Technology Roadmap to Improve

Wellbore Integrity
SUMMARY REPORT
Technology Roadmap to Improve
Wellbore Integrity
SUMMARY REPORT
Disclaimer

This Technology Roadmap to Improve Wellbore Integrity: Summary Report

brought together experts from industry, academia and government to
examine wellbore integrity issues that may arise during the entire life cycle
of a well.

The inclusion of information in this document should not be considered as

endorsement by members nor their organizations. Working Group members
assume no responsibility for errors or omissions in the content.

Third-party materials

Some of the information contained in this publication or product may be

subject to copyrights held by other individuals or organizations. To obtain
information concerning copyright ownership and restrictions, contact
Andrew Wigston at andrew.wigston@canada.ca.

PDF: Cat. No. M134-59/2019E-PDF

ISBN 978-0-660-29598-5

Paper : Cat. No. M134-59/2019E

ISBN 978-0-660-29599-2

© Her Majesty the Queen in Right of Canada, as represented by

Natural Resources Canada, 2019

Aussi disponible en français sous le titre : Feuille de route technologique pour

l’amélioration de l’intégrité des puits de forage : rapport sommaire

Commercial reproduction and distribution are prohibited except with

written permission from NRCan. For more information, contact NRCan at
copyright.droitdauteur@nrcan-rncan.gc.ca.
Executive Summary
Canada is a hydrocarbon superpower, with 10% of the world’s proved crude oil reserves
(3rd largest), and 1.2% of its natural gas reserves (15th) at the end of 2016. Even as
the world transitions to less carbon-intensive energy sources, crude oil and natural
gas will continue to provide 50% of the globe’s energy needs for decades, including
here in Canada. Improving the environmental performance of the upstream oil and
gas sector while maintaining a competitive business environment is a priority for
the Canadian oil and gas industry and government regulators. Wellbore leakage has
received considerable attention over the past number of years for several reasons. The
predominant leakage fluid is natural gas, which is largely composed of methane—a
potent greenhouse gas (GHG). Federal and provincial governments, along with industry,
have pledged to reduce methane emissions from the upstream oil and gas sector1.
According to Environment and Climate Change Canada, emissions from wellbore
leakage were 7.2 megatonnes (Mt) CO2 equivalent (CO2e) in 2015, which was 4.3% of
total emissions from the upstream sector2,3. The Council of Canadian Academies 2014
report on shale gas development in Canada raised concern about the potential for
potable groundwater contamination from wellbore leakage. Leakage is also a significant
economic burden on industry and orphan well funds. The cost to remediate leaky wells
ranges from tens of thousands of dollars for simple cases to millions for more complex
ones. While the majority of wells in Canada don’t leak4, the overall cost is still enormous
given that nearly 580,000 wells were drilled between 1955 and 2017, and over a
hundred thousand new wells will need to be drilled over the coming decades to meet
projected hydrocarbon production increases. The National Energy Board predicts, for
their reference case, that crude oil production will increase by 59% over 2016 levels by
2040, and of this, 75% will be from wells (i.e. non-mined oil sands).
Industry and government regulators in Canada have worked together to successfully
improve wellbore integrity for decades. For example, the average daily emission rate
of wellbore leakage for non-serious wells in Alberta has declined by 40% from 2000
levels to ~13 m3/day in 2016, and the median, or typical rate, is even less than this.
In order to continue to improve the environmental and economic performance of the
upstream oil and gas industry, Natural Resources Canada (NRCan), in collaboration with
Canada’s Wellbore Integrity and Abandonment Society (WIAS), launched a process to
develop a Technology Roadmap to Improve Wellbore Integrity. The technology roadmap
(TRM) brought together experts from industry, academia and government to examine
wellbore integrity issues that may arise during the entire life cycle of a well. Considering

1
Including a pledge by Alberta to reduce methane emissions by 45% compared to a 2010 Environment and
Climate Change Canada (ECCC) baseline value.
2
Data available at the time the report was written. ECCC estimated 2016 wellbore leakage emissions to be
7.1 MtCO2e.
3
For comparison, methane emissions from solid waste management (i.e. landfills) were 22 MtCO2e, and
those from enteric fermentation (i.e. livestock emissions) were 25 MtCO2e in 2015 (ECCC’s 2017 National
Inventory Report, 1999-2015, Part 3, Table A9-3).
4
Out of the ~440,000 wells drilled in Alberta, only ~5% have reported leakage.

Executive Summary iii

that many operators have low incidences of wellbore leakage, existing technology and
practices are very effective for the most part. Thus, the TRM captures best practices
to address wellbore integrity issues where possible. For remaining knowledge and
technology gaps, it provides recommendations on research and development (R&D) to
address these. The TRM is not an exhaustive document as the subject is too large and
complex to capture in one report. Rather, the intent of the TRM is to provide a high-level
document that: (i) is a reference source; (ii) will facilitate action on specific wellbore
integrity issues; and, (iii) will help guide R&D so that it is focused on topics that will
have the most costeffective environmental and economic impact.

For the TRM, the subject of wellbore leakage was broken into six topics: (i) Magnitude
and Impacts of Wellbore Leakage; (ii) Designing, Drilling and Construction; (iii) Leak
Source Identification; (iv) Remediation Strategies; (v) Abandonments; and, (vi) Industry
Knowledge, Best Practices and Regulations. Reports were commissioned for each and
were produced by a cross-section from academia and industry. Draft reports were
presented at an open workshop in 2016 and revised based on feedback and expert
reviews. The TRM is a high-level summary of these topic-specific reports and readers
are encouraged to consult the individual reports for more detail5. The following presents
some highlights from each report.

Magnitude and Impacts of Wellbore Leakage: This report focused on Alberta as it has
the majority of Canada’s hydrocarbon wells and is the most studied. There are multiple
sources and emitters of methane to the atmosphere and shallow subsurface—both from
the upstream oil and gas sector and other industrial sectors, as well as natural sources.
The impacts are agnostic of the source. Thus, it is imperative to understand their relative
contributions and avoidance/mitigation costs in order to develop the most cost-effective
methane reduction strategies.

Beginning in the 1980s industry and regulators in Alberta began to reduce the rate of
well integrity issues. As of 2016, 5% of the 440,000 wells drilled in Alberta developed
leakage. Emissions from wellbore leakage have declined since 2008, even as the number
of wells has increased, and was, according to the Alberta Energy Regulator, 1.56 MtCO2e
in 2016. About 30% of this was from wells classified as serious (vent flow greater
than 300 m3/day, amongst other criteria), which must be immediately remediated;
the remainder is from non-serious wells (which must be remediated, at latest, at
abandonment), with an average rate of 13.2 m3/day, although the median, or typical rate,
is less. Of the 10,326 leaking wells, 96.7% were nonserious.

The risk of wellbore leakage resulting in pervasive contamination of soil and potable
groundwater in Canada is considered low: only a few instances of aquifer contamination
have been identified in spite of the hundreds of thousands of wells drilled. In Alberta
only 0.66% of wells leaked to the subsurface (termed gas migration [GM]), and GM
effects are predominantly localized around the well. In light of other sources of methane
in the subsurface and the considered low risk of groundwater contamination, it is
recommended that R&D be conducted to determine if acceptable wellbore leakage

5
The topic-specific reports can be accessed through the Wellbore Integrity TRM page, which is found on
NRCan’s TRM webpage at: http://www.nrcan.gc.ca/energy/offices-labs/canmet/5765

iv Technology Roadmap to Improve Wellbore Integrity – Summary Report

rates can be established such that soil and groundwater use is not impaired. Such
studies could inform the development of risk assessment-based approaches to wellbore
remediation for non-serious wells. Not requiring remediation of all non-serious leaks
at abandonment in instances where the risks and impacts are considered acceptable
will reduce the cost of abandonments. This will allow limited resources to be deployed
against other environmental problems, and will facilitate the abandonment of
uneconomic wells for owners, who may leave wells in a suspended state as remediation
costs may be too onerous to abandon them, and provincial orphan well funds.

Designing, Drilling and Construction: How a well is designed, drilled and constructed
is critical in determining the likelihood of leakage over its lifetime, including post-
abandonment. Leakage occurs when pathways develop in the cement that is used to
seal the annular space both between casings, and the outermost casing and borehole
face, and fluids invade and migrate upwards in these. Leakage also may occur when
fluids migrate from inside to outside the casing due to corrosion of the casing or
leaky connections. The failure of annulus seals is primarily the result of poor mud
displacement during cementing, gas migration into cement during setting, microannulus
or stress crack formation during operation, or autogenous shrinkage during cement
hydration leading to the formation of a micro-annulus.
Drilling oil and gas wells remains a challenging task considering their requirements
(e.g. depth, length, pathway), environment (pressure, temperature, fluid composition),
and operating conditions (e.g. cyclic high pressure and temperature for fracked and
thermal heavy/oil sands wells). But, many operators have low incidence of wellbore
leakage as a result of: considering a well’s complete life cycle during design; following
best practices (published and in-house); and spending extra time and money up front…
in other words, doing things right in the first place. Thus, significant reductions in
wellbore leakage can be achieved tomorrow by getting more operators to behave like
industry-leading ones. Wellbore integrity may be improved to an even greater extent by
conducting R&D on advanced cement formulations and casing materials (e.g. expandable
packers) to improve their resiliency under fluctuating and extreme conditions, and their
long-term durability. It is also recommended that R&D be conducted to validate the
efficacy, safety and cost effectiveness of operational practices employed during drilling
and construction which have shown the potential to reduce wellbore leakage, but which
well owners and service companies are reluctant to employ because of their novelty
or perceived risk of damaging a well. For example, determining if pipe rotation overly
fatigues well casing.

Leak Source Identification: In order to fix a leak, you first need to determine the
depth (and thus formation) at which it is originating so that an effective seal can be
emplaced at the leak source, or in some cases, at an overlying competent caprock. Source
formations are commonly thin, uneconomic gas-bearing strata that were bypassed
during drilling on the way to deeper pay zones. There are three types of methods
used to identify sources: (i) acoustic energy measurements; (ii) carbon isotopes; and,
(iii) formation evaluation. Regulations don’t specify which to use, but best practice is to
employ the application of all.

Executive Summary v
Acoustic tools listen for the sound produced as fluid flows in the annulus, and pinpoint
the depth of the source. Advances in acoustic energy measurements to improve source
identification and magnitude include: spectral noise logging; geophone noise surveys
that employ an array of sensors downhole; and fibre optic digital acoustic sensing.
Geological formations have a distinct ratio of 13C to 12C (an isotopic fingerprint). By
comparing the ratio from a sample of leakage gas against those from samples collected
from producing formations as the well (or nearby wells) was/were drilled, it is possible
to identify the source. Wells are variably logged after they are drilled and/or cased
in order to determine the lithology and formation properties (e.g. fluid composition,
porosity). These help inform source identification by indicating parameters such as gas-
bearing formations, caprocks and zones of poor cement quality. A lack of standardized
data/sample acquisition and interpretation is a major barrier to successful source
identification. It is recommended that these be developed using existing knowledge
and that R&D be conducted to address gaps (e.g. effect of heat from thermal wells on
isotopic ratio). Developing a high-quality comprehensive isotopic fingerprint database
with samples from all producing horizons from hydrocarbon producing regions would
be extremely helpful.

Remediation Strategies: Regulations governing the fixing of leaks (i.e. remediation

or intervention) are objective-based because the variety of scenarios and remediation
technologies preclude the development of proscriptive-based regulations. Most
jurisdictions allow for some leakage during a well’s lifetime, but require complete
isolation at abandonment. The remediation process is: (1) identify the source of the leak
(as previously discussed); (2) develop access to the source/leakage pathways; (3) seal
the leak; and, (4) verify success. The most common method is “squeeze placement,”
a method in which the casing is perforated at the leak source and a sealant, most
commonly Portland cement, is forced into the leakage pathways. In addition to cement,
there are a variety of other sealants (e.g. resins, metal alloys, pressure-activated sealants,
and more) that have (or claim to have) better sealing properties and durability. The
success rate of the cement squeeze method can be low (50% in some regions). The
cost of cement squeeze remediations can range from tens of thousands to millions of
dollars. Inadequate leak source identification and poor communication with leakage
pathways are two of the primary reasons for lack of success (for any method), but
cement properties may also contribute (e.g. particle size can be a barrier to entry for
small channels).

Given the number of remediations performed, there is considerable data on what does
and doesn’t work under given conditions; however, this information is not widely
shared amongst companies, particularly for failures. Improving data sharing on
remediation practices and results is recommended. Such data would help inform the
development of a comprehensive Industry Recommended Practice (IRP), which would
support regulations that are (by design) lacking in technical content. Such an IRP should
include topics like a description of the various sealing materials and methods available,
and decision-making tools (e.g. flow charts) to guide their selection considering the
well’s conditions. Lab- and field-based independent evaluation of various remediation
materials and methods (particularly novel ones that have not been applied in the field

vi Technology Roadmap to Improve Wellbore Integrity – Summary Report

much or at all) should be pursued and supported by the development of protocols and
methods to evaluate their efficacy in a consistent manner.

Abandonments: Dry holes or wells that are no longer economic are sealed during the
abandonment process in order to prevent the migration of fluids within the wellbore and
near-wellbore region. The basic technology associated with plugging and abandoning
wells has not changed significantly since the 1970s. The basic steps are: (1) test for
surface casing vent flow (SCVF)/GM and remediate if present; (2) prepare the wellbore
for abandonment; (3) plug the well (commonly by emplacing ~ 8 m of cement on top
of a mechanical bridge plug); and, (4) cut and cap the well. Abandoned wells develop
leaks either because of inadequate sealing of the (usually) cemented annulus and/or
inadequate sealing within the casing. Since monitoring began in Alberta in 1910, 7% of
the 25,000 wells that have developed leakage were of the abandoned well type.

The methods used to remediate annulus leaks as discussed above are applicable to
both producing wells and those to be abandoