Dr. Maurice B. Dusseault, BSc, PhD, PEng, is deputy director of the Porous Media Research Institute and Professor of Geological Engineering in the Earth and Environmental Sciences Department of the University of Waterloo, Canada. Dusseault did not always intend to be an academic. He dropped out of university in 1965 to work in the oil industry as a roughneck for a year, then as a drilling fluids specialist for two years. He then returned to university and obtained a PhD in Civil Engineering in 1977 from the University of Alberta. He was awarded a five-year AOSTRA Professorship, held in Civil and Mineral Engineering at the University of Alberta until 1982, when he went to Waterloo to become chair of the Geological Engineering Program. Dusseault suggests that his time in industry gives him an advantage over people who have spent their entire career in academia. He also suggests that every engineer should spend some time as a laborer!

 Dusseault is active in research in petroleum geomechanics and new production methods. He teaches short courses about geomechanics, mostly focusing on heavy oil, to private and national oil companies, government agencies and research organizations. He also acts as a project advisor for many companies. Dusseault has published over 430 articles in conferences and journals on topics such as sand production, salt mechanics, slurry fracture waste injection, heavy oil technologies, pressure pulsing, monitoring of in situ processes, properties of reservoir rocks and borehole stability. He is a member of the SPE, EAGE, and the CIM Petroleum Society as well as a number of other professional societies, and has been a Professional Engineer for 30 years.

 When Dusseault embarked on his PhD, oil sands were not the hot topic they are today and operators were not applying much science to their production. “They were simply pumping in steam and hoping for the best” says Dusseault. For his PhD, he studied the rock mechanics of the Athabasca oil sands — one of the first in North America to do so. He has been studying the geomechanics of heavy oil development ever since, and considers himself lucky to have selected a topic that has subsequently achieved such a high profile.

 Dusseault estimates that the world has 13–14 trillion barrels of oil, of which about 55% has a viscosity greater than 10,000 cP. Most of the heavy oil is in unconsolidated sands less than 1,200m beneath the surface. Water- and steam- based recovery methods are effective for oils with viscosity less than about 5,000 cP. Water alone is unlikely to give a recovery factor (R_F) better than 15%. Steam can deliver up to 40% or more, but incurs high costs because of the price of natural gas and high heat losses into the surrounding strata. In addition, R_F can be impacted by instabilities in gravity drainage, coning, fingering and capillary forces. Dusseault suggests that solvents and polymers usually fail and that biological methods are also unlikely to succeed – after all, there have been bacteria in the oil for millions of years.

 CHOPS

Cold Heavy Oil Production with Sand (CHOPS) can be very effective, even in thin beds (< 10m) where steam methods are inefficient. CHOPS system design requires a good understanding of the production mechanisms based on operational experience. This understanding must include the consequences of high levels of sand production and the fact that very high drawdown can lead to water production, which will kill a well.

 CHOPS incurs a massive influx of sand into the well due to stress from the overburden. This movement generates a liquefied zone around the borehole surrounded by an area of high permeability, with wormholes and dilated zones. Dusseault commends the use of multicomponent seismic to map these zones, because S-waves will not travel through the liquefied zone and P-wave velocities will change with compressibility. Microseismic monitoring can “hear” yielding and shearing in the reservoir, so can be used to detect regions of production.

 CSS

 Cyclic Steam Stimulation (CSS) imposes temperature changes of up to 250 degC. This causes expansion of the hot area around the well, leading to shearing and dilation in the surrounding cooler formations. In addition, over time, the reservoir becomes warmer. These changes in the reservoir could be exploited in subsequent phases of a sequenced production approach, particularly with horizontal wells. Expansion of the reservoir can often be mapped by elevation changes at the surface, enabling production to be optimized. Dusseault cites the example of Shell Canada’s Horizontal Cyclic Steam (HCS) operations at Peace River, where steam was being injected into about 30 wells, but for several of these wells, no expansion was observed. Based on this observation it was decided that pumping a lot more steam into 6 to 8 wells at a time would be much more effective.

 SAGD

 Steam Assisted Gravity Drainage (SAGD) is carried out at very small pressure gradients, which helps stabilize the process, avoiding the high pressure gradients that can potentially lead to channeling and isolation of parts of the reservoir. Shale barriers can present a challenge to SAGD, but dehydration and differential expansion of sand and shale can lead to fracturing, so breaking down these barriers. HCS can be more effective than SAGD at breaking down thick shale barriers because high pressures help fracture through the shales — another example of why understanding the reservoir is key to planning the best recovery method.

 Combining Technologies

 Conventional pressure, gravity, water-assisted, CHOPS, CSS, HCS and SAGD methods all have pros and cons, both technical and economic. Dusseault promotes the application of complementary methods either simultaneously or in sequence to provide synergies that will increase R_F over the long term, both in heavy oil reservoirs and mature conventional fields. He argues that resources will be more rationally developed if a long-term approach is adopted – planning ahead for multiple phases of extraction that exploit the physical changes in the reservoir that result from hydrocarbon production, such as the heat left behind from a steam injection process or the increased permeability resulting from CHOPS operations. To do this rationally, reservoir geology and the effect of each technology must be well understood. Reservoir monitoring will also be beneficial.

