Duvernay magazine Fall 2019

The Magazine Of The Oil & Gas Industry

Fall, 2019

Price: $12.95

Premier issue

Oil & Gas

Welcome to the new Oil & Gas quarterly magazine We are in Whitecourt, Fox Creek, Valleyview, Edson, Rocky Mountain House, and Drayton Valley.

Our next publications: January, April, and July, 2020

THE

For advertising/ advertorial, contact: theduvernay@gmail.com or Vicki at 780-268-3955 or Valerie at 780-706-1858 theduvernay.com

contents

4

THE Premier Issue - Fall, 2019 Editor-in-Chief Valerie Winger Advertising/Public Relations Vicki Winger Art Director Catalin Ciolca

23 28

8

24

03 Tools Interrogator & Sabertooth Spectral Noise Acquisition Platforms 04 History The early days of the Fox Creek boom 07 Advisory National Energy Board Safety Advisory 08 Report Net interprovincial migration positive but slow 09 Showcase Send us your best photos!

10 Development Increasing number of earthquakes in Fox Creek 11 Development Earthquake monitoring 11 Development CAPP releases new VR program 12 Editorial Protecting AER protects Alberta energy industry integrity 14 Editorial Alberta Energy Regulator overhaul a dangerous game 16 Projects Expanding Pembina’s Duvernay Complex 18 Donation Shell Canada donates $50,000 to local organizations 19 Report Oil and gas drilling down in 2019 21 Technology The shift to horizontal fracturing 23 Environment At what cost do we save the caribou?

24 Report Normal and unusual things made from oil and gas we use almost daily!

28 Forecast Current Drilling Forecast 30 Opinion Let’s not miss Canada’s LNG opportunity 31 Opinion Alberta’s energy prosperity is Canada’s prosperity 32 Study overview Canadian crude oil and natural gas production 36 Map Duvernay Formation Summary 38 Report AER water use performance 40 Incidents OHS notices about industry fatalities

Contributors ATB Financial; Encana Corporation Canadian Association of Petroleum Producers; Pembina Pipeline Corporation; Alberta Energy Regulator; Bill McLaughlin; Tristan Goodman, President of The Explorers and Producers Association of Canada (EPAC); Todd Loewen, MLA Printer CentralWeb www.centralweb.ca Contact Valerie Winger, 780-706-1858 Vicki Winger, 780-268-3955 Email: theduvernay@gmail.com Fax: 1-866-647-4105 Address Box 2395, Whitecourt, Alberta. T7S 1W3

theduvernay.com

37

tools

Interrogator & Sabertooth Spectral Noise Acquisition Platforms

By Travis Ryan, Versa-Line Services Inc.

T

echnical advancements within the oil and gas industry have evolved at a rapid pace in years past as the industry strives for increased efficiencies in data acquisition, deployment options, and costs associated with both.

One of the many ways that Versa-Line Services, an Alberta owned private slick line, electric line, and swabbing company, has tried to align with these demands to implement new technological variations to old technologies. With ever-evolving liabilities within our industry, in terms of abandonments, one such technology we offer is Spectral Noise Logging. We are proud to offer our current and future clients our Interrogator and Sabertooth Spectral Noise Acquisition platforms.

Interrogator is a real-time based acquisition software where noise measurements obtained by a conventional noise tool are put through a software platform to provide a sensitized visual representation of the noise signals obtained and is an industry leader in SCVF (surface casing vent flow) and GM (gas migration) diagnostics. This software platform allows for an increased range of measurement as compared to traditional conventional noise tools and provides an increased range of 4 Hz to 20 kHz, up from 4 Hz to 10 kHz. The processed data provides a spectral presentation highlighting channel flow and micro-annulus flow.

Sabertooth is a memory-based Spectral Noise and High Precision Temperature acquisition platform. This tool’s memory capabilities allow us to provide our clients with options without sacrificing data capability and quality. Our Sabertooth noise tool is a hydrophone type noise acquisition tool providing a range of measurement unmatched within our industry and ranging from 8 Hz to 60 kHz with a dynamic range of 80 Db. Like our Interrogator platform, the Sabertooth data is presented in a spectral presentation to highlight channel flow, micro-annulus flow, fluid movement behind multiple barriers of pipe, and out to five metres from the tool sensor itself in a 360° radius. This allows for a clearer understanding of where fluid and gas move behind pipe, and aids our clients in

determining source points of flow, thief zones, loss of production, and aid in providing pinpoint production profiles.

Our team of experienced professionals work with our clients and strive to provide clarity to our clients within this, and all parts of our business. This is just one of the many ways Versa-Line Services are “dedicated people providing customer satisfaction.”

Interrogator Noise Presentation

- Cased Hole Logging - Perforating - Slickline - Swabbing - High Deviation Toolstring - Sabertooth Logging

Whitecourt Grande Prairie Toll Free 1.866.447.7922 Red Deer www.versa-line.comFall, 2019Calgary 3

history The early days of the Fox Appearing on maps in a Dominion land surveyor’s notebook dating as far back as 1928, the townsite of Fox Creek, Alberta was not officially founded until July 6, 1952.

U

Services With a proven track record of high-quality workmanship and remarkable service, you can be sure that you’ve made the right choice when you select Lynx Controls. We are experienced in every area of industrial, commercial and residential work for electrical and instrumentation jobs.

Some of the areas that we can provide outstanding services: • Design/build electrical installations • Instrumentation, installation and calibrations on devices • Electric motor and variable frequency drive installation • Troubleshooting and customized control applications • Troubleshooting and diagnosis of any electrical related issues • Instrumentation and calibration services performed by experienced journeyman technicians.

• Electrical and instrumentation maintenance contracts

• • •

• •

On-Call technicians available 24/7 to respond when issues arise Creating and executing of preventative maintenance programs Prefab services including electrical design and construction of skid buildings and panel boards Underground electrical construction, including trenching and cable locating services.

Residential electrical services such as lighting and outlet repair, circuit breaker repair, electrical wiring and more

Let Lynx Controls help you with your next project. Contact us today.

Lynx Controls 3370 33 St, Whitecourt 780-268-3333

4

Fall, 2019

p until the 1950s, it was one of the most northern remote parts of Alberta until the discovery of forestry, oil, and natural gas reserves.

The opening of Highway 43 from Whitecourt to Valleyview in 1955 allowed for easier access for equipment and people to move into the area. Over the next several years, Fox Creek became a very active place as lumber was a big commodity on both the north and south sides of Highway 43. In 1956, Alberta Forest Services built the first two homes in the hamlet to support a ranger station that opened a year later.

Highway Avenue and 1st Street (the initial stage of Kaybob Drive from the highway) was constructed in 1956 paving the way for the opening of the first two businesses, both of which were gas stations.

It wasn’t until 1957 when California Standard Company Ltd. farmed out a well at 07-22-64-19-W5 to Phillips Petroleum using Hewgley’s Drilling. It turned out to be a big error as the well was a significant discovery of gas in the Beaver Hill Lake zone. California Standard immediately followed with a joint venture between two other companies, British American and Phillips Petroleum to drill another one at 07-33-6319-W5. This well, too, proved very successful and so began the race for more productive wells to be drilled in the area.

Other companies such as Placid Oil, Ohio Oil Company, and Hudson’s Bay Oil and Gas began moving into the area and drilling on both sides of Highway 43. Also, in the mid 1950’s, Pan American Petroleum Corporation (formerly Stanolind Oil & Gas Company) and British Petroleum began construction and upgrades in the 60-19-W5 section and access roads around the Berlin Tower. It is these three companies that eventually merged to form Amoco and later became BP Amoco.

The boom of oil activity began and, for the next six years, a total of 12 oil and gas fields were discovered including the significant discovery in 1961 of the Kaybob South Field by a group of nine oil companies. The first big well discovered in the Kaybob South Field was at 11-33-59-18-W5 by California Standard (later known as Chevron).

From 1961 to 1972, there were over 100 wells drilled in the south field with an average depth of 11,000 feet

Creek boom and a total of 1,800 wells drilled by 1967 all within the Devonian Beaver Hill Lake formation. Massive construction and fieldwork began to build five gas plants in the Fox Creek area to tie in all the wells. For 22 months, a 1,600-man camp was set up for these projects. Chevron Standard also built and commenced operations in 1972 for its Kaybob South Gas Plant which was the largest sour gas processing plant in the world.

With the oilfields in full swing, Chevron Standard was one of the first major companies helping to boost the hamlet by building 60 bungalow homes and a 24-suite apartment complex for its employees and their families. Later came more subsidized housing of 131 units and apartments which Amoco Canada (formerly Dome Petroleum then Hudson’s Bay Company) sold to its employees.

Information obtained from Fox Creek Reflections created by the Historical Society

FIRE COMBO UNITS WILDLAND RESPONSE UNITS SHOWER UNITS

AIR TRAILERS MEDICAL SERVICES AIR MONITORING

Fall, 2019

5

advisory

We have the gear to get you going and MORE! Check out the brands we carry:

National Energy Board Safety Advisory

O

n July 3, 2019, the National Energy Board issued a safety advisory to inform pipeline operators of a potential hazard regarding API 5L Monogram Electric Resistance Weld pipe joints manufactured

by Hyundai Steel in its Ulsan, South Korea mill. A review of recent pipeline incidents in Alberta did not find any links to the hazard identified; however, this hazard, if present, could lead to pipeline integrity issues in the future. As such, the AER is reminding licensees that they must conduct an engineering assessment if they become aware of a condition that can lead to failures in their pipeline systems as per clause 10.3.2.1 of CAN/CSA Z662 – Oil and Gas Pipeline Systems: Where the operating company becomes aware of conditions that can lead to failures in its pipeline systems, it shall conduct an engineering assessment to determine which portions can be susceptible to failures and whether such portions are suitable for continued service.

Open Late till 8:00 pm,

Monday to Friday and 7:00 pm Weekends

Two locations to serve you better FOX CREEK, 20B Commercial Crt. 780.622.2253 VALLEYVIEW, 5004,Fall, 50th Ave 780-524-2386 2019 7

report

Net interprovincial migration

positive A but slow

high unemployment rate, sluggish job creation and tepid growth overall is keeping a lid on the net flow of people into Alberta from the rest of Canada, but we have not been in negative territory since the second quarter of 2018.

People come to Alberta from other parts of the country— and vice versa—for lots of reasons. Some are relocating for school, some are seeking adventure, some are returning home to retire or to be with family, and some are looking for work.

It’s the availability of jobs—or the lack thereof—that makes the net flow of interprovincial migrants a useful economic indicator. Simply put, it’s a good sign if more people are coming than going.

Sure enough, Alberta gained about 29,000 residents via interprovincial migration in 2014 when the economy was booming and lost almost 18,000 in 2016 when it was in the grip of a recession.

So it’s a good sign that more people have moved to Alberta from other parts of the country than left over the first 6 months of 2019. Net interprovincial migration has been positive for the last 4 quarters after 12 consecutive quarters in the red.

Less encouraging, however, is the fact that we gained only 417 people from interprovincial migration in the second quarter of 2019, down from 1,974 in the first quarter and well below the average before the recession.

8

Fall, 2019

showcase

Send us your best photos!

Send in your best work photos along with a brief description to be showcased in our next publication. Email photos to: theduvernay@gmail.com

Getting a massive drilling rig ready for the Arctic Submitted by Charmaine Robinson

Flare Submitted by Kevin James Beaton

DISCOVER THE OPPORTUNITY

Valleyview

Fox Creek

EXPANDYOURVISION.CA

Drilling rig at dawn Submitted by Debbie Campbell

Coil Tubing Job Submitted

by Terry Goddard

Situated in the heart of the Deep Basin, Greenview is poised to become Alberta’s centre of energy diversification.

One of the most productive regions in Canada, Greenview is an ideal location for oil & gas activities, offering many diverse investment opportunities.

MDGREENVIEW.AB.CA

Well completion Submitted by Bradley Smith

A typical day at work Submitted by Ed Steenburg

development

Increasing number of earthquakes in Fox Creek monitoring and reporting requirements in place for hydraulic fracturing operators in the area.

Our Requirements

A

lberta’s Fox Creek area has experienced an increasing number of earthquakes since December 2013 that have been associated with hydraulic fracturing operations.

While there have been no known impacts to the public, nearby infrastructure, or the environment, we want to help ensure the safe, orderly, and environmentally responsible development of energy resources. For this reason, we have

Before operating, companies drilling within the Duvernay Zone in the Fox Creek area must assess the potential for earthquakes caused by, or resulting from, hydraulic fracturing.

A company must be prepared to implement a response plan if an earthquake is detected.

Companies in the area must comply with Subsurface Order No. 2, which imposes seismic monitoring and reporting requirements in the zone. The order specifies that companies conducting hydraulic fracturing operations in this zone must monitor seismic activity within 5 kilometres of their wells during operations.

We also have a number of requirements in place to protect subsurface and wellbore integrity during hydraulic fracturing. Directive 083: Hydraulic Fracturing continued on page 11

Connecting with your community

T

he Duvernay is one of the Western Canadian Sedimentary Basin’s most important source rocks and stretches from Rocky Mountain House to Fox Creek in Alberta. This region offers significant growth opportunity for Encana where we have been securing our land position since 2009. We presently control one-third of the top-tier land in the liquidsrich area of the Duvernay.

Similar to 2018, our 2019 development activity has been weighted heavily to the first half of the year. We are running a two-rig program and drilling and completing two to six wells per multi-well pad. An estimated 16 wells on a total of five pad sites are planned for the year. Also under construction will be two single pad oil batteries and minor pipeline infrastructure along with routine production and maintenance operations.

10

Fall, 2019

Development update

continued from page 10 – Subsurface Integrity addresses the hydraulic fracturing risk • Seismic event of 4.0 ML or greater: the operator must to subsurface well integrity. immediately cease operations and report it to us. They cannot resume operations without our approval.

Ranking System

Companies operating in Fox Creek must follow a “traffic light” system to monitor for seismic activity.

• Seismic event of less than 2.0 local magnitude (ML): no action is required by the operator.

• Seismic event of 2.0 ML or greater: the operator must immediately report the event to the AER and implement their response plan.

Earthquake monitoring

S

ince 2013, specialists at AGS have been adding seismic monitoring stations in and around Fox Creek.

Built into each station is a seismometer, a device that measures ground vibrations. Any detected vibrations are recorded digitally and sent, in near real time, to AGS, where the data is analyzed. All of this information allows experts to detect and monitor earthquakes.

With the latest station up and running, Todd Shipman, Senior Advisor of induced seismicity, says AGS is eager to tackle its next challenge: how to make its findings accessible to those who sense the ground is shaking.

“In the future, we’d like to put all of our data into the hands of Fox Creek residents,” says Shipman. “We’re looking at ways we can equip someone to look up what they are feeling and where an earthquake sits on a scale of magnitude.”

In the meantime, AGS experts continue to monitor ground vibrations across the province. The seismic monitoring station in Fox Creek is part of an extensive network of over 50 stations all over Alberta.

The Regional Alberta Observatory for Earthquake Studies Network (RAVEN) is used by the AGS in conjunction

What It Feels Like

Current research suggests that a seismic event in Fox Creek with a magnitude of less than 3–4 magnitude ML could feel like vibrations of a passing truck and may not be noticed. An event with a magnitude of 4–5 ML could have more noticeable effects in terms of sound, vibrations, and overturning of unstable objects. The actual effect depends on ground conditions. with networks operated by other research organizations, including Natural Resources Canada, the University of Alberta, the University of Western Ontario, the University of Calgary, the Montana Bureau of Mines and Geology, and the United States Geological Survey.

For more information about earthquake monitoring in Alberta, visit the AGS website.

CAPP releases new VR program Submitted by Canadian Association of Petroleum Producers

I

f a picture is worth a thousand words, then a virtual reality experience is an entire encyclopedia. Canadian Association of Petroleum Producers (CAPP) is using new, innovative tools to help inform and educate Canadians about the country’s oil and natural gas sector – and virtual reality is among those tools.

Virtual reality (VR) incorporates video, audio, and animation, but goes beyond flat-screen video to create a one-of-a-kind, immersive experience that puts the viewer in the heart of the action. The beauty of VR

is how it allows the viewer to be in situations that would normally be inaccessible to most people. Ride along in a gigantic oil sands haul truck, stand on the floor of an active drilling rig, or see the highly co-ordinated sequence of events during hydraulic fracturing operations.

VR is a tremendous communications tool providing amazing facts, background information, and stunning visuals that add up to a powerful learning experience.

E-mail virtualreality@capp.ca to request a VR experience at your next event.

Fall, 2019

11

editorial

Protecting protects Alberta energy industry integrity

12

Fall, 2019

AER It might be tempting to vilify AER as playing a part in the woes that have befallen the industry but quite the opposite is true.

By Bill Whitelaw, President and CEO JuneWarren-Nickle’s Energy Group

T

here were days through the spring and summer when thousands of people poured into Calgary’s streets to demonstrate support for Canada’s upstream oil and gas sector.

There were placards, posters and T-shirts with slogans.

There were chants and speeches. There was undeniable passion.

They rallied to support the integrity of Canadian oil and gas – and they were telling politicians (and other Canadians) in no uncertain terms to get with the support program.

The key word here is integrity. Rally attendees were telling politicians: Quit screwing up the sector and start supporting its integrity. Do that and you support Canadian prosperity.

Integrity and prosperity go hand in hand.

So, will we pour into the streets to rally in similar fashion to protect the Alberta Energy Regulator’s (AER) integrity – and its critical independence – as it enters a process with potential for political tinkering?

The United Conservative Party government has launched its AER review. And it smells to high heaven of craven politicking and agenda setting – including, one might suspect, an effort to slide the AER closer to Alberta Energy, the provincial ministry for most things on the province’s energy landscape.

AER’s independence from government isn’t necessarily top of mind for ordinary Albertans. But the regulator’s ability to protect the interests all Albertans, not just those noisy UCP supporters, is in peril.

This could rock the foundation of a system that has worked marvellously well for decades.

Energy Minister Sonya Savage has made much of AER’s alleged growth in staff and the lengthy time it takes to process applications. Those dynamics, she contends, discourage investment and interest in Alberta’s energy industry.

But would investors be eager to park capital in a jurisdiction

in which the independent regulator approved applications that then resulted in lengthy hearings, and then court action?

Those kinds of delays can kill projects.

Since 2013 when the current AER was formed, has staffing actually grown?

And given AER’s recent initiatives in cutting red tape, are application times actually increasing?

The Responsible Energy Development Act sets out much of the legislative framework that AER works within and it has a strong focus on stakeholder engagement.

Presumably, these are details that will be up to deputy ministers Grant Sprague and Bev Yee, who are leading the review, to ferret out as they delve into details that may not be apparent to politicians.

An impartial review might also point to how under-investment has hampered AER’s ability to discharge its responsibilities.

In the spirit of fairness – and to avoid the perception of political machinations – it would be a good idea for the review board to get a first-hand demo of the OneStop toolkit.

Is there a political agenda at work?

That seems logical given the UCP penchant for finding ways of appeasing, even compounding, industry angst.

So, the review seems impeccably and deliberately timed to be kept off the public radar, since the UCP machine has rolled out a flurry of panels and consultations. That there’s a federal election concurrently running in which Alberta angst will be front and centre also provides a useful veil.

All of this, of course, may simply be cover for coming budgetary blades that will cut swiftly and deeply.

That’s why Albertans must step up, including those whose daily bread is earned in the energy sector.

It might be tempting to vilify AER as playing a part in the woes that have befallen the industry. But quite the opposite is true.

And once we get our hydrocarbons to tidewater, the world will want to know that those products come from a jurisdiction that’s well regulated and that the environment is appropriately protected. And that all that happens as the result of a framework safely distanced from political interference.

The Canadian Association of Petroleum Producers has survey data that says people around the world prefer Canadian hydrocarbon supplies. And the summer’s rallies featured a common cry: “The world needs more Canada.”

That’s true. Canada’s energy sector has much to offer, not least of which is a strong regulatory ethos.

But it’s also true that the world expects more of Canada.

Independent regulation is the least we can offer.

That’s why it’s time to rally again to ensure UCP doesn’t damage an enterprise critical to provincial prosperity.

Bill Whitelaw is president and CEO at JuneWarren-Nickle’s Energy Group. © Troy Media Fall, 2019

13

editorial

Alberta Energy Regulator overhaul a dangerous game Weaken the regulatory framework at your peril. Sloppy regulation begets sloppy industrial operation. And that drives investment away.

By Bill Whitelaw, President and CEO JuneWarren-Nickle’s Energy Group

G

rant Sprague and Bev Yee, Alberta deputy ministers of energy and environment respectively, are very capable senior bureaucrats. Here’s hoping they bring to bear all their skills for the review of the Alberta Energy Regulator.

They should keep in mind that the review ought not to be the witch hunt the current political framing suggests it is.

Increasingly, investors look to ensure they capitalize energy companies that take seriously those considerations related to environment, social and governance.

That should serve as a reminder not to toss out the baby with the bathwater as the United Conservative Party seeks to erase anything vaguely associated with the thinking of the previous NDP government.

enabling human progress We develop the energy that improves lives and powers the world forward 14

Fall, 2019

canada.chevron.com/kd

Alberta energy politics are becoming hateful and divisive. And instead of constructively and collectively understanding the complex restructuring with which it must grapple, the industry has become fractious and fragmented. So we find answers to complex issues are distilled down to naively simplistic solutions.

There are elements of the sector that simply adore a bogeyman. There’s plenty to be had if you subscribe to the UCP thesis that everything wrong in energy is someone else’s fault.

The Alberta Energy Regulator (AER) is merely the latest culprit the UCP is handing to those in the sector looking for something to hang in effigy.

Want a scapegoat for energy sector travails? The UCP has a closet full ready to trot out: other provinces, other Canadians, foreign interests, liberal politicians.

One key driving force behind the review, suggests Alberta Energy Minister Sonya Savage, is the time it takes to process an application. She points to other jurisdictions like Texas, which she argues processes things exponentially faster.

Implicit in her argument is that this is attractive to investors.

To a point it may be, but the minister’s advisers would do well to get in front of her the other side of the Texas story: about investment leaving in droves and about looming environmental debacles, particularly involving water.

One thing increasingly binds investors together: an expectation that companies with which they place capital understand and respond to environment, social and governance imperatives. And they expect solid and robust regulatory frameworks within which firms operate in order to safeguard their capital.

AER is a world-class regulator. In recent times, it has introduced a broad spectrum of improved services designed precisely to solve the very problems of which it has been accused. It has been tackling red-tape challenges for years.

Two recent innovations come to mind: the One Stop process that simplifies applications dramatically and the Integrated Decision Approach, which reflects a long-range understanding of an application.

Regulatory dynamics are a two-way street. Many companies that have hacked staffing in recent years need to assess the quality of their regulatory requests. Remember: garbage in, garbage out.

Good regulators are creatures of the sector and society. So AER ought to mirror regulatory and socio-economic realities.

Has the AER’s staffing grown in recent years?

It has changed, largely in response to the increasingly complex environment in which it’s expected to function – an environment that bears little resemblance to even 15 years ago. For example, when AER was created, it took on the Environmental and Sustainable Resource Development Department

functions. Yet its staffing has remained relatively flat for the last several years.

The UCP is desperate to appease certain elements of the industry. But destroying AER’s ability to balance environmental and fiscal imperatives could actually set Alberta’s recovery back dramatically.

Weaken the regulatory framework at your peril. Sloppy regulation begets sloppy industrial operation. And sloppy industrial operation begets sloppy reputation and social unrest. And the kind of capital you want driving the sector loathes sloppy reputations and the risk it brings.

For Sprague and Yee, and the interim board, this will be a delicate task. Deputy ministers must be, of course, political creatures to be effective in their roles. Here’s hoping they help their political masters guide a reasonable and rationale review that keeps front and centre a regulator’s role in a robust economy.

And here’s hoping the UCP resists its political impulse to toss people and process under the nearest conveniently rolling bus.

Perhaps most important will be the stakeholder input. It ought to guide the review to stay away from the UCP temptation to bring the AER closer to political will.

Remember the great line from the Joni Mitchell song Big Yellow Taxi: “You don’t know what you got ’til it’s gone.” © Troy Media

THE Our issues in 2020 are January, April, July, and October.

To advertise and receive a discount for the above four publications, contact us today!

Call Vicki at 780-268-3955 or Valerie at 780-706-1858 Email: theduvernay@gmail.com Fax: 1-866-647-4105

THEDUVERNAY.COM Fall, 2019

15

projects

Expanding Pembina’s

Duvernay Complex

P

embina is busy at our Duvernay complex as we expand our capacity with the construction of three capital projects.

Duvernay II

Pembina continues to progress construction of our Duvernay II project, which includes 300 MMcf/d of raw gas separation and water removal infrastructure; a 100 MMcf/d sweet gas, shallow cut processing facility; 30,000 bpd of condensate stabilization; and other associated infrastructure.

The capital budget of Duvernay II is $320 million, including the modifications required to meet sour specifications.

Regulatory and environmental approvals have been received.

Onsite mechanical construction has commenced and the majority of long-lead equipment has been installed onsite.

The project is trending on budget and on schedule with an expected in-service date in the fourth quarter of 2019.

Duvernay III

Pembina is also progressing our Duvernay III project, which includes a 100 MMcf/d sweet gas, shallow cut processing

16

Fall, 2019

facility; 20,000 bpd of condensate stabilization; and other associated infrastructure.

The capital budget of Duvernay III is $175 million, including the modifications required to meet sour specifications.

Detailed design is progressing, and long-lead equipment has predominantly been ordered.

The project continues to track on budget and on schedule with an expected in-service date in mid-to late 2020, subject to regulatory and environmental approvals.

Duvernay Sour Treatment Facilities

Pembina executed further agreements with a third party to construct sour gas treating facilities at the Duvernay Complex (the “Duvernay Sour Treatment Facilities”). These facilities have a capital budget of $65 million and an anticipated in-service date in the first quarter of 2020.

Engineering for the project is progressing and onsite construction is expected to commence later this year. With the addition of sour treating infrastructure, Pembina is positioned to handle future third-party sour gas volumes at our Duvernay Complex.

Fall, 2019

17

donation

Shell Canada donates $50,000 to local organizations Through a social investment initiative called the Community Grants Program, Shell Canada contributed $50,000 among 10 local organizations.

T

he annual program uniquely puts the decision-making in the hands of the community giving a panel of com­ munity representatives the opportunity to decide which non-profit organizations and projects are most deserving of the grant. Over the past 10 years, Shell has invested over $4,000,000 in the community of Fox Creek through social investment activities.

This year, the Community Grants Program received 10 applications. Six Fox Creek residents including a senior, a youth, a working mom, and a local business owner formed the community panel to determine funding allocation for the greatest impact in the community. Mayor Jim Hailes and members of council joined the 10 groups along with Shell representatives for a dinner and celebration event where the recipients accepted their community grants.

The Community Grants Program and selection process helps highlight the initiatives and areas of need that are most important to Fox Creek.

For more information on the Shell Community Grants program visit Shell.ca/communitygrants or contact Community Liaison Charlene Parker at 780-725-4801.

The successful 2019 projects include:

• Fox Creek Municipal Library – Technology/Seating upgrade • Town Public Safety Division – Helmets for Kids • Fox Creek School – CNC Computerized Router and Outdoor Classroom • Fox Creek Nordic and Trail Club – Trees and Drainage • Fox Creek Playschool – Technology Upgrades • Community Resource Centre – Seniors Healthy Living Program and Community Garden Upgrades • Friends of the Fox Creek Hospital – Examination Chair • Fox Creek Curling Club – Facility Roofing • Fox Creek Chamber of Commerce – Canada Day 2019 • Fox Creek School Parent Council – Apples for Kids 2019/20 School Year Shell strives to be a good neighbour in communities where it operates, and social investment is one way we can help support the well-being and sustainability of our local communities.

18

Fall, 2019

www.collinvacuumtrucks.com

780077883800 cvt2@telus.net

report

Oil and gas drilling down in 2019

By ATB Financial’s Economics & Research Team

T

he number of active drilling rigs is down so far this year.

The average number of active rigs over the first nine months of 2019 was 92 compared to 140 over the same period last year. This represents a drop of 34 per cent.

With pipelines full, natural gas prices weak, and uncertainty around when new pipe and liquefied natural gas (LNG) export capacity will be online, companies and investors are reluctant to engage in more drilling.

The annual average for active drilling rigs peaked at 382 during the 2005 natural gas boom and sat at 252 in 2014 before the oil price collapse triggered provincial recession of 2015-16. The annual average got as low as 81 in 2016, but bounced back to 147 in 2017 and 138 in 2018.

The rig count is an important bellwether of oil and gas exploration and production. It’s also a proxy for employment in the oil and gas field services sector.

According to the Canadian Association of Oilwell Drilling Contractors, each active rig represents about 21 direct jobs and 124 indirect jobs. With the average year-to-date rig count at just 92, this means the rigs were supporting almost 7,000

fewer workers (-34.1 per cent) over the January to September period this year compared to last year.

This does not represent all jobs lost in the oil and gas sector, but it is another way to highlight the tough year it is having and how pipeline delays and other challenges are affecting workers and their families.

Fall, 2019

19

20

Fall, 2019

technology

The shift to horizontal fracturing Hydraulic fracturing involves injecting fluids into deep underground formations at high enough pressures to create fractures in the rock. This opens pathways in the impermeable rock to allow oil and natural gas to flow. Water and sand constitute more than 99 per cent of the fracturing fluid.

T

he remaining one per cent consists of added chemicals to improve the fracturing efficiency and effectiveness. All chemicals are used in extremely low concentrations and have not been shown to be hazardous for their intended

use.

Hydraulic fracturing of vertical wells has been done in Western Canada for over 60 years. While the types of fluids used in hydraulic fracturing operations have changed over time, the pumping practices have remained consistent. It wasn’t until the late 1990s in the Barnett shale in Texas that Mitchell Energy combined horizontal drilling with hydraulic fracturing to dramatically increase the recovery of natural gas from impermeable formations. Other companies soon began duplicating this method to unlock oil and natural gas from tight reservoirs, ushering in the shale revolution.

Although horizontal wells are more expensive to drill, this approach allows the well bore to contact more of the reservoir thereby increasing recoveries and improving the overall economics. This approach also reduces the number of wells required to economically produce a reservoir.

In the Duvernay field, horizontal drilling and completions operations can reach depths greater than three kilometres below potable groundwater sources and extend more than three kilometres laterally. Most wells in the Duvernay take several days to complete and may comprise as many as 30 hydraulic fracturing stages (higher in some cases) to ensure optimal contact with the reservoir. Multi-well pads are commonly used to reduce the environmental footprint of these operations.

The next issue will be a discussion on new technology and innovations in the industry.

Fall, 2019

21

We are top-of-mind when it comes to plant & field construction and maintenance and we also have full pipefitting and welding crews at the ready.

With our professionally skilled employees, trained supervisors and strong management team, ProFoxx Energy Services offers: You’re guaranteed our best work, delivered safely and on time.

We know that maintaining the integrity and production levels of existing piping systems is critical to our clients.

Facility & Lease Site Construction • Experienced pipefitters and crews • ABSA certified

(B31.1 and B31.3) • Lease layout • Platform and stair fabrication • Pile capping • 6000 sq/ft fabrication facility with 5ton bridge crane Facility Maintenance • Experienced crews • Crew trucks with pickers • New worker shadow program • Turn around and shut down crews • Specialized equipment

ProFoxx Energy Services

205 1st Street, Fox Creek, AB, T0H 1P0 780-622-5015, info@profoxxenergy.com

environment At what cost do we save

the caribou?

Alberta’s Woodland Caribou are a threatened species according to the Federal Governments Species at Risk Act. As a result, the Federal Government released a pan Canadian strategy requiring all provincial governments to reduce disturbance levels in all caribou ranges.

T

he Federal analysis suggests that all of Alberta’s caribou ranges are at or over acceptable disturbance levels. In 2015, the Alberta Government hired a mediator, Eric Denhoff, to provide recommendations to the Alberta Government to address this complicated issue. The Denhoff report recommended a number of strategies intent on minimizing industrial disturbance on the landscape in specific regions of Northern Alberta, one of which is the Little Smoky range.

The Provincial Government has acted on a number of these recommendations, such as a multi-year deferral of forest harvesting, and in 2016 interim restrictions on the sale of mineral rights within the caribou range which applied to petroleum, natural gas, and other industrial mineral rights as well as changes to the standard operating conditions for seismic exploration activity.

In December 2017, the Government of Alberta released a draft provincial Woodland Caribou Range Plan which incorporated many recommendations from the Denhoff report, input from the public consultation for the draft Little Smoky and A La Peche Caribou Range Plan which proposes the development of new requirements for new oil and gas approvals and seismic exploration programs; the introduction of mandatory integrated land management requiring multi-use corridors and shared access for industrial activities; the consolidation of forest harvesting operations in pre-defined areas per decade; and the identification and protection of conservation areas in caribou ranges.

Since this period, new government has been elected, and they have chosen a different course of action on the caribou file. The Alberta government decided the best strategy is to engage the federal government in the development of Section 11 Conservation Agreement, as permitted under the Species at Risk Act. Many organizations and stakeholders have been reviewing Section 11 agreement for its adequacy to address several factors and have forwarded their concerns to the provincial government. It is hoped that the province will carry

these concerns to the federal government when the wording is finalized in Section 11 for the conservation and recovery of the Woodlands Caribou. Once the document is signed, it will be a blueprint for the next five years for Caribou Range Planning in Alberta.

Concerns with the current Section 11 Agreement is that it will drastically reduce what industry can do and where. For those whose livelihood rests solely on forestry and the oil and gas industry, this does not bode well.

Ray Hilts, Senior Consultant in Forestry and Environment in Whitecourt, said, “The current agreement isn’t adequate in terms of our region and communities. It appears habitat centric and pre-determines to eliminate all additional forest disturbance.

The federal Woodlands Caribou Strategy definitions of critical habitat and undisturbed habitat appear to be largely academic, untested, and unproven in the field. There is no getting around that our industries must be able to use caribou ranges for development. Conservation strategies must include plans to conserve caribou but also allow businesses, industries, and communities to prosper and flourish. A socio-economic analysis needs to be done and expert data provided to the government. Again, if the current Section 11 Agreement goes through, it suggests the Alberta Government abandon the Healthy Pine Forest Strategy which has been in effect since 2006 and addresses the fight against the Mountain Pine Beetle.”

Without proper forest management, the Pine Beetle could very well take over and destroy the forest, and having a dead forest is not good for caribou. Another piece for consideration to the caribou decline is the increased population in the wolf which is one of the main predators of caribou which is currently not acknowledged in the agreement. “There are just too many gaps in the Section 11 Agreement that need assessing including the definite lack of acknowledgement for our socioeconomic impact,” added Hilts. The two levels of government are currently reviewing stakeholder input. It’s not known at this time when the final Section 11 Agreement will be released.

Fall, 2019

23

report

Normal and unusual things

made from oil and gas we use almost daily!

By Bill McLaughlin, Certified Compound Technician

Medical Getting sick is bad. But getting sick without having oil and natural gas products to help you heal would be terrible.

Hospitals rely on petroleum products to provide sterile care to their patients. Even if you just need a pill to combat a headache or hay fever, it’s oil and natural gas to the rescue!

Here are some of the oil and natural gas products that fall into the medical category:

24

Fall, 2019

Bathroom Can you imagine smearing oil and natural gas on your face? Or in your hair? How about on your lips or under your arms? Or into your eyes?

Well, you do – every time you use moisturizer, shampoo, lip balm, deodorant or contact lenses!

Here are some of the oil and natural gas products you might find in your own bathroom:

Fall, 2019

25

report Household

From the moment you put on the coffee in the morning, until you set your alarm in the evening, you’re using oil and natural gas products at home. How many of these oil and natural gas products do you use in your home?

26

Fall, 2019

Yard Even if you don’t use chemical fertilizers or pesticides in your yard, you probably still use oil and natural gas products. When you water your garden with a hose, set out your recycling bin or pop on a pair of safety goggles to trim the hedge, you’re using petroleum products. Here’s how oil and natural gas fit into your yard:

About 46 per cent of a barrel of oil is used for fuel; the rest is used in the chemical industry to make our lives more comfortable. More than 6,000 products are produced from oil and gas currently.

For us to think that we can eliminate oil and gas from our society is a pie in the sky idea that will take some time, if ever, to quit.

Heating and cooling come to mind if we don’t want to become cave dwellers and stop our way of life altogether.

Think about costs which only become affordable when we innovate and invent new methods of doing things. Taxing and forcing society through regulation to change will have a limited effect and create an underground economy which brings about more regulation. We know what happens when the government regulates and controls the economy and it is not good anywhere that it has been tried.

Just a few words on why we need oil and gas and will continue to rely on this resource well into the future.

Fall, 2019 27

forecast

Fox Creek, AB Dispatch

780.622.9330 Oilfield Safety Specialists

Current Drilling Forecast 2019 Forecast: Total Wells (Western Canada): 6,962* Q1 2019

Q2 2019

Q3 2019

Q4 2019

Active Rigs = 280

Active Rigs = 118

Active Rigs = 185

Active Rigs = 220

Fleet = 552

Fleet = 527

Fleet = 522

Fleet = 522

Utilization = 51%

Utilization = 22%

Utilization = 35%

Utilization = 42%

Op Days** = 23,502

Op Days** = 10,453

Op Days** = 16,525

Op Days** = 19,138

Average 2019

Assumptions

Active Rigs = 201

* Actual ** Calculation based on spud to rig release

Fleet = 531

WTI = $58.75/bbl (USD)

Utilization = 38%

AECO = $2.00/mcf (CND)

Op Days** = 69,617

10.0 days/well

Retail Sales Safety Rentals Specialized PPE

Traffic Control / Site Security

On site Security Road-use Tracking Flagging Pilot Trucks Emergency Traffic Control

Operating Days & Wells Completed Time Period

Operating Days

Wells Drilled

2016 Actual

43,184

4,627

2017 Actual

69,353

6,031

2018 Actual + Q4 Forecast

69,110

6,911

2019 Forecast

69,617

6,962

2018 vs. 2019

508 or 0.7%

51 or 0.7%

Confined

Impact on Employment Indirect Jobs

Jobs per Rig

Active Rigs

Direct Jobs 21*

124*

145

2016 Actual

112

2,357

13,919

16,276

Total Jobs

2017 Actual

194

4,074

24,056

28,130

2018 Actual + Forecast

207

4,342

25,637

29,979

2019 Forecast

201

4,216

24,893

29,109

2018 vs. 2019

-6

-126

-744

-870

28

Fall, 2019

Breathing Air Space Qualified NCSO Trained Supervisors Experienced in H2S and Benzene

Medical Standby Services Qualified

Medical Staff day coverage Rapid Response for Industrial Incidents 24/7/365

w w w. a l b e r t a s a f e t y c o n t r o l . c o m

Fall, 2019

29

opinion

Let’s not miss Canada’s LNG opportunity When Canada’s energy ministers met earlier in July in BC, they rightly discussed attracting investment and increasing market access as key priorities. However, the policy conversation about Canadian energy continues to miss the opportunity in liquefied natural gas (LNG). Now is the time for Canada to position itself as a global leader in LNG and to put the right policy framework in place to build a lower carbon energy future.

By Tristan Goodman, President of The Explorers and Producers Association of Canada (EPAC)

T

wo elements should drive this discussion at the policy level – Canadian natural gas supply and global demand.

There is no doubt the outlook for both is strong and even necessary to achieve global emissions reductions.

Canada is the fifth largest producer of natural gas in the world with an estimated resource of 1,220 trillion cubic feet. That’s equivalent to a 300-year supply at current production levels. Canada’s natural gas entrepreneurs, principally located in Alberta and northern BC, stand ready and able to sustainably develop this resource.

Doing so would deliver a needed economic boost in these regions but also produce benefits for the rest of the country by capturing increased returns on Canada’s resources.

Canadians can take pride in knowing that our producers responsibly develop these resources.

Canada is renowned for our environmental, social, and governance standards – among the highest and most stringent in the world. For example, Canada has committed to reducing methane emissions from oil and gas by 40 to 45 per cent below the 2012 level by 2025

30

Fall, 2019

– and has regulations in place to meet this commitment. At the same time, the sector’s entrepreneurs are constantly innovating to improve performance from the development and implementation of new technologies to operational practices to improve efficiency. These conditions position Canada as a supplier of choice for the world.

The world needs Canadian energy. Credible forecasts all point to a rising demand for natural gas - the International Energy Agency projects an increase of 43 per cent by 2040.

BP’s 2019 Energy Outlook suggests a 38 per cent increase by 2040 even in a rapid transition scenario.

Electrification is a key driver of this demand. Urbanization and electricity use across the developed world will only increase, and natural gas offers a lower carbon fuel than coal or diesel to supply that demand. Renewable power will undoubtedly continue to grow, too, and supply some of that energy mix but a transition cannot simply bypass natural gas given the scale and demand for energy globally. A natural gas cogeneration plant emits approximately 40 to 50 per cent less CO2 emissions in comparison to coal according to the US Energy Information Administration. Indeed, displacing coal-fired power in Asian markets with Canadian natural gas is low hanging fruit among the global emissions reduction opportunities if we are prepared to seize it.

Governments at the provincial and federal levels need to take an ‘all-of-government approach’ to capture these benefits.

An aligned vision across the federal and provincial governments supported by coherent policy direction from their respective departments is required – finance to establish a competitive fiscal framework, energy and trade to ensure market access and, importantly, environment to begin unlocking the international market mechanisms to realize Canada’s clean LNG potential in a lower carbon future.

Article 6 of the Paris Agreement introduces the opportunity for market solutions and bilateral co-operation between countries to achieve their emissions reduction targets. A system that ensures those reductions are robust and verifiable is critical to its success and requires sustained political attention to achieve.

The scale of this opportunity for Canada is immense and we are beginning to see traction. Chevron Canada Resources is now seeking approval on a modified plan for its LNG project in Kitimat, BC that would set a new benchmark for emissions intensity globally. The approved LNG Canada export facility is already the largest private sector investment in Canadian history at $40 billion. Similarly, Woodfibre LNG in Squamish, BC is signaling that it intends to move forward with construction later this year. What is required now is the vision to make sure these opportunities are not lost and the right policy framework to ensure Canadian natural gas plays a leading role in the global energy transition.

Alberta’s energy prosperity

is Canada’s prosperity Several weeks ago, you may have read headlines about a drone attack on Saudi Arabia’s largest crude-processing plant.

However, following on the heels of those headlines was another troubling story: “Attack on Saudi Arabian crude plant leaves Canada’s biggest oil refinery vulnerable” as the National Post put it. That Canadian oil refinery is in New Brunswick and is owned by Irving Oil Ltd.

By Todd Loewen, MLA

A

t first, it might seem odd to hear of a connection between Saudi oil production and Canadian refineries. After all, Canada sits atop the third largest known reserves of crude in the world. Why would disruptions to Saudi Arabia’s supply leave a major Canadian refinery vulnerable?

As it turns out, the Irving refinery in New Brunswick receives about 40 per cent of its crude inputs from Saudi Arabia.

This is the extraordinary and, frankly, absurd situation that our nation finds itself in today with our largest domestic refinery on the east coast left vulnerable to price and supply shocks while we, here in Alberta, have our attempts to build pipelines blocked by motivated special interests and apathetic national leadership. This lack of pipeline capacity causes the price of the oil we sell to drop to a fraction of its actual value all while refineries in the east pay top dollar from foreign sources. This two-fold hit is unacceptable.

This story is a stark reminder that we still heavily rely on unstable sources of foreign crude despite richly possessing such vast amounts of natural resources here at home. We still rely on oil from foreign dictatorships and areas threatened by violence even though Canadian energy resources are produced to the highest environmental and ethical standards in the world.

More than that, this story reminds us that Alberta’s oil and gas industry is, and should continue to be, a benefit to all of Canada. Canada should not have to rely on foreign crude shipped half away around the globe to refine the products we require. Albertan oil is the solution and the construction of

pipelines is the way that Alberta can continue to fuel Canadian prosperity.

Of course, Alberta’s contributions to Canada go beyond the value that our energy reserves provide heating homes and powering vehicles. Economist Jack Mintz wrote that, “No other province has contributed so much to the rest of Canada” as Alberta has. In fact, he noted that in the past 57 years, Alberta has paid over $600 billion more to Ottawa than it has received back in transfers and federal spending.

And, what of the spin-off benefits of the Albertan entrepreneurial spirit? I’m thinking of the employment opportunities we have offered to hundreds of thousands of Canadians from beyond our provincial borders. Albertans have never been a greedy people, and I think we are all happy to know many fine, hard-working folks who came to Alberta looking for jobs and opportunities. All we ask is that the rest of the country respect the positive impact that our industry has had on the lives of so many citizens.

I write this in the middle of a federal election campaign when it has been so important to make the case for Alberta’s energy sector. Regardless of the outcome, the UCP Government will continue to promote the benefits of energy prosperity for us all. We will push back against those who attempt to smear and undermine us. We will stand up for Alberta’s important role in making Canada a world energy leader.

Todd Loewen is the Member of the Legislative Assembly for Central Peace-Notley

Fall, 2019

31

study overview Canadian crude oil and Supply costs, economic impacts and emissions outlook (2019-2039) This study examines Canada’s conventional crude oil and natural gas industries including production forecasts and supply costs over the next 20 years. The study covers onshore and offshore conventional oil including shale and tight oil activity, conventional natural gas, coalbed methane, tight and shale gas, and the associated natural gas liquids (pentanes plus and condensate only). It does not include oil sands.

BACKGROUND AND STUDY SCOPE In this study, the overall oil outlook is shaped based on several factors: the dynamics of the US crude imports (declining before 2030 and growing afterwards), relatively stable demand from domestic refineries, the pentanes plus and condensate’s growth underpinned by the demand from oil sands, the additional pipeline exports to Central Canada to displace foreign oil, and additional exports via the Trans Mountain Pipeline.

The outlook for gas is formed based on the expectations of additional domestic natural gas consumption, declining net exports to the US, and the additional demand for gas from LNG developments.

The Duvernay is a shale play in Alberta that contains natural gas, natural gas liquids, and crude oil.

When considering recent drilling intensities, the corridor to the east of the Rocky Mountains has, collectively, the highest concentration of activity. These formations include Montney, Cardium, Duvernay, and Millington Spirit River. CERI’s analysis shows Dinara that the liquids rich Duvernay basin has attractive project economics with supply costs for horizontal wells averaging around CAD$40/barrel for crude oil and CAD$1.50/Mcf for natural gas. Operators’ continued focus on plays like the Montney and Duvernay lead to a substantial growth in condensate production in the projection period which in Alberta is forecast to grow to 466,000 barrels per day in 2039.

COLLIN TOILET

Rentals & Service Quality Service with Excellence in Cleanliness and Prompt Service Providing regular portable toilets; all-weather heated toilets w/power; single & double units available

780.778.2448

natural gas production STUDY FINDINGS For crude oil, the pricing environment over 2014-2018 had an impact on the industry and led to a sharp reduction in production. More than 200 Mbpd of oil production was lost from 2014 to 2016. However, from 2016 the trend reversed and is expected to do so until 2025 reaching approximately 1.4 million bpd (without pentanes plus and condensate).

This is followed by a decline to 1.3 MMbpd due to falling production in Newfoundland and Labrador (Figure E.1) by the end of 2039. Growth in crude oil production will be led

by Alberta followed by Saskatchewan (Figure E.1). Together with Saskatchewan, Alberta is affected most by the dwindling US imports in the coming years. After 2030 exports to the US

Canada Crude Oil Production Forecast

grow due to the decline in production from their maturing shale fields.

Total pentanes plus and condensate will keep growing for the forecasted period from 418 Mbpd in 2019 to 604 Mbpd in 2039 underpinned by demand from oil sands and driven by liquids-rich natural gas drilling.

For natural gas, an incremental trend in production in recent years was caused by two factors: addition to the net exports to the US by 0.4 billion cubic feet per day (bcf/d) and an in­ crease in domestic gas consumption. However, the net exports to the US started to decline in 2017 and are expected to continue for the foreseeable future. Growth in domestic demand by 2.5 bcf/d in the next 20 years will largely, but not completely, counterbalance this decline of net exports. The domestic incremental demand is expected to come from the electricity sector which explains 47 per cent of growth, followed by industry which drives 35 per cent of gas demand additions including by the oil sands sector (NEB, Energy Futures 2019).

Source: CERI, BCOGC, AER, Government of SK, Government of MB, CNLOPB, PSAC, CAPP

Total Canadian Natural Gas Production

Source: CERI, Government of SK, BCOGC, AER, PSAC, CAPP

Fall, 2019

33

study overview STUDY FINDINGS

Emissions for Crude Oil Production (top) LNG plants provide an opportunity to develop production and Natural Gas Production (bottom) capacity in western Canada and attract more growth-oriented investments into the upstream gas industry. Such a scenario will lead to a consistent increase in production until 2029 to levels slightly over 25 bcf/d. Post-2029, production will stabilize through the remainder of the study period. The gas for LNG will constitute approximately 30 percent of total Canadian production by 2039 and is expected to be supplied by British Columbia and Alberta.

This study also examines the economic impacts of the Canadian conventional oil and natural gas industry on the Canadian economy (Table E.1) as well as on the US economy.

The impacts analysis is done for the period 2019-2029.

Total Economic Impacts from Oil and Natural Gas Development, 2019-2029*

*The effects in each province show both direct and indirect effects of crude oil developments within that province, while the effects for Canada represents direct and indirect effects of crude oil developments in all Canadian provinces.

For the forecast period of 2019-2029, it is estimated that the total US gross state product impact (direct and indirect) will amount to almost US$19.6 billion or CAD$26.2 billion. The total employment impact (direct and indirect) is measured in creating or preserving 153.2 thousand full-time equivalent jobs in the 11-year period.

Another component in the study is carbon dioxide equivalent emissions from the oil and gas upstream activities.

More specifically, upstream emissions encompass emissions from the following activities: drilling, production and extraction, processing in the field, and venting, flaring, and fugitive emissions.

On average, annual emissions from oil production will be 31.1 million tonnes/year during the study period or less than 1 per cent below the 2017 level. Alberta and Saskatchewan will generate the highest emissions at 48 and 35 per cent, respectively (Figure E.3 on the following page). For the natural gas production, on the other hand, the average annual emissions will be 44.7 million tonnes/year over the 2019-2039 period, or 10 per cent decrease compared to 2017 levels due to methane reduction regulation implementation. Alberta and British Columbia will generate the highest emissions at 57 and 15 per cent, respectively.

34

Fall, 2019

Paramount Resources:

Committed to the Duvernay

I

n December 1978, Paramount Resources Ltd. became an independent, publicly traded Canadian oil and gas company. Founded by Clay Riddell, the company began exploring for gas in northeast Alberta. In 1995, Paramount drilled its first gas well in the Fox Creek region. It has acquired assets and companies over the past 25 years to become a top explorer and producer in the area.

With the discovery of the Duvernay resource play, Paramount’s legacy company Trilogy Energy Corp. drilled its first exploratory Duvernay well in 2009. Encouraged by the oil and liquids production from that initial well, the company continued to develop its Duvernay position as it believed the Duvernay would become a world class resource play. Over the last 10 years with continued

drilling, completion, and innovative technologies, the Duvernay play has moved from the exploration stage to a full commercial development.

In August 2017 Paramount acquired Apache Canada Limited (another company actively involved in the Duvernay) and shortly after that Trilogy and Paramount merged. This made Paramount an intermediate exploration and produc­tion company with an extensive portfolio of liquids-rich re­source plays in the Montney and Duvernay formations with the financial capacity to develop these opportunities.

Paramount has a strong environmental and safety culture and believes in supporting the communities where we operate. Paramount has local offices in the Kaybob region located in Whitecourt and Fox Creek.

To learn more about Paramount visit www.paramountres.com

map

Duvernay Formation Summary

Electrical & Instrumentation

Locally Owned & Operated Distributor

Distributor

Distributor

Distributor

Carrier of:

NOW OPEN at 3709 - 38 Avenue, Whitecourt Monday-Friday 6:30 am to 5:00 pm

780-396-8950

36

Fall, 2019 www.eisupply.ca

The Duvernay Formation covers an area of approximately 130,000 square kilometres or 20 per cent of the area of Alberta.

T

he AER and Alberta Geological Survey have published resource estimates for formations in Alberta. In summary, the total in-place resource endowment for the Duvernay ranges from 350 to 540 trillion cubic feet of natural gas, seven to 16 billion bbl of natural gas liquids, and 44 to 81 billion bbl of oil. These estimates support that the Duvernay shale contains a massive initial resource in place; however, the amount of this resource that can be economically recovered is dependent on drilling and completions optimization, cost reductions, expected liquids yields, commodity pricing, and social, environmental, and regulatory constraints.

Despite the uncertainty associated with these technical, social, and economic factors, operators working in the Duvernay continue to drill new wells within the liquids-rich regions of the resource. This demonstrates that as the understanding of this complex resource continues to improve, and new breakthroughs in technology are discovered, further cost savings are being realized. As development continues, operators can delineate optimal geological areas and unlock the liquids potential contained in this resource. Development growth within the core acreage of this formation continues despite the current low commodity price environment bolstering the Duvernay’s status as a world-class shale resource.

Fall, 2019

37

report

AER water use performance We encourage companies to conserve non-saline water when developing water management plans for hydraulic fracturing operations. However, using large volumes of alternative water for hydraulic fracturing can be challenging.

P

roduced water which can be used as an alternative water source, is a by-product of hydrocarbon production; however, the amount of produced water varies depending on the formation. Formations are considered either “wet” meaning that actively producing wells in the area can supply significant amounts of produced waters for re-use in hydraulic fracturing or “dry” meaning operating wells do not produce water at a high enough volume to sustain a hydraulic fracturing operation. In dry formations, there is less alternative water available.

In some areas, there may be abundant non-saline water sources available that can sustain operators’ planned development without posing a risk to the local environment. Where this is the case, companies may prefer to use non-saline water as it removes the risk of moving and storing poorer quality alternative water on the landscape.

There are practical limitations to using alternative water: companies may not have viable options for alternative water sources (i.e. produced water) or may not have infrastructure that supports alternative water use. There are also stringent requirements in place for storing and transporting large volumes of alternative water which has led to some companies using non-saline water because it may not be feasible or practical to develop infrastructure to use alternative water. The AER is working to remove these limitations to make it easier for companies to use more alternative water and, in turn, less non-saline water.

A company’s water use efficiency depends on several factors and, in hydraulic fracturing, it depends on the stage that a project is in. Hydraulically fractured wells are expected to produce hydrocarbons for years afterwards without needing any additional water. This means the water intensity of a hydraulic fracturing operation decreases over time.

The average hydraulically fractured well begins with an average water-use intensity of 0.39 in its first year of production, a number that lowers to only 0.09 after five years of production.

This intensity will continue to decrease because most wells produce hydrocarbons for longer than five years without using any more water.

In 2018, nearly 29 million cubic metres of water was used to fracture new wells. Of the total water used, over two per cent of the water was recycled, and the remaining 98 per cent was make-up water.

Since 2014, the total production from all wells fractured increased, and annual water use has also increased. Economic conditions have recovered slightly over the last five years, so more wells have been drilled and fractured and, as a result, more water has been used. Production reached over 521 million

38

Fall, 2019

barrels of oil equivalent (BOE) in 2018.

In 2018, over 28 million cubic metres of make-up water was used for hydraulic fracturing. Non-saline water accounted for almost 97 per cent of the make-up water used. While alternative water sources only made up about three per cent of the total, the volume of alternative amounted to more than 900,000 cubic metres, a volume that is still quite substantial and could have otherwise been non-saline water. There was a slow but steady increase in the use of alternative water for fracturing operations because companies invested in infrastructure to store and move this type of water.

Since 2014, make-up water use has increased by about 180 per cent. Hydraulic fracturing companies used about 18 per cent (27 million cubic metres) of the non-saline water allocated while wells that have been hydraulically fractured produced over 521 million BOE in 2018. Non-saline water use intensity refers to the amount of non-saline water in barrels used to produce one BOE. Non-saline water use intensity for hydraulic fracturing is different from other extraction technologies that use water on an ongoing basis (i.e. EOR, oil sands mining, and oil sands in situ). Typically, wells that are hydraulically fractured only use water once: during the initial hydraulic fracturing completion.

The wells are then expected to produce hydrocarbons for years afterwards without the need for additional water requirements.

As a result, we calculate the non-saline water use intensity based on the first 12 months of available production data following the fracture. Using this shows that operators used 0.52 barrels (bbl) of non-saline water to produce one BOE. Since 2014, non-saline water-use intensity for hydraulic fracturing has increased by over 100 per cent. This is likely because of: • New technology: Hydraulic fracturing in horizontal wells is still a relatively new recovery method, and it takes time for companies to test different strategies to improve hydrocarbon recovery.

• Varying geological conditions: Water-use intensity varies between geologic formations and within individual formations that companies operate. Some consistently need more water per well because of the properties of the rock in the formation. For example, in 2018, non-saline water-use intensity for wells in the Duvernay Formation (part of the Woodbend Group) was more than 20 times higher than it was for wells in the Glauconitic Formation.

• Non-saline water-use intensity is expected to vary in the short term as operators test different methods to improve hydrocarbon production.

For full details on the Alberta Water Use Performance Report, go to www.aer.ca.

ADDITIONAL SERVICES • Fluid Pumping • Vac Trucks • Mobile Filter Units SUPER Bs • Aluminum TC407 spec, sour sealed, 40,000kg payload, C/W scrubber • Aluminum TC407 spec, sour sealed, 36,000kg payload, C/W scrubber • Stainless steel TC407 spec, sour sealed, 33,000kg payload, C/W scrubber

24 HOUR DISPATCH 780.876.8730

• Aluminum TC407 spec, sour sealed, 33,000kg payload, C/W scrubber • Stainless steel TC407 spec, sour sealed, 30,000kg payload, C/W scrubber BODY JOB • Aluminum TC407 spec, sour sealed, 15,000kg payload, C/W scrubber • Stainless steel TC407 spec, sour sealed, 13,000kg payload, C/W scrubber

Whitecourt, Clairmont and Dawson Creek Fall, 2019

39

incidents

O

ccupational Health and Safety (OHS) issues notices after a fatality to help industry prevent similar incidents. Industry notices are an educational resource.

They don’t identify violations of OHS legislation or lay blame on worksite parties.

Incident Notice: 2018-01 Type: H2S Exposure Incident Summary The worker was found unresponsive at an oil battery where an injection valve was open with gas escaping. The battery is a sour gas site and the operator was working alone.

Incident Notice: 2018-02

Type: Crush Incident Summary A worker climbed inside an enclosed dry mineral mixing hopper to unplug the bottom auger. When another worker activated the mixer, the worker in the hopper was pinned between the agitator and the equipment’s inside wall and suffered fatal injuries.

Incident Notice: 2018-08

Type: Crush Incident Summary Two derricks were laying on the ground side by side while being prepared for return to service. Workers were in the process of threading one of the derricks when a clinching sound was heard. At the same time the work was being stopped, the derrick moved causing a worker to be caught between that derrick and the one adjacent to it suffering fatal injuries.

Incident Notice 2018-16

Type: Explosion Incident Summary An unplanned explosion occurred in or around the separator building at a well site. Three workers were on site providing services to that site at the time of the incident. One worker succumbed to injuries sustained from the explosion, and another worker was admitted to hospital.

Incident Notice 2017-09

Type: Struck by Object / Fatality Incident Summary A worker was completing a pressure test on the coil tube connector. The worker was positioned over the wellhead and was hit by the test pipe sustaining fatal injuries.

Incident Notice 2016-01

Type: Explosion / Fatality (two workers) Incident Summary: An explosion occurred inside a compressor building at an upgrading facility. The workers were changing out valves on a compressor when the explosion occurred. Two workers were fatally injured.

40

Fall, 2019

- Pipeline R.O.W. - Reclamation - Remediation - Mulching & Clearing - Timber Salvage

Your home away from home

Room options of

• Kitchenettes • Suites • King / Queen beds • Full complimentary breakfast

FOX CREEK, AB | 313 - 1 Avenue | 1-780-548-3338