In 2004, the large Mangala, Aishwariya, and Bhagyam oilfields were discovered in the remote Barmer Basin of Rajasthan, India. These fields contain light, paraffinic crude oils with a wax appearance temperature approximately 5ºC less than reservoir temperature, and in situ viscosities that range from ~8cp to ~250cp. Development plans for these fields are based on hot waterflooding to prevent problems with in situ wax deposition.

This paper discusses a few issues associated with waterflooding viscous oils, presents some viscous oil waterflood results from around the world, and benchmarks the expected performance of the Rajasthan fields to this database. Given that the Rajasthan oils have some properties that may be considered "unusual" and potentially troublesome for waterflooding, and that there is no long-term production data or a history-match of waterflood performance in hand, these benchmarks were considered very important reality checks. In actual fact, fields with similar or much higher viscosities are routinely waterflooded with excellent recoveries in Canada, the USA and elsewhere.


Waterflooding is sometimes dismissed as an ineffective process for a viscous oilfield, with development plans focused on more exotic and expensive recovery mechanisms such as chemical or thermal processes. However, basic application of Darcy's law and fractional flow theory, combined with operations that focus on production at very high watercuts, clearly shows that viscous oilfields can yield reasonably good ultimate recoveries under waterflood.

A recent technical review (Reference 1) stated that there are few detailed case histories which describe viscous oil waterfloods, that the limited data available is sometimes conflicting as it shows a very wide range of oil recoveries, that the understanding of high mobility-ratio waterfloods is inadequate, and that some of the viscous oil waterflood recovery mechanisms may be different than those acting in conventional light oil reservoirs. However, there is a large amount of publicly available "raw" data from basins around the world that can help flesh out some "typical" viscous oil waterflood performances. For example, there is substantial viscous and heavy oil production in Western Canada, with well-developed systems for recording, archiving and reporting oil and gas field performance data (Reference 2). Note that all production, injection, log, core, fluid, pressure, land, pipeline and facility data can be accessed for every well, pool and field in Western Canada (except for confidential 'tight-holes' which may be restricted for a short period of time); essentially, if you measure something, you must report it. The ~500,000 wells drilled in this region provide a fairly comprehensive technical dataset. These and similar data from other countries can provide benchmarks and templates for the performance of viscous oilfields under waterflood.

The data show that most viscous oilfields can yield good waterflood recoveries if a few basic tenets are followed: development on close well spacing, appropriate facility design, sufficient throughput of injected water, a voidage replacement ratio close to unity, production to very high watercuts, proper reservoir surveillance, and flexibility in adjusting the waterflood patterns employed are all keys to successful and economic projects. All of these factors are within the control of the Operator, and the analogs clearly show that recovery is maximized by injecting as much as possible on close well spacing, regardless of the crude viscosity. For many viscous oilfields, simple and cheap waterflood operations are often the base recovery mechanism to which other more expensive and difficult-to-operate processes should be compared.

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