discussion paper: petroleum operations, costs and ... paper: petroleum operations, costs and...

Discussion Paper: Petroleum Operations, Costs and Opportunities in Nova Scotia Nova Scotia Hydraulic Fracturing Independent Review and Public Engagement Process

Lead Author: Michael Gardner

Expert Panellists: Dr. Frank Atherton, Dr. Michael Bradfield, Kevin Christmas, Dr. Shawn Dalton, Dr. Maurice Dusseault, Dr. Graham Gagnon, Dr. Brad Hayes, Constance MacIntosh, Dr. Ian Mauro & Ray Ritcey

Supporting Contributor(s): Margo MacGregor & Dr. David Wheeler

This discussion paper provides a basic overview of the process of exploring for and producing hydrocarbons, with a focus on economics rather than technical matters. It describes generally what is involved in each phase of activity – exploration, field development, production and abandonment – setting out the costs and benefits, including opportunities for involvement by the local workforce and contractors.

Discussion Paper: Petroleum Operations, Costs and Opportunities in Nova Scotia

How to Read this Paper

This discussion paper will in due course form the basis of a chapter in the final report produced for

the Hydraulic Fracturing Independent Review and Public Engagement Process in Nova Scotia.1 The

paper should be read in conjunction with the Primer on Hydraulic Fracturing2 which we released on

March 10th 2014. The paper has been prepared to describe key aspects of petroleum operation

costs and benefits to share with Nova Scotians.

It is important to note that this paper does not represent the entirety of the Panel’s discussions to

date on economic issues. We are very conscious that potential and actual economic costs and

benefits of hydraulic fracturing in the US and in other jurisdictions are highly contested. We also

recognise the challenge of predicting the future regulatory drivers and constraints on economic

costs and benefits of hydraulic fracturing in Canada - particularly in a province like Nova Scotia

where there is no history of onshore oil and gas production. In submissions received by the Review

to date, many of our stakeholders have questioned the reliability of claims of economic benefits

associated with unconventional gas production and we are therefore highly sensitive to the need to

base our commentary on potential economic costs and benefits for Nova Scotia on relevant

evidence.

Externalities are discussed briefly in this paper, but broader socio-economic questions are not

addressed in detail; they will be discussed in the Introductory Chapter of the report and in

forthcoming discussion papers. This discussion paper does not address any of the potential

environmental, social or health impacts of hydraulic fracturing or issues relating to land rights or

ownership of resources. These subjects, among others, will be covered in other discussion papers

and the final report. To see a full list of other topics being considered for chapters of the final

report, and to view the tentative release schedule for discussion papers upon which these chapters

will be based, please visit the project document page on our website.

1 See the Verschuren Centre (Cape Breton University) website http://www.cbu.ca/hfstudy for full details of the study

and all project documentation. 2 Available from http://www.cbu.ca/hfstudy

http://www.cbu.ca/hfstudy/resources/project-documents

http://www.cbu.ca/hfstudy


How to Provide Feedback on this Chapter

We now invite feedback on this discussion paper – for example if there are any aspects that are not

clear or which require further explanation. Please email your feedback to [email protected] with

‘Economics’ in the subject line using the feedback form3 available on the website. We request that

you do not make comments directly in the PDF document and prefer to receive feedback using the

form provided, in an email or word attachment, or alternatively please write to HF Review,

Verschuren Centre for Sustainability in Energy and the Environment, Cape Breton University, P.O.

Box 5300, 1250 Grand Lake Road, Sydney, Nova Scotia, B1P 6L2. Feedback on this chapter can be

received at any time until June 2nd, 2014. All feedback received will be taken into account in the

final version of the document.

Thank you

Dr David Wheeler

President of Cape Breton University, on Behalf of the Expert Panel, 16th May 2014

3 The feedback form can be found on the website at: www.cbu.ca/hfstudy/resources-project-documents

mailto:[email protected]

http://www.cbu.ca/hfstudy/resources-project-documents

Contents

List of Figures ............................................................................................................................................ ii

1. Overview ........................................................................................................................................... 1

2. Exploration ........................................................................................................................................ 1

2.1. Obtaining exploration rights ..................................................................................................... 1

2.2. Identifying the hydrocarbon resource ...................................................................................... 2

2.3. Drilling the exploration well ...................................................................................................... 3

2.4. Hydraulic fracturing .................................................................................................................. 5

3. Development and production ........................................................................................................... 8

4. Petroleum development costs and benefits – industry perspective .............................................. 10

5. Petroleum development impacts – a community perspective ....................................................... 13

5.1. Risk factors and potential costs .............................................................................................. 13

5.2. Benefits ................................................................................................................................... 14

References .............................................................................................................................................. 17

ii

List of Figures

Figure 1: Vibroseis Trucks ............................................................................................................................. 3

Figure 2: Corridor Resources Drill Site near Sussex New Brunswick ............................................................ 5

Figure 3: Hydraulic Fracturing Operation - Equipment and Layout .............................................................. 6

Figure 4: ‘Christmas Tree’ Assembly of Valves and Fittings used to Control Flow from a Well ................... 7

Figure 5: Natural Gas Processing Plant ......................................................................................................... 8

Discussion Paper: Petroleum Operations, Costs and Opportunities in Nova Scotia

1. Overview

This paper provides a basic overview of the process of exploring for and producing hydrocarbons, with a

focus on economic costs and benefits, not technical matters. It describes generally what is involved in

each phase of activity – exploration, field development, production and abandonment – setting out the

costs and benefits including opportunities for involvement by the local workforce and contractors. Other

papers cover technical matters in greater detail, including such topics as geology and resource potential,

legal and regulatory considerations, and potential environmental and health impacts. The discussion

assumes natural gas discoveries, although it is possible that oil may also be discovered.

The technical information in this paper is derived from published materials, with cost and local content

estimates for conducting the various hydrocarbon activities based on information obtained directly from

industry sources in Atlantic Canada and elsewhere in North America. Providing even a rough guide to

what onshore petroleum exploration and development could mean for Nova Scotia requires a range of

assumptions, given the limited onshore activity in the Province. Accordingly, the reader is cautioned

that the activity and associated cost and content estimates are highly speculative and should at best be

considered indicative, rather than definitive, of what could occur if this activity were ever to be pursued

in Nova Scotia.

2. Exploration

2.1. Obtaining exploration rights

The first step in conducting an exploration program is to acquire exploration rights. Hydrocarbons in or

under Nova Scotia lands are normally considered to be owned by the Crown4, so rights to explore must

be obtained from the province regardless of whether they are on Crown land or land owned privately

(permission from the landowner is required to enter private land). The Department of Energy (DOE)

issues and manages rights under the Petroleum Resources Act and Regulations.i

The process of acquiring exploration rights involves the following:

A petroleum company nominates the parcel(s) of land it wishes to explore.

DOE issues in the Royal Gazette and media a competitive Call for Exploration Proposals for the parcel(s) nominated.

4 An exception arises in the case of federal lands that are located within provinces, such as national parks and

Indian reserves. Resources located under federal lands are considered to fall under federal jurisdiction.

Hydraulic Fracturing Independent Review and Public Engagement Process in Nova Scotia 2

Companies interested in the land have 60 days to submit a bid specifying their work commitment (activity and expenditures) and information related to experience and technical/financial capability.

The company meeting the criteria and submitting the best proposal would be awarded an exclusive right to explore through an Exploration Agreement (EA), a contract between the company and the Minister of Energy.

The EA is typically for an initial period of three years, during which time the company must drill at least

one well. Two renewals of three years are available, provided the company continues to explore. The

land reverts to the Crown at the end of the EA period, or if terms and conditions of the EA are not met.

If hydrocarbons are discovered in commercial quantities, a Production Agreement (PA or lease) may be issued on submission of a satisfactory development program. The lease is typically for 10 years, with renewals on agreed terms and conditions.

Prior to carrying out any work under the EA and PA, the company would have to complete any required environmental impact assessments. Also, as part of the process, consultation and accommodation of First Nations may be necessary at various stages.

2.2. Identifying the hydrocarbon resource

Hydrocarbons are trapped in geological structures far beneath the surface: at depths of 1,000-2,000 m in

Nova Scotia, and at 2,500-3,000 m depths in New Brunswick.ii Surface features of the land provide

indications that an area might hold potential, but it is only through detailed analysis of sub-surface

conditions that potential structures can be identified. This analysis, typically costing $1-2 million, is

carried out by integrating several types of information:

Geological: petroleum geologists conduct field surveys, examining surface features and rock formations, possibly taking core samples of rock, interpreting the data to determine the types of rocks that may be present at depth, and mapping the area.

Geochemical: geochemists collect rock and core samples, subjecting these to laboratory tests to determine the potential of source rock to generate petroleum.

Geophysical: geophysicists conduct seismic and magnetic surveys to create 3D images of sub-surface structures to identify potential hydrocarbon traps and reservoirs. The size, thickness and characteristics (porosity and permeability) of the reservoir rock are estimated in order to determine the hydrocarbon volume (reserves) in place. The analysis would also determine the type of hydrocarbon present (natural gas and/or oil).

Depending on the location and complexity of the geology, it could take several months to several years

to complete geological and geophysical assessments. Conducting the seismic survey tends to be one of

the more costly aspects of the work, requiring specialized companies (and individuals) with substantial

investments in equipment and technical expertise. A seismic survey is conducted using ‘vibroseis’ trucks


(Figure 1), often complemented by other means. Wherever possible, trucks operate on existing roads,

but can operate off-road if necessary, with the permission of landowners.

Vibroseis trucks have heavy metal plates installed underneath and operate by lowering these plates and

vibrating simultaneously for a few seconds, emitting sound waves over a range of frequencies. This is

repeated at regular intervals several hundred times during a typical day. These sound waves are picked

up by small microphones (‘geophones’) set out along pre-determined seismic lines. Cables linking the

geophones carry the signal to a recording truck that measures the sound waves. The data are sent to a

computer centre for processing, resulting ultimately in images of the subsurface geological structure.

Figure 1: Vibroseis Trucks

Source: http://www.lithoprobe.ca/

2.3. Drilling the exploration well

If the geological analysis identifies a potential hydrocarbon bearing structure, then the next step is to

determine the best location to drill an exploration well. It is only by drilling a well that a petroleum

company can confirm a structure’s content. Further wells may be needed to determine the size of the

reservoir. Consultation with First Nations may or may not be required at this or subsequent stages.

Nova Scotia is very much a ‘frontier’ jurisdiction with respect to land-based petroleum exploration, with

fewer than 30 wells drilled in the past decade. Consequently, the equipment needed would not

ordinarily be available locally. Once the petroleum company selects a drilling contractor, the drilling rig

and associated equipment would likely be brought in from western Canada (where hundreds of rigs are

available), or possibly the U.S. Mobilizing and de-mobilizing a rig is a major operation involving over 50

transport trucks and costing several hundred thousand dollars.

The exploration drilling contractor could be hired either on a turnkey basis, or cost per day or per metre

drilled. A turnkey approach with a fixed price for the well is common where the geology is well known

and the contractor is familiar with the area. The contractor would be responsible for hiring the sub-


contractors who provide the various goods and services needed to complete the well. The cost per

day/metre approach would be more common in frontier areas where less is known about the geology

and contractors would be reluctant to take on the risk of a fixed price contract. In such cases, the

petroleum company is more likely to act as the general contractor and hire the sub-contractors.

Once a site for a well is determined, environmental and safety assessments conducted, and all approvals

received, the land is cleared and a pad constructed for the drilling rig and associated equipment and

facilities (generator, pump house, trailers, and various storage tanks). A typical drill site is shown in

Figure 2.

Depending on the depth of the hydrocarbon bearing structure (about 1,000-1,500 m in Nova Scotia), the

well could take 3-5 weeks to drill. Drilling is a 24-hour, seven day a week operation. It starts with

drilling a starter hole and installing conductor pipe or surface casing, and then bolting or welding a

wellhead/blowout preventer to the casing. The drill bit, collar and a section of drill pipe are lowered

into the hole, and connected to the rig assembly. A rotary table turns the drill pipe and bit, causing it to

penetrate the earth. Successive sections of drill pipe are threaded to the string until the desired depth is

reached. Drilling mud is pumped through the drill pipe to lubricate the wellbore, to float rock cuttings

out of the hole, and also to add weight to counteract any reservoir pressure. The rock cuttings are

tested to determine when reservoir rock is reached. The formation is assessed using logging techniques

(data gathering) as the drilling progresses.

If the initial geological assessment (or experience) suggests the hydrocarbons are located in flat

reservoirs characterized by low natural permeability, then the eventual drilling strategy would rely on a

combination of horizontal drilling and hydraulic fracturing. Advances in drilling technology, the use of

rotary steerable bits in particular, make it possible to deviate from the initial vertical wellbore and drill

horizontally a kilometre or more. Penetrating a flat reservoir horizontally greatly increases the effective

area that a well is able to reach, thereby increasing its potential productivity.

At various stages of drilling, the integrity of the well is maintained by running strings of casing (steel

pipe) and cementing them in place. The final stage consists of running production casing the length of

the wellbore and cementing it in place. Casing serves the dual purpose of stabilizing the wellbore and

creating a pressure barrier designed to keep hydrocarbons inside the well tubulars (and water outside).

Proper design, construction and testing of the casing are critical to well integrity and preventing a

potential source of groundwater contamination.5

5 This topic will be covered in detail in a subsequent discussion paper.


Figure 2: Corridor Resources Drill Site near Sussex New Brunswick

Courtesy of Corridor Resources

It is worth noting that if the first well produces results that eventually justify commercial development,

the usual practice would be to directionally drill multiple wells from a single pad. Not only does this

extend the reach into different parts of the reservoir and optimize hydrocarbon recovery, it minimizes the

footprint of surface activity and reduces drilling costs. Pads vary in area, but are typically in the range of 1

hectare. Drilling multiple wells is simply a matter of ‘skidding’ the rig to its new location on the pad and

repeating the process described above.

Drilling for hydrocarbons involves a combination of highly technical activities carried out by specialized

companies. Typically, as many as 70 or so individuals employed by about 20 sub-contractors are required.

The drilling crew usually consists of two crews of six, plus two supervisors. Sub-contractors include

companies with expertise in mud logging, wireline logging, directional drilling, casing, cementing, perforating,

fishing, flow testing, transportation, construction, repair and maintenance, and catering. Nova Scotians

could fill many of the jobs based on their experience offshore, in western Canada, the U.S. and abroad.

2.4. Hydraulic fracturing

Once the wells have been cased and cemented, the pad is cleared of the drilling rig and associated

equipment to make way for the hydraulic fracturing (HF) equipment needed to complete the well. HF is


a technique used to stimulate a higher permeability flow path for hydrocarbons in a reservoir with low

natural permeability. The technical aspects of HF were covered in our Primer on Hydraulic Fracturing.6

HF operations are conducted by highly specialized contractors using a suite of equipment designed

specifically for this purpose. With limited demand for services and the high cost of equipment, there are

no HF contractors resident in eastern Canada, so equipment would need to be brought in from western

Canada, or possibly the U.S. An HF operation would see several trucks fitted with powerful high-

pressure, high-volume pumps connected to the well(s) with high pressure hoses; a slurry blender (for

mixing the fracturing fluid and proppant7, usually sand or ceramic particles of varying size); various

storage tanks for fracturing fluids and proppant; and a monitoring unit.iii A typical HF ‘spread’ is

depicted in Figure 3.

Figure 3: Hydraulic Fracturing Operation - Equipment and Layout

Courtesy of the Canadian Society for Unconventional Gas

HF requires significant volumes of water (5,000 to 100,000 m3 per well)8. The water is typically obtained

from nearby lakes or rivers, or from municipal water supplies, and transported to the well site by tanker

trucks. This process can involve 40-60 tanker movements per day to and from the site over a 2-3 week

period. Increased traffic on local roads resulting in higher road maintenance costs, congestion, and

greater risk of accidents are among the concerns expressed by the public and are addressed in the risks

6 Available from http://www.cbu.ca/hfstudy

7 See Primer on Hydraulic Fracturing

8 One m

3 is equal to 1000 litres



and concerns section of this discussion paper. On the economic benefit side, trucking activities

represent an economic opportunity for local contractors.

Wells with long horizontal sections in the reservoir would be fractured in stages, starting at the end of

the wellbore. Each stage of 100 m or so would be isolated from the rest of the well with a cement plug.

A perforating tool would be used to create openings in the casing and cement in that stage, and then

the fracturing job begins. The fracturing fluid is pumped at high pressure (up to 100 megapascals or

15,000 psi, reaching up to 265 litres/sec) for 20 minutes to a few hours, depending on the rock

properties and the properties of the fluid and proppant. When that stage is complete, it is plugged and

the process moves to the next section until the length of the well formation in the reservoir has been

completed. The entire HF operation may take 2-3 weeks.

At this point, the plugs would be drilled out and a short flow test of the well may be performed to

evaluate its productive capacity. The final steps would be to remove the blowout preventer from the

wellhead and replace it with a ‘Christmas Tree’– an assembly of valves and fittings used to control flow

from the well (Figure 4), and install production tubing inside the casing. Tubing protects the casing from

corrosion and provides an efficient flow conduit for hydrocarbons. The wells would then be ready for

production – to be tied into a gas plant (using small diameter gathering lines) for processing and

shipment via pipeline.

Figure 4: ‘Christmas Tree’ Assembly of Valves and Fittings used to Control Flow from a Well

Source: http://www.sunryoil.com/wellhead_xmas.html

Depending on the absorptive capacity of the reservoir into which the fracturing fluids have been

pumped, a percentage of the fluid will flow back out of the well when the pressure is released (known as


‘flowback’). Most of this flowback occurs in the early stages of production and is stored in tanks or pits

onsite. Flowback water can be re-used in subsequent HF operations, though this would depend on its

composition (suitability) and the economics of other management alternatives (treatment and

disposal).iv

3. Development and production

Since exploration began in Nova Scotia over 135 years ago, some 125 wells have been drilled without a

significant discovery (NSDOE 2012). This is typical of frontier areas. It can take many years and

considerable seismic exploration and drilling before the geology of a region is understood. Even after an

initial discovery, it could be many years, if ever, before sufficient reserves are proved to justify

commercial development. Our Nova Scotia offshore experience serves as a good example. Twenty years

of exploration (1959-1979) occurred before natural gas was discovered in commercial quantities near

Sable Island. It took almost 20 years of further assessment before the decision was taken to develop the

Sable field. Field development took two years, with production beginning in late 1999.

Figure 5: Natural Gas Processing Plant

Courtesy of Corridor Resources

In the case of onshore exploration and development, the experience of Corridor Resources in New

Brunswick offers the only example in the region. Following geological assessment in the 1990s that


identified hydrocarbon potential, Corridor drilled an initial exploratory well near Sussex in 2000 that

confirmed the potential. Over the next several years, further drilling led to the discovery of sufficient

reserves to justify field development. By mid-2007, Corridor had built a gas processing plant (Figure 5)

and gathering system tying in these wells, and linking its facilities via a 50 km lateral line to the

Maritimes & Northeast Pipeline (M&NP) system. Today, Corridor has 29 producing wells on 10 well

pads and is continuing its exploration and development work.

It is premature to say whether commercial quantities of natural gas or oil exist in onshore areas in Nova

Scotia.9 But if land-based exploration were to lead to natural gas discoveries with commercial potential,

then it would be reasonable to expect that development and production might follow a similar pattern

to New Brunswick:

geological assessment leading to identification of areas of hydrocarbon potential;

drilling and testing an exploration well if the geological assessments were favourable;

drilling and testing further wells, possibly over a period of years, if the initial well provided encouraging results;

determining the size of the recoverable reserves and conducting preliminary planning work for production wells (number, location, timing) and ancillary production facilities to develop the field (including gathering lines, gas plant, and link to a pipeline or to industrial customers/local distribution companies);

determining whether the discovery offers commercial potential (estimating and comparing development and operating costs with projected revenues based on production levels and market price forecasts);

if the project economics are favourable, meeting all pre-project regulatory and legal requirements (conducting consultations with First Nations and communities, carrying out environmental and socio-economic impact assessments), preparing a development plan and filing it with the regulator, securing financing, and developing a project implementation plan (detailed development plan, procurement strategy, hiring contractors, etc.), and implementing the project;

operating the project including drilling new wells and bringing them into production as existing wells are depleted;

implementing abandonment and reclamation work according to regulation once wells have reached the end of their productive lives. This involves removing gathering lines and all surface equipment (the wellhead), removing surface casing, capping the well by filling it with cement, and restoring the land to its pre-development state. Monitoring requirements are typically prescribed in regulations.

9 This topic will be covered in a subsequent discussion paper.


4. Petroleum development costs and benefits – industry perspective

The economics of petroleum exploration and development are challenging, given the level of

expenditures required, in the light of uncertainties surrounding such factors as resource, market,

technology, environment and financing. Costs rise at each stage in the process, while revenues (and

significant economic benefits) could be years away. Tens or hundreds of millions of dollars could be

spent before a discovery is made, if one is made at all. If hydrocarbons are found, then from the

petroleum company’s perspective, it comes down to whether the recoverable reserves are high enough

and long-term market conditions favourable enough to generate sufficient revenues to justify the

further costs needed to develop and operate the field.

Table 1 provides an indication of the scale of the costs of each phase of activity, moving through the

process from geological assessment to production. Approximate costs by activity are presented in detail

for drilling and fracturing a single well. This provides a basis for identifying and quantifying local

spending and associated sub-contracting and employment opportunities.

An estimate of the capital and operating costs for what might be considered a minimally attractive

development is also provided in Table 1 to give a sense of scale. This estimate requires assumptions to

be made about the size of recoverable reserves in a discovery; likely production rates per well; the

number and layout of wells needed; the size of the plant needed to process the gas (assuming a natural

gas discovery); the length of gathering lines to tie the wells to the gas plant; and the size and length of

the pipeline linking the gas plant to the main transmission line or distribution system.

By applying percentage estimates of local participation to expenditures, it is possible to derive a rough

estimate of the work that could be carried out by Nova Scotian contractors and individuals (this is

referred to as local content). To summarize:

Assessing resource potential: local consultants would be expected to provide support services, but the scientific expertise for much of this work resides mainly in western Canada where most of the petroleum exploration and production takes place. Unless and until an industry develops in Nova Scotia, local content would be confined to support services. Content is estimated at 25-30% of the $1.0-2.0 million needed to conduct the geological and geophysical assessment.

Exploration Drilling: many Nova Scotian companies and individuals have capabilities and experience based on offshore work and work in western Canada, placing them in a good position to supply early stage environmental assessment, First Nations Traditional Ecological Knowledge (TEK) consultations, and site development, as well as various drilling support services. The more technical and higher cost inputs would be imported to the province (drilling rig, directional drilling services, drill bits, casing). Local content is estimated at 30-35% of the $5.0-6.0 million needed to drill an exploration well.


Hydraulic fracturing: whereas several individual sub-contractors provide the technical services required for drilling, HF services are supplied by a limited number of companies with substantial investments in equipment and expertise and form a major sub-contract in their own right. Established companies from western Canada (or possibly the U.S.) would perform the work in Nova Scotia. Local content is estimated at 20-25% of the $3.0-3.5 million needed to hydraulically fracture a well (below 20% if propane were to be used instead of water as the fracturing fluid).

Development: moving beyond a single discovery well to a full field development assumes on-going drilling success over a period of years, such that a minimum economic volume of recoverable reserves is found that is likely to generate an adequate return on the investment in the production facilities needed to process the gas and carry it to market. Based on the assumptions in Table 1, that investment could range between $500-600 million, of which 35-40% could represent Nova Scotia content. Drilling the assumed 50 wells needed for development forms a major component of this investment. The higher content during development is attributable to higher levels of participation in drilling development wells, and in construction activities related to the gas plant (assumed capacity of 40-50 MMcf/day), gathering lines and transmission line lateral. Between 250 and 400 full-time equivalent jobs would be created during the assumed 4-5 year initial development phase.

Production: unconventional gas wells experience more rapid declines in production than conventional wells, though what this means in terms of the overall productive life of a well is unclear because of limited experience. A field development strategy would anticipate the need for on-going drilling to replace production as wells were depleted. The costs in Table 1 make no assumption about the overall duration of production, simply providing an annual operating cost estimate of $5-6 million annually based on a 50-well development. The 25-35 personnel and services needed during operations would be sourced in Nova Scotia. In addition, under the terms of the Production Agreement, the province would receive royalties based on a percentage of the fair market value of gas produced each month.

Abandonment: carrying out abandonment activities would typically cost in the range of $175-200,000 per well. Local contractors would carry out this work.


Table 1: Shale gas drilling and hydraulic fracturing activities and cost estimatesSource of supply

Phase/Activity Cost ($000) Nova Scotia Other Canada % US

% $000s Jobs(FTE)

Assess resource potential 1,000- 350- 650

Duration:8-12months 2,000 500 1-2 1,500

Permitting & lease agreements 25 1.00 25

Environmental survey & approvals 50 1.00 50

Geological survey/analysis 1,500 0.25 375 0.75

Exploration well 5,000- 1,500- 3,000- 500-

Duration: 1-2 months 6,000 1,900 2-3 3,500 600

Site planning & construction 150 1.00 150

Drill rig mobilization 500 0.40 200 0.60

Drill rig operations 1,250 0.00 0 1.00

Directional drilling services 550 0.00 0 1.00

Supervision 350 1.00 350

Wellhead 100 0.00 0 1.00

Drilling fluids 400 0.50 200 0.50

Logging services 250 0.30 75 0.70

Casing (pipe and installation) 750 0.05 38 0.25 0.70

Cementing 200 0.60 120 0.40

Drill bits 200 0.00 0 1.00

Fuel 250 1.00 250

Fluid & cutting disposal 225 1.00 225

Equipment rental & services 425 0.50 213 0.50

Hydraulic fracturing (2/well) 3,000- 900 2,100-

Duration: <1 month 3,500 1,100 1-2 2,400

Equipment mobilization & set-up 500 0.40 200 0.60

Stimulation services 1,250 0.00 0 1.00

Propane & sand supply/transport (option) 500 0.00 0 1.00

Water & sand supply/transport (option) 500 1.00 500 0.00

Coiled tubing services 225 0.00 0 1.00

Monitoring & control services 200 0.00 0 1.00

Well test & flowback recovery 300 0.70 210 0.30

Security & fire protection 50 1.00 50 0.00

Equipment rental & services 50 1.00 50 0.00

Development (50 wells@5 wells/pad) 500,000- 200,000- 300,000-

Duration: 2-3 months/well 600,000 250,000 250-400 350,000Drill/frac production wells ($8MM/well) 400,000 0.30 120,000 150-250 0.70

Build gas plant 35,000 0.60 21,000 50-100 0.40

Install flowlines and lateral (100km@$1MM/km) 100,000 0.50 50,000 35-50 0.50

Land restoration 3,000 1.00 3,000 5-10 0.00

Production (operations) 5,000- 5,000

Duration: 10-20 years (annual cost/personnel) 6,000 6,000 25-35

Personnel 1,500 1.00 1,500 20-25

Operations & Maintenance 3,500 1.00 3,500 5-10

Property taxes 500 1.00 500

Abandonment (50 wells) 8,000- 8,000-

Duration: <month 10,000 10,000 3-4

Services 5,000 1.00 5,000

Land prep & restoration 4,000 1.00 4,000

1. Phase totals expressed in ranges to reflect uncertainty; activities expressed as point estimates to simplify content estimation.

Source: various industry sources.


5. Petroleum development impacts – a community perspective

5.1. Risk factors and potential costs

Completing wells using HF techniques is controversial because of the actual and perceived risks posed.

Among the costs to the petroleum company is the acquisition of large-scale insurance coverage and/or

bonding to meet regulatory requirements regarding unforeseen incidents. Though HF would be subject

to regulation in Nova Scotia, including requirements for petroleum companies to take measures to

address factors contributing to risk, many submissions to our Review Panel indicate clearly that public

concern exists about the potential for HF to result in significant and even irreparable environmental

and/or social costs.

Among the concerns highlighted in submissions to our Review and also in the literature concerning HF

experience in other areas of North America that have economic implications are:v

Water requirements: most HF operations require substantial quantities of water. Water requirements can range up to 20 million litres per well, and are usually obtained locally from lakes, rivers or municipal systems. Though amounts used per well may be small in comparison with other uses or in relation to overall supply (in Nova Scotia volumes are regulated), volumes used for HF are nonetheless a matter of public concern. To address this concern, and also because in many cases it makes economic sense (i.e. it is cheaper than disposal/treatment), companies are increasingly recycling flowback water for use in further HF operations. Industry is also using propane or liquefied petroleum gas (LPG) instead of water as the HF fluid (in gel form). After fracturing, the LPG becomes a vapour under pressure, returning to the surface with the natural gas where it is recaptured.10

Transportation and roads: related to the volume of water are concerns about the method of transportation – typically by tanker truck – and the implications for traffic levels, safety and road conditions. These implications vary from location to location depending on the distance between drill sites and water sources, and on the types of roads travelled. Local roads in rural areas tend not to be designed to withstand the stresses imposed by heavy truck traffic. That the community would bear the costs of repair is a matter of public concern. Traffic congestion, safety risks, additional road noise and dust are also matters of public concern. Some of these potential adverse consequences can be reduced or eliminated through traffic management, and with respect to road damage, by establishing a compensatory framework requiring petroleum companies to pay their share of repair costs.

Chemical ingredients: chemical ingredients typically account for about 1% by volume of the HF fluid. Specifics about which chemicals and at what concentrations have been matters of public concern specifically with respect to the risk of toxicity and effects on groundwater. The unwillingness of some companies to reveal ingredient details (where not required to by regulation)

10

The relationship between water resources and unconventional gas resources is explored in a forthcoming discussion paper.


has served to heighten concern. Full disclosure is required by regulators in some provinces, while in others (including Nova Scotia) companies must provide the information at the request of the regulator.

Storage/treatment of chemicals and flowback water: chemicals are stored onsite before blending with water, and flowback water is stored onsite before disposal/treatment (or recycling). The concern is about improper storage with the risk of leaks and contamination of soil, surface water and groundwater. Where possible flowback water is re-cycled for use in other HF operations. It may also be injected into disposal wells, assuming the rock formation is suitable.

Effects on drinking water: this is one of the greatest concerns expressed by stakeholders, resulting in part from uncertainty about how HF works and the nature and security of the safeguards in place (casing and cementing), and in part from reports of drinking water contamination in areas where HF operations are taking place (whether resulting from HF or other factors). If contamination were to occur, the fear is that it would impose costs arising from impaired health, the need to secure alternative water sources for those affected, and also from remediation efforts.

Quantifying any possible costs that could arise from these risk factors is impossible without reliable

information on the probability of a triggering event and the dollar value of any resulting damage. Such

information is not available for Nova Scotia because the limited drilling and HF that have occurred do

not provide an adequate statistical basis for computing probabilities, and nor is there information on

any environmental costs related to this experience. But even on the much larger scale of activities

elsewhere in Canada and in the U.S., the data needed to reliably assess environmental impacts is not

available. As the recent report of the Council of Canadian Academies concludes, “While tens of

thousands of shale gas wells have been drilled across North America over the last two decades…there

has been no comprehensive investment in the research and monitoring of environmental impacts.”vi

5.2. Benefits

The expenditures set out in Table 1 represent potential benefits when viewed from the perspective of

the community. This is because they create opportunities for local suppliers of goods and services, who

in turn generate employment and income. Like other industrial activities, these direct expenditures lead

to demand elsewhere in the economy, creating the spinoff effects contributing to economic growth.

Our experience in Nova Scotia with the benefits associated with hydrocarbon development is based on

50 years of offshore activity, including the drilling of some 225 exploration and development wells and

the implementation of one oil project (Cohasset-Panuke) and two natural gas projects (Sable and Deep

Panuke). Industry in the province has benefitted from these projects through the supply of goods and

services during field development and production. Overall, project expenditures have run to the billions

of dollars. vii

Projects exhibit a characteristic pattern of 2-3 years of intense development activity (high capital

investment and employment), followed by several years of stable operations (relatively low levels of


spending and employment). Over the years, these projects have created employment for thousands of

workers in Nova Scotia, providing them with valuable and highly portable skills and experience. Access

to natural gas has contributed to a more diversified energy portfolio in the province. The province has

also benefitted from royalty payments in the $1.5-2.0 billion range.

Any potential future onshore hydrocarbon exploration and development in Nova Scotia would share

some of these characteristics, but would differ greatly in terms of scale. Onshore activity has the

characteristic expenditure profile associated with capital intensive industries: a period of high demand

for contractors, sub-contractors and their employees during initial field development (4-5 years),

followed by several years of production featuring relatively low but steady expenditure and

employment. This pattern is evident in the figures in Table 1, which show annual spending exceeding

$100 million during the few years of a single field development, and then dropping to the $10 million

range annually during production. The experience in western Canada with conventional natural gas

shows that as discoveries continue to be made and the industry matures, this spending pattern tends to

become less evident because of the continual flow of projects.

This paper does not take the question of economic impact beyond the stage of direct expenditures for a

single development set out in Table 1. The impacts would be larger and extend more deeply into the

economy should a shale gas industry actually develop. A study of the economic impact of shale gas

development in Québec offers some guidance on the nature and scale of impacts in a frontier area,

though it is purely speculative in nature.viii We could look to Alberta and British Columbia for some

insights into what shale gas development could mean in terms of economic impact, though

development there is still at a fairly early stage.

Looking to the experience in jurisdictions outside Canada where development is more advanced may be

helpful in understanding the economic impacts. For example, much has been written about the impacts

arising from the Marcellus and Barnett developments in the U.S.ix Indeed, studies of these developments

tend to play an important role in informing public perceptions about the pros and cons of shale gas

exploitation. But readers of these various studies should be cautioned about two things: first, the U.S.

experience springs from a particular set of rules governing resource exploitation (ownership of sub-

surface rights and industry regulation); and second, the analysts are not always as objective or thorough

as we would like them to be.

Directly related to the rules governing resource exploitation in the U.S. is the concern that shale gas is

prone to a boom-bust cycle of development characterized by periods of intense activity when the

drilling and related developments take place, followed by a sharp decline in activity (employment) once

production begins. Though the increase in economic activity has its positive aspects, there are negative

ones as well. These include a rise in administrative and service costs as communities deal with more

intensive use of infrastructure and an influx of workers, and adverse economic effects as rising demands

for goods and services ‘crowd out ‘existing businesses.


Central to the rapid and seemingly uncontrolled pace of development in the U.S. is the ownership of

subsurface rights where the unconventional gas is found. The decision to allow exploration and

exploitation in the U.S. rests largely with landowners, who own the subsurface rights. By contrast, in

Canada, subsurface rights are normally assumed to belong to the Crown. This provides provincial

governments, through the regulatory process (issuing exploration licences), with a means of controlling

the pace of development. Controlling the pace of development, in turn, provides an important

mechanism for mitigating many of the potential adverse economic consequences that could arise.


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