June 2007, Volume 46, No. 6 49

Investigation of Key Parameters in SAGD Wellbore Design and Operation

P.A. VANder VAlk*, P. YANg Nexen Inc.

*Now with encana Corporation

Peer reviewed PaPer (“review and Publication Process” can be found on our web site)

IntroductionIt is generally accepted that optimal SAGD performance re-

quires control of produced fluids to some subcool value so that a liquid level is maintained above the production well. This liquid level reduces the tendency for steam to flow directly into the pro-duction well liner, which ensures that steam is used efficiently in the SAGD process. However, too much liquid accumulation can reduce productivity, primarily due to a lower fluid temperature and corresponding higher fluid viscosity at the drainage faces and at the critical points of convergence to the production liner.

Optimum performance of the SAGD process can be defined for each project and reservoir type, however optimization is generally based on bitumen production rate (CDOR) and steam-to-oil ratio (SOR), often with conflicting imperatives.

One critical parameter in this optimization is subcool. Nasr’s work indicates that there is no appreciable difference in CDOR be-tween 5˚ and 30˚C of subcool for two-dimensional models (Tawfik Nasr, Alberta Research Council, Personal Communication, Feb-ruary 2005). However, Ito and Suzuki(1) demonstrated that the optimum SOR for the Hangingstone reservoir occurs at subcool ranges of between 30˚ and 40˚C with reasonable productivity. Edmunds(2) indicated that 20˚ to 30˚C subcool was a reasonable

AbstractA simulation study was carried out to evaluate the impact of

wellbore pressure drops and subcool control on SAGD reservoir performance using a three-dimensional fully coupled reservoir/wellbore model. This work builds on several concepts introduced by others and attempts to provide a method to evaluate these con-cepts and the relationships between them.

The results indicated a significant impact on steam chamber conformance, productivity and SOR at various operating pres-sures due to wellbore pressure drops. Pressure profiles within the injection and production wells were transferred into the reser-voir, skewing the predominantly gravity drainage process. The chamber shape and conformance influence performance as it re-lates to subcool control. Sensitivities were run to evaluate the im-pact of key parameters.

This paper highlights some critical factors that affect SAGD performance and behaviour. Potential mitigating measures are in-troduced, such as liner and tubing design, variable perforations and injection ports, along with practical operating implications of each. The impacts of the findings on artificial lift selection and operation are discussed with regard to subcool control and net positive suction head available (HPSH). Potential implica-tions to low pressure (LP-SAGD) operations are also considered in that light.

operating target for the 2D cases. However, he discussed the real world complications of the three-dimensional case in some detail as well.

Edmunds’ work hinted that localized variability in subcool would occur, so that control of production rates to some optimum mixed or average subcool would result in steam production at some points along the liner, and large liquid level accumulations at other points. This is primarily due to the fact that the flow ca-pacity of the wellbores is much greater than that of the reservoir in the same direction, making compensating steam movements in the reservoir difficult. Also, local liquid levels can not effectively drain parallel to the well due to the very low drainage angles(2). Edmunds discussed the concept of multiple solutions and that typical mixed subcool control to 5˚ to 20˚C would likely draw steam into the pro-duction liner at certain sections.

Kisman(3) took this discussion further by evaluating the impacts of variable drawdown in 3D modelling. His results concluded that an aggressive mixed subcool control strategy or even steam pro-duction was required for optimal 3D performance. Drawdown variations, as studied by Kisman, are prevalent in all Athabasca reservoirs due to geological heterogeneities, flow convergence ef-fects and liner design and plugging issues.

Subcool is not the only critical operating parameter in SAGD. The shape of the steam chamber, steam distribution and inflow conformance are arguably as or more important, and each of these parameters act in concert in the recovery process. Edmunds and Gittins(4) discussed the concept of steam distribution in SAGD wells and the importance of the pressure drop in the injection liner in defining chamber shape and process performance. The general concept is as follows: injection well pressure gradients are inferred into the reservoir and overpower the relatively small pressure gra-dients in the production wells, resulting in a sloped fluid interface. The fluid accumulates to compensate for the overall pressure gra-dients by increasing hydrostatic head in the lower pressure areas of the reservoir. Thus, it is generally accepted that optimal injection wells should be designed to ensure that the average pressure drop is less than 45 kPa for well pairs with a vertical separation of 5 m.

Ong and Butler also evaluated the impact of wellbore pressure drop and well size on SAGD performance, focusing on mixed vis-cosity relationships and the hydraulic capacity of the production well(5). They concluded that SAGD performance would be im-peded if the well diameter was too small, which would cause hy-draulic losses in the well and skew the liquid interface parallel to the well pair.

The bulk of this paper deals with the investigation of these two fundamental SAGD concepts: subcool and wellbore pressure drops in 3D modelling scenarios.

50 Journal of Canadian Petroleum Technology

Reservoir Coupled SAGD ModelsThe majority of the modelling work studied in this paper was

carried out with the EXOTHERM reservoir simulator. Tan, Butter-worth and Yang(6) outlined the model construction, methodology and validation.

For more detailed analysis of the injection well hydraulics, Q-Flow (a discretized thermal wellbore simulator) was utilized. This software provided more flexibility, instant results and finer discrete resolution as the transient and time-based effects of the reservoir are intentionally excluded. This model was used to independently evaluate wellbore pressure drops and steam quality distributions for various completion scenarios.

Overview and ProcedureDescription of the Reservoir Model

The model was set up as a typical Athabasca reservoir with rock and fluid properties similar to those outlined by Edmunds(2). The reservoir and wellbores were constructed with 8 to 100 m sections along the well length and with 1 m by 1 m grid blocks in the x and z directions. The reservoir is characterized by 25 m of pay thickness, with clean sands in the vicinity of the wellbores and some distrib-uted shale sections higher in the reservoir. The wells are maintained on a flat trajectory through all cases. The basecase production well design is an 800 m long, 178 mm liner section with a 114 mm pro-duction tubing string landed at the toe such that production fluids converge at the toe tubing inlet and flow through the tubing to the heel. The basecase injection well has the same mechanical config-uration, but injection occurs at both heel and toe points.

Control of the Reservoir Model

The circulation phase was handled consistently for each run. Steam was circulated down the injection well and returns from the injection well were limited to 60 m3/day. Simultaneously, 60 m3/d of steam (CWE) was also circulated down the production well and return volumes were allowed to increase over time. This allowed for steam injection into the injector to increase during the circula-tion phase and provided a smooth transition to SAGD mode. Full conversion to SAGD occurred at 60 days.

Production well control was based on a constant mixed subcool control point in the ‘build’ section of the well, inside the tubing string for the entire well life. For the purpose of this study, sub-cool was defined as the difference between the control point satu-rated steam temperature and the temperature observed at that same point. It was critical to ensure that the control point was not in the open liner section (adjacent to inflow) to adequately capture the notion of mixed subcool. This methodology produced very stable production profiles at all subcool values. This is the most realistic modelling control point for any artificial lift system.

Steam injection was based on 100% quality at the heel of the well. The volume split was based on 2,700 kPa being available to both strings in the ‘build’ section. This assumption ensures that counter-current heat exchange effects are suppressed by limiting the flow of steam in the tubing string. Figure 1 shows the basic physical setup of the model.

Where bitumen rate (CDOR) and steam-oil ratio (SOR) are quoted, they are as the average over a 1-year period from 1.5 to 2.5 years. This period represents the plateau of the production profile and should appropriately indicate stable long-term performance. Where pictures or parameter details are used, they are extracted from the end of two years (730 days).

Q-Flow Model Design and Description

The more complex wellbore modelling work was decoupled from the reservoir and completed using Q-Flow. The details and functionality were outlined by McCormack(7). This model was pri-marily used to study the frictional pressure drops, steam quality dis-tribution and counter-current heat transfer effects in the injection wellbore. For the purposes of this study, the mass flow entering the reservoir was considered constant along the well length and well-head qualities were assumed to be approximately 95 – 97%.

Summary of Cases Studied

• Basecase• Smaller Injection Tubing• Larger Injection Liner• Smaller Production Tubing• Mid-sized Injection Liner• Low Pressure Basecase• Low Pressure Large Injection Liner• Variable Slot Density on Injection Liner• Alternate Completion Methods with Q-Flow

Modelling ResultsBasecase [178 mm (7 in)] Injection liner

The base design was completed with a constant subcool through the duration of the run. Figure 2 shows bitumen production rates (CDOR) for the various subcool values. Two cases were run with some live steam production (5 and 30 m3/d) at the control point. It is clear that the highest productivity occurs with a very low subcool or with some live steam produced. Figure 3 shows the

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FIGURE 1: Basic model architecture.

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FIGURE 2: CDOR for 178 mm injection liner with various subcool (steam draw) targets.

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FIGURE 3: Rate and SOR vs. subcool for 178 mm basecase injection well.

June 2007, Volume 46, No. 6 51

average plateau SOR and CDOR again with various subcool values or some live steam production.

This well architecture tends to limit steam injection at the toe to approximately 40%. This injection split leads to pressure gradients in the production and injection wells as shown in Figure 4. The rel-atively small annular flow area causes frictional pressure losses as flow moves from the injection point and is delivered through the liner slots to the reservoir. These pressure gradients are imposed on the reservoir as the reservoir does not have the hydraulic capacity to evenly distribute the pressure, even with steam movement in the chamber along the axis of the well. The result is a steam chamber that is drawn down to the production well at the heel and toe. Fluid accumulates above the producer in the other areas’ head to achieve pressure equilibrium.

In the middle sections of the well pair, the steam chamber is demonstrating a ‘chimney’ effect. This is shown in Figure 5, which compares the steam chamber shape at segments 1 (heel), 3, 5 and 8 (toe).

Figure 6 shows the production rate for each segment along with the fluid level point where the chimney widens. Clearly produc-tivity is maximized in areas with a very low liquid level (i.e. low

local subcool) and impaired in areas with a high liquid level, espe-cially if the injector is flooded.

Figure 7 shows the incremental bitumen production between the 20˚C subcool and 1˚C subcool cases. The boost in production at 1˚C mixed subcool is notably from the middle sections of the well-bore, and the end sections see little incremental production or even a drop in production with more aggressive subcool control.

This response appears to be due to the fact that as steam is drawn into the production liner, mass flow in that area is somewhat self-limited due to the specific volume of steam and turbulent flow effects. More aggressive control then implies a larger system draw-down and thus a larger drawdown at each wellbore segment. This causes more oil to be produced from the alternate segments.

Smaller Injection Tubing

Another model used the same 178 mm liner, but replaced the 114 mm tubing with an 89 mm string. This design has the effect of injecting a greater proportion of steam to the heel, given the pres-sure assumptions controlling the injection flow. The percentage of total injection to the toe was reduced from about 40% to approxi-mately 10% for this sensitivity. Otherwise, excessive counter-cur-rent heat transfer would occur, resulting in superheated steam at the heel and low quality steam at the toe. This injection split causes an even more severe pressure gradient at the heel of the well and exaggerates the fluid level so that steam is only drawn down at the heel.

These exhibited similar results in the SOR and CDOR at sub-cool values less than 30˚C, similar to those of the basecase as shown in Figure 8.

larger [245 mm (95/8 in)] Injection liner

A full set of model runs were completed using the same config-uration and procedure as the basecase, with the injection liner size increased to 245 mm. These runs showed a consistent improvement in productivity (up to 22%) and SOR over the entire range studied,

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FIGURE 4: Injection and production well pressure gradients for 178 mm liner at 20˚C subcool.

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FIGURE 5: Comparison of steam chamber shape for 178 mm and 245 mm injection liner at Segments 1 (heel), 3, 5 and 8 (toe).

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FIGURE 6: CDOR vs. fluid level above producer for 178 mm injection liner.

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FIGURE 7: Comparison of CDOR per section of well length for 178 mm injection liner with 20˚C and 1˚C subcool (2,700 kPa).

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FIGURE 8: CDOR and SOR for 178 mm injection liner with 89 and 114 mm tubing.

52 Journal of Canadian Petroleum Technology

especially in the 10˚ to 20˚C subcool range. Figure 9 shows the comparison of CDOR and SOR for the base and 245 mm cases.

The pressure drop in the injection well for these cases was con-sistently low at 13 kPa. The SOR starts to increase for subcool values less than 20˚C. The slope of this increase is consistent and is caused by steam vapour drawn into the production well, having not consumed its latent heat in the process resulting in reduced SAGD efficiency.

Investigation of the fluid level above the production well in each of the blocks indicates that the chamber is drawn down near the toe of the well, while the fluid level at the heel sections remain at or just below the injection well. The production rate in each of the segments is more uniform than the basecase, as is shown in Figure 10. This productivity is dependant on the steam chamber height and width. Figure 5 shows a comparison of chamber shape for the 245 mm and 178 mm cases.

With minimal pressure drop in the injection well (13 kPa), the pressure drop in the production well (33 kPa) dominates fluid level tilt. The fluid is drawn very near to the production well for sev-eral segments closest to the toe. Ideally, the production well would have minimal pressure loss, however the 114 mm tubing leaves a small annular flow area which causes significant pressure drop.

Smaller Production TubingA sensitivity with smaller (89 mm) production tubing indicated

that performance was not appreciably impacted. However, the res-ervoir fluid level was flatter, productivity was slightly skewed to the heel and SOR was much more uniform for each of the seg-ments. This shows that the frictional pressure losses in the produc-tion well can have an impact on steam chamber growth. The CDOR per section was more uniform as the pressure drop in the produc-tion liner was reduced from 33 to 11 kPa. This may not seems sig-nificant, but when wellbore undulations are taken into account, the impact on rate may be appreciable.

This low pressure drop, combined with the low injection liner pressure drop, made for the most uniform steam chamber growth and fluid levels. Note that the difference in hydraulic loss in the production and injection wells was only 2 kPa; nearly ideal.

219 mm Injection linerAnother sensitivity run was made using a 219 mm injection well

liner to evaluate if there is a linear relationship between liner size and SAGD performance. The results indicate that productivity and SOR were nearly identical to the 245 mm case, indicating that at the injection rates studied, the cost of the larger (245 mm) liner may not be justified. The authors recognize that directionally, 219 mm liners may provide suitable technical and economic benefits, but suggest further evaluation work for a wide range of reservoir situations is required.

low Pressure CaseSensitivities were run on both the 178 and 245 mm liners for

lower operating pressure. These cases were carried out by initially running the model at 2,700 kPa and 20˚C subcool for the first year.

Then the injection pressure was reduced to 1,400 kPa and sub-cool controlled at target for the duration of the model run. The pur-pose of these sensitivities was to study the expected increases in frictional pressure losses in the injection well from the effects of the specific volume of steam at lower operating pressures. These effects would be balanced against the reduction in steam rate re-quired at lower pressures. The lower steam requirements are due to two factors: 1) decreased CDOR due to increased viscosity; and 2) decrease in reservoir heat ‘loss’ and SOR.

Results from the 245 mm case indicated that CDOR and SOR decreased according to expectations as derived from temperature and viscosity relationships (approximately 40% loss of produc-tivity for the pressures studied). This indicates that the large in-jection well architecture is still optimal as the total pressure drop in the injection well only increased from 10 kPa to 30 kPa and the fluid level remained below the injector for the full well length.

Results from the basecase (178 mm) showed fluctuations in the SOR and reduction in CDOR for the 10˚ and 20˚C subcool cases that are greater than would be expected by simple viscosity reduc-tions. This behaviour was evident in the higher pressure basecase but was exacerbated in the low pressure runs as is shown in Figure 11. This behaviour was evident for both 114 and 89 mm tubing strings, with exaggerated reduction in efficiencies. These cases ex-hibit more extensive flooding on the injection well than the 2,700 kPa cases. Therefore, the loss in SAGD efficiency at lower pres-sures will be even greater than at high pressure. This is likely due to the impact on lower absolute temperatures (thus more viscous bitumen) for the same subcool values at lower pressures.

Slot density – designed SkinSteam injection could be biased by imparting a designed ‘skin’

on the injection liner. The general principle governing the tilted fluid level, as outlined by Edmunds(2), is that the pressure drop in the annulus of the injection well is easily transferred into the reser-voir, creating a higher pressure in the heel area inside the chamber. This pressure gradient causes a liquid level variation along the length of the well. Thus, the heel dominates the chamber shape as discussed.

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FIGURE 9: CDOR and SOR vs. subcool for 178 and 245 mm injection well designs at 2,700 kPa.

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FIGURE 10: Productivity and steam injection for 245 mm liner at 2,700 kPa and 20˚C subcool.

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FIGURE 11: CDOR and SOR for 178 mm liner at 2,700 and 1,400 kPa.

June 2007, Volume 46, No. 6 53

If an equivalent pressure drop (or ‘skin’) could be designed into the injection liner, imparting variable flow resistance, reservoir pressure gradients would be greatly reduced or even eliminated. Kaiser et al.(8) addressed production well liner design optimiza-tion using this principle combined with convergent pressure ef-fects. The design logic would need to be re-framed for injection of steam rather than production of emulsion. However, the concepts of open area, skin and flow convergence/divergence would still be applicable.

The volume of steam compared to that of emulsion (water) flowing through the slots would dictate that the slot density varia-tion required for ideal design would be two orders of magnitude greater than the ideal design for a production well. Flow velocities of steam for a fully optimized system approach the speed of sound and, as such, design risk such as jetting erosion, non-Darcy flow and system flexibility must be appropriately addressed.

A compromise design utilizing blank joints could be imple-mented to impart variable open area. This should improve per-formance to some extent by using the reservoir and subcritical divergence effects to ‘buffer’ the pressure distribution.

Figure 12 shows the modelled results of an injection well with variable slot density (5 to 100% of the fixed density case) from the heel to the toe of the liner. This virtually eliminates the pres-sure gradient in the reservoir near the heel. It can be seen that the overall performance of this design is better than the basecase and a fully engineered case should converge on the 245 mm design.

Alternate Completion Methods

The benefits of the larger liner are demonstrated above and are even more critical in cleaner reservoirs or longer wells with higher total steam injection and production rates. The simplest approach to well design to account for pressure gradients as discussed is to increase the liner size from 177 mm to 219 mm, or even 245 mm. In the case of very long wells (1,000 m or more) or very high rate wells (700 m3/d or more of steam injection), liners have been de-signed and installed in the field as large as 273 mm. The benefits of these designs is a reduced pressure drop in the liner annulus and improved reservoir performance through a more uniform steam in-jection distribution and uniform production inflow characteristics.

The high capital cost of larger liners is often challenged at project approval and has been difficult to justify with the pub-lished results to date, though a case could be made based on the results of this study. Typical installation costs of a suitable 245 mm liner design with completion tend to be in the order of 40% higher than the equivalent length 177 mm well. This is due to require-ments for larger hole sizes, casing sizes and increased rig time. Ta-pered liners have been contemplated, however the incremental cost savings are minimal as hole size and intermediate/surface casing designs would be identical. So are there other methods that can be employed to ensure the injection well hydraulic gradients are minimized?

Small diameter Insulated TubingA typical 177 mm injection well with 89 mm outside diameter

insulated tubing would provide a reasonable flow area in the liner annulus while ensuring minimal heat transfer between the tubing and annulus fluids. This would allow a greater proportion of steam to be injected to the toe (ideally 50% of total), reducing pressure gradients while maintaining even quality distribution. However, SAGD performance benefits are limited. As well, the long-term re-liability of insulated tubing and its high cost typically limit its use on commercial projects.

Tubing Pull Back WorkoverA reasonable solution to existing injection wells that have a sig-

nificant pressure gradient or a strategy for future wells may be to circulate the wells with tubing placed to the toe. Then, some period of time after initialization of the SAGD process, pull the tubing string back to some intermediate point such that the pressure gra-dients are minimized or balanced with the production well. An ex-ample of this end configuration is outlined in a similar strategy in the Senlac Phase C injection wells(9). The downside of this method is that a high pressure-high temperature workover would be re-quired and that positive placement of steam to the toe is sacrificed. However, this method is very suitable for wells that do not require circulation prior to SAGD.

extended Concentric TubingLong Lake SAGD injection wells are designed with a 177 mm

tubing string landed just above the liner top with 114 mm tubing run concentrically/eccentrically inside the 177 mm string, landed at the toe.

A slight modification to this typical concentric design would ad-dress many of the injection design issues raised. The short tubing string could be extended to some length, so that the end of the string is approximately one third of the distance into the liner sec-tion. This length would be chosen such that the hydraulic pres-sure drop back to the heel is nearly equal to the hydraulic pressure drop to the toe injection flow null point. This would require that the short string size be reduced to fit safely inside the liner. The long string diameter could be reduced to 89 mm at the interme-diate casing point (ICP) and run through the short string to the toe. Figure 13 shows this completion method. This configuration would essentially split the flow from heel injection into two direc-tions rather than from the heel to the liner section. This dramati-cally reduces injection annulus hydraulic pressure drops over the critical high flow area near the ICP by simple flow splitting. Figure 14 shows a comparison of the annulus pressure and quality profiles for this design compared to the 219 mm injection liner with 114 mm tubing to the toe. The results indicate a significant decrease in the pressure gradient near the heel of the well.

Modelling work indicates that the control and operation of this design requires detailed analysis. The inner annulus flow area is re-stricted from the heel to the outlet of the short string. This creates a significant pressure drop and, in turn, causes a pressure differential between the long and short injection strings. This situation causes extreme heat transfer from the short to the long string and results

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FIGURE 12: Comparison of bitumen rate for fixed and variable slot density at 20˚C subcool.

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FIGURE 13: Extended concentric completion.

54 Journal of Canadian Petroleum Technology

in superheating of the tubing string and loss of quality in the short string. However, after the short string outlet, heat is transferred back from the tubing to the annulus. An optimal design would bal-ance both pressure drop and quality of injected steam.

Study work completed to date on this design indicates that it is suitable for a wide range of steam injection rates and provides greater operator flexibility to control steam quality at the toe of the injection well. However, proportions of steam injection to the long and short strings seem to require tight flow controls and may re-quire a cascade flow control scheme. The effects of superheating steam, TDS precipitation and corrosion should be considered further.

Steam Ports or limited entry Perforation (leP) design

Typical SAGD injection schemes deliver steam to the liner an-nulus at two points (toe and heel) and then flow is distributed from those points. This causes large localized pressure gradients near these points. If injection could be achieved through several points, localized flow rates and corresponding pressure gradients would be significantly reduced.

This could be accomplished with the use of critical flow con-trol using LEP (Limited Entry Perforations), or the simple addition of appropriately sized (subcritical) nozzles along the long tubing string while maintaining toe and heel injection. The sizing of these nozzles could be carried out with the methods outlined by Small(10) or Boone et al.(11) in either critical or subcritical flow regimes.

Preliminary modelling results show that this methodology would reduce the local pressure gradients near the heel of the well by nearly an order of magnitude compared to the basecase. This would provide a pressure profile superior to even the 245 mm liner case at significantly lower cost. However, pure LEP de-signs may have extensive tubing annulus heat transfer, causing a slight quality variation in the annulus. Modelling indicates that the quality dropped inside the tubing string and that the annulus steam was superheated. It is expected that the heat transfer would be large enough to ensure a reasonable quality distribution through the en-tire well length. These effects require more detailed study to fully appreciate. Design and testing of suitable injection ports, resistant to nozzle wear and buffer flow impingement on the liner, are re-quired to ensure liner and nozzle integrity are maintained.

Discussionliner Friction loss

Hydraulics in both of the injection well and the production well can have an effect on the steam chamber growth and conformance. Given an ideal reservoir with uniform clean sand, optimal well designs would eliminate any pressure losses in either wellbore. However, some hydraulic losses in the injection well may be com-pensated for by opposing pressure losses in the production well to some extent.

Any pressure gradient in the well will result in pressure gra-dients in the reservoir which must be compensated for by steam movement and hydrostatic head (fluid level). If the fluid level is al-lowed to rise above the injection well, optimal SAGD performance will be sacrificed.

Mixed Subcool TargetsConfigurations which have low fluid levels (below the injection

well) will be less sensitive to subcool control. Productivity should be near optimal up to 20˚C subcool, with less than 5% reduction in CDOR (see Figure 9). SOR would actually be optimal around 20˚C subcool.

Configurations which have low localized fluid levels and ‘flooded’ fluid levels in other areas require very low subcool con-trol or even some steam draw. Otherwise, significant reductions in CDOR (15 to 20% less than optimal) may occur.

geologyAll of the design theory discussed above applies directly to uni-

form reservoirs. However, the Athabasca deposits are renowned for their geological heterogeneity. Shale stringers, breccia and IHS bedding between the injection and production wells will result in variable permeability and gravity drainage characteristics, and thus, variable local inflow rates along the wellbore length. These impacts will skew the local subcool values as much or more than a non-optimized injection well design. The authors recognize this fact, but also adhere to the philosophy of designing to controllable factors. That is, design the optimal well architecture for a uniform geological environment.

If geological certainty could be increased, it is conceivable that these concepts could be further studied and harnessed to optimize SAGD well design and operating performance to account for geo-logical impacts such as pay pinch outs and thick shale bedding.

Flexibility – Balance of designOne must be careful in the application of the design principles

discussed. It would be easy to focus on one parameter and lose sight of others. Many alternate factors must be considered in the architecture and it is important to balance the optimal technical de-sign with other factors to ensure the design has some flexibility. These other factors include:

• Productivity/Injectivity Range (field experience shows that +/- 30% of average design is reasonable);

• SOR range (+/- 20%);• Planned or unplanned changes in operating pressure;• Managing the circulation phase;• Capital cost; and,• Workover strategies, safety and operating costs.

MeasurementAs discussed above, the mass production rate control in the

EXOTHERM models was achieved by maintaining a constant sub-cool in the intermediate casing section of the well. In reality, opera-tors do not typically have the temperature and pressure data at this point in the well unless a pump is used as the lift mechanism. More typically, temperature and pressure are measured at the toe of the well in the annulus prior to entry into the production tubing. Prac-tically, the measured control points and heat exchange effects must be considered for each different operating situation. For example, toe subcool measurements may indicate that steam is present at the toe of the well, but the actual subcool in the build section may be relatively high. However, the basic principles and methodology discussed are valid in most cases.

Producing PointsHeel or multiple production points were not directly studied in

this work. However, results above indicate that the production well design may have a slight impact on chamber growth, depending on liner and tubing size and placement. Ideally, allowances for

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1,420

1,430

1,440

1,450

1,460

0 39 78 117

156

195

234

273

312

351

390

429

468

507

546

585

624

663

702

741

780

819

858

Liner Length (m)

Pre

ssur

e (k

Pa)

0

0.2

0.4

0.6

0.8

1

1.2 Steam

Quality (fractio

n)

Pressure ext. Pressure no ext.

Quality ext. Quality no ext.

FIGURE 14: Injector annulus pressure and steam quality for extended concentric design vs. non-extended 219 mm liner with 114 mm tubing.

June 2007, Volume 46, No. 6 55

production from at least two points should be considered for oper-ating flexibility and pressure gradient minimization.

Implications for Artificial liftGas or steam lift has long been the standard for artificial lift in

SAGD wells, however, recent design modifications to electric sub-mersible and other pump designs have provided a choice for opera-tors. Edmunds and Chhina(12) noted the benefits of lower operating pressures on SOR, facility costs and project economics. Kisman(3) also noted the need for lower pressure operations due to gas over bitumen issues and thief zones. But he also discussed the impor-tance of steam trap control on bitumen productivity and SOR, con-cluding that vigorous control with very low mixed subcool values was required for optimal long-term performance.

The results of this study indicate that there will be a wide range of subcool/performance relationships for SAGD well pairs. De-pending on friction loss and chamber flooding effects, aggressive subcool may not be required. Low pressure gradient designs will provide the greatest flexibility and choice in artificial lift selection, design and operation.

Artificial lift System limitationsGas lift has limitations, such as fluid rate reductions at lower

bottomhole pressures. Depending on fluid rate, gas lift seems to be operable down to 30 to 40% of the system head. This points to the need for a mechanical lift system (pump) for some SAGD applications.

However, all pumping systems require a fluid level above the intake of the pump, which can be expressed as net positive suction head required (HPSHr). In order for a pump to work efficiently, the available head must be greater than the head required.

Head available can be expressed as the difference between the pressure at the pump intake (corrected for loss of head due to fric-tion and elevation change) and the saturation pressure of steam at the temperature of the system. This is essentially a pressure form of the subcool relationships. For example, a pump with suction pressure of 1,400 kPag and 191˚C (7˚C subcool) would have an NPSHa of 200 kPa. Many pumping systems, including electric submersible pumps, have NPSHr < 200 kPa.

A well system will have a lower NPSHr at lower pressures for a given subcool, due to the steeper slope of the steam saturation curve. That means it will be harder for a pump to achieve very low subcool control at lower operating pressures. Additionally, any heat generated by the lift system (such as a downhole motor) must be accounted for in the evaluation. This only highlights the need to consider the injection well design in SAGD, especially in lower pressure applications where the effects of steam behaviour on the reservoir and lift system is most aggravated.

Further StudyThe results discussed in this paper are a small sample of the pos-

sible scenarios that could be studied, and the concepts and notions discussed justify further study and explanation. The methodology presented may have merit in evaluation of the following:

• Detailed evaluation and analysis of basecase CDOR and SOR deviations at moderate subcool. This would include evalua-tion of heat exchange effects in the production well, removal of the production tubing and elimination of geological im-pacts at the top of the reservoir model.

• Evaluation of recovery factors, with models run to a predeter-mined economic cutoff rather than an arbitrary time cutoff. It is postulated that recovery factors would not be appreciably impacted, however, this assumption requires validation.

• Operating with variable drawdown and geological hetero-geneities as outlined by Kisman. Can geology be defined accurately enough to justify designing wells to counteract geology?

• Sloped trajectories and wellbore sinuosity effects on ramp-up rates and recovery factors.

• Developing strategies to modify operating parameters and targets based on observed steam breakthrough. How is a change in injection control or architecture translated into im-proved performance or modification of the chamber growth path?

• Further study of multiple injection points and alternate com-pletion schemes discussed. The results are promising, but merit further study and definition.

Conclusions1. A fully coupled model (Reservoir – Wellbore) has been suc-

cessfully applied to evaluate SAGD well architecture.2. CDOR is relatively insensitive at subcool less than 20˚C for

designs with low frictional pressure drop for both high and low pressure cases.

3. CDOR is very sensitive to subcool for designs with high fric-tional pressure drop, pointing to the need for aggressive sub-cool control (some live steam draw).

4. CDOR and SOR are severely impacted by mixed subcool control beyond 40˚C in all cases.

5. Pressure gradients are transferred into the reservoir and com-pensated by steam movement and fluid level buildup.

6. Wellbore hydraulic capacity dominates inflow conformance in clean sands. SAGD performance is detrimentally impacted by high localized pressure gradients in injection wells. These effects are more evident in lower pressure operations.

7. Well architecture should provide for an even fluid level (steam trap control) over the entire length of the well pair. At a minimum, fluid levels should be maintained below the in-jection well.

8. Hydraulics affect SAGD performance behaviour which, in turn, affects artificial lift selection and operating conditions.

9. There are a variety of practical and flexible cost-effective means to ensure minimal pressure gradients.

AcknowledgementsThe authors gratefully acknowledge the numerous people at

Nexen Inc. and OPTI Canada Inc. who supported and contributed to this work, the simulation software providers and the continued helpful efforts of Mr. Tan and Mr. McCormack in support of this work.

NOMeNClATUreCDOR = bitumen production rateCWE = steam injection rateHPSH = net positive suction headHPSHr = net positive suction head requiredICP = intermediate casing pointIHS = lateral accretion beddingLEP = limited entry perforationsLP-SAGD = Low Pressure SAGDSOR = steam-to-oil ratio

reFereNCeS 1. ITO, Y. and SUZUKI, S., Numerical Simulation of the SAGD Pro-

cess in the Hangingstone Oil Sands Reservoir; Journal of Canadian Petroleum Technology, Vol. 38, No. 9, pp. 27-35, September 1999.

2. EDMUNDS, N., Investigation of SAGD Steam Trap Control in Two and Three Dimensions; Journal of Canadian Petroleum Technology, Vol. 39, No. 1, pp. 30-40, January 2000.

3. KISMAN, K.E., Artificial Lift—A Major Unresolved Issue for SAGD; Journal of Canadian Petroleum Technology, Vol. 42, No. 8, pp. 39-45, August 2003.

4. EDMUNDS, N.R. and GITTINS, S.D., Effective Application of Steam Assisted Gravity Drainage of Bitumen to Long Horizontal Well Pairs; Journal of Canadian Petroleum Technology, Vol. 32, No. 6, pp. 49-55, June 1993.

56 Journal of Canadian Petroleum Technology

5. ONG, T.S. and BUTLER, R.M., Wellbore Flow Resistance in Steam-Assisted Gravity Drainage; Journal of Canadian Petroleum Technology, Vol. 29, No. 6, pp. 49-55, November-December 1990.

6. TAN, T.B., BUTTERWORTH, E. and YANG, P., Application of a Thermal Simulator with Fully Coupled Discretized Wellbore Simula-tion to SAGD; Journal of Canadian Petroleum Technology, Vol. 41, No. 1, pp. 25-30, January 2002.

7. McCORMACK, M., SAGD Injection Wells—What Your Prof Never Told You; Journal of Canadian Petroleum Technology, Distinguished Authors Series, Vol. 41, No. 3, pp. 17-23, March 2002.

8. KAISER, T.M.V., WILSON, S. and VENNING, L.A., Inflow Analysis and Optimization of Slotted Liners; SPE Drilling and Completions, Vol. 17, No. 4, pp. 200-209, December 2002.

9. BOYLE, T.B., GITTINS, S.D. and CHAKRABARTY, C., The Evo-lution of SAGD Technology at East Senlac; Journal of Petroleum Technology, Vol. 42, No. 1, pp. 58-61, January 2003.

10. SMALL, G.P., Steam-Injection Profile Control Using Limited-Entry Perforations; SPE Production Engineering, Vol. 1, No. 5, pp. 388-394, September 1986.

11. BOONE, T.J., YOUCK, D.G. and SUNS, S., Targeted Steam Injection Using Horizontal Wells With Limited Entry Perforations; Journal of Canadian Petroleum Technology, Vol. 40, No. 1, pp. 25-30, January 2001.

12. EDMUNDS, N.R. and CHHINA, H., Economic Optimum Operating Pressure for SAGD Projects in Alberta; Journal of Canadian Petro-leum Technology, Distinguished Authors Series, Vol. 40, No. 12, pp. 13-17, December 2001.

Provenance—Original Petroleum Society manuscript, Investigation of Key Parameters in SAGD Wellbore Design and Operation (2005-116), first presented at the 6th Canadian International Petroleum Conference the 56th Annual Technical Meeting of the Petroleum Society), June 7-9, 2005, in Calgary, Alberta. Abstract submitted for review December 10, 2004; edi-torial comments sent to the author(s) January 10, 2007; revised manuscript received January 22, 2007; paper approved for pre-press January 22, 2007; final approval May 8, 2007.

Authors’ BiographiesPaul Vander Valk currently works for En-cana Corporation in Calgary as Group Lead of Production, coordinating production en-gineering and operations activities for the Foster Creek and Christina Lake SAGD projects. Prior to joining Encana, Paul worked at Nexen, developing the Long Lake pilot and commercial projects. He has over 10 years of SAGD and related ex-perience with exposure to several projects including the Kerrobert Thermal, Surmont

and Kirby Lake SAGD projects in field and office production po-sitions. Paul holds a B.Sc. in civil engineering from the Univer-sity of Calgary, an MBA from Edinburgh Business School and is a member of APEGGA, the Petroleum Society and CHOA.

Peter Yang is currently Reservoir Engi-neering Manager of Long Lake Phase II for Nexen Inc. He has over 20 years of expe-rience, primarily in the thermal recovery of bitumen. Before joining Nexen in 1999, Peter worked on several thermal recovery projects and related technology develop-ment, including AOSTRA’s UTF Phase B project from 1989 to 1994. From 1995 to 1998, he held senior positions with Sun-wing Energy Ltd. (a Calgary-based energy

company active in China). Peter holds a B.Sc. degree (1982) from Daqing Petroleum Institute, China. He completed his M.Sc. at the University of Calgary (1989) under the supervision of Dr. R.M. Butler. He wrote his thesis on the “Effects of Heterogeneities in SAGD.” Peter is a member of the CHOA, the Petroleum Society and APEGGA.