David Law, Schlumberger, Canada, looks at the latest heavy oil recovery techniques.

Image: Insulated pipes help to maintain steam properties in thermal production.

With the increase in energy demand and as conventional oil and gas resources become harder to find and access, the industry is looking

to heavy oil as one of the solutions to bridge the energy gap. Heavy oil, once considered costly and inefficient to produce, is now seen as a viable energy resource and what’s more, heavy oil reserves have only relatively recently begun to be explored. Some experts believe that heavy oil supplies now represent more than half the world’s known resources; the problem, of course, is that heavy oil is notoriously difficult to recover, transport and refine.

Recovering moreMany types of heavy oil exist and a variety of production processes are being used and developed to recover it. There have been many new recovery technologies investigated over the past few years with the overall goal to increase recovery factors while respecting new environmental constraints. Some are incremental improvements such as better integration of reservoir data to optimise steaming operations to reduce steam requirements, while offshore heavy oil developments have benefited from better techniques for completing horizontal wells in heavy oil reservoirs.

Heavy oil matters

As a rule, the more viscous the oil the more expensive it is to recover. The main challenge is to lower the viscosity of the oil to make it flow more easily, and to better understand the composition of the oil and how to handle heavier components. Bitumen (viscosity > 10 000 cP) is generally recovered through surface mining if it is less than approximately 70 m below the surface. Bitumen is separated from the sand using hot water and chemicals and is then diluted with condensate or other light liquids before being transported to an upgrading facility or heavy oil refinery. In situ methods are used to recover bitumen in reservoirs too deep to mine, up to a depth of approximately 600 m.

In situ combustion In situ combustion (ISC) is a heavy oil recovery technology that has been around for more than 40 years. The technology involves installing downhole heaters and injecting air or oxygen, igniting some of the oil in the reservoir and allowing it to burn at a controlled rate. As the burn front advances through the reservoir, it generates enough heat and combustion gas to lower the viscosity of the oil out front, driving it towards producing wells.

ISC has promise for the future because it has a lower environmental footprint and a better thermal efficiency compared to other thermal recovery techniques. This is because heavy metals and coke are left behind in the reservoir and some upgrading occurs in situ, resulting in relatively low or zero water usage. ISC is also generally

thought to deliver higher recovery rates compared to other methods and recovery can often be in the order of 70%. New configurations are being experimented with to improve results further. In the past, supporting technologies were not available for this method. Now, with increasing environmental pressures and advances in the high temperature capability of upstream oilfield development technologies, this option is looking more attractive to those with suitable reservoirs.

Simulation software can now help to reduce some of the uncertainties associated with the method, and more high temperature drilling and completions equipment coupled with high temperature monitoring technology has become available in recent years to maximise recovery and avoid the potential of bypassed pay. These advances help to manage the fire front, improve reservoir understanding and enable better overall results. In short, technology has helped to make this method less uncertain than it was previously. Today there are two commercial heavy oilfields being produced using ISC, and operators in North and South America and Asia are also investigating it as a recovery option.

SAGD developmentsAs previously stated there are other thermal recovery methods available to the industry. Steam flooding and cyclic steam stimulation (huff ‘n’ puff) are the enhanced oil recovery technologies most commonly used in heavy oilfields in North America, Indonesia, China and the Middle East. These are generally large, shallow onshore fields in areas with good

Figure 1. Shallow heavy oil deposits mean slant wellheads are a common site in Alberta.

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infrastructure. They also tend to be less costly to develop than bitumen mining projects.

Additionally, steam assisted gravity drainage (SAGD), a relatively new steam based technique used to produce bitumen in reservoirs that are too deep to mine, is gaining recognition. SAGD was developed in Canada and is being pilot tested in bitumen deposits in Russia, China and the Middle East. Production is achieved by using well pairs. The well pairs are drilled horizontally, one above the other, into the bottom part of the formation. The top well serves as the steam injector while the bottom well serves as the producer. As steam is injected into the top well, it rises to the top of the oil producing formation. The high pressure steam decreases the viscosity of the oil in the formation to the point where the oil will flow. This allows the bottom well to produce oil and water that has condensed from the steam. There are several production methods possible: natural flow, gas lift, unique high temperature electrical submersible pumps (ESPs) and special all-metal progressive cavity pumps (PCPs).

Since steam generation is the largest single expense, the trick with SAGD or any steam process is to minimise the steam-to-oil ratio (SOR). Even a small shift in the SOR can significantly impact a field’s overall economics.

Even more recently, variations of SAGD have been developed. XSAGD pronounced ‘Cross-SAGD’ uses the same steam chamber process as standard SAGD; however the injectors and producers are perpendicular, not horizontal, creating a criss-cross pattern for improving drainage. Additionally, ES-SAGD or Expanding Solvent-SAGD is a steam based hybrid process with a solvent or mixture of solvents added to the steam in the SAGD process. The hybrid process synergises the advantages of a steam based technique, which has a high oil production rate but is energy intensive with significant environmental impact, and a solvent based technique, which is less energy intensive and environmentally friendly but has a low oil production rate.

Additionally, horizontal alternative steam drive (HASD) is a process based on a pattern using horizontal wells acting alternatively as oil producers and steam injectors. The recovery mechanism is a combination of horizontal steam flooding between wells and cyclic steam stimulation of each of the horizontal wells in the pattern. HASD has the potential to be more efficient than cyclic steam injection or direct steam flooding alone.

Primary production methodsMany reservoirs are not suitable for steam based thermal recovery. For example, certain reservoirs are either too deep for steam injection due to heat losses in the well, or they lack a suitable cap rock capable of resisting the steam pressure in the reservoir, or they may be located in areas that are environmentally sensitive and cannot support the surface infrastructure required to generate steam. In some cases where the viscosity of the oil at reservoir conditions is relatively low (100s of cP), non-thermal recovery methods such as waterflood, horizontal wells to improve reservoir contact, multilaterals, fishbone laterals and cold heavy oil production with sand (CHOPS) may be used to recover the oil.

All of these methods have lower upfront investment costs yet suffer from lower recovery factors. Additionally, since they do not depend on the operation of costly surface facilities to recover the oil, they can be shut down more readily than the more complex thermal recovery projects. Surprisingly, today the operating costs for these methods are not significantly lower than the operating costs for thermal recovery projects due to the current relatively low price of gas.

Gas injection using CO2 or light hydrocarbon solvents is also receiving interest by those operators looking to switch from primary (e.g. CHOPS) to enhanced oil recovery (EOR) methods. The challenge is managing the cost of the solvent versus the price of the oil recovered. Better reservoir and fluids characterisation, combined with geomechanics knowledge and simulations — to understand the way solvents interact with the fluids and rock within the reservoir and to understand how the solvents could be recovered over time — are helping to improve the economics of this recovery option.

Other non-thermal EOR methods being investigated include injecting polymers and enzymes into the reservoir to help the oil flow more easily. Polymers help reduce viscosity by creating water enveloped oil-in-water emulsions. Enzymes affect the surface adhesive properties of the oil and allow it to flow more readily.

Vapour extraction, or VAPEX, which is a solvent based technique, is also in the experimental stage. Similar in mechanics to SAGD, but using vapour instead of steam to mobilise the oil, the solvent vapour condenses into the heavy oil and reduces its viscosity. The bitumen is fluidised not by heat transfer, but rather by molecular diffusion of the light hydrocarbon. The challenges are similar to those of gas injection and the solvents required currently make this method uneconomic for mainstream operators to consider.

Another cold production technology known as viscosity reducing water alternating gas (VR-WAG) is being used in heavy oil reservoirs in Alaska, as steam based methods cannot be used generally due to environmental concerns. VR-WAG involves injecting rich natural gas, which is a gas containing high fractions of ethane and propane, alternating with water injection. The rich gas swells the oil and reduces its viscosity; the lower viscosity oil can then be recovered by water injection.

Cold and thermal recovery optimisation studies Current approaches to recovery planning of heavy oil reservoirs are generally based on empirical approaches coupled with long pilot studies to confirm critical assumptions of the recovery design. An approach that is closer to the recovery planning for a conventional reservoir is, however, now within the industry’s grasp.

The reservoir development strategy is based on an accurate characterisation of the reservoir to build an accurate earth model, which feeds into a predictive reservoir simulator. The simulator is used to optimise reservoir recovery and production goals through carefully conducted simulation studies prior to engaging in any costly pilots. In an ideal world the need for pilots would be eliminated; however, this approach is relatively new due to the recent emergence of the technologies required to follow the approach. Therefore, a simulation study is conducted to mitigate risk

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Figure 2. The density of the crude makes it heavier than

conventional light oil. and to select the most appropriate pilot for optimum recovery and production. A range of technologies are now available that can characterise heavy oil reservoir geology and fluid models.

The classical inputs from seismic and formation evaluation well logs are enhanced by data from nuclear magnetic resonance (NMR) and dielectric logs designed to measure heavy oil viscosity as well as water saturation and relative permeability. Current technology is being developed for soft rock sidewall coring and viscous oil fluid sampling in addition to soft core and fluid analysis technology to measure geomechanical rock properties and pressure volume temperature (PVT) heavy oil properties at reservoir steam temperatures. The data is integrated to build an earth model in a platform such as Petrel* seismic to simulation software, which is used to drive simulation studies to investigate various recovery strategies. Simulation studies using simulators such as ECLIPSE* reservoir simulator or ECLIPSE thermal software allow fast experimentation without the cost of conducting expensive pilots, saving both time and money. Ultimately the optimisation study leads to the design of an efficient pilot to test the critical predictions of the study.

Recovery and efficiency through monitoring and controlAn important trend in the industry is to improve the management of the reservoir to simultaneously optimise recovery, production and energy usage. This effort requires the use of monitoring technologies that measure fluid production parameters (multiphase flow), measurements that are made inside the wells (for example, pressure, temperature, etc.) and interwell or reservoir scale measurements (surface or crosswell measurements such as seismic, electromagnetic and gravity). These measurements provide operators with knowledge of how the reservoir is responding to the EOR stimulus that they are providing.

In addition, measurements of the stimuli are also required, such as steam quality, injection rate, pressure, temperature and surface facility parameters. These can also be made at surface or inside the wells. These measurements must be entered into an integrated system such as the Avocet* production software platform, which also allows operators to control the stimuli to produce the field.

As an example in a SAGD project, technologies exist to manifold the steam injector and the producer to compensate for differences in steam injectivity along the horizontal injector as well as variations in

reservoir permeability along the producer well. A first design for the optimum steam injection rate, generated through simulation studies, is programmed into the completion string. Once steaming operations are in progress, the steam chamber can be monitored through a distributed fibre optic sensor in the producer well, or surface or crosswell seismic measurements and adjustments can be made to the completion string to optimise the steam conformance in the reservoir.

A similar approach is used to adjust and optimise the inflow of oil in the producer. In this way, not only does the operator improve the recovery of reserves, but it is also able to prevent wastage of steam and control production to match the specification of the rest of the system. Some operators are already using an approach similar to that described here and others are gaining interest in this recovery method.

Bringing it all togetherHeavy oil is needed to satisfy current and future oil demand, and advances in exploration techniques enable us to

pinpoint its location. For these reasons an increasing number of oil and gas companies are expanding their heavy oil portfolios throughout the world. As heavy oil is different from conventional oil, new technologies and services are required for production. O T

Note* Mark of Schlumberger.

Figure 3. Visualisation solutions can help solve subsurface challenges.

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