Reservoir Modeling to Investigate the Impacts of Geological Properties on Steam-Assisted Gravity Drainage (SAGD) at the Orion Project, Lower Cretaceous Clearwater Formation, Alberta

Zexuan Wang1*1Department of Earth and Atmospheric Sciences, University of Alberta, Edmonton, AB, Canada, zexuan@ualberta.ca

*Present address: Department of Earth and Environmental Sciences, University of New Orleans, New Orleans, LA, USA, zwang15@uno.edu

When compared with steam-assisted gravity drainage (SAGD) operations in the McMurray Formation, Athabasca Oil Sands, SAGD projects in the Clearwater Formation at Cold Lake did not perform as expected, likely because of reservoir properties. This paper found three issues: (1) historical oil production rates (OPRates) range from 4,000 to 6,000 bbls/D, much lower than the expected 10,000 bbls/D; (2) the average CSOR is around 4.5, much greater than the forecasted CSOR; and (3) abnormal and irregular growth of steam chambers were detected by the observation wells. However, previous research results explain-ing the effects of reservoir parameters on the SAGD performance were mainly derived from the laboratory experiments, rela-tively simplistic numerical simulations, and field studies at Athabasca Oil Sands and outside the Canada.

This paper will use the Orion SAGD case study from Cold Lake to: • Investigate the impacts of reservoir properties on the SAGD thermal efficiency by field evidences • Identify key geological parameters influencing each well pad • Summarize major geological challenges for Orion SAGD expansion

Introduction

SAGD production performance was analyzed to quantify the performance of each well pad using: (1) temperature profiles that monitored the growth of the steam chamber; (2) cumulative steam-oil ratios (CSORs); and (3) oil production rates (O-PRates), which are direct indicators of thermal efficiency. The steam temperature under the injection pressures, which range from 3.5 MPa to 4.5 MPa, was calculated by Standard Steam Table to be 240 ºC to 260 ºC, indicating that any temperature de-tected less than this represents absence of steam.

Wireline logs were interpreted to characterize reservoir properties, which were used to build 3D models, including shale con-tent model, porosity model, oil saturation model, and permeability model. For each model, three equiprobable realizations were generated and averaged into a final one. 3D visualizations and 2D cross sections of the reservoir revealed spatial distri-bution and heterogeneity of each property.

Methods

Orion SAGD is located in the Cold Lake oil sands region (Fig. 1), covering 2,048 hectares, following the Hilda Lake Pilot Project. Currently, seven well pads are active (Fig. 1), including Pilot Pads 1 and 3, and Pads 103 to 107, which orientated along the west-east. Multiple observation wells (OBs) along the horizontal wells monitored steam chamber growth. Bitumen was produced from Clearwater Formation by the production wells, which are positioned 5 m below injection wells. The hori-zontal well length is 750 m and the lateral spacing between well pairs is 100 m (BlackRock, 2001).

The Clearwater Formation of the Lower Cretaceous Mannville Group (Minken, 1974), is the primary focus for thermal de-velopment in the Cold Lake (Jiang et al., 2010). This succession consists of 40-m shallow marine unconsolidated sand capped by 5-m shale at a depth of 425 m. Donnelly (1999) divided the sand interval into units C1, C2 and C3. Net-pay is C2 whose average properties are listed in Table 1. This 23-m fine to medium-sized and well-sorted clean shoreface sand consists of 35% quartz, 15% chert, 20% feldspar, and 30% rock fragments.

Background of Orion SAGD Project

Net-pay thickness 23 m (20-27 m)Depth 425 m

Vertical permeability 3.5 D (3-5 D)Porosity 36%

Bitumen saturation 61%Bottom water No

Oil viscosityreservoir-condition 75,000 mPasOil viscositysteam-condition 4 mPas

Particle-size distribution Coarsening UpwardCaprock fracture pressure 10,000 kPa

Reservoir temperature 16 °CReservoir pressure 3,200 kPa

Producing gas-oil ratio 35 m3/m3

Oil gravity 10.5 APIStudy Area

Fig. 2 shows CSORs and OPRates versus elapsed time. Pilot Pads 1 and 3 have the lowest CSORs around 3.5, indicating the highest thermal efficiency. Pads 103, 105 and 107 have moderate CSORs around 4.05. Pads 106 and 104 have the highest CSORs around 6.8, indicating the lowest thermal efficiency.

Orion SAGD Production Performance Analysis

Fig. 2—Left plot showing CSORs versus time, and right plot showing OPRates versus time of well pads.

Fig. 1—Maps showing Orion project area (within the red polygon) and wells. Pilot Pads 1 and 3 are in red; Pad 103 is in light green; Pad 104 is in yellow; Pad 105 is in blue; Pad 106 is in brown; and Pad 107 is in dark green.

Table 1—Reservoir properties of unit C2 (BlackRock, 2001 and Jiang et al., 2010)

Orion SAGD Reservoir Models

Oil Saturation Model

Permeability Model

Porosity Model

The spatial distributions and heterogeneities of shale content, porosity, oil saturation, and permeability are revealed below. The horizontal and vertical resolutions are 25 m and 0.1 m respectively.

Shale Content Model

Fig. 3—3D view of shale con-tent model and fence diagram

(mean value: 0.13)

Effects of Impermeable Barriers and Low-Permeability Zones on Steam Injectivity and Steam Chamber Growth

The highest temperature detected by observation well 4 (OB4) reached at 220 ºC (Fig. 9a), indicating the reservoir nearby was saturated with steam. However, steam chamber was limited between the injector and producer without upward move-ment, revealed by its triangular shape. Cross section (Fig. 10) shows that a laterally continuous impermeable barrier exists just above the well pair near OB4, Therefore, this barrier likely prevented the upward growth of steam chamber. Temperature of OB2 only reached at 150 ºC (Fig. 9b), indicating the absence of steam. It is noteworthy that the injection well was penetrat-ing a low-permeability zone (Fig. 10). Therefore, probably the steam injectivity was reduced significantly by the low-perme-ability zone. In contrast, the temperature profile (Fig. 9c) of OB1 shows a much thicker steam chamber, reaching at the level 12 m above the injection well. The impermeable barrier affecting OB4 is thinner towards OB1, and eventually pinched out. In addition, the low-permeability zone affecting OB2 disappears at OB1 (Fig. 10). Therefore, probably the steam chamber formed and developed freely until encountering the upper impermeable barrier, which is 12 m above the injection well.

The author expressed his appreciation to Drs. Jose Alvarez and Ron Sawatzky, the principal researchers at Alberta Innovates Technology Futures, for their critical suggestions on this study.

Acknowledgements

BlackRock Ventures Inc. 2001. Orion EOR project: application, EIA and supplemental information.Donnelly, J. K. 1999. Hilda Lake a Gravity Drainage Success. Presented at the SPE International Thermal Operations and Heavy Oil Symposium, Bakersfield, California, 17-19 March. SPE-54093-MS. http://dx.doi.org/10.2118/54093-MS.Jiang, Q., Thornton, B., Russel-Houston, J. et al. 2010. Review of Thermal Recovery Technologies for the Clearwater and Lower Grand Rapids Formations in the Cold Lake Area in Alberta. Journal of Canadian Petroleum Technology, 49 (09): 2-13. SPE-140118-PA. http://dx.doi.org/10.2118/140118-PA.Shell Canada Limited. 2014. In Situ Oil Sands Progress Presentation. Orion 10103, Shell Canada Limited, Calgary, Alberta.Wang, H. Y. 2009. Application of Temperature Observation Wells during SAGD Operations in a Medium Deep Bitumen Reservoir. Journal of Canadian Petroleum Tech nology, 48 (11): 11-15. SPE-130439-PA. http://dx.doi.org/10.2118/130439-PA.

Selected References

This paper used the Orion SAGD as a case study to demonstrate the impacts of reservoir properties on SAGD operations in Cold Lake Oil Sands. A set of Clearwater Sand reservoir models were generated and SAGD production performance analyses were performed. Pilot Pads 1 and 3 have the highest thermal efficiency, whereas Pads 104 and 106 have the lowest thermal efficiency. Issues of steam absence and irregular steam chamber growth were identified. Among all the geological parameters discussed in this paper, high shale-content zones, impermeable barriers, low-permeability zones, thin net-pay, and low oil-saturation zones are the most critical issues in this area reducing the thermal efficiency of contiguous well pads. The field evidences have been summarized below: (1) high shale-content zones had an impact on Pad 103 where the steam could only bypass these zones and the steam chamber was irregularly shaped; (2) impermeable barriers affected Pilot Pads 1 and Pad 103 where continuous and extensive impermeable barriers exist closely above the injection wells, which may dictate the thickness of SAGD-able intervals, impair the vertical extension of the steam chambers, and cause steam-channeling issues; (3) low-permeability zones influenced Pilot Pad 1 and Pad 104 where injection wells directly penetrated low-permeability zones, significantly reducing the steam injectivity and causing the absence of steam chambers; (4) thin net-pay with 18 m in thickness is the dominate factor causing the highest CSOR and lowest thermal efficiency at Pad 104; (5) low oil-saturation zones had an effect on Pad 106 where the average of oil saturation is 55%, resulting in the poor production performance even though the steam chambers developed successfully.

In addition, the major challenges for the Orion SAGD expansion to the unexploited area mainly consist of relatively wide-spread distribution of impermeable barriers, low-permeability zones, and relatively large area of low oil saturation.

Conclusions

Fig. 4—3D view of porosity model and fence diagram (mean

value: 0.35)

Fig. 5—3D view of oil satura-tion model and fence diagram

(mean value: 0.62)

Fig. 6—3D view of permeability model and fence diagram (mean

value: 3D)

DiscussionEffects of High Shale-Content Zones on Steam Chamber Shape

The temperature profile at Pad 103 (Fig. 7) shows an irregular shape, with two sharp spikes, indicating the steam channeling issue. High shale-content zone is characterized by a parallelogram-shaped pattern (Fig. 8), which can explain the irregular shape of steam chamber. The steam could not expand through the high-shale content zone, but instead laterally bypassed this zone. Eventually, the steam only presented below and above this zone.

Effects of Thin Net-Pay on CSORThe long-term average CSORs and OPRates (Fig. 2) show that Pad 104 has the lowest thermal efficiency and lowest OPRates in contiguous well pads. The reser-voir isopach map (Fig. 11) reveals that Pad 104 pene-trated through a thin net-pay where the thickness is av-eraged at 18 m. The current thickness may not be suffi-cient to allow gravity to act as an adequate driving mechanism. Therefore, probably the significant loss in thickness is the primary factor to contribute to the high-est CSOR and lowest thermal efficiency of Pad 104.

Effects of PorosityFig. 12 shows the porosity is relatively homogeneous through the entire study area, without any obvious variation trend. Therefore, lack of the distinct variation makes it hard to identify the impact of porosity on each well pad in the Orion area.

Key Parameters Affecting the SAGD Performance of Each Well PadPad104106107105103

Pilot 1Pilot 3

Key ParametersThin net-pay, low-permeability zone

Low oil-saturation zone, high shale-content zoneThin net-pay

High-permeability zoneImpermeable barrier, high shale-content zoneImpermeable barrier, low-permeability zoneImpermeable barrier, high shale-content zone

CSOR6.836.774.134.033.973.723.30

Cumulative Oil Production (m3)182,545205,124354,452399,039359,185277,165251,010

Effects of Low Oil-Saturation Zones on CSORThe long-term average CSORs and OPRates (Fig. 2) show that Pad 106 has the second lowest thermal efficiency and the lowest OPRates in contiguous well pads. However, the steam chambers near both observation wells were well formed above the injec-tion wells at Pad 106 (Fig.14). The oil saturation de-creases drastically from Pad 103 to Pad 106 (Fig. 15). The average oil satu-ration is 70% at Pads 103 and 105, and 55% at Pad 106. Therefore, probably the low oil-saturation zone contributed to the poor production performance of Pad 106.

Effects of Dip Angles of Impermeable BarriersWhen encountering a dipping impermeable barrier, steam chamber will migrate up-dip preferentially. This paper used a novel method, pseudo-borehole imaging (PBI), to explore the dip angles. PBIs were created by circle-shaped (radius was set at 10 m) cross sections intersecting the permeability model to mimic the borehole imaging tools. Fig. 13 shows six PBIs to il-lustrate the nealy horizontal nature of impermeable barriers at each well pad. Therefore, dip angles of impermeable barriers have a negligible effect on steam chamber growth and CSOR in Orion SAGD.

252526262727282829293030

3131 3232 3333 3434 3535 3636

T64T64

R3W4

R3W4

1 km

Orion SAGD Boundary Vertical Well Horizontal Well

2468

101214

1 25 49 73 97 121 145 169 193

Pilot Pad 1Pilot Pad 3Pad 103Pad 104Pad 105Pad 106Pad 107

Cum

ulat

ive

Ste

am O

il R

atio

Elapsed Time (Months)

02,0004,0006,0008,000

10,00012,000

1 25 49 73 97 121 145 169 193

Pilot Pad 1Pilot Pad 3Pad 103Pad 104Pad 105Pad 106Pad 107

Mon

thly

Oil

Pro

duct

ion

Rat

e (m

3 /mon

th)

Elapsed Time (Months)

0.4

0.2

0.0

0.4

0.2

0.0

0.24

0.30

0.36

0.42

0.42

0.36

0.30

0.24

0.8

0.2

0.4

0.6 0.8

0.2

0.4

0.6

10

0020406080

00204060810

Vsh

Vsh

500 m

500 m

500 m

500 m

Φ

Φ

So

So

K (D)

K (D)

420

430

440

450

460

4700 40 80 120 160 200 240

MD

(m)

Temperature (°C)

Vsh 0.4

0.0

0.1

0.3

0.2

420

430

440

450

460

4700 50 150100 200

MD

(m)

Temperature (°C)

420

430

440

450

460

0 50 150100 200Temperature (°C)

410

420

430

440

450

400

0 50 150100 200Temperature (°C)

420

400

440

380

MD

(m)

380

400

420

440

MD

(m)

390

410

430

390

410

430

0 40 12080 160Temperature (°C)

200 240 280 0 40 12080 160 200 240Temperature (°C)

So 0.8

0.6

0.4

0.2K (D)10

8060402000

MD

(m)

MD

(m)

29

26

23

20

17

H (m)well control

0.2

0.3

0.4

Φ

Pilot Pads0.40°

Pad 1031.00°

Pad 1040.46°

Pad 1050.57°

Pad 1060.86°

Pad 1070.29°

Pilot Pads 107

103 105 104 106

Fig. 7—Temperature profile at Pad 103-OB3

Fig. 8—Cross section of shale content model at Pad 103

OB3

Fig. 9—Temperature profiles of (a) OB4, (b) OB2, and (c) OB1 of Pilot Pad 1

(a) OB4 (b) OB2 (c) OB1

OB4 OB2 OB1

Fig. 10—Cross sec-tion of permeability model at Pilot Pad 1

Fig. 11—Isopach map of reservoir

500 m

107

104 106103 105

Pilot Pads

Fig. 12—Cross section of porosity model

103 105 104 106

Fig. 13—Pseudo-borehole imagings of permeability

model

Fig. 14—Temperature profiles of (a) OB1 and (b) OB2 of Pad 106

Fig. 15—Cross section of oil satu-ration model from Pads 103 to 106

(a) OB1 (b) OB2

103 105 104 106-OB2 OB1

OB3