The Journal of the Canadian Heavy Oil Association

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TECHNICAL EDITOR Gordon Stabb COM M ITEE M EM EBERS Adrian Dodds KC Yeung Bruce Carey Mark Savage Breanden Daniels ADVERTISING Please direct advertising inquiries to 2

ABOUTTHECANADIAN HEAVYOILASSOCIATION The mission of the Canadian Heavy Oil Association is to provide an appropriate technical, educational and social forum for those employed in, or associated with, the heavy oil and oilsands industries. #100 221 10th Avenue SE Calgary, Alberta T2G 0V9 403.269.1755





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MEMBERSHIPBENEFITS Network with other industry professionals through our Member Exclusive " SOCIAL LINK" plat f or m where you can create your own groups for collaboration, connect with mentors or expand your circle. Save on SOCIAL EVENTS, TECHNICAL EVENTS and WORKSHOPS with a CHOA Membership. Exclusive Member Resources like our M ONTHLY INDUSTRY HIGHLIGHTS and the JOURNAL OF THE OF THE CANADIAN HEAVY OIL ASSOCIATION


has big benefits,

including an outstanding technical program in a variety of formats, popular networking events, access to

the Journal and members-only sections of, discounts for events and workshops, and the opportunity to apply for annual scholarships for CHOA members and family. Most importantly, CHOA membership provides the opportunity to belong to a heavy oil community and contribute to an organization dedicated to improving knowledge on heavy oil and oilsands issues. Visit 5


MESSAGEFROMCHOA'SPRESIDENTCARALYNBENNETT As the incoming President of the Canadian Heavy Oil Association, I am tremendously excited and wholeheartedly privileged to be tasked with painting the picture of our vision for the CHOA in 2019 and beyond.


The task at hand necessitates some reflection. As times change, and we?ve had a lot of change in the last decade, it?s always worthwhile to take a step back and consider the default context in which we operate and make our decisions.

We are faced with the greatest challenge of Canada?s oil and gas industry in several decades and, to me, that sounds like an incredible opportunity for achievement. One that we can attain if we commit to the mindset that ?failure is not an option? and if we commit to working together. Remember, not so long ago, we did change Canada?s and the world?s energy future with the development of commercial oil sands mining, CHOPS and SAGD technologies ? and that?s to name just a few. It is time for us to take action to re-instill pride in our world class industry. Our success, I think, will depend on our ability as an industry to attract and empower talent and our capacity to develop and implement both incremental and step-change technologies to meet or preferably exceed the expectations of our global commitments, the investment community and our own home-grown regulators. We have a noble challenge in front of us as we strive to make the world a better place.

GLJ Petroleum

So I ask: Why does the CHOA exist as an organization? Simply, we exist to accelerate the careers of our members and to strengthen Canada?s energy sector. It is also important to remember, that we came to be as a result of a specific need within Canada?s heavy oil industry. In large part because of the staggering size of our heavy oil resource base and the tremendous amount of variability within it, a need emerged to create forums for sharing knowledge, advancing technology and, ultimately, developing our country?s heavy oil resources safely, responsibly and sustainably, to the benefit of society, both nationally and globally. Does this sound familiar and, perhaps, relevant? The CHOA was created to address this need and we have been busy successfully delivering on our mandate for almost 35 years. So then, What is the CHOA?s role tackling today?s challenges? While we remain true to our purpose and steadfast in our Connect Share Learn mandate, today we see an important role for our organization, proactively supporting our industry and facilitating its successful evolution. One thing is clear, as an industry, we are not going back to the past, so we better have our eyes up as we move towards the future. Think of that hill on your training run ? you can?t be looking at your feet, you need to focus on the crest and commit to the pace.


If you are a problem solver, if you are an innovator, if you are a collaborator, you are in the right place at the right time. The health of our industry will also depend in no small measure on improving the dialogue about our relevance, our importance to society. We need to take more ownership in the conversations about our industry and do our part as individuals and companies to rebalance the conversations. With this in mind, the CHOA is engaging in two new initiatives in 2019: a developing professionals initiative and an advocacy initiative. In October, developing professionals and members in general can look forward to a formal workshop, Changing the Discussion: How to Talk About Oil and Gas. You can also look forward to a series of intimate leader-mentee events where developing professionals can pick the brains of a leader in a personable casual end of day setting. To be clear, our advocacy efforts will not be about policy setting or telling our members what they should think. Rather, our efforts will focus on sharing our stories, recognizing our points of pride and building our skills for better conversations within and outside of industry. We can be a part of resetting the message. New initiatives aside, the CHOA will be working to reinforce our core deliverables, facilitating technology development and knowledge sharing through our technical and our professional development and networking events, and we will be working to modernize the delivery of our content. You can look forward to a refreshed website and our new blog where we will share event updates, member and sponsor profiles and articles from our Journal. Going forward we will be hosting the Journal from our site, expanding the content to include monthly in situ project and technology highlights and a regular advocacy column. We will also continue to build our social media outreach with the support of our members. Finally, we will be moving our home base, so stay tuned for an exciting announcement on that over the next couple of months. Last year was a strong year for the CHOA, we turned a corner, and, thanks to our staff, volunteers, Scott Rempel, our past President and the rest of the board, we are well positioned to launch forward, refreshed, in some new directions for 2019. I look forward to experiencing and being a part of the CHOA?s impactful contributions to industry and to seeing you all at our events. Caralyn Bennett CHOA Pr esiden t



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Land reclamation is an example of where we are aggressively working to advance our innovative thinking ? and accelerate the pace of progressive reclamation of disturbed land at our mining and in situ locations. This work includes: The Nikanotee fen Now more than six years after completing the three-hectare Nikanotee (pronounced Nee-ga-no-tee; Cree word for ?future?) fen, the ongoing research and monitoring are showing that the fen continues to progress. The fen (a form of wetland area that is a highly productive and diverse ecosystem) is remaining wet through the seasonal weather cycles, water quality is good and plants are growing and spreading naturally. Suncor was one of the first companies in the world to complete reconstruction of this type of wetland. This work was completed in co-operation with a number of university researchers and consultants from across the continent. Located at their Oil Sands base plant near Fort McMurray, Alberta, the fen is fed by a man-made 32-hectare watershed. The project is the culmination of more than 10 years of


