Full-Field Heavy-Oil Conversion From Cold to Hot Production
- Dennis Denney (JPT Senior Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- March 2012
- Document Type
- Journal Paper
- 100 - 103
- 2012. Society of Petroleum Engineers
- 2 in the last 30 days
- 99 since 2007
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This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146695, "Full-Field Heavy-Oil Conversion From Cold to Hot Production: Challenges and Solutions," by F.E. Jansen, SPE, A. Curtis, SPE, L.V. Mejia-Cana, J. Ramsdal, SPE, and J.O. Selboe, SPE, Statoil ASA, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.
With an increasing interest in extra-heavy-oil (EHO) extraction, several heavy-oil fields will be produced initially by a cold-production scheme, and, at a later stage, thermal production in the form of steam injection can be used to enhance the recovery. In an EHO cold-to-hot conversion scheme, several choices must be made with respect to well positioning, completion options, timing, and scale of the conversion.
Challenges in establishing a good reservoir-management plan for EHO reservoirs over their entire life span stem from the complexity of modeling heavy-oil recovery, fine-grid requirements, very large models, and dedicated tools (i.e. thermal vs. conventional simulators). In this sense, crude oils can be divided roughly into three groups: those that flow without added heat (e.g., conventional oils), those that do not flow without added heat (bitumen), and those that will flow initially but yield a less-than-satisfying recovery with only cold flow (e.g., many EHO fields that are the focus of this paper).
The challenge for reservoir-management optimization of EHO reservoirs is combining slow pressure propagation (low mobility), unfavorable mobility ratio to water, and the large area, thus requiring a very large number of wells to achieve good reservoir drainage and acceptable field-production rates. The environmental requirements regarding minimization of footprint and water handling, combined with possible conversion from cold to hot production, make the handling of wells even more complex.
If the in-situ viscosity is low enough to allow economical natural flow without added heating of the reservoir, primary cold production normally is preferred if the reservoir compressibility and aquifer support are high enough to deliver a reasonable recovery (often by use of horizontal wells, downhole diluent injection, pumps, and narrow well spacing to increase well rates and field recovery). In some cases, the reservoir and mobility relationship is appropriate for waterflooding.
Several cold-production options exist: waterflooding, with or without polymer, and cold heavy-oil production with sand (CHOPS). However, full-life-cycle evaluations must be made because waterflood and CHOPS preclude subsequent hot-production conversion. Important for all of these techniques is the use of downhole pumps—hydraulic pumps, electrical submersible pumps, and progressing-cavity pumps (PCPs). The most common is the PCP because of its reliability and ability to handle high-viscosity fluid and sand. Diluent, in the form of light hydrocarbons, often is injected downhole (as deep into the well as possible) to reduce the effective viscosity in the well and flowlines. Diluent handling and possible regeneration can be important.
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