CHOA 35th Anniversary Edition Journal - Issue 4

OPINION

The Case for Liquid Solvents: Lessons Learnt from Industrial Pilots on Steam-Solvent Co-injection

BY ZHANGXING (JOHN) CHEN, RAN LI, WEI WU, SHENG YANG, JINZE XU, QIONG WANG, MOHSEN KESHAVARZ, XIAOHU DONG, XINFENG JIA, MIN YANG, MAOJIE CHAI, AND DONGQI JI*

RESERVOIR SIMULATION GROUP, DEPARTMENT OF CHEMICAL AND PETROLEUM ENGINEERING, UNIVERSITY OF CALGARY

(*CURRENTLY: M. KESHAVARZ AT SUNCOR ENERGY INC., X. DONG AND X. JIA AT CHINA UNIVERSITY OF PETROLEUM (BEIJING), M. YANG AT CHINA UNIVERSITY OF PETROLEUM (QINGDAO), AND D. JI AT CHINA UNIVERSITY OF GEOSCIENCES (BEIJING))

ABSTRACT

Adding a solvent in a steam-based recovery process is conducive to mobilizing bitumen through solvent dissolution, reducing water usage by decreasing steam consumption, decreasing greenhouse gas (GHG) emissions released by the recovery process, and potentially unlocking currently uneconomical reservoirs. This article stems from a presentation at the annual Energi Simulation Summit in 2021, summarizes the lessons learnt from several key pilot evaluations, and will shed light on finely designing viable solvent-steam co-injection strategies and projects.

ABSTRACT

Steam assisted gravity drainage (SAGD) has proven to be the most promising process for the commercial in situ recovery of bitumen in Alberta [1]. For high quality and thick reservoirs, SAGD can achieve a bitumen recovery of over 50% original bitumen in place (OBIP) and a steam-oil ratio (SOR) of 2.5 to 4.0. But for thin (thickness less than 15 m) or partially depleted or low bitumen saturation reservoirs, the SOR can be much higher, and the process becomes uneconomic due to an excessive heat loss to the overburden and a large heat requirement to heat the reservoir rock. Oil production companies have continued to look for alternative processes for more economic and more environmentally sustainable recovery of bitumen, particularly when the Canadian government has announced plans [2] to increase the carbon tax from its current level of $30 per ton to $170 per ton over the next nine years in responding to climate change. The most recently issued data from the Government of Canada indicated that in situ thermal operations in Alberta emitted 43 megatons (Mt) of carbon dioxide in 2019 [3].

Promising avenues for improving SAGD to achieve lower costs and lower carbon emissions include steam-solvent co-injection recovery processes. Examples include the Solvent Aided Process (SAP), Liquid Addition to Steam for Enhancing Recovery (LASER), Expanding Solvent SAGD (ES-SAGD), Solvent Assisted SAGD (SA-SAGD), Solvent Cyclic SAGD (SC-SAGD), Solvent Co-Injection (SCI), Solvent Low Pressure SAGD (SLP- SAGD), and Enhanced Modified Vapour Extraction (eMVAPEX) processes [4-13]. Adding a solvent is conducive to diluting bitumen and reducing its viscosity through solvent dissolution whose effect is determined by solvent mass transfer and heat conduction in the reservoir. A large solvent diffusion coefficient leads to a high oil mobility and consequently

an uplift in the bitumen production rate. In addition, solvent injection reduces freshwater usage intensity (per barrel of bitumen produced) and its treatment compared to pure steam injection, thereby resulting in a reduced SOR. Furthermore, solvent injection contributes to declined GHG emissions intensities. According to the Oil Sands Emissions Limit Act, Alberta imposes restrictions on GHG emissions for bitumen production. Adding a solvent will reduce the need for energy-intensive steam generation, whose impact, relative to SAGD, is a 65% reduction in direct GHG emissions according to Canadian Energy Research Institute [14].

Despite the abovementioned benefits, some of the previous steamsolvent co-injection pilots have not performed well as per their design and/or execution. From the field projects listed in Table 1 below, important learnings included:

• Convincing laboratory experiments and/or reservoir simulations were not carried out for demonstrating the co-injection feasibility, particularly for heterogeneous reservoirs with lean zones and shale layers. Effects of reservoir heterogeneity on co-injection were not well understood.

• The solvent that was used was too heavy and was injected for a too brief period of time (e.g., Nexen’s 2006 pilot).

• The solvent concentration used was too low to be effective (e.g., Suncor’s Firebag 2005 pilot).

• A pilot was conducted when the bitumen recovery was already so high that there was insufficient bitumen left for further economic recovery (e.g., Devon’s 2013 pilot).

• Thorough sampling and study of produced fluids were not conducted for evaluating solvent recovery.

• An appropriate adjustment of sub-cool during co-injection is not properly established.

• A good baseline was not established with steady steam for proper comparison.

• Steady operations were not performed for removing effects of variations in operating parameters.

• A proper switching point to convert to normal SAGD to recover solvent was not well-founded.

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This article summarizes our evaluations of several previous and potential industrial co-injection pilots in terms of a solvent type, solvent ratio, bitumen rate, and SOR. Particularly, lessons learnt from both successful and less successful co-injection pilots are provided. On these bases, specific recommendations on how to finely design steam-solvent coinjection strategies and pilots are presented to maximize the co-injection success opportunities.

ABSTRACT

Table 1 summarizes several key industrial steam-solvent co-injection pilots conducted in Canada [15-17]. Solvents are divided into three main categories in terms of their volatility: light solvents (volatility comparable to C4 and lighter), heavy solvents (volatility comparable to C8 and heavier) and medium solvents (between the light and heavy categories). For multi-component solvents, an average molecular weight is used as the criterion to include them in one of these categories. As examples, Imperial Oil’s SA-SAGD Pilot, Connacher’s SAGD+ Pilot, and Suncor’s ES- SAGD Pilot are analyzed.

Imperial Oil SA-SAGD T13 Pilot

The target reservoir in this pilot project was the Clearwater formation [18]. There were two horizontal well pairs (WP1 and WP2) and three observation wells per well pair in the pilot area. WP1 consisted of T13- 01 and T13-02 and WP2 was composed of T13-03 and T13-04 (Figure 1). Table 2 lists the basic parameters of this pilot. Under the operating pressure of 3,500 kPa, a solvent mixture (diluent composited of C3 to C10) was co-injected with steam at a concentration of 10 - 20% volume percentage. Solvent injection was first conducted in WP2 for around 26 months and then switched to WP1 to compare hydrocarbon production rates and SORs.

A 30% bitumen rate uplift and 25% SOR reduction were achieved by the pilot. The solvent recovery reached 75% in WP2, and lower GHG emission intensity and water usage were reported. From Figure 2, during steam-solvent co-injection, the hydrocarbon production rate of WP2 was increased from 40 to 75 m3/day and its SOR dropped from 6 to less than 4 Sm3/Sm3. Similarly, adding a solvent mixture in steam increased the hydrocarbon production rate of WP1 from 30 to 50 m3/day and reduced its SOR from 5 to less than 3 Sm3/Sm3.

Company and Project

Encana / Cenovus Senlac SAP (2002)

Operating Pressure

Solvent

Concentration and Duration

5000 kPa

C 4

15 wt% for 7 months

Improved oil rate

and SOR

Performance w.r.t. base SAGD

Light Medium HeavyNA

NA

Encana / Cenovus Christina Lake SAP (2004)

Not reported

C 4

15 wt% for ~1 year

(initial co-injection

plan: 3 years)

Improved oil rate and SOR

NA

NACenovus Christina Lake SAP (2009)

Variable (2200 to 2900 kPa)

C 4

Less than 25 wt% for ~2 years

Improved oil rate and SOR

NA

NANexen Long Lake ES- SAGD (2006)

~1400 kPa Jet B (consisting of mainly C 7 to C 12 )

5 vol% for 2 months

NA

NA

No improvement

observed

Imperial Oil Cold Lake SA-SAGD (2010)

Connacher Algar SAGD+ Phase 1 (2011)

Connacher Algar SAGD+ Phase 1.5 (2012)

Suncor Firebag ES- SAGD (2005)

Conoco Phillips Surmont E-SAGD(2012)

Devon JF SCI pilot (2013)

~3500 kPa Diluent (mixture of C 3 to C 10 )

3500-4000 kPa

3500-4000 kPa

Condensate (consisting of mainly C 4 to C 8 )

Condensate (consisting of mainly C 4 to C 8

)

~2500 kPa Naphtha (mixture of C7 to C9)

~3500 kPa A blend composed of mainly C 3

, C 4 , C 6

Up to 20 vol% for 8 months in WP-2 and then switched to WP-1

10 to 15 vol% for 5 months

10 to 15 vol% for ~ 3 years

15 vol% in one well pair and 2 vol% in the other well pair

18 vol% in one well pair and 20 vol% in the other well pair

NA

NA

NA

Improved oil rate and SOR

Improved oil rate and SOR

Improved oil rate and SOR

NA

NA

NA

NA NA Inconclusive

Improved oil rate and SOR

Improved oil rate and SOR

~2800 kPa

C 6

Up to 20 vol%

NA

Reduced oil rate

and steam

NA

NA

Table 1: Summary of Previous Industrial Co-injection Pilots

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“In our opinion, the Imperial Oil SA-SAGD Pilot has been one of the most successful SA-SAGD field trials so far; it performed successful SA-SAGD operations, 4D seismic monitoring, and simulated history matching.”

To gain a comprehensive understanding of this SA-SAGD pilot, thermocouples and RST (reservoir saturation tool) logs were arranged to monitor temperature profiles and saturations. 4D seismic data was also acquired to compare the obtained temperature profiles. Moreover, laboratory experiments were carried out to evaluate the influencing factors and numerical simulations were performed to match the liquid production rate and SOR. In our opinion, the Imperial Oil SA-SAGD Pilot has been one of the most successful SA-SAGD field trials so far; it performed successful SA-SAGD operations, 4D seismic monitoring, and simulated history matching.

Reservoir oilBitumen

Operating pressure3,500 kPa

Co-injected solvent

Co-injection period

Solvent concentration

Mixture of C3-C10

WP2: 2010/09/01 – 2012/06/15; WP1: 2012/04/01 – 2016/07/01

Up to 20 vol%Table 2: Basic Parameters of the SA -SAGD T13 Pilot

Figure 1: Planar View of the SA-SAGD T13 Pilot Area (Data from AccuMap) [18]

Figure 2: Injection and Production Rates of the SA -SAGD T13 Pilot [18]

CHOA JOURNAL — April 2022 42

Connacher’s SAGD+ Pilot in Algar

Well pairs 203-2 and 203-3 were chosen to conduct a light hydrocarbonsteam co-injection test (Phase 1) from July to November 2011 (Figure 3) [19]. At the very beginning, the solvent concentration was determined to be approximately 10 vol% and it was further increased to 15 vol% in October 2011. An increase of 28% in the bitumen production rate is shown in Figure 4. This corresponds to a reduction of 16% in the SOR after solvent injection when compared with the production data in April 2011. 89% of the injected solvent was recovered until April 2012.

Another two well pairs (203-1 and 203-4) were selected for a second test (Phase 1.5) of the process from May 2012 to April 2015. Between May and August 2012, solvent injection was approximately 10 vol%. After that, the injection rates were adjusted down to around 6%, decreased to about 4% in March 2013, and further averaged to be 5.9% in 2014. It was discovered that the bitumen production rate rose by 30% and the SOR had a 32% decline during the period between May 2012 to April 2013 (Figure 4).

Figure 3: Planar View of Connacher’s SAGD+ Pilot Area (Data from AccuMap) [19]

Figure 4: Solvent Injection and Bitumen Production Rates for Connacher’s SAGD+ Pilot [19]

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Suncor’s ES-SAGD Pilot

Four out of seven well pairs in Pad 109S were used for ES-SAGD (April 2019-May 2020) with a hydrocarbon co-injection concentration of 5-15 vol% (Figure 5) [20]. Pad 109S is located in the northeast of Suncor’s Firebag project with a hydrocarbon area of 1.5 MMm2, continuous reservoir thickness of 28.5m, porosity of 0.33, bitumen saturation of 0.77 and exploitable bitumen in place of 57 MMbbl. Until May 2020, the cumulative oil production in this pad was13 MMbbl and its recovery factor was 23%.

With the co-injection of hydrocarbons, the bitumen production rates from the tested four well pairs were found to increase while the rates from other wells without solvent injection remained unchanged. In addition, early diluent return trends have been established. As shown in Figure 6, the oil rate increased by 40% while SOR decreased by 30%.

Figure 5: Planar View of Suncor’s ES-SAGD Pilot Area (Data from AccuMap) [20]

Figure 6: Oil Production Rate and SOR of ES-SAGD Wells for Suncor’s Pilot (Data from AccuMap)

CHOA JOURNAL — April 2022 44

Ongoing and Future Industrial Co-injection Pilots

Ongoing and future industrial pilots will also provide both insight and inspiration into the application of steam-solvent co-injection. For example, Cenovus FCCL Ltd. has been operating a pilot at its Foster Creek W16 pad for over a year, MEG Energy Corp. has essentially completed an eMVAPEX pilot at its Christina Lake ‘A’ pad, and CNRL has conducted its ES-SAGD pilot at two G10 well pairs in Kirby, which reduces SOR by up to 50%. Suncor will continue their ES-SAGD development efforts in a second well pad in Firebag.

Imperial’s planned SA-SAGD project in Aspen [21] will provide a valuable reference (Figure 7). As per their design, Imperial will operate at a bottom hole pressure of up to 3,400 kPa, and gas lifts will be used during the pilot start-up. The operation pressure will be reduced to around 2,500 kPa and the solvent concentration will be approximately 16.7 vol% during the pilot ramp-up. When the project comes to steady-state operations, the bottom hole pressure will be maintained between 1,000 to 2,500 kPa and the solvent concentration will stay the same. Imperial planned to inject a solvent mixture for ten years before the project wind-down. Imperial’s SA-SAGD design with a longer solvent co-injection period and a higher volumetric fraction of solvent might more substantially benefit steam-solvent co-injection performance. In addition to a proposed pilot at Aspen, Imperial has recently announced that their 10,000 b/d SA-SAGD project in the Grand Rapids Formation at Cold Lake is planned to be operational in 2025.

“Ongoing and future industrial pilots will also provide both insight and inspiration into the application of steam-solvent co-injection.”

Figure 7: Aspen’s SA-SAGD Well Profiles [21]

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Lessons Learnt from Industrial Pilots

Previous field pilots provided invaluable experience and knowledge in finely designing steam-solvent co-injection projects. For example, as addressed above, it is highly recommended that consistent monitoring, thorough sampling and accurateanalysis of produced fluids are conducted in field tests to obtain a reliable value for solvent recovery, a good baseline is established with steam only to allow for proper comparison, pilot tests are operated in a steady manner with minimal operational interference to yield conclusive results, and the effects of reservoir heterogeneity on steamsolvent co-injection need be well understood.

More importantly, a viable steam-solvent co-injection strategy should follow several important guidelines [15, 22]:

• Solvent co-injection is mainly an acceleration process. An early start of co-injection expedites solvent benefits and allows enough time for its recovery after ceasing co-injection.

• Terminating co-injection during the final stages of the process and continuing with pure steam injection provide sufficient time for solvent recovery.

• Retained solvents can be partially re-evaporated with pure steam injection (due to increased average reservoir temperature), which can then be produced and recovered.

• Occurrence of solvent re-evaporation can result in lower residual bitumen saturation inside a steam chamber compared to SAGD.

• Solvents are injected in sufficiently high concentration to make an observable difference (preferably 10-15 vol%).

• One selects a solvent that is light enough to travel in the reservoir as a vapor with steam but heavy enough to have high solubility in bitumen. In most cases, the solvent will need to have dominant constituents of C4, C5, and C6. Considering availability and costs, multicomponent solvents (e.g., gas condensates) are the practical choices for steam-solvent co-injection.

• A pilot test must be of a sufficient size and duration to yield definitive results.

• Convincing laboratory experiments and/or reservoir simulations are recommended to demonstrate the co-injection feasibility and perform sensitivity and economic analyses.

“A viable steam-solvent coinjection strategy should follow several important guidelines”

Large bitumen holdings in Alberta are enormous and very important to the provincial and national economy, and Canadians are demanding their environmentally responsible recovery. In addition to addressing this environmental challenge, steam-solvent co-injection can have other potential benefits, such as reduced water usage, uplifted bitumenproduction rates, shorter project life, decreased SOR (energy intensity), higher ultimate recovery factors, reduced requirements for pipeline transportation, wider well spacing, operation in regions with operating pressure constraints, and unlocking currently uneconomical reservoirs. Extensive lessons have been learnt from the previous and current co-injection pilots and projects in the past 20 years and would significantly impact and accelerate the implementation of future field operations. It is now the critical time to move strategically from pilots to commercialization, especially in responding to Alberta’s recent regulations on industrial GHG pricing regulations and trading systems [23]. It might be advisable that laboratory experiments and reservoir simulation studies are performed before a new co-injection project is implemented, to demonstrate its co-injection feasibility, sensitivity analysis and economical gain, particularly for heterogeneous reservoirs with lean zones and significant barriers to flow, which can improve the success chance of the project and save its operational costs in millions.

“It is now the critical time to move strategically from pilots to commercialization, especially in responding to Alberta’s recent regulations on industrial GHG pricing regulations and trading systems”

Acknowledgements

This article is partly support by an NSERC CRD project that consisted of the industrial partners Computer Modelling Group Ltd., Canadian Natural Resources Ltd., CNOOC International Ltd., Energi Simulation, PetroChina Canada Corp., and Suncor Energy Inc. The authors also thank the CHOA Editorial Committee for their valuable comments for improving this article. The authors wish to thank the CHOA Editorial Committee for their valuable comments in improving this article.

REFERENCES

Comprehensive references for this article are located online.

CHOA JOURNAL — April 2022 46

Zhangxing (John) Chen holds the NSERC/Energi Simulation Industrial Research Chair and Alberta Innovates Industrial Chair and is a Killam Professor at the University of Calgary. His Ph.D. (1991) is from Purdue University, USA. He has authored/co-authored 25 books, published 1,000 research articles, and owned 30 patents. Dr. Chen is a Fellow of the Royal Society of Canada, Canadian Academy of Engineering and Energy Institute of Canada, and a Member of Chinese Academy of Engineering and European Union Academy of Sciences. He has received numerous prestigious awards, such as NSERC’s Synergy Award for Innovation, The Outstanding Leadership in Alberta Technology Award, IBM Faculty Award, and Fields-CAIMS Prize. His research interest is in Reservoir Engineering and Simulation and Renewable Energy.

Ran Li is currently a research associate in the Reservoir Simulation Group at University of Calgary. She holds Ph.D. and master’s degrees in petroleum engineering from University of Calgary, and a bachelor’s degree in petroleum engineering from China University of Petroleum (East China). She has extensive industrial and academic project experience in oil sands and shale gas.

Wei Wu is currently a Ph.D. student in the Department of Chemical and Petroleum Engineering at University of Calgary. Her research interests include thermal recovery, heat transfer, rock wettability, experimental measurements of water flooding, and reservoir simulation. She holds a M.Sc. degree in Petroleum Engineering from University of Calgary in 2017 and a B.Sc. degree in Geochemistry from Yangtze University.

Sheng Yang holds a PhD degree in Petroleum Engineering from University of Calgary in 2018. His research interests include thermal recovery, artificial intelligence, tight reservoir simulation, and reservoir characterization. He has authored/coauthored over 30 technical papers. He holds a M.Sc. degree in Integrated Petroleum Geoscience from University of Alberta, a M.Sc. degree in Petroleum Geology from China University of Petroleum (Beijing) and a B.Sc. in Geophysics from Yangtze University.

Jinze Xu holds Ph.D. and master’s degrees in petroleum engineering from University of Calgary, and a bachelor’s degree in petroleum engineering from China University of Geosciences (Beijing). He has more than five years of working experience in international oil and gas companies in Canada.

Qiong Wang holds a Ph.D. degree in petroleum engineering from the University of Calgary and currently is a visiting scholar in the Reservoir Simulation Group at the University of Calgary. Her research interest is in improved heavy oil recovery methods and CCUS techno-economic analysis.

Mohsen Keshavarz is currently a Project Economist within Suncor Energy’s Strategy and Corporate Development team. Formerly, he held reservoir and production engineering roles in Suncor. His research interests include analytical and numerical modeling of thermal and solvent-thermal recovery processes for heavy oil and oil sands. He is a registered professional engineer in Alberta and holds master’s and PhD degrees in petroleum engineering from the University of Alberta and the University of Calgary, respectively.

Xiaohu Dong is currently an associate professor at the China University of Petroleum (Beijing). Previously, he was a post-doctoral fellow at the University of Calgary. His research interests include thermal/non-thermal heavy oil recovery techniques, multiphase flow in porous media, phase behavior of fluids in unconventional reservoirs, and EOR processes. He holds a PhD degree in petroleum engineering from the China University of Petroleum (Beijing).

Xinfeng Jia currently works at China University of Petroleum (Beijing). He holds a PhD degree in petroleum engineering from University of Regina. His major research areas include thermal recovery of heavy oil, solvent assisted steam injection, and reservoir simulation.

Min Yang currently works at China University of Petroleum (East China). She holds a PhD degree in petroleum engineering from University of Calgary. Her major research areas include thermal recovery of heavy oil, solvent assisted steam injection, in-situ combustion, and reservoir simulation. She has authored or coauthored over 20 refereed-journal articles and conference papers.

Maojie Chai is currently a PhD student in the Reservoir Simulation Group at the University of Calgary. His research topic for his Ph.D. in petroleum engineering is concerned with the development of a dimethyl ether (DME) injection process for heavy oil recovery. His research interests include analytical and numerical modelling, phase behavior simulation and asphaltene precipitation forecasting.

Dongqi Ji is a post-doctoral fellow at China University of Geosciences (Beijing) since 2020. His research interests are thermal, thermal-solvent, gas-assisted and electrical heating methods for heavy oil/oil sands recovery, as well as relevant numerical simulation software developments. He has a B.Eng. degree in petroleum engineering from China University of Petroleum (Beijing), and M.S. and Ph.D. degrees in petroleum engineering from University of Calgary.

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