collaborative research. The University of Waterloo led the fen hydrological feasibility modelling, in partnership with the Cumulative Environmental Management Association (CEMA). Suncor funded the design and construction of the fen. Along with Teck Resources Limited and Imperial Oil Limited, Suncor is funding ongoing research and monitoring of the constructed site. The Nikanotee fen is now a joint industry project, contributed by Suncor to other members of Canada?s Oil Sands Innovation Alliance. PASS Built upon the processes currently used in Suncor ?s Tailings Reduction Operation (TRO? ), they have now developed permanent aquatic storage structure (PASS), a fluid tailings treatment process to significantly increase the amount of fluid tailings to treat in a more sustainable manner. PASS combines the TRO? process with the addition of a coagulant to improve the quality of the water expressed from the treated fluid tailings. The treatment process allows for rapidly dewatering the fluid tailings as the clay particles adhere to the flocculant, safely expressing most of the trapped water

and providing an effective means for creating a lake that achieves their closure plan, and do so in an accelerated timeline. To validate this closure concept, Suncor constructed a demonstration pit lake, now called Lake Miwasin (meaning beautiful in Cree) that contains PASS-treated fluid tailings that will have an aquatic cover established in 2018. The project is planned to be monitored and adaptively managed for the next 15 years. Lake Miwasin Now known as Lake Miwasin, Suncor ?s demonstration pit lake (DPL) is part of their aquatic closure technology development program designed to ensure mine sites can be successfully reclaimed. The DPL project incorporated the PASS fluid tailings treatment process as the first step to accelerating the process to establish a lake capable of supporting a full ecosystem of aquatic life. An aquatic cover will now be established on the treated tailings and operated in the same way planned for the full-scale closure drainage system. Pit lakes are a necessary part of successful closure and reclamation considered a best practice in mining


industries around the world. There are a number of pit lakes in Alberta created from former coal mine pits and are now used for recreational fishing, swimming. They continue to demonstrate naturally colonized fish and staging areas for migratory birds. Throughout the Lake Miwasin project, engagement with Indigenous communities is a major focus for Suncor. Suncor is collaborating with communities on the research and monitoring program so they can learn from each other. Before construction work began, Suncor invited Elders from a neighbouring community to perform a blessing on the land that will be used to develop the demonstration lake. In August 2018, Indigenous Elders and Suncor ?s Indigenous co-op and summer

students participated in planting vegetation around the lakeshore. The planting list included culturally-significant wetland plants, such as ratroot, sweetgrass and sweet gale, Indigenous elders and knowledge holders recommended these plants through the Suncor-sponsored Culturally Significant Wetland Plants Study. In May 2019, members of the First Nations and Metis community member were invited for the Lake Miwasin / Constructed Wetland Treatment System workshop. The workshop provided an opportunity for additional community input on the proposed research and monitoring projects for the community led monitoring (CLM) program for the Lake Miwasin project.



Technical Article

Im pr oved SAGD Pr odu ct ion Well Placem en t w it h Bot t om Wat er BY:MARKSAVAGE,P.L. GEO In t r odu ct ion Bottom water (BW) is found in numerous McMurray Formation reservoirs throughout the Athabasca region of NE Alberta. BW is defined as a zone below the base of bitumen pay with high water saturation (Sw), and can be in direct or non-direct contact with overlying pay. Figu r e 1 shows the BW as a dark blue colour .

Figur e 1 Bottom Water Cr oss-Section (Sour ce: AER 2016 D54 File 8591)

Established by outcrop and control with vertical oil sands evaluation (OSE) wells, BW can have a variable structure and contact geometry with the high viscosity bitumen. A key technical challenge to placing a steam assisted gravity drainage (SAGD) producer well is understanding the BW elevation relative to the pay zone. 3D seismic can?t resolve a sand-on-sand bitumen/BW contact because of the similar density of bitumen and water. Historically, to mitigate the producer well intersecting the BW, most operators applied a producer well stand-off height of +4m above the bitumen/BW contact. The opportunity associated with this technical challenge is to minimize the stand-off height while achieving the operational conditions required for the daily production of these SAGD wells. Reducing the stand-off height by 0.5m adds incremental reserves and can improve 10

economics for a SAGD pad, dependent on reservoir quality and BW structure. The data and figures used in this article are sourced from the Alberta Energy Regulator ?s Directive 054 In-Situ Performance (D54) presentation site, except where noted. The opinions shared are from my first-hand experience working on six different SAGD assets and over 110 SAGD well pairs. My opinions don?t necessarily represent those of my former employers. Back gr ou n d Throughout the history of SAGD well placement, resistivity-based logging while drilling (LWD) technology has evolved. Never the less, a persistent challenge of LWD

technology is the inability to look ahead of the drill bit. The depth of investigation (DOI) of today?s ultra-deep LWD (UDLWD) has dramatically improved, and is now capable of up to 30m DOI, depending on reservoir conditions. While this scale of DOI is impressive and is significant to understanding the reservoir architecture, limitations remain during the drilling process because of the tool?s relative position to the drill bit in the bottom hole assembly (BHA). Dependent on the service provider, and the UDLWD tool configuration used, the tool could be as much as 30m behind the drill bit. This position of the UDLWD tool in the BHA, combined with the unpredictable nature of the bitumen/BW contact could still result in a production well intersecting the BW.

Figu r e 2 shows a BW (dark blue colour fill) wireline log example identified by the resistivity log?s low reading, third column from the right. Note the sand-on-sand contact at the bitumen/BW contact. Figu r e 3 shows another BW log example (dark blue colour fill) from a different operator. The resistivity log is in the first column from the right. This ability to identify BW using geophysical wireline logs aids in confirming the attributes and elevation of the BW at a specific location. By combining the OSE well wireline log picks with a Pre-Cretaceous unconformity structure map derived from 3D seismic, large-scale BW trends can be derived, see Figu r e 4. The cold colours (blues) represent thick BW and are correlatable to Pre-Cretaceous unconformity structural lows. But, at the scale required to confidently plan and drill a SAGD producer well path, the elevation of the BW surface between the well control would be uncertain, see Figu r e 5. This uncertainty can manifest as unpredictable and rapid changes in the BW elevation and characteristics, see Figu r e 6.

