PAPER 2006-153

Fluid Movement in the SAGD Process

A Review of the Dover Project

A. L. AHERNE Suncor Energy Inc.

B. MAINI University of Calgary

This paper is to be presented at the Petroleum Society’s 7th Canadian International Petroleum Conference (57th Annual Technical Meeting), Calgary, Alberta, Canada, June 13 – 15, 2006. Discussion of this paper is invited and may be presented at the meeting if filed in writing with the technical program chairman prior to the conclusion of the meeting. This paper and any discussion filed will be considered for publication in Petroleum Society journals. Publication rights are reserved. This is a pre-print and subject to correction.

Formerly with Devon Canada Corporation

Abstract The fundamentals of Steam Assisted Gravity Drainage (SAGD) steam chamber development are now well understood through Butler’s analytical models, and extensive field and laboratory testing. However as industry continues to extend SAGD to new reservoirs and looks towards SAGD wind down at the end life of the projects, it is important that we recognize the value of not only understanding the steam chamber but also of the movement of fluid in the reservoir. The Dover SAGD Pilot is the most mature pilot of its kind in the world. A study of this Pilot has been undertaken in an attempt to understand the behavior of the fluid within and in front of the steam chamber. The economics of SAGD are significantly impacted by the cost of generating steam. At roughly 1mcf/bbl of bitumen produced for an SOR in the range of 2.3-2.5 m3/m3, natural gas is the single largest operating cost in a SAGD project. Water movement within the reservoir can impact the natural gas consumption wherein warm steam condensate not recovered must be replaced in the process by colder make-up water,

decreasing the heat efficiency of the steam generation. Further, where water loss to the reservoir is high, the steam-oil ratio (SOR) may be negatively impacted. As we approach the 20th anniversary of the initiation of the Dover Pilot, the cold water injection test performed prior to any thermal operations taking place is revisited here. Understanding the transmissibility of water in the reservoir is key to choosing the optimal operating pressures and maximizing the value of a project. It has been widely published1,2 that the injection of non-condensable gas (NCG) into SAGD chambers will result in the accumulation of the NCG at the top of the chamber, cooling the chamber. The lower temperatures within the chamber cause the viscosity of the bitumen to increase thereby reducing the bitumen production rate. This has been suggested as a method of winding down steam chambers as they reach their economic producing limits3, ,4 5. From April 1998 to May 2002 NGC was injected with steam at the Dover Pilot. The gas volume injected at reservoir conditions was triple the volume of the produced bitumen over that time. The SAGD chambers did not behave as predicted. The bitumen production rate did not fall off any more than would be expected from a mature steam chamber and live steam was still detectable through the thermocouples within

1

PETROLEUM SOCIETYCANADIAN INSTITUTE OF MINING, METALLURGY & PETROLEUM

the steam chamber. Further, an increased overall recovery was observed, most likely from the gas assistance in the production of previously inaccessible reserves. The simulation model developed to describe, as well as further observations regarding the behavior of NCG in the reservoir, are discussed.

Introduction Geographically located in northeast Alberta, the Athabasca Oil Sands deposit forms part of the western Canadian oil sands. With an estimated 1.7 trillion barrels of oil in place, it is arguably the single largest oil deposit in the world. SAGD, developed by Butler6 in the early 1980’s, is to date, the most successful in-situ method of exploiting this resource. Several field trials from 1983 to present including PetroCanada Corporation’s Dover Pilot (Dover) have been conducted. These projects have demonstrated the success of SAGD in field applications. The results of these projects have created enormous interest in SAGD for use on a commercial scale, with several large scale projects on line and predicted SAGD production by 2010 ranging from 500,000 to 1,000,000 barrels of oil per day7. The early stages of SAGD recovery are now well understood through extensive field and laboratory testing. However, this technology is still developing with most field pilots having been run for less than five years. The Dover SAGD Pilot is the most mature pilot of its kind in the world. Further, it is composed of well pairs of varying maturity, within distances that could allow the well pairs to interact. As a result, a study of the Dover Pilot has been undertaken in an attempt to understand the behavior of the transmissibility of water and gas in and in front of the steam chamber. A schematic illustrating the well layout at Dover can be found as Figure 1.

Phase A – Water Transmissibility

Cold Water Injectivity Test The first phase of the pilot, Phase A, consisted of three horizontal well pairs, approximately 55m in length, separated by approximately 25m. Twenty-six, vertical observation wells were drilled from surface through the reservoir, to measure temperature, pressure, and surface heave resulting from the subsequent SAGD operations. From November 12-28, 1987, prior to the first steam injection into Phase A, a cold water injection test was undertaken. The water was injected into the A1 (center) injection and production wells. The injection took place at hydrostatic pressure of between 1550 – 1100 kPa, the original reservoir pressure was 510 kPa. Initial water injection into each well was 12 m3/d, falling to 8 m3/d over the course of the test. The pressure responses at the observation wells are shown in Figure 28. Of interest is the relative positioning of the observation wells with respect to the depth of the horizontal wells. Assuming an average surface elevation, the approximate depths of AP1 (producer) and AI1 (injector) were 161m TVD and 156m TVD respectively. Only the piezometers in AGP1, AGP2, and AGP4 at the respective depths of 157.6m, 157.6m and 160m TVD were located at depths at or below that of the horizontal wells. All three of these piezometers demonstrated a pressure

response, and the logs of these wells indicate that all three piezometers are located in bitumen rich zones. It can therefore be inferred from the pressure responses that water did move horizontally through this sand. A numerical model was created based on Chalaturnyk’s9 geological description of the area in order to evaluate the water injection movement and associated pressure responses in the model. Figure 3, Figure 4, andFigure 5 show the history match obtained for the water injection, as well as the pressure behavior at AGP1, AGP2, and AGP4. Also in the simulation model, the pressure from the injection has traveled laterally from the injection wells, consistent with the observations in the piezometers located in the upper portions of the reservoir. In order to achieve full injectivity of water in the simulation, the following parameters were adjusted:

i) The irreducible water saturation was decreased and a slight relative permeability to water was created over the range in which the initial water saturation is mobile, to allow the injection of water into the model.

ii) The endpoints of the water relative permeablities were adjusted upwards in the water saturation region from irreducible to 45%. This allowed water to propagate horizontally and prevented large pressure build-ups near the injection points.

iii) Saturations were changed by introducing a small free gas saturation and the correspondingly decreasing oil saturations. The addition of gas saturation prevented sharp pressure responses. The reduction of bitumen saturation allowed the water saturation in the model to be maintained, preventing an associated reduction in the relative permeability to water and maintaining the necessary water injectivity.

The pressure responses at the piezometers coupled with the sustainability of water injection into AI1 and AP1 provide strong evidence of cold water transmissibility within the McMurray Formation.

Phase A Numerical Simulation Steam injection into the Phase A horizontal wells began in December 1987, and concluded in December 1989. Over this time, bitumen recovery of approximately 25,000m3, 60% recovery of OOIP, and a steam injected to oil recovered ratio (SOR) of 2.38 had been achieved. This exceeded the performance of any previous in situ bitumen recovery performance in Alberta up to that time, and Phase A remains one of the few SAGD pilots to undergo a complete wind down. Utilizing the geological model based on Chalaturnyk’s work, and incorporating the increased water mobility, a history match of the Phase A Pilot was undertaken, the results of which can be found in Figure 6. The enhanced water transmissibility in the model prevented the extreme pressure build-up around the chamber, allowing full injectivity. The question then becomes, how, with increased water mobility, can steam be contained within the over-pressured steam chambers?

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At initial reservoir conditions, with an average 85% oil saturation and 7ºC, the relative permeability to oil achieved through the simulation study is 0.96 whereas the relative permeability to water is 2.14e-3. However, the viscosity of the bitumen is 4.3 million cP and that of water is 1cP. Calculating the water oil mobility ratio (M) at these conditions:

M = krwµo ……………………………… (1) kroµw

The mobility ratio is 9600 which strongly favors the flow of water. At initial conditions, bitumen can be considered to be immobile. At steam temperature, bitumen and water viscosities approach parity and, since bitumen has a much higher relative permeability at high oil saturation the mobility ratio becomes much smaller than one, and oil becomes significantly more mobile than water. The simulation results indicate that it is the fluid movement ahead of the chamber that allows the steam to be largely contained within the chamber. When a SAGD chamber is operated above the reservoir pressure and the bitumen within the chamber becomes heated, bitumen becomes mobile and is forced ahead of the chamber in banks. As the bitumen is further pushed out into the reservoir it cools losing viscosity and limiting the extent of the banks. The oil movement into the reservoir in turn pushes non-condensable gas and water, both mobile at reservoir conditions, ahead of the bank propagating both an increase in pressure as well as higher temperatures ahead of the steam chamber front. The edge of the bank closest to the chamber has very high oil saturation, reducing the water saturation in these areas to its residual saturation and rendering water immobile in these regions. It is difficult for steam from the chamber to finger through the bank as steam is a condensable fluid, and is liquid water at the chamber edge of the bank where the temperature is cooler than the steam chamber. As a result the bitumen banks limit steam loss from the chamber. The bitumen banks are perpetually being eroded and shifted outward as the steam chamber develops. Figure 7 is an idealized representation of what was observed in the simulation.

Implications for Operating Pressure For SAGD operations in reservoirs where the bitumen saturation is high (>80%) and the corresponding water relative permeability is low, operating at pressures above reservoir pressure will result in additional water loss. This will be true especially during early times before the bitumen banks have had the opportunity to set up. This additional water loss will have only a small impact on the SOR, as the fluid lost is condensed steam, and it would normally be produced to surface without contributing energy to the steam chamber. The impact of water loss on natural gas consumption results from warm steam condensate not recovered that must be replaced by cold makeup water, decreasing the heat efficiency of steam generation. There are also facility capital implications in that larger volumes of makeup water must be sourced. While this is a consideration, the operating pressure decision will likely be dominated by parameters such as geomechanical effects and additional heat losses at higher pressures.

In regions where the initial oil saturation is lower, and the water relative permeability is higher, not only will these regions have a higher SOR as less bitumen is heated per unit of rock and water but it will be difficult for the bitumen to bank in these areas. When the SAGD wells are operated at pressures higher than the reservoir pressure, if the reservoir contains lean zones that are laterally extensive, both water and steam will propagate through these zones and result in a very high SOR. As water transmissibility exists in bitumen rich zones, it will be difficult to maintain pressure gradients between well pairs. In order to maintain an economic SOR the field operating pressure will have to be tailored to the wells in the lean zones.

Phase B – Fluid Movement The test of the SAGD concept at Phase A of the Dover Project was successful, however, the peak rates at these wells were limited to a rate of 20m3/d due to the well pair length of 55m in the horizontal section. The three Phase B wells were a commercial length of 500m and spaced 70m apart. Injection into these wells began in 1993. Commercial rates of 110m3/d of bitumen per well were demonstrated.

Water Leak Off The Total Fluid produced to Steam injected Ratio (TFSR) is used to indicate the degree of balance in the reservoir between the fluid withdrawn and the steam injected. Assuming no fluid loss ahead of a steam chamber, the ideal producing TFSR can be calculated. TFSR = H2O Prd + Oil Prd - Steam in chamber ……….. (2)

Steam Inj Every cubic meter of bitumen production would be replaced by a cubic meter of steam, which at 2,500kPa and 225ºC is equivalent to 0.045m3 of water at standard conditions. At an SOR of 2.5, 2.5m3 of steam (CWE ) injected and equivalent volume of water will be produced. As the steam volume in the chamber is nearly two orders of magnitude less than the volume of water produced or injected, it is the water that will have the largest impact on the TFSR. The calculation of a balanced TFSR under these conditions is: TFSR = 2.5m3 + 1m3 -0.045 m3

2.5 m3

TFSR = 1.38 m3/m3

At a TFSR of less than 1.38m3/m3 under these conditions, either water is leaking off from the steam chamber or the pressure of the reservoir would increase. The plots of TFSR and the cumulative TFSR for the Dover total field production can be found in Figures 8 and 9. By December of 1998, the cumulative TFSR in Phase B was 1.27m3/m3, and by December of 2003 it had increased to a balanced 1.39m3/m3. Because TFSR represents balanced production and injection it would be expected that the pressure in the Phase B chamber

Steam in cold water equivalent at standard conditions.

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would remain constant. The pressure of the steam chamber can be calculated from the vertical temperature observation wells in Phase B. The presence of 100% mole fraction steam can be identified as there is effectively no measurable thermal gradient in a column of steam. The temperature is therefore that of saturated steam at a given pressure. Figure 10 is a plot of the instantaneous temperature profiles from December 1993 to December 1998 in the vertical observation well BT4. The y-axis is depth, measured in meters above sea level, and the x-axis is the temperature. The gamma and resistivity logs for this well are to the right of the plot. The reservoir in which BT4 is located contains a thick column of high quality sand. Since steam temperature is easily observed at this well, BT4 is well suited for the calculation of steam chamber pressure over time. The nearest horizontal production well BP2 is located at an approximate depth of 273m above sea level (mASL). Figure 11 shows the depth versus temperature plot of BT4 annually for the years between December 1998 and December 2003. During this period, it is possible to observe the decease in temperature in the chamber caused by the drop in operating pressure. The data in 2002 and 2003 had become erratic due to the failure of some of the thermocouples. This was a common occurrence at that point in time, particularly among the gauges exposed to steam temperature for many years. The steam chamber pressure for Phase B, as calculated from BT4, can be found in Table 1. Despite maintaining a TFSR of 1.27m3/m3 at Dover to December 1998 the pressure in Phase B dropped from 2.35 to 2.07 Mpa. From December 1998 to December 2003, the pressure dropped again from 1.95 to 1.44Mpa. This suggests fluid leakoff from the chamber to the surrounding reservoir. These observations are in agreement with the water balance seen for the field as a whole. From 1993, when Phase B was initiated, until December of 2003 at which time Phases B, D, and E were in operation, the cumulative production and injection volumes, in CWE, were as follows: Steam Injected: 3101 E3m3 Oil Produced: 1245 E3m3 Water Production: 2799 E3m3 Net Water Loss: 246 E3m3 The net water loss calculation assumes that the bitumen produced is replaced entirely by steam at saturated conditions. The net water loss to the reservoir is therefore 8%, consistent with the other observations of water mobility at Dover.

Non-Condensable Gas Pilot By April of 1998 Phase B had produced 460E3m3 of bitumen, 85% of its estimated economic cumulative production, and a wind down strategy was initiated. This strategy involved injecting 0.8mol % of non-condensable gas (NCG) with steam. Simulation work done at that time predicted that the NCG would accumulate at the top of the chamber, cooling the chamber10. The lower temperatures within the chamber would cause the viscosity of the bitumen to increase, stopping its flow and reducing the time required on wind down. From April 1998 to May 2001 and from September 2001 to May 2002 8-12E3m3/d of methane was co-injected with steam into the Phase

B chamber. From May 2001 to September 2001 flue gas was injected at a rate of between 33 and 40E3m3/d. A total of 16.3E6m3, at standard conditions, of NGC was injected into the chamber. By May 2002 the chamber pressure had dropped to 1.7MPa due to a reduction in steam injection, at this pressure the reservoir equivalent volume of injected gas is 1.58e6m3, triple the volume of the produced bitumen. Given the volume of gas injected, it is not possible that it remained in the SAGD chamber. Therefore the indication is that it flowed into the reservoir ahead of the chamber, otherwise the pressure in the chamber would have increased. There are several implications for the Phase B chamber associated with this gas movement. First, the chamber did not cool as expected. While the Phase B production declined during this time period, the decrease in bitumen production is no more than would be expected from a SAGD well given the reduction in steam injection rate, drop in chamber pressure (hence temperature); and maturity of the well pair. Secondly, Phase B had produced a cumulative volume of 686E3m3 of bitumen as of December 2003. This production exceeded the predicted Phase B recovery by 144E3m3. From April 1998, temperature profiles show that the temperature had risen into the Inclined Heterolithic Stratification (IHS) in the upper section of the reservoir. The displacement of bitumen in this section is the result of the Steam and Gas Push (SAGP) process11, by which the flow of gas and steam rising counter current to the draining oil increases the pressure towards the top of the reservoir and tends to push the oil down. The SAGP process allowed the production of bitumen from the IHS, a portion of the reservoir previously believed to be inaccessible. Finally, the injection of NCG has prolonged the life of the well pair. As steam was diverted from Phase B to other, less mature patterns, NCG re-entered the chamber as the pressure dropped, reducing the loss of pressure and maintaining higher temperatures and drainage rates. Further evidence of the fluid movement ahead of the steam chambers, was seen at the observation wells, which recorded pressure then temperature response well ahead of the arrival of the steam chamber. An earlier publication by the author12 calculated the theoretical rate of pressure-front velocity through bitumen. As of December 2003 Phase B continued to produce at a bitumen rate of 70m3/d with an average steam to oil ratio (SOR) of 1.2 for the last six months of the year. Figure 12 is a plot of the historical Phase B production and injection rates.

SAGD Simulation History Match The total field simulation history match was achieved using a static model based on a similar geological description with only slight modifications to the fluid properties developed in the Phase A simulation previously discussed. No changes were made to either the water or gas relative permeability curves, although a slight reduction in oil saturation was applied, without endpoint modification, allowing additional water movement. The oil relative permeability at high water saturation was increased and the endpoint was moved to a water saturation of 95% (from 85%) to increase oil production rates later in the life of the chamber. The results of the total field history match for daily injection and production rates are in Figure 13. Figure 14 is the plot of the history match at the observation well BT1

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where the symbols represent the temperature seen in the simulation overlain on the actual temperatures observed at this well.

Acknowledgement The authors would like to express their appreciation to colleagues Devon Canada Corporation for their technical input and support for this work. Thank you to Gregg Birrell and Mike McCormack for sharing so generously of your time and talent.

In the simulation, the injection wells were constrained on water injection with a maximum bottom hole injection pressure limitation, the production wells were constrained on total fluid production with a minimum bottom hole pressure and a maximum steam injection production restriction. Using these parameters good matches for total fluid production and steam and gas injection were achieved. Good matches were also obtained for water and oil production until 1999 when flue gas injection began, at which point the model predicted a slight over-production of water and under-production of oil; approximately 10%. The plot of the simulated history match for the cumulative steam injection and the total fluid and bitumen production are in Figure 14.

NOMENCLATURE k = permeability M = mobility ratio ro = relative to oil rw = relative to water REFERENCES

1 Butler, R. (1999, March). The Steam and Gas Push (SAGP). Journal of Canadian Petroleum Technology, pp. 54-61. 2 Yuan, J. –Y., Law, D. H. –S., & Nasr, T. N. Impacts of Gas in SAGD: History Matching of Lab Scale Tests. Paper 2003-202, presented at the Canadian International Petroleum Conference (June 10-12, 2003), Calgary, Alberta, Canada.

Implications for SAGD Wind Down The fluid mobility in the reservoir allows pressure to be transmitted quickly between steam chambers. As mature chambers wind down it is important that their pressure be maintained to prevent the leak off of steam from proximal producing steam chambers. While the injection of NCG is still a method by which steam chamber maintenance can be achieved during wind down, the gas injected will not be confined to the steam chamber. The gas leakoff will impact the end-life economics of SAGD and it may be more economic to use NCGs other than methane, such as flue gas or CO2 to effect pressure maintenance, although additional facility capital costs associated with injecting and reproducing these corrosive gasses will be incurred.

3 Yee, C.T., & Stroich, A. Flue Gas Injection in to a Mature SAGD Steam Chamber at the Dover Project (formerly UTF). Paper 2002-301, presented at the Canadian International Petroleum Conference (June 11-13, 2002), Calgary, Alberta, Canada. 4 Zhao, L., Law, D. H. –S., & Coates, R. (2003, January). Numerical Study and Economic Evaluation of SAGD Wind-Down Methods. Journal of Canadian Petroleum Technology, pp. 53-57. 5 Zhao, L., Law, D. H. –S., Nasr, T. N., Coates, R., Golbeck, H., Beaulieu, G., & Heck, G. SAGD Wind-Down: Lab Test and Simulation. Paper 2003-045, presented at the Canadian International Petroleum Conference (June 10-12, 2003), Calgary, Alberta, Canada. 6 Butler, R., McNab, G., and Lo, H. (1981). Theoretical Studies on the Gravity Drainage of Heavy Oil During In Situ Steam Heating. Canadian Journal of Chemical Engineering, Vol. 59, pp. 455-460 7 Alberta Economic Development, Oil Sands Industry Update, May 2003. Conclusion 8 Edmunds, N., Pennacchioli, E., Suggett, J., & Gittins, S. (1994, February). Wrapup Report: AOSTRA: Underground Test Facility: Phase A. UTF Product Report # 3020.

The cold water injectivity in Phase A, as well as the gas injection into and the accelerated pressure movement ahead of the steam chamber in Phase B, provide evidence of fluid movement both at initial conditions and ahead of the steam chamber front. The history match of the Phase A cold water injection test indicates that the irreducible water saturations are very low, and that the relative permeability to water is higher at initial reservoir conditions than previously published.

9 Chalaturnyk, R. J. (1996, Spring). Geomechanics of the Steam Assisted Gravity Drainage Process in Heavy Oil Reservoirs. A thesis submitted to the Faculty of Graduate Studies and Research in partial fulfillment of the requirements of the degree of Doctor of Philosophy in Geotechnical Engineering, Department of Civil Engineering, Edmonton, Alberta. 10 Yee, C.T., & Stroich, A. Flue Gas Injection in to a Mature SAGD Steam Chamber at the Dover Project (formerly UTF). Paper 2002-301, presented at the Canadian International Petroleum Conference (June 11-13, 2002), Calgary, Alberta, Canada.

The implication of the fluid transmissibility is that SAGD well pairs should not be considered in isolation, rather the impacts of operating conditions need to be evaluated on a pad and field basis. Considered in this paper were the impacts of fluid mobility on steam injection pressures because operating a SAGD chamber above the reservoir pressure will allow steam condensate leak-off and lead to additional operating costs. The use of NCG on SAGD wind down needs consideration given that the gas transmissibility will necessitate larger volumes of NCG in the wind down, impacting the economics of the end life of SAGD chambers.

11 Butler, R. (1999, March). The Steam and Gas Push (SAGP). Journal of Canadian Petroleum Technology, pp. 54-61. 12 Aherne, A., Birrell, G. Observations Relating to Non-Condensable Gasses in a Vapor Chamber: Phase B of the Dover Project. Paper 2003-202, presented at the SPE International Thermal Operations and Heavy Oil Symposium and International Horizontal Well Technology Conference ,Calgary, Alberta, Canada, (November 4-7 2002).

Not considered in this paper, is an evaluation of the effect of fluid movement on the effects on solvent and steam solvent hybrid processes. With a greater fluid mobility in the reservoir that has been previously been contemplated, solvent will also likely move ahead of the chamber, resulting in less solvent recovery. This will have impacts on the profitability of these processes and is an area of future study.

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Tables

Date Dec-93 Dec-94 Dec-95 Dec-96 Dec-97 Dec-98 Dec-99 Dec-00 Dec-01 Dec-02 Dec-03Temperature ( C) 218.7 220.4 219.8 221 225 214 211 212 208 198 196Pressure (MPa) 2.27 2.35 2.32 2.37 2.56 2.07 1.95 1.99 1.84 1.50 1.44

Table 1: Phase B, BT4 Temperature Profiles 1998-2003

Figures

N

PHASE E

B3

B2

B1

PHASE B

500 m

70 m

SCALE0 200 m

Tunnels

A3 A1 A2

Well Pair

Well Pair

25 m

60 mPHASE A

F&G

E1750 m

90 m

D2

D1

PHASE D

750

m

DOVAP

500

m

N

PHASE E

B3

B2

B1

PHASE B

500 m

70 m

SCALE0 200 mSCALE0 200 m

Tunnels

A3 A1 A2

Well Pair

Well Pair

25 m

60 mPHASE A

F&GF&G

E1750 m

E1750 m

90 m

D2

D1

PHASE D

750

m

90 m90 m

D2

D1

PHASE D

750

m

DOVAP

500

m

DOVAP

500

m

Figure 1: Dover Field Layout

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Figure 2: Phase A Cold Water Test Piezometer Responses From Edmunds et al., February 1994

Phase A CWI Observation Well Pressure Field History File

AGP4 160 Phase A CWI_Press.fhf

Pressure AGP4 160 Phase A CWI_Press.fhfPressure: 44,3,2 Phase A_(21)_CWI(25).irf

Time (Date)

Pre

ssur

e (k

Pa)

1987-11-1 1987-11-11 1987-11-21 1987-12-1 1987-12-11500

550

600

650

700

Figure 3: Phase A Water Injection, AGP4 160.4 Pressure

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Phase A CWI Observation Well Pressure Field History FileAGP2 157.6 Phase A CWI_Press.fhf

Pressure AGP2 157.6 Phase A CWI_Press.fhfPressure: 27,3,8 Phase A_(21)_CWI(25).irf

Time (Date)

Pre

ssur

e (k

Pa)

1987-11-1 1987-11-11 1987-11-21 1987-12-1505.0

510.0

515.0

520.0

525.0

Figure 4: Phase A Water Injection, AGP2 157.6 Pressure

Phase A CWI Observation Well Pressure Field History FileAGP1 157.6 Phase A CWI_Press.fhf

Pressure AGP1 157.6 Phase A CWI_Press.fhfPressure: 2,3,6 / 8,1,1 Phase A_(21)_CWI(25).irf

Time (Date)

Pre

ssur

e (k

Pa)

1987-11-1 1987-11-11 1987-11-21 1987-12-1 1987-12-11500

510

520

530

540

Figure 5: Phase A Water Injection, AGP1 157.6 Pressure

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Phase A Thermal Simulation ModelIncreased Water Transmissiblity

Liquid Rate SC Default-Field-PROWater Rate SC Default-Field-PRO Oil Rate SC Default-Field-PRO Liquid Rate SC total field Water Rate SC total fieldOil Rate SC total field

Time (Date)

Liqu

id R

ate

SC (m

3/da

y)

1988-1 1988-7 1989-1 1989-7 1990-1 1990-7 1991-10

20

40

60

80

100

120

Figure 6: Production History Match Phase A

9

Overburden

Underburden

112 3

43 2

4

Injection Well

Production Well

Overburden

Underburden

112 3

43 2

4

Injection Well

Production Well

Index 1. Steam Chamber - steam injected in the upper well flows to interface and condenses, both

temperature and pressure are largely that of saturated steam. 2. Drainage Region – heated bitumen and steam condensate drain into the production well, some of

the heated bitumen is pushed, as a result of a pressure gradient into the bitumen ahead of the chamber

3. Banked oil – heated oil is banked ahead of the chamber at very high bitumen concentrations, with a large temperature gradient in this region with temperatures as high as 200ºC at the chamber edge to as low as 50ºC along the reservoir.

4. Cooler bitumen – movement of connate water and non-condensable gasses ahead of the steam front.

Figure 7: The SAGD Mechanism

Dover - Total Fluid Produced to Steam Injected Ratio Phases B, D, &E

0.000

0.500

1.000

1.500

2.000

2.500

3.000

3.500

4.000

4.500

5.000

Dec-91 Dec-92 Dec-93 Dec-94 Dec-95 Dec-96 Dec-97 Dec-98 Dec-99 Dec-00 Dec-01 Dec-02 Dec-03

Date

TSFR

(m3/

m3)

Total (m3/m3) Phase B (m3/m3) Phase D (m3/m3) Phase E (m3/m3)

Figure 8: Total Fluid to Steam Ratio – Per Phase

10

Dover - Cumulative Total Fluid Produced to Steam Injected Ratio Phases B, D, &E

0.000

0.200

0.400

0.600

0.800

1.000

1.200

1.400

1.600

1.800

2.000

Dec-91 Dec-92 Dec-93 Dec-94 Dec-95 Dec-96 Dec-97 Dec-98 Dec-99 Dec-00 Dec-01 Dec-02 Dec-03

Date

Cum

ulat

ive

TSFR

(m3/

m3)

Total (m3/m3) Phase B (m3/m3) Phase D (m3/m3) Phase E (m3/m3)

Figure 9: Cumulative Total Fluid to Steam Ratio – Per Phase

BT4 Temperature Profiles 1993-1998

270.0

275.0

280.0

285.0

290.0

295.0

300.0

305.0

310.0

0.0 50.0 100.0 150.0 200.0 250.0

Temperature (C)

Dep

th (m

asl)

Dec-93 Dec-94 Dec-95 Dec-96 Dec-97 Dec-98

270

275

280

285

290

295

300

305

310

0 100 200 300

GR AP I

1 10 100 1000

FE ohm- m

BT4

FE

GR

Figure 10: BT4 Temperature Profiles 1993-1998 - Phase B, Dover Project

11

BT4 Temperature Profiles 1998-2003

270.0

275.0

280.0

285.0

290.0

295.0

300.0

305.0

310.0

0 50 100 150 200 250

Temperature (C)

Dep

th (m

asl)

Dec-98 Dec-99 Dec-00 Dec-01 Dec-02 Dec-03

270

275

280

285

290

295

300

305

310

0 100 200 300

GR AP I

1 10 100 1000

FE ohm- m

BT4

FE

GR

Figure 11: BT4 Temperature Profiles 1998-2003

Figure 8: Full Field Simulation Results, Daily Injection and Production Rates

Phases B, D, E Dover Project

12

Figure 9: Full Field Simulation Results, Cumulative Injection and Production

Phases B, D, E Dover Project BT1

0

20

40

60

80

100

120

140

160

180

200

220

1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

270

280

290

300

310

Figure 10: BT1 Temperature Profile

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