 SPE paper 65509 proposes a “Fast SAGD” approach in which, after the reservoir is heated and communication is established between adjacent SAGD wells, alternate well pairs are converted to single HCS operations. At a later stage, Dusseault suggests that inert gas injection (IGI) would encourage gravity drainage of some of the remaining oil from the reservoir, which will remain hot for several years after cessation of steam injection. This final production would be at low flow rates, but also at low cost. The inert gas would also help to insulate the reservoir, preserving the heat to help oil flow.

 CHOPS generates massive disturbance in the reservoir, including increased porosity, permeability and compressibility, coupled with loss of horizontal stress and the breaching of shale barriers. These changes will all benefit the effectiveness of subsequent thermal processes. Using a combination of alternating vertical and horizontal wells, HCS could be applied to establish communication between adjacent vertical CHOPS wells and then SAGD applied to steam-drive the whole reservoir, benefiting from the rapid spread of heat and hydrocarbon flow through zones disturbed by CHOPS. As a last phase, alternate wells would be converted to IGI, pumping steam or gas to the top of the reservoir while some of the remaining oil flows slowly through gravity drainage into horizontal wells. For such a sequential scheme to be implemented, well geometry and completions would need to be decided in advance, for example to complete a CHOPS well so that it can later be converted for thermal use. Furthermore, drilling into a hot reservoir or intervening in a hot well may be undesirable, making late redevelopment drilling problematic.

 Sequential schemes require more up-front investment but will achieve better returns in the long-term. Several CHOPS producers are now regretting that their wells are not suitable for thermal use and that their reservoirs have become too disturbed to be re-drilled. In Canada alone, there are about 10,000 inactive CHOPS wells in zones 4–15m thick – possible candidates for post-CHOPS CSS, or air injection.

 Prospects for other technologies

Dusseault remains optimistic about in-situ combustion (ISC), although many tests to date using vertical wells have failed due to instabilities such as channeling. He predicts that Toe to Heel Air Injection (THAI™) will have an important role in reservoirs 6–18m thick. The technique can handle shale, and its water requirements are very small. In addition, some sulfur and more than 80% of heavy metals in the oil are left behind. Dusseault suggests that THAI might be used as part of a sequential process, perhaps applied after pre-conditioning of wells with steam. Steam co-injection with air might also help control the combustion front, reduce the combustion temperature somewhat, and help upgrading through aquathermolysis.

 Based on the experience of SAGD, THAI will probably take a long time to become established. Roger Butler wrote a patent for a thermal gravity drainage process in 1969 while working for Imperial Oil. It took until 1982 for the Canadian government to support the SAGD idea and a further decade for the oil industry to accept the idea of using gravity drainage instead of high pressure gradients to produce oil.

 Today, directional drilling technology can deliver an almost unlimited range of well geometries so has enabled a revolution in heavy oil production. Many techniques can now be much more effective, such as injecting solvents (VAPEX) and gases.

 VAPEX may become an effective technology for production of oil with viscosity less than about 1000 cP. Higher viscosities require higher percentages of solvent, rendering the process uneconomic. Adding small amounts of hydrocarbons to SAGD injection wells also seems to have some benefit. The solvent becomes a gas when hot then cools to a liquid that can dilute the oil and flow back to the production well for recycling. If the recycling process is efficient, cold injection of solvent might be effective, removing the costs associated with heating. Supercritical CO₂ flows easily – much more easily than water – so could be used to enhance production. However; for the CO₂ to remain supercritical requires high pressures, so while this technique could be effective at depths over 1000 m, it is not appropriate for the shallow sands in which most heavy oil exists.

 Screening process to determine production technique

Dusseault is looking at a wide variety of heavy oil recovery technologies – some proven, some emerging and others still conceptual. He is bringing together the physics of these processes and a variety of earth models to develop a screening process to identify the most appropriate production solution for particular reservoir conditions.

 Dusseault has used his screening system to help PDVSA with a project to evaluate their recoverable reserves. Some of the results of this work were presented in the 2008 World Heavy Oil Congress paper 437 “Estimating Technically Recoverable Reserves in the Faja Petrolífera del Orinoco.” Venezuela has better reservoirs than many heavy oil regions, with thicker zones, relatively low viscosity oil and lower levels of sulfur and asphaltenes. SAGD has only recently been introduced to the Faja, although Dusseault estimates that it could be successfully applied at about 70% of the cost of comparable operations in Canada.

 Before the study, official estimates of reserves in the Orinoco Belt were about 40 billion barrels. Petróleos de Venezuela, S.A. (PDVSA) now says that 236 billion barrels of extra-heavy crude are recoverable using proven technology. Dusseault says that this is still a conservative estimate, and that more than 300 billion barrels could be recovered using sequenced technologies.

 Energy-efficient solutions

Dusseault is not only a promoter of alternative production schemes, but also suggests that operators consider innovative energy-efficient and environmentally friendly total solutions. One such potential solution involves “clean” power generation using coal gasification, which he sees as a natural match for heavy oil. Coal combustion can produce power, heat, hydrogen and CO₂. The heat can be scavenged for thermal processes such as SAGD, CSS or HCS. Among many other uses, hydrogen can be used to hydrogenate and thus lighten heavy oil. In some circumstances, CO₂ miscible flooding will aid production and its sequestration might earn cash credits or tax breaks. Dusseault says that to make the best use of technology in the quest for improving heavy oil recovery factors, keeping an open mind is vital.