Figur e 3 Bottom Water Log (Sour ce: AER 2013 D54 File 10073) Figur e 2 Bottom Water Log (Sour ce: AER 2018 D54 File 10097)



To mitigate uncertainty of the BW elevation during drilling an innovative use of the UDLWD tool combined with a horizontal pilot hole is a solution that can be considered. This solution was tested during drilling of the 2016 Statoil Canada Ltd. Leismer Pad L5 infill well program using the Baker Hughes Visitrak UDLWD tool (Source: Vetsak, A. et al, 2017). Since this initial test in 2016, the process of using a horizontal pilot hole coupled with an UDLWD tool has evolved. Using the OSE well control along and offsetting the well path and by incorporating 3D seismic, a preliminary elevation surface of the BW top of structure (blue dashed line) is estimated, see Figu r e 7.

missed by using only the OSE well log data. This revised top of BW surface (blue colour fill polygon) is used to finalize the producer lateral trajectory (green solid line), see Figu r e 7. The added information can be used to reposition the planned drill path of the producer well to minimize stand-off height, to understand and avoid reservoir complexities and to ultimatelybetter operate the producer. Including the UDLWD data and the revised BW surface in planning and during drilling, will minimize geological uncertainty and increase drilling efficiency of the lateral section in the SAGD producer well. Because of the UDLWD?s

Figu r e 4 Bot t om Wat er Th ick n ess M ap (Sou r ce: AER 2016 D54 File 10935)

This preliminary BW surface is used to plan the pilot hole trajectory (red line) and to plan the preliminary trajectory for the producer well (dashed black line). The horizontal pilot hole and the lateral section of the producer use the same surface hole, build section and intermediate casing point. The pilot hole and producer are drilled using the same BHA. The pilot hole is drilled using a simple flat trajectory at an elevation estimated to be between the producer and injector. The UDLWD resistivity and LWD gamma ray data from the pilot hole, combined with the OSE well control data is then be used to develop a revised elevation surface of the BW top. Figu r e 8 is an example from Leismer Pad L5 and demonstrates the structural surface details that can be gained from use of the pilot hole?s UDLWD data, (right-hand image). Note the structural high region (warm colours) 12

potential 30m DOI, the resistivitydata could provide reservoir characteristic insight associated with the upper portion of the reservoir, above the injector, and possibly the top of pay. This information could be used during the operation of the well pair and would be useful to plan future well interventions, e.g. placement of tubing deployed flow control devices, steam splitters or bridge plugs. In conclusion, this article used BW uncertainty as inspiration for an alternative well placement process, design and execution. A similar alternative pilot well process could be used for solving other reservoir related well placement challenges, such as complex reservoir geometry, heterogeneous reservoir quality at or near the base of pay, and variable fluid saturation (lean zones) within the reservoir.

Ref er en ces Fustic, M., Bennett, B., Huang, H., Larter, S. R. 2012. Differential entrapment of charged oil ? New insights on McMurray Formation oil trapping mechanism. Marine and Petroleum Geology 36 (2012), pages 50 ? 69. Vetsak, A., Jablonski, B., Theunissen, I. 2017. Increased Exposure Oil Reserves by Optimizing Wellbore Placement with Extra-Deep Azimuthal Resistivity LWD Service. EAGE Horizontal Wells 2017, Kazan, Russia, May 15 ? 19. Vetsak, A., Jablonski, B. 2018. Increased Exposed Bitumen Reserves by Optimizing Wellbore Placement in Oil Sands with Extra-Deep Azimuthal Resistivity LWD Service.

Figur e 5 Bottom Water Cr oss-Section (Sour ce: AER 2016 D54 File 10935)

Figur e 6 Chr istina River Outcr op, Bitum en (Sw ~20%) / Bottom Water (Sw =100%), yellow note pad is 20 X 12 cm . (Sour ce: Fustic, M .et al 2012)



Figur e 7 Conceptual Diagr am for Alter native Design and Execution Pr ocess (Sour ce: Savage,

Figur e 8 M apped Top of Bottom Water Str uctur e Sur face, OSE Wells Only (Left) and Wells w ith UDLW D Data (Right). (Sour ce: Vetsak, A. et al 2018)


Mark Savage, P.L. Geo

Mark Savage, P.L. Geo., has been in the oilsands business for over 18 years. Mark started his oilsands career with Petro-Canada working on the Lewis, MacKay River and Fort Hills projects. Since leaving Petro-Canada in 2008 he has been actively engaged in various oilsands assets with Ivanhoe Energy Ltd., Statoil Canada Ltd. and Athabasca Oil Corporation. He has collaborated on and lead in-situ operations and development projects.

Source CAPP member data for spending 2016-2017, aggregated by CAPP 2019


?Getting to Know Industry Leaders?, Bank and Baron -- June 6th, 2019

PHOTO COURTESY OF Mary Hansen, McDaniels & Associates

CHOA'SDEVELOPINGPROFESSIONALS The CHOA is pleased to announce our new Developing Professional initiative. The initiative aims to encourage the attendance of developing professionals at CHOA events, provide opportunities to connect with others in industry, and support the continued education of members. A Developing Professional is defined as an individual who is in the first ten years of their career. The initiative is being led by Lia Carnevale (GLJ), Mary Hansen (McDaniel) and Alex Hollister (IPC), with some exciting events planned for 2019. The launch of our first event series, ?Getting to Know Industry Leaders?, occurred on June 6 at the Bank and Baron. This event series encourages developing professionals to meet and have meaningful discussions with industry leaders over appetizers and wine. Developing professionals are given the opportunity to share their thoughts and opinions firsthand and hear those of leaders in return. The event is limited to 15 professionals to ensure the


discussions are candid and constructive. The first event was hosted with John Festival, President and CEO of Broadview Energy. His insights were greatly appreciated by the attending developing professionals. The series will continue through 2019 with additional industry leaders and developing professionals. One of our upcoming events, ?Changing the Discussion: How to Talk about Oil and Gas?, an event to give attendees the confidence to speak proudly and intelligently about the industry, is planned for October 2019. This formal event will be a panel discussion, followed by breakout discussions. The event will conclude with a networking session, food and beverages. The event will be open to both developing and experienced professionals to encourage the exchange of ideas and opinions. Please watch your inbox or your SOCIAL LINK announcements.

Technical Article

WHYSOMESAGDPROJECTSPERFORMBELOWEXPECTATIONS BY:KCYEUNG Steam Assisted Gravity Drainage (SAGD) is currently the dominant commercial in-situ recovery process of oil sands resources in Alberta. With long horizontal injector and producer wells and continuous steam injection and production, the performance of SAGD is superior to other thermal recovery process in the high viscosity bitumen environment. The first few SAGD projects in Alberta were successful in terms of production rates and efficiency of steam/oil ratios. However, a number of the later SAGD projects have not performed as well, operating below the expectations of operating companies. Here we are going to look at the challenges of meeting ?expected performance.? Reser voir Ch ar act er izat ion an d Pr odu ct ion For ecast n a number of cases, SAGD projects have performed below expectations because those expectations were overly optimistic or based on incomplete data analysis. Companies generally develop production forecasts by using analytical and/or numerical simulation. Numerical simulation is preferred as it can take into consideration the heterogeneity of the reservoir, especially reservoirs with more interbedded barriers and baffles which affect vertical permeability. Sometimes history-matching is performed using an analog SAGD project, if available, but care must be taken to distinguish the difference in reservoir characteristics. Assumptions of how wells were operated in the analog project may need to be made to

achieve results because some operating procedures may not be known from public data. The set up of the geological model used in the simulation depends on the amount and quality of information available from evaluation wells, seismic, and geoscientific interpretation. Limited data on well control, seismic, core analysis and reservoir fluid analysis results in higher uncertainty of reservoir parameters in the geological model. A more optimistic than realistic production forecast may result from a numerical simulation when inexact assumptions of operating procedures, and a high uncertainty geological model are used. The negative impact of the extent, placement and frequency of vertical permeability barriers and water rich, high mobility zones may not be properly taken into account. As a result, the production forecast will be optimistic. Moreover, in order to attract investment and to obtain approval and sanction for a project, some companies may tend to use data from the better part of a project area for modelling to get a better economic evaluation.

Well Design Well design is critically important to the success of a SAGD project, including well placement; lateral spacing between well pairs; horizontal well trajectory; sand control design; and casing and tubing design. a) Placement of wells: In order for a company to book more reserves, wells may be placed close to the bottom of the exploitable part of

the reservoir. However, performance of the wells could compromised if the lower zone lower permeability zones, low saturation zones or is too close to bottom water.

the be has oil the

b) Lateral spacing between well pairs: If the lateral spacing between well pairs is too large, there is steam and heat loss to the reservoir in between the well pairs, especially in the first few years of operations. This would negatively impact initial performance of the wells. However, follow-up infill wells can be used to recover the heat, and improve steam oil ratio. c) Horizontal well trajectory: An improper horizontal well trajectory, undulated along the bottom of reservoir rather than a flat horizontal profile, and non-uniform separation between the injector and producer can cause communication between the injector and producer in a short horizontal section (short-circuiting), resulting in a negative impact on the development of the steam chamber. This can also happen if the vertical spacing is too small between the injector and producer (either by design or equipment error). d) Sand control design: Slotted liners used to be the standard sand control design for SAGD wells, but this has changed over time. Laboratory tests are usually conducted to provide an optimum slot design. If the slots are too large it could cause excessive sand production. Slots too small can easily get plugged with fine sand. In some reservoirs of the Upper and 5


Middle McMurray, Wabiskaw, and Clearwater Formations, the sands are finer and may cause plugging and impede the inflow of production fluids. The negative impact on production rate would be worse for slotted liners with smaller openings than for other sand control designs such as wire-wrapped screen liners. Wire wrapped screen liners are more common in newer SAGD producers in Lloydminster, at Husky's Tucker Lake Project, at the JACOS Hangingstone expansion and at Devon's Jackfish 2 Project. e) Casing and tubing design: The pressure drop in circular pipes depends on the length and diameter of the pipe as well as the flow velocity. Smaller pipe diameter, longer pipe length and higher flow rate will cause a higher pressure drop. Although smaller casings (and thus smaller holes) will reduce the cost of drilling and smaller tubing will reduce the cost of well completion, the resulting high pressure drop may cause flow control problems. For steam injector, the injection pressure at the heel could be significantly higher than the pressure at the toe, and vice versa for the producer. Thus the pressure differential at the heel will be much higher than the pressure differential at the toe. This imbalance will make it more difficult for steam conformance and subcool control.

1. Premature Conversion from Circulation Phase to SAGD Phase: In order to meet a certain production schedule, SAGD wells are sometimes converted from circulation phase to normal SAGD phase prematurely, without sufficient thermal communication between the injector and the producer along the full horizontal length of the wells. Because sufficient thermal communication may be from only a small horizontal section of the producer, the production could drop after a short time, or would not improve as expected. Another operating procedure which may cause production problems is the application of a high pressure differential between the injector and producer during circulation in an attempt to accelerate the communication (bull heading). Although this can help with a faster start-up, this forced communication can cause difficulty establishing uniform steam chamber development along the well length (conformance), as bull-headed communication would be along the more permeable section of the well only. Moreover, there is a higher risk of sand production and abrasion, resulting in liner damage.

Facilit ies Design If individual wells do not produce as much as expected, the project will not reach its designed capacity unless more wells are drilled. However, a project?s steam generation capacity is designed based on the designed steam oil ratio. If the steam oil ratio is higher than forecast, there will not be enough steam to yield the designed project oil rate no matter how many wells are drilled. Facilities should be designed with input from the operations team and consider factors addressing ease of servicing the equipment and vessels, as well as proper locations of measuring devices and sample points. Designers should be mindful that a design which works well in California may not be appropriate for the cold environment of a Canadian winter. Retrofitting the facilities after the fact would delay the production ramp up. Reliability of the facilities plays an important role in meeting the production target. Problems in the steam generators and problems in the high temperature steam separator, which prevent consistent production of high quality steam, will negatively affect the project performance. Oper at ion In the forecast of well performance from reservoir simulation, it is usually assumed that the whole horizontal section of the well contributes to production. Even if heterogeneity of the reservoir has been taken into consideration in the simulation, missteps in operation could negatively impact well performance. Some missteps may include: 18

2. Subcool Control: Subcool is the temperature difference between steam saturation temperature of the injector and the production temperature of the producer. Subcool control is very important in SAGD operation. If the production temperature of the producer is close to the steam saturation temperature of the injector, the subcool is low and vice versa. Low subcool is usually preferred to maximize production because oil viscosity is lower at higher temperature. However, care must be taken by the operator to ensure that the subcool will not become too low as it would result in more steam production. The high velocity of the steam and the sand or fines it may carry, could result in sand production and liner damage in the producer well. It is to be noted that some reservoirs can tolerate a lower

subcool while some may need to operate at a higher subcool, depending on the tendency of sand production. 3. Pressure Control and Fluid Balance Although the operating pressure is supposed to be below the maximum operating pressure (MOP) as assigned by the regulator, human or equipment errors may cause the operating pressure to be higher than the MOP, in which case the caprock could be breached. The loss of steam and fluid from the oil sands formation through the caprock not only affects the well performance, but may also cause environmental damage including cross flow into shallower formations, contamination of overlaying aquifer zones, or a surface blow out. One way to regulate reservoir pressure is to monitor the volumes of injected and produced fluid. Significant imbalance in favour of injection may cause over-pressuring of the reservoir, unless there are thief zones. On the other hand, aggressive production without sufficient injection can cause a pressure and temperature drop in the reservoir.

My recommendations are: · Be realistic. · Recognize the limitations of available data for reservoir characterization and the resulting uncertainties. · It may be warranted to forecast a range of steam/oil ratio and project production rather than a single number. · Project design and operation decisions should be based on industry best practices and principles of sound engineering. Avoid undue consideration of politics or optics. · Utilize technical people with SAGD expertise and experience in order to increase the project?s chances for success.

4. Data Collection and Quality Availability of good quality data is essential to the evaluation of project performance. This includes but is not limited to pressure, temperature, and fluid volumes. Measurement tools may not always function properly, especially during winter. Using erroneous data to analyze the SAGD project performance will result in an ineffective or potential damaging strategy. 5. Communication of Personnel Although an overall operating strategy is usually set up for the project, each SAGD well pair may need to be operated differently to optimize performance. Conflicting opinions between the members of the operating team (reservoir engineer, production or operation engineer, geoscientists, operators, supervisors and managers) may occur as to how to operate the wells. The responsibility and accountability of each team member should be well defined to prevent communication breakdown. Effective communication channels should be established early between operation, production and reservoir staff. Con clu sion s an d Recom m en dat ion There are many factors that can cause a project to perform below expectations. These include: - Production forecast too optimistic - Insufficient data for reservoir characterization

K.C, Yeung

K.C. Yeung is currently Chairman, Partners Energy Development Corp. in Calgary, Canada. He has more than 40 years experience in the oil and gas industry, primarily in the area of heavy oil and oil sands reservoir development and R&D. He previously worked for Texaco Exploration Canada, Suncor, Husky and Brion Energy (now PetroChina Canada),

He was a past President of the Canadian Heavy Oil Association (2005/2006), past Chairman of the Petroleum Society of CIM (2007) and past Director of Society of Petroleum Engineers (SPE) Canada (2011-2013). He had been the Technical Conference Chairman for the World Heavy Oil Congress (WHOC) from 2006 to 2018. He currently serves on the Board of Directors for Energi Simulation. He is an Associate Editor for the SPE Reservoir Evaluation and Engineering Journal. Mr. Yeung has been giving lectures and short courses on heavy oil recovery methods in Canada, China, Europe, Middle East, South America and U.S. to promote Canada?s heavy oil technology and to share his knowledge and experience with the industry.

- Improper well design - Facilities design and reliability issues - Various operational issues Importantly, some companies may want to use a more optimistic forecast to attract investment, but this creates a high risk of not meeting performance expectations. 5


Sponsor Feature


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consistently shown a reduction in execution times by more than 50% and reduced non productive time associated with some key delivery processes. Our technology is versatile and has broad application across industries, with flexible mobilization and commercial options. eXper t , a product of the eWorking portfolio has workers fully connecting in real time with field experts at multiple site locations through a tablet or phone. eXpert facilitates high resolution video and audio streaming for real-time reviews and decision making. This reduces mobilization of team members who would otherwise have to go to site, resolves client queries and concerns immediately, and ultimately reduces delays to the project. The technology leads to savings from massive logistics efforts in planning time, specialists, engineers and budget holders can quickly identify, solve and approve remote problems. Our updated version of eXpert includes remote collaboration technology development with our technology partner. This partnership enables Wood to access live video streaming, hands free cube camera including thermal imaging, and leverages our partner ?s technology to maximize call connections in low bandwidths and areas of limited connectivity. eWor k pack , another product of the suite, connects all reviewers to the same source, allowing them to see and interact with the review process as it progresses. For example, red line markups can be made available to workpacks in real time which allows

information to be sent back to home office faster. With more visibility to the field, developments can be trialed and validated in much shorter time schedules and eliminate the need for paper copies. The eWor k in g M edia Por t al links the two products and provides the means to manage, share and centrally store all of the content created from the eXpert calls as well as any eWorkpack progress updates (as-builds), and package closeouts. Linking all the data inputs from eXpert and eWorkpack enables all parties to connect effectively from any location to support and direct the operation. Currently, Wood is rolling out the next phase in the eWorking portfolio, eWor k pack 2. This is an integrated work management system for real time progressing from the field against tasks within job cards and workpacks. Data centric execution allows for easy handover from construction to commissioning and no data will be lost during with critical phase. Feedback collected so far confirms the package has been easy to use, is built for the field and is lightning-fast. Our field teams can remain confident as we provide them with the most current set of drawings and documents. By working closely with our customers, we have been provided opportunities to apply our eWorking technology and achieve a new standard in how digital solutions will transform the industry to make it faster, safer and more efficient.

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Technical Article

Understanding Tubing Deployed Flow Control Devices in SAGD K. Gohari and O. Becerra, Baker Hughes, a GE Company

Introduction Steam Assisted Gravity Drainage (SAGD) is a complex process which requires more control relative to conventional applications during the production operations. Control of the production profile along the wellbore and prevention of hot spots are essential in improving the drainage efficiency. Over a decade ago the first Flow Control Device (FCD) completions were installed in SAGD wells in Canada with the intention of improving the steam chamber conformance and reducing the steam-oil ratio. The first installations were Liner Deployed (LD) FCDs. Based on the success of LD FCDs, operators progressed to retrofitting with Tubing Deployed (TD) FCDs in underperforming SAGD producers, primarily completed with slotted liners. While the majority of the wells retrofitted with TD FCDs have shown better performance, well failures have been reported and in some cases performance of wells with TD FCDs were below expectations. Hence the question of what?s the cause for this discrepancy with the number of perceived underperforming TD FCDs compared to the LD FCDs.

Liner Deployed vs. Tubing Deployed While the equipment required for both TD FCD completions (Figure 1) and LD FCD completions (Figure 2) are the same, the configuration of the completion and the operating point of the devices performance envelope are quite different. These differences are due to two key factors, the time of implementation in the wells life and the existence of an annular gap. LD FCD completions are installed prior to the initial production phase of the well, allowing them to exert a rate dependent pressure drop ensuring a good development of the steam chamber. In the case of TD FCDs, the completions are installed after a period of time post initial production; the development of the steam chamber has already initiated, perhaps with an uneven conformance. Hence the TD FCDs are used as a corrective measure (reactive) whereas the LD FCD are used as preventative measure (proactive).

Figure 1:Tubing Deployed (retro-fit) FCD Completion

Figure 2: Liner Deployed FCD Completion


For LD FCD completions it is believed that the formation sand will be retained by the sand control media (i.e. screens, slotted liners, etc.) and hence the gap between the open-hole and sand control media will be packed, so once the operation starts radial flow will be dominate the process. Based on this consideration for optimum productivity, screen contact is of paramount importance especially in lower quality sands; this results in the requirement of a larger number of FCDs. In the case of TD FCD the hole stability is provided mechanically by the liner (i.e. with either screens or slots), ensuring that an annular gap exists between the liner and the tubing containing the FCDs. This results in fewer FCDs being required. Therefore, TD FCDs are generally associated with higher fluid

Figure 3: Performance of several FCDs

production rates per joint of FCD compared to the LD FCDs. Figure 3, shows the performance of three devices offering varying degrees of resistance; the section highlighted in blue is a general operation window for LD FCDs. While TD FCD wells may also operate in this blue section, there are a number of the TD FCDs that will operate outside of it. The existence of the annular gap, as in the case of TD FCDs, heightens concerns of erosion. If the liner sand control media is not sized correctly or is in poor condition then alternative approaches to FCDs may be required.

Objective of FCDs The main objective of the TD FCDs is to improve steam chamber conformance

by controlling the production flux profile and choking back the unwanted fluid phase. Unlike conventional applications, where mobility and flow performance of the oil phase is only varied by position on its relative permeability curve, in thermal applications the temperature determines mobility of the oil. Hence the production flux profile along the well is a function of the temperature profile. In hotter well segments the oil will have higher mobility while in colder segments the oil will have lower mobility, and in some cases, oil may have no mobility as the temperature is too low (less than 80°C). Therefore, improving steam chamber conformance is an important objective that can lead to increased productivity. Figure 4, shows the Inflow Performance Relationship (IPR) for a SAGD well (orange curve) that has been matched to actual production data. This model is based on the temperature profile pre-installation of the TD FCDs. The temperature profile had hot and cold sections. By implementing the FCDs, production from the hotter zones should be choked back leading to

higher drawdowns in the cooler less developed segments of the well, and result in improved conformance. Once the steam chamber conformance is improved the productivity rate of the well should increase, as depicted by the green curve in Figure 4.

Understanding Breakdown



Considering that passive FCDs are designed to add a rate dependent pressure drop, it should be expected that the productivity will be altered. However, looking at the performance behavior of an FCD device without consideration of the impact on drawdown could lead to a less effective completion design or to completions that exhibit higher than expected drawdown. This can be explained by an example that is used as proxy, based on analysis of several wells in a field. Figure 5 shows the IPR of the well represented by the dashed black line. The yellow, darker yellow, light orange, dark orange and red dashed lines describe the IPR for the various segments of the well with different reservoir quality. Red is the higher quality sand segment, while the yellow is the lower quality sand segment. The higher quality sand (red) is the segment that provides the majority of the production. To limit the production in the red segment and promote production from lower quality sand in the yellow segment of the well, FCDs could be utilized. The performance of three FCDs with a varying degree of 5


applications [3].

Figure 5: IPR for a well with different quality of sands

resistance are shown by the three blue dashed lines; the lighter blue line represents a lower resistance FCD setting while the darker blue line represents the higher resistance setting. Note that at lower rates the difference between the settings is small, however the difference increases with increased production rates. The ?solution?point where the IPR curve and the performance of the FCD cross represents the production rate achieved from this segment at the desired flowing bottom-hole pressure in the annulus if the same fluid breakdown is assumed. The pressure difference from the solution point to the reference pressure that originated the FCD device curves (green dotted line) is the pressure drop through the FCD. The reservoir pressure minus the pressure at the solution point is the drawdown upstream of the FCDs. As observed, a single FCD resistance setting can provide the solution for a range of production rates. For example, FCD 2 is able to choke the two higher quality sand segments while promoting higher drawdown in the low quality sands. Choking back the higher quality sands responsible for the majority of the production pre FCDs, will result in a lower production rate for a given Flowing Bottom Hole Pressure (FBHP); giving the impression at first glance, that the device is exerting a higher pressure drop than expected. The presence of steam, will further exacerbate the pressure drop through 24

the FCDs in that segment and shift FCD performance curves to the left; the performance could be significantly impacted even though the presence of steam may just be associated with a single compartment (usually the hotter/higher quality sands). To achieve the same or a higher liquid production rate as pre FCD, a higher total drawdown than expected will be observed. Hence when evaluating an FCD completion an entire system performance should be taken into account.

TD FCD Key Considerations The first and most important step is to determine if a well is a good candidate to be retro-fitted with FCDs. While the FCDs have provided value in a lot of cases there are instances where implementation of TD FCDs has exacerbated a problem rather than solving it. Further, if TD FCDs are to be retrofitted in a slotted liner then an analysis should be conducted to ensure that the liner is in good condition (no plugging) or if further remediation is required. There are three key design elements that have shown better results.

This will ensure that the FCD exerts the control needed to further enhance productivity in the lower quality segments. The selection of the FCD resistance setting should be made with the objective of controlling the average to higher quality segments. It important to note, that high quality sections may not have been developed yet and could be cold prior to the installation of the FCDs. FCDs would promote the development of cold high quality sections and therefore enough compartmentalized flow resistance needs to be available to control these high quality sections once they are developed. The second design element is that in thermal applications a constant resistance setting with equal length compartments should be used. This is due to the fact that as the temperature profile changes the deliverability of the sections changes hence constant design approach will ensure that today?s design will perform in the future regardless of the changing conditions. It is important to note that the FCDs are flow rate dependent. Therefore as demonstrated in Figure 6, by having a large enough pressure drop to control the good quality segments, the resistance provided by the FCDs (red) will be less than the drawdown across the formation (blue) in the poor quality segments. In a low production segment the majority of the pressure drop will be from reservoir drawdown rather than FCDs. Note again, that when most of the pre FCD well production is from a single segment, the total pressure drop will be greater than expected based on performance of the FCDs.

The first design element is the pressure drop through the devices needs to be greater than the pressure drop through the sandface [1] [2]. This design element was established in conventional applications and it is Figure 6: Simple depiction of the pressure drop breakdown believed to be equally valid in thermal

The third design element is that with increased reservoir heterogeneity, a higher number of FCD compartments with a higher resistance setting will provide a better control along the wellbore.

Summary While some failures and performance below expectations have been observed with TD FCDs, there have been many wells retro-fitted with FCDs that have performed well. For a successful implementation of TD FCDs an evaluation should be conducted to determine if the well is a suitable candidate, and to forecast the expected improvement in well performance once ideal steam chamber conformance is achieved. If it is the right candidate a

holistic design approach that takes into account the key element of pressure drop as previously explained, should be used to ensure improved performance and minimize well failures. Nevertheless, barriers still exist to better understanding of thermal completions and how to optimize them. Optimizing completions requires quantification of the flow profile along a well. In conventional applications, production logging tools are used. In thermal applications, Distributed Acoustic Sensing (DAS) coupled with Distributed Temperature Sensing (DTS) has potential to provide the solution for quantifying and characterizing flow along the well. This would allow engineers to understand and accurately setup models for well performance analysis and design.

References [1] K. Gohari, H. Jutila, C. Mascagnini, A. Gryaznov, N. Goodwin, M. Howell, P. Kidd and B. Bijani, "Novel Workflow for the Development of a Flow Control Strategy with Consideration of Reservoir Uncertainties," 2015. [2] M. Madan, K. Gohari, R. Vicario, H. A. Jutila and H. A. Mohammed, "Milestones, Lessons Learned and Best Practices in the Designing, Deployment and Installation of ICDs in Saudi Arabia," 2015. [3] M. Irani, "On Subcool Control in the SAGD Producers. Part II: Localized Hot Spots Effects and Optimization of Flow-Control-Devices," 2018.

Oscar Becerra Moreno holds mechanical engineering diploma from University of Carabobo, oil and gas specialist diploma from University de Oriente and Master of Science degree in mechanical engineering from University Simon Bolivar (Venezuela). Oscar began his oil and gas career with the Venezuelan National Oil Company (PDVSA) in 1992 as a production engineer and an artificial lift researcher. Since then he has held positions in Petrobras Energia as senior production engineer in Venezuela and Argentina and in PetroChina Canada as a senior production engineer. He has also worked with service companies supporting lower completions, intelligent completions and artificial lift in Latin America, the Middle East and Canada. Currently, Oscar is the Reservoir Optimization Manager for Lower Completions - Global at BHGE.

Kousha Gohari is currently the lead of the Optimized Completion Strategies Group at Baker Hughes Canada, a GE Company (BHGE). After obtaining a petroleum engineering degree from the Texas Tech University, Kousha joined Baker Hughes and has held a wide range of positions in completions, reservoir and production engineering. Kousha has extensive experience working in the Gulf of Mexico, the North Sea and the Middle East. He has expertise in flow control devices and completion optimization for reservoir management. Kousha holds a number of patents and is an author of numerous technical papers. Currently, Kousha is serving on the Committee of the SPE Thermal Well Integrity and Design Symposium 2019.




CHOA M em ber Pr of ile

Heat h William son Vice Pr esiden t , CHOA

As CHOA?s secretary in 2018, once he became comfortable with the board format, he looked to see how they could modernize, to ?nsure support from the

future generation of energy demand solution providers?. As of May 2019, he became the Vice Heath Williamson was on the front lines of the energy President of the Canadian Heavy Oil Association. And, sector early in life. Literally. Growing up in Lloydminster, despite the economic climate in the energy sector, in the heart of the oil patch, he watched ?All the trucks CHOA has seen marked growth in their membership and services rolling by.?, but it wasn?t until much later numbers this past year and a half. that he truly understood the industry.

Ear ly Fou n dat ion s

New Con t en t an d Deliver y

Fast forward to adulthood, Heath eventually enrolled in Heath describes the CHOA Board as operational with the University of Alberta with an interest in Petroleum every individual director taking on actionable duties. Engineering. To help pay for his education, his entry ?We all chip in. We all lead major events. We hold each into the patch truly began with a company called Mike?s other accountable? says Heath. Oilfield Services, where he enjoyed working on well sites across Alberta and Saskatchewan. Both of Heath?s parents were teachers, and that Around 2005 Mike?s did a job for BlackRock Ventures, a common thread is perhaps one of the reasons for the start-up oil company, and at that moment Heath direction he would like to take the CHOA. ?I?m really decided this was his next step. He also fully admits he excited about what we?re going to roll out with the proceeded to ?Hound them with phone calls?. This CHOA this year.? Says Heath. ?We?re going to really focus dogged persistence lead to a job as an operator the on content delivery for our membership. We need to following summer. give them more digital content and reasons to visit our website where they can stay up-to-date with the The company was soon bought out by Shell but community.? maintained the existing set of employees. In 2009, the former principals of BlackRock came together again to Fu t u r e Vision s an d CHOA form BlackPearl Resources Inc. where Heath had been employed for over 10 years. ?Any time we put on a technical event; we want to In the last quarter of 2018, BlackPearl merged with Lundin Group of Company?s International Petroleum Corp. ?With top tier people and projects,? says Heath of IPC, ?the combined company is well-positioned to achieve sustained growth over the next 5 years.? As Heath moves on to pursue personal ventures within his CutBlack Ventures Investment & Advisory Enterprise, he wishes his friends at IPC Canada ?nothing but tremendous success.?

Fir st In t r odu ct ion

record it. We want to put it on our website.? Heath says. ?Then we can offer this content to our members even if they?ve missed an event.? They are also entertaining the possibility of creating an integrated digital app to assist them with content distribution and industry advocacy, dates for social events or conferences etc. ?We?ll certainly need to find additional funds to make this dream a reality, and we?ll also be polling our members to see what exactly they?d like in terms of content and delivery.?

?Really,? he continues, ?CHOA events facilitate a huge amount of collaboration, networking, and information sharing. I would love to see the CHOA fostering a digital Canadian Heavy Oil community around a hub of industry related content. I believe if we could aggregate all of our content, we could get to a critical mass of member-users who will sustain the CHOA for years to His interest ignited; Heath was eventually asked to be a come.? speaker at Slugging it Out by Doug Fisher of Pengrowth. From there, he joined the organizational committee for Heath?s passion for working with CHOA obviously hasn?t this event and then chaired it the following year. Now a diminished, and the future looks bright for CHOA?s familiar face at these events, Heath was approached by membership as a result. CHOA?s Board of Directors and offered a seat on their board in 2018. With a growing foundation of experience, Heath?s first exposure to CHOA came in 2010 from being encouraged to attend events like the Slugging it Out Conference (a co-branded event with SPE and CHOA) by his long time boss and friend, Chris Hogue.



Monthly Industry Highlights By Bruce Carey & Lia Carnevale

D54 Pr oject Review s - M ay 2019 ATH Leism er

Har vest (KNOC)

· Regulatory approval received for field-wide NCG co-injection

· BlackGold continued its production ramp-up to average 6,515 bbl/d

· Plan to finish Pad 7 well completions on 5 well pairs · Evaluating opportunities for tubing-deployed FCDs into producers on Pads 1-5

Can adian Nat u r al Resou r cee Lim it ed

· Regulatory approvals received for 10 well pairs and 13 infills

· Signed to buy Devon Energy?s Canadian assets for $3.8 billion.

CNOOC Lon g Lak e

Con n ach er Oil an d Gas Lim it ed

· ICD results have been generally positive; will continue to evaluate · Great Divides?s Q1 2019 production was down 15% from Q1 2018 to 10,754 bbl/d installations · 3 Sustaining SAGD well pairs will be drilled and completed in 2019-2020 · Evaluating re-start of NCG injection on Pad 7N and 7E

M ar at h on Pet r oleu m Cor por at ion

· 10 infill wells drilled in 2018; planning further drills

· Decided to cancel a planned project increasing heavy oil processing capacity at one of the largest refineries in the U.S.

· Progressing construction of K1A replacement pipelines & restart of facility

M EG En er gy

COP Su r m on t

· Christina Lake?s bitumen production averaged 87,113 bbls/d in the first quarter of 2019, seven per cent lower than the same period in 2018, and attributed to the Alberta government's mandated production curtailment program

· Continuing to evaluate NCG co-injection for pressure management and thief zone mitigation. · Evaluating multilateral infill producers off of existing SAGD producers. · Evaluating infill opportunities. · Evaluating redevelopment opportunities for under-performing pads.

OSUM Or ion · Program planned to further delineate Upper Grand Rapids Channel Sou r ce: -reports/activity-and-data/in-situ-performance-presentations

DOB an d BOE Ar t icles of Not e ? M ay 2019 Pen gr ow t h Cor por at ion

Hu sk y En er gy · In June, the company will begin using artificial intelligence at its Lloydminster thermal oil operations as it looks to get ?even more juice? out of the prolific assets.

Ot h er · Alberta?s total in situ bitumen production increased by approximately 11,500 bbls/d in March, likely in part due to easing of the province?s oil curtailment order. Primary production volumes led the gain, increasing approximately 8,200 bbls/d month-over-month. · A new study by IHS Markit says the breakeven WTI price for a SAGD expansion is now US$45/bbl, compared to US$65/bbl in 2014. For a mining project without an upgrader it?s US$65/bbl, down from $100/bbl in 2014. Sou r ce: Daily Oil Bulletin and BOE Report

· Lindbergh showed a 20% year-over-year increase in bitumen production from 15,118bbl/d to 18,193 bbl/d At h abasca Oil Cor por at ion · Leismer - L7 sustaining pad rig released, first production anticipated Q4 2019


Tech n ical Pu blicat ion s of Not e ? M ay 2019 · ?An Experimental Study of Emulsion Phase Behavior and Viscosity for Athabasca Bitumen/ Diethylamine/Brine Mixtures? (SPE-189768-PA)

· ?Polymer-Flood Field Implementation: Pattern Configuration and Horizontal vs. Vertical Wells? (SPE-190233-PA)

Regu lat or y Applicat ion s of Not e ? M ay 2019

· ?Maximizing the Value of Information of a Horizontal Polymer Pilot Under Uncertainty Incorporating the Risk Attitude of the Decision Maker ? (SPE-190871-PA)

Can adian Nat u r al Resou r ces Lim it ed

· ?Performance Evaluation of Fly Ash as a Potential Demulsifier for Water-in-Crude-Oil Emulsion Stabilized by Asphaltenes? (SPE-192364-PA) · ?Advancing High-Temperature ESP Technology for SAGD Applications? (SPE-194387-M S) · ?Analyzing SAGD Producer Flow Instability and ESP Deterioration Using Dynamic Flow Simulations: A Field Case Study? (SPE-194403-M S)

1920884: Application to steam Primrose East Area 2, Phases 90-95 using a modified CSS steaming strategy. Im per ial Oil Resou r ces Lim it ed 1921176: Application to construct and operate an ?Enhanced Bitumen Recovery Technology Pilot? at the Aspen oil sands lease to assess a high solvent concentration process (90% by vol) with steam (10% by vol) at pressures ranging from 500 kPa (150oC) to 1500 (200oC) starting in 2023. M EG En er gy

· ?Assessment of ESP No-Flow Events in SAGD Production Wells? (SPE-194420-M S) · ?Diffusivity of Gas Into Bitumen: Part I - Analysis of Pressure-Decay Data With Swelling? (SPE-195574-PA) · ?Diffusivity of Gas Into Bitumen: Part II - Data Set and Correlation? (SPE-195575-PA) · ?Upscaling the Steam-Assisted-Gravity-Drainage Model for Heterogeneous Reservoirs? (SPE-195587-PA)

1921245: Application to extend the current eMVAPEX Experimental Scheme at Christina Lake for two additional years ending in September 2021. MEG requires more time and data to assess whether the process is commercially viable.

Sou r ce:

· ?An Empirical Oil, Steam, and Produced-Water Forecasting Model for Steam-Assisted Gravity Drainage With Linear Steam-Chamber Geometry? (SPE-195675-PA) Sou r ce: 5 29


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Even t Spon sor sh ip Oppor t u n it ies



SLUGGING IT OUT - Annual Spring Conference CHOA FALL CONFERENCE Annual STAM PEDE Par t y CHOA GOLF Tou r n am en t Annual DARE TO BE BOLD EVENT- Charity Event Spon sor sh ip In qu ir ies Karmen Chant -


President Caralyn Bennett GLJ Petroleum Consultants Vice-President Heath Williamson International Petroleum Corp. Treasurer Hansine Ullberg Kostelecky


Director Louisa DeCarlo Danrich Resources Corp.

Director Kudjo Fiakpui Alberta Energy Regulator Director Gordon Holden Surmont Energy Ltd. RGL Reservoir Management Ltd. Director Carmen Lee Past President Husky Energy Scott Rempel WOOD

Director Keith Schilling Baker Hughes GE Director Allan To Suncor Energy

DISCLAIMER: The purpose of the Journal of the CHOA is to publicize the association's activities and provide an appropriate technical, educational, and social forum for those employed in or associated with the heavy oil and oilsands industries. Association publications shall contain no judgmental remarks or opinions as to the technical competence, personal character or motivations of any individual, company or group. Further, technical remarks, opinions and conclusions expressed in articles published in the Journal of the CHOA are those of the author and are not officially endorsed by the CHOA unless otherwise noted. Material contained in the Journal of the CHOA is intended for informational use only.

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