormholes

In CHOPS wells, high drawdown brings in sand. Most of this sand production comes from the creation of wormholes radiating out from the well; providing the horizontal component and increasing the productivity index (PI).

The formation of wormholes is hard to predict or control and their growth is influenced by local stress fields. West knows the value of accurate subsurface imaging to improve reservoir understanding. To this end BP has already acquired a 3D multicomponent seismic survey that will form the baseline of a 4D time-lapse study. This was the first multicomponent 3D survey to be shot on the North Slope. Multicomponent surveys measure both the pressure (P) and shear (S) seismic wavefields. This combination can provide significantly more information about the subsurface than conventional surveys. Potential benefits of multicomponent data include enhanced structural imaging and indications of regional stress patterns, lithology, fluid saturation, pressure and gas seepage. A repeat survey is scheduled to be acquired after 4 or 5 years of production. After which, a detailed analysis of the differences between the datasets should enable West to map changes in density and/or areas of gas breakout at the end of wormholes. West’s team is also executing a program of geomechanical studies of the Ugnu reservoir development, assisted by BP’s global technology support network.

Meeting the Challenges in Alaska

Compared to areas such as Lloydminster, Canada, operations in Alaska present several challenges. Logistical costs in Alaska are higher, not least because of the remote location. Permafrost presents both an operational and environmental challenge. The operations are in an Arctic wetlands environment, which provides nesting grounds for several endangered species, so BP is acutely aware of the need to manage its environmental impact and footprint. The company is working hard to address a wide range of environmental issues, and one area of study is looking at ways to extend the reach of CHOPS wells to get maximum drainage from the minimum number of pads.

Although the CHOPS process produces relatively little CO₂—much less than a thermal recovery project—it does produce small volumes of gas, and it is intended that this gas will be captured, compressed and sent to the processing facility.

Sand Production and Management

CHOPS operations produce a lot of sand; up to 50% at the start of production, reducing rapidly as a percentage over time. Early total production is very low; perhaps just 20 bbl of oil equivalent (per day) as the wormholes start to form. As wormholes develop, production rises while the proportion of produced sand reduces, typically to 1–2% after about 6 months. At Lloydminster, maximum oil production levels are usually reached within 6–12 months. Sand production requires special surface facilities, which BP is currently constructing. As in Lloydminster, the majority of the separation for the pilot wells will be done on the pad.

The overall volume of sand that is expected to be produced should not become a limiting factor. Nevertheless, BP is looking at ways to streamline its sand management. The company already operates the world's largest “grind and inject” facility, located 35 miles away from the new pilot site in Prudhoe Bay. Here, produced sand and solids are injected into a highly porous non-hydrocarbon bearing semi-brackish aquifer, a solution that meets with government agency approval. If the Ugnu pilots are successful, a new facility closer to the operations may be considered.

The Future of Heavy oil Projects in Alaska

Although factors such as reservoir depth, compartmentalization, OWCs, permafrost, surface conditions and high cost all represent challenges, Alaska provides several benefits for heavy oil production, such as a good existing infrastructure, including roads and pipelines, and the local availability of diluent, which is mixed with the heavy oil to enable it to flow through the pipeline. In addition, West emphasizes that there is a large and well trained workforce in the region, which may be a key differentiator in contributing to the future competitiveness of heavy oil projects in Alaska.

Recovery factor (RF) is, as yet, unknown, but is expected to be in the range of 8–10% as is typical of CHOPS wells in Canada. BP is working to enhance recovery from the Ugnu pilot wells through a better understanding of the production process, imaging of the wormhole network and improved operating practices. Looking to the future, follow-up EOR processes such as solvents and/or thermal may be applicable.

West believes the close ties BP fosters with industry consortia, academia and service companies will help to address the challenge of improving the overall recovery factor. There is considerable scope for improving reservoir simulation of CHOPS production systems and benefits to be gained through extended reach drilling, stepping-out from CHOPS well pads.

Achieving Higher Recovery Factors

There are an estimated 20 billion barrels of oil in place on the North Slope. Just 1–2 billion barrels are technically recoverable today from the Schrader Bluff, West Sak and Ugnu reservoirs, so a small increase in RF would make a big difference. A lot of the oil is in thin sand units, and for many potential CHOPS targets the oil is close to the OWC. Once wormholes extend into water, they often stop producing oil. Using geosteering to optimally position horizontal wells should improve oil recovery close to the OWCs.

BP plans to use the existing pad to drill an additional three pilot wells, this will help to assess the repeatability of the initial experiment while minimizing footprint. One of the new wells will be a horizontal well with sand control in the form of slotted liners.

In this complex environment, West believes the ultimate success of the pilot project depends on several factors: With the high costs of operating on the North Slope, the efforts BP is applying to improve recovery factors should help to avoid marginal economics. These efforts will blend local and global expertise with new technologies, and new application of existing technologies. In addition, the diluent—a lighter oil produced in declining fields on the North Slope—used to transport heavy oil through existing pipelines may not last forever. Moreover, ongoing EOR projects to improve recovery from these fields, combined with continuing exploration, will mean the existing transport system should also play a part in the long-term viability and commercial success of the Ugnu heavy oil operations.