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HEAVY OIL ACTIVITY in the African continent is continuing to increase. Activity exists in Egypt, with most of the production for heavier crudes coming from Chad and Angola.

Additional heavy oil deposits have been discovered offshore Angola and bitumen deposits in Madagascar which are now in early development planning phases.  There is increasing interest in advancing heavier oil projects, so effective thermal production technologies that maximize potential recovery factors, while respecting environmental constraints and reducing energy requirements, are gaining momentum within the region.

In more established heavy oil regions around the world, process improvements in thermal heavy oil recovery are evident. Such projects take steam-induced production projects; for example the Steam-Assisted Gravity Drainage (SAGD) concept, which was developed in Canada to extract bitumen from deposits that are too deep to mine, and adapt the thermal techniques to best fit the low reservoir temperatures, and local geological and operating conditions. Variations to the main steam-based processes, e.g. SAGD, HASD or Cyclic steam injection are being tested in Canada, Venezuela, Indonesia, Russia, China, Syria, the Middle East and Madagascar. Of course, to apply these systems effectively requires the integration of the reservoir with surface operations data. This delivers a holistic view of a reservoir, which enables well placement or completion decisions to be made that can foster an optimum energy balance for maximum extraction.

Significant operational efficiencies in steam-based schemes are possible where an inclusive approach to project planning is taken to minimize energy losses to boost recovery from heavy oil fields. The judicious application of steam-based processes can significantly increase the recovery factors obtained from a reservoir, where surface and reservoir elements are considered as a whole. This article illustrates the importance of understanding and then optimizing the use of energy requirements for each phase of the process. The results presented are from a heavy oil development in Venezuela in which SAGD is planned to be used over a 15 year period. As heavy oil development progresses in Africa, some of the lessons learnt in South America can be more applicably related than those developed elsewhere for considerably colder reservoirs and ambient conditions.

Consumption of energy to generate steam

Steam injection projects require large amounts of energy to generate steam. It is estimated that more than half a million barrels of oil in energy equivalent terms could be saved from a relatively small area of one of these operations by the optimal placement of surface steam generation equipment, along with the use of nitrogen-based completion fluids, and other optimization measures. The net energy balance in a SAGD-based development suggests that the net energy loss to the over- and under-burden is around 25% over 15 years. Nonetheless, a SAGD process in a 33 m thick reservoir is energy efficient, by delivering more energy than it consumes.

The overall energy balance for a steam-injection project can be integrated with surface and reservoir systems to evaluate potential efficiencies. Energy intensity indices can then be established to measure energy obtained from oil and gas production, relating to the energy used in the extraction process, in this instance referred to as “lease-burned” fuel or oil.

In this study, homogeneous and heterogeneous reservoirs were examined considering the configuration of surface steam generation equipment and its proximity to injection wells; the effect of steam propagation through a reservoir and energy losses; and the flow of produced fluids to the surface and to a first stage separator. Additionally, energy-saving and efficiency gains could be achieved by using nitrogen to insulate the annulus between casing and production tubing on both injection and production wells. This precaution strongly influences the ultimate recovery factor.

For the analysis, an integrated five well pair SAGD system spanning an area of approximately 40 hectares was used with a steam generation unit, fitted with a heat exchanger, then a steam trap, feeding into an injection network routed through the reservoir and then back up into production wells. A total of 44 scenarios were examined, based on a 33 m thick reservoir having a temperature of 147 degF and an initial pressure of 1,350 psia. One of the variables analysed was the distance from the boiler and separators to the furthest wellhead, which varied between 1.2 km and 2 km. Another was the use of either nitrogen or water in the annulus between casing and tubing on both steam injection and production wells.

Heat exchangers and the production network

The results indicate that introducing a heat exchanger in the surface steam generation system to recover the heat from the hot water removed by the steam trap, has the potential of saving over 80,000 bbl of lease oil over 15 years. At the same time, moving the steam generator from 2 km to 1.2 km away from the wellhead could avoid another 20,000 bbl of oil consumption over 15 years.

Looking at the production network, the effect of increasing the distance from the furthest production wellhead to the separator, from 1.2 to 2 km increases heat losses from 19 to 26 MMBTU/day. This represents around 6,700 barrels of lease oil during the 15 year process. The energy losses are lower than in the injection network, because produced fluids would be on average, 200°F/ 93°C 'colder' than injection steam.

Completion fluids

Turning to completion fluids, the negative effects on injection wells of heat leakage through the casing by leaving water in the annulus between casing and production or injection tubings are evident. Water, because of its high specific heat, severely impacts the heat losses, significantly reducing the efficiency of the process.

Where water is present in injection wells, heat losses can be double those where nitrogen is used, from 46 to 105 MMBtu/day: The increase volume of lease oil that would have to be burned under these circumstances over the 15 year life of the project would amount to more than a quarter million barrels just by not completing the steam injectors in a properly insulated manner.

Allowing water into the completion fluid residing in the annular space would reduce the quality of steam at the bottom of the injectors, resulting in several other negative consequences. It would reduce the enthalpy – the ability of the steam to transfer heat to the sandface; it would more than double the amount of hot water (in lieu of steam) delivered by each injector – from 28 per cent to nearly 60 per cent, reducing the amount of dry steam by more than 30 per cent, adversely impacting the performance of the SAGD process. Lastly, it would increase the water cut during production.

Production wells

For production wells, there is an impact as well to the temperature of the wells whether water or nitrogen-are used as completion fluids. A year after production start-up, production wells with nitrogen in the annulus achieve a temperature of 280°F/ 138°C, while the temperature in production wells with water in the annulus rises less, to around 250°F/ 121°C. The higher temperature shown by the producers completed with nitrogen, result in lower viscosities of the oil flowing inside the tubing, implying higher flow velocities, lower residence time in the well and a tendency to decrease energy losses in the overall process in spite of their higher flowing temperatures.

Heat losses in production wells were modelled for both water and nitrogen completion in the annular space, over five and 15 years. Over five years, the heat loss rate for a nitrogen completed production well is 15.4 MMBtu/day, but for a water completed well the figure rose to 33 MMBtu/day – a 17.6 MMBtu difference per well per day. Assuming an average difference of 14 MMBtu per day per well, over 15 years, the penalty for allowing water in the annular space of the producers would have cost the burning of about 60,000 additional barrels of lease oil.

As wells with water in the annulus often require artificial lift, a further 10,000 bbl of production would be lost in energy balance terms through the need to use Electrical Submersible Pumps (ESPs) – based on the energy consumption of the ESPs. In summary, over the 15 year life of the relatively small project exemplified in this case, the total loss of production for failing to properly complete the production and injection wells and not using a heat exchanger at the steam generator inlet (excluding the effects from reservoir inefficiencies) would amount to close to half a million barrels of oil.

Energy Balance

An examination of reservoir impacts indicated that total heat losses were around 70% of the net energy injected. Initially losses occur mainly in the injection network, but after about four months, losses decrease as the ground surrounding the injector wells warms up. Then heat losses to adjacent formations, the over- and under-burden, begin to increase and continue as production progresses. After about three years of steam injection more that 50% of the energy provided by the steam and hot water is lost outside the reservoir. For thinner formations, the time to reach the 50 per cent mark is shorter and conversely, for thicker formations it is longer. The trend continues over time, for all reservoir types.

After 15 years of steam injection, the energy retained in the reservoir is about 25 per cent of the total energy consumed to generate steam. Looking at recovery factors, the SAGD process for thick formations is deemed energy efficient: Oil production is considerably greater than the amount of crude that would be required to be consumed to generate the energy demanded by the process.

Energy losses were greater in injection wells, but properly completed and insulated injectors can increase the fraction of energy transmitted to the reservoir, increasing recovery.

Also, heat exchangers, proper insulation of the surface and down-hole injection and production systems and adequate placement of the generators to minimise distances to wellheads increase the overall efficiency of the process. To further boost energy efficiency, the application of secondary heat recovery techniques on production fluids can carry around 20 per cent of the energy generated from steam injection. Integrated energy balance analyses add a significant understanding to the process and are ideally suited to help target the more vulnerable components of the system to optimize field applications.

In the present day economic climate, carefully planned, efficient spending is essential. As steam generation can be the largest single expense in heavy oil production, the trick with SAGD and any other steam-based process is to minimise energy losses to boost recovery on heavy oil fields. Even a small shift in energy savings can significantly impact a field’s overall economics. By using energy balance to optimize steam-based scenarios, efficiencies from heavy oil reservoirs can be increased and objectives achieved more effectively. As the profile of heavy oil rises in Africa, the energy balance techniques outlined in this analysis will become increasingly relevant and useful.

Figure 2. Gross and Net recovery factor. Wells completed with Nitrogen and Water

Authors: Ernesto Valbuena, José Luis Bashbush, Adafel Rincón; Schlumberger: Presented at SPE Latin American and Caribbean Petroleum Engineering Conference, Cartagena, Colombia, June 2009.