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Keys to heavy oil: The importance of planning ahead
Until recently, many producers thought commercial quantities of heayv oil were unique to a handful of large fields in Canada, Venezuela and the United States.
Now that market conditions have changed, prospects are quickly opening up in Brazil, Mexico, China, the Middle East, Russia and elsewhere. The fact is, most of the world’s remaining oil has an API gravity of 22 or below, which is one way the industry defines heavy oil.
Producing heavy oil is quite different from conventional reserves. The first challenge is selecting the right production method from a range of alternatives. Many operators use some form of steam injection to heat the reservoir, but not all reservoirs are suitable candidates.
Planning a heavy oil development is like designing a house; the foundation must be right, because it will affect everything you do in the future. The design is influenced by factors such as geology, permeability, viscosity, gravity, miscibility, and the location of the field.
Transporting heavy oil also raises questions. To flow through pipelines, heavy oil must either be kept warm, mixed with solvents, or blended with lighter crudes. Flow assurance is particularly challenging in subsea developments and colder climates. If a more viscous oil is to be blended, asset managers may have to proceed with heavy oil developments while they still have ample supplies of lighter crude.
Not only is heavy oil more expensive to produce and harder to transport than lighter crude, there are other challenges, including new technologies beyond the experience of most operators. While it is certainly possible to turn a profit with heavy oil, new developments require plenty of upfront planning.
Refining is a good example. Although the technology exists to process nearly 100 percent of a barrel of heavy crude into useful products, it takes equipment that relatively few refiners have. Those that do, benefit from heavy oil’s 15 to 20 percent price differential, so the economics of any new heavy oil development depend in part on the proximity of refiners who can handle it. Industry journals suggest that 45 percent of all refineries could be upgraded to handle heavy crude, but only about 25 percent are equipped to do so today, and most of those are in the United States.
Production methods
Heavy oil may be light as honey or thick as peanut butter, even within the same reservoir. Heavy oil exists in many environments and there are a variety ways to produce it, but methods for recovering conventional crudes work poorly or not at all with heavy oil.
Heavy oil developments often have more wells than other fields. The reservoirs, which tend to be widespread and relatively shallow, also produce much longer than conventional plays. Primary and cold production, however, yield very low recovery factors. Heavy oil operators using one of several thermal processes to heat the reservoir can expect more than a decade of steady production from a good well, and recovery factors ranging from 30 to 70 percent.
Although thermal recovery increases the lifting costs new technology is being developed to reduce the steam-to-oil ratio.
Steam-Assisted Gravity Drainage (SAGD), for example, is a thermal process that employs pairs of horizontal wells with lateral sections one above the other. The upper well is the steam injector and the lower well is the producer. Simulations on some of the first SAGD wells predict that operators can expect them to produce at commercial rates for at least 15 years. Other promising heavy oil technologies may employ solvents alone, or a combination of solvents and steam.
Modeling for the life of the field
Most successful heavy oil operators drill pilot wells to learn as much as possible about their reservoirs before selecting a recovery system, and some continue drilling test wells throughout the life of the field. The immediate goal of pilot testing is to create an accurate model for the full-field development.
Once production begins, simulations run on the model allow engineers to select and optimize the recovery process and to remain flexible in the full-field development. Adequate simulations are paramount for informed decisions and these depend on reliable inputs of reservoir and fluid characteristics. When fluid flow properties are introduced into this 'static' model it becomes 'dynamic'. The dynamic model solves a set of flow and heat equations which describe the mechanisms of the heavy oil recovery process in order to predict the recovery performance.
It is important to know key reservoir properties such as fluid pressure, volume and temperature (PVT). Special Core Analysis (SCAL) tests the formation rock for capillary pressure and relative permeability.
Additional fluid sampling could include a suite of solubility tests 
for saturates, aromatics, resins and asphaltenes (SARA). Operators should consider CO2 phase compatibility tests and thin-bed analysis. Other geologic interpretations can help define the depositional environment, stratigraphy and petrophysical framework of the reservoir.
Logging (with NMR) and testing reveals not only the fluid composition and viscosity, but how it differs throughout the reservoir and how it might change over time. Understanding those changes makes it possible to design drainage systems that work in the operator’s favor. By constantly updating the model as new data come in, the model also becomes a reliable guide for the life of the field, which can easily be more than 50 years.
That longevity is one of the key reasons that heavy oil is attractive to asset managers and it brings home the importance of good planning. After all, what operators do to their fields in the beginning is what they will likely have to live with for a very long time.