Steam Assisted Gravity Drainage (SAGD) is currently the dominant commercial in-situ recovery process of oil sands resources in Alberta. With long horizontal injector and producer wells and continuous steam injection and production, the performance of SAGD is superior to other thermal recovery process in the high viscosity bitumen environment.
The first few SAGD projects in Alberta were successful in terms of production rates and efficiency of steam/oil ratios. However, a number of the later SAGD projects have not performed as well, operating below the expectations of operating companies.
Here we are going to look at the challenges of meeting “expected performance.”
Reservoir Characterization and Production Forecast
In a number of cases, SAGD projects have performed below expectations because those expectations were overly optimistic or based on incomplete data analysis.
Companies generally develop production forecasts by using analytical and/or numerical simulation. Numerical simulation is preferred as it can take into consideration the heterogeneity of the reservoir, especially reservoirs with more interbedded barriers and baffles which affect vertical permeability.
Sometimes history-matching is performed using an analog SAGD project, if available, but care must be taken to distinguish the difference in reservoir characteristics. Assumptions of how wells were operated in the analog project may need to be made to achieve results because some operating procedures may not be known from public data.
The set up of the geological model used in the simulation depends on the amount and quality of information available from evaluation wells, seismic, and geoscientific interpretation. Limited data on well control, seismic, core analysis and reservoir fluid analysis results in higher uncertainty of reservoir parameters in the geological model.
A more optimistic than realistic production forecast may result from a numerical simulation when inexact assumptions of operating procedures, and a high uncertainty geological model are used. The negative impact of the extent, placement and frequency of vertical permeability barriers and water rich, high mobility zones may not be properly taken into account. As a result, the production forecast will be optimistic.
Moreover, in order to attract investment and to obtain approval and sanction for a project, some companies may tend to use data from the better part of a project area for modelling to get a better economic evaluation.
Well design is critically important to the success of a SAGD project, including well placement; lateral spacing between well pairs; horizontal well trajectory; sand control design; and casing and tubing design.
- a) Placement of wells:
In order for a company to book more reserves, wells may be placed close to the bottom of the exploitable part of the reservoir. However, the performance of the wells could be compromised if the lower zone has lower permeability zones, low oil saturation zones or is too close to the bottom water.
- b) Lateral spacing between well pairs:
If the lateral spacing between well pairs is too large, there is steam and heat loss to the reservoir in between the well pairs, especially in the first few years of operations. This would negatively impact initial performance of the wells. However, follow-up infill wells can be used to recover the heat, and improve steam oil ratio.
- c) Horizontal well trajectory:
An improper horizontal well trajectory, undulated along the bottom of reservoir rather than a flat horizontal profile, and non-uniform separation between the injector and producer can cause communication between the injector and producer in a short horizontal section (short-circuiting), resulting in a negative impact on the development of the steam chamber. This can also happen if the vertical spacing is too small between the injector and producer (either by design or equipment error).
- d) Sand control design:
Slotted liners used to be the standard sand control design for SAGD wells, but this has changed over time.
Laboratory tests are usually conducted to provide an optimum slot design. If the slots are too large it could cause excessive sand production. Slots too small can easily get plugged with fine sand. In some reservoirs of the Upper and Middle McMurray, Wabiskaw, and Clearwater Formations, the sands are finer and may cause plugging and impede the inflow of production fluids. The negative impact on production rate would be worse for slotted liners with smaller openings than for other sand control designs such as wire-wrapped screen liners. Wire wrapped screen liners are more common in newer SAGD producers in Lloydminster, at Husky’s Tucker Lake Project, at the JACOS Hangingstone expansion and at Devon’s Jackfish 2 Project.
- e) Casing and tubing design:
The pressure drop in circular pipes depends on the length and diameter of the pipe as well as the flow velocity. Smaller pipe diameter, longer pipe length and higher flow rate will cause a higher pressure drop. Although smaller casings (and thus smaller holes) will reduce the cost of drilling and smaller tubing will reduce the cost of well completion, the resulting high pressure drop may cause flow control problems. For steam injector, the injection pressure at the heel could be significantly higher than the pressure at the toe, and vice versa for the producer. Thus the pressure differential at the heel will be much higher than the pressure differential at the toe. This imbalance will make it more difficult for steam conformance and subcool control.
If individual wells do not produce as much as expected, the project will not reach its designed capacity unless more wells are drilled. However, a project’s steam generation capacity is designed based on the designed steam oil ratio. If the steam oil ratio is higher than forecast, there will not be enough steam to yield the designed project oil rate no matter how many wells are drilled.
Facilities should be designed with input from the operations team and consider factors addressing ease of servicing the equipment and vessels, as well as proper locations of measuring devices and sample points. Designers should be mindful that a design which works well in California may not be appropriate for the cold environment of a Canadian winter. Retrofitting the facilities after the fact would delay the production ramp up.
Reliability of the facilities plays an important role in meeting the production target. Problems in the steam generators and problems in the high temperature steam separator, which prevent consistent production of high quality steam, will negatively affect the project performance.
In the forecast of well performance from reservoir simulation, it is usually assumed that the whole horizontal section of the well contributes to production. Even if heterogeneity of the reservoir has been taken into consideration in the simulation, missteps in operation could negatively impact well performance. Some missteps may include:
- Premature Conversion from Circulation Phase to SAGD Phase:
In order to meet a certain production schedule, SAGD wells are sometimes converted from circulation phase to normal SAGD phase prematurely, without sufficient thermal communication between the injector and the producer along the full horizontal length of the wells. Because sufficient thermal communication may be from only a small horizontal section of the producer, the production could drop after a short time, or would not improve as expected.
Another operating procedure which may cause production problems is the application of a high pressure differential between the injector and producer during circulation in an attempt to accelerate the communication (bull heading). Although this can help with a faster start-up, this forced communication can cause difficulty establishing uniform steam chamber development along the well length (conformance), as bull-headed communication would be along the more permeable section of the well only. Moreover, there is a higher risk of sand production and abrasion, resulting in liner damage.
- Subcool Control:
Subcool is the temperature difference between steam saturation temperature of the injector and the production temperature of the producer. Subcool control is very important in SAGD operation. If the production temperature of the producer is close to the steam saturation temperature of the injector, the subcool is low and vice versa. Low subcool is usually preferred to maximize production because oil viscosity is lower at higher temperature. However, care must be taken by the operator to ensure that the subcool will not become too low as it would result in more steam production. The high velocity of the steam and the sand or fines it may carry, could result in sand production and liner damage in the producer well. It is to be noted that some reservoirs can tolerate a lower subcool while some may need to operate at a higher subcool, depending on the tendency of sand production.
- Pressure Control and Fluid Balance
Although the operating pressure is supposed to be below the maximum operating pressure (MOP) as assigned by the regulator, human or equipment errors may cause the operating pressure to be higher than the MOP, in which case the caprock could be breached. The loss of steam and fluid from the oil sands formation through the caprock not only affects the well performance, but may also cause environmental damage including cross flow into shallower formations, contamination of overlaying aquifer zones, or a surface blow out.
One way to regulate reservoir pressure is to monitor the volumes of injected and produced fluid. Significant imbalance in favour of injection may cause over-pressuring of the reservoir, unless there are thief zones. On the other hand, aggressive production without sufficient injection can cause a pressure and temperature drop in the reservoir.
- Data Collection and Quality
Availability of good quality data is essential to the evaluation of project performance. This includes but is not limited to pressure, temperature, and fluid volumes. Measurement tools may not always function properly, especially during winter. Using erroneous data to analyze the SAGD project performance will result in an ineffective or potential damaging strategy.
- Communication of Personnel
Although an overall operating strategy is usually set up for the project, each SAGD well pair may need to be operated differently to optimize performance. Conflicting opinions between the members of the operating team (reservoir engineer, production or operation engineer, geoscientists, operators, supervisors and managers) may occur as to how to operate the wells. The responsibility and accountability of each team member should be well defined to prevent communication breakdown. Effective communication channels should be established early between operation, production and reservoir staff.
Conclusions and Recommendation
There are many factors that can cause a project to perform below expectations. These include:
- Production forecast too optimistic
- Insufficient data for reservoir characterization
- Improper well design
- Facilities design and reliability issues
- Various operational issues
Importantly, some companies may want to use a more optimistic forecast to attract investment, but this creates a high risk of not meeting performance expectations.
My recommendations are:
- Be realistic.
- Recognize the limitations of available data for reservoir characterization and the resulting uncertainties.
- It may be warranted to forecast a range of steam/oil ratio and project production rather than a single number.
- Project design and operation decisions should be based on industry best practices and principles of sound engineering. Avoid undue consideration of politics or optics.
- Utilize technical people with SAGD expertise and experience in order to increase the project’s chances for success.
By K.C. Yeung
K.C. Yeung is currently Chairman, Partners Energy Development Corp. in Calgary, Canada. He has more than 40 years experience in the oil and gas industry, primarily in the area of heavy oil and oil sands reservoir development and R&D. He previously worked for Texaco Exploration Canada, Suncor, Husky and Brion Energy (now PetroChina Canada), He was a past President of the Canadian Heavy Oil Association (2005/2006), past Chairman of the Petroleum Society of CIM (2007) and past Director of Society of Petroleum Engineers (SPE) Canada (2011-2013). He had been the Technical Conference Chairman for the World Heavy Oil Congress (WHOC) from 2006 to 2018. He currently serves on the Board of Directors for Energi Simulation. He is an Associate Editor for the SPE Reservoir Evaluation and Engineering Journal. Mr. Yeung has been giving lectures and short courses on heavy oil recovery methods in Canada, China, Europe, Middle East, South America and U.S. to promote Canada’s heavy oil technology and to share his knowledge and experience with the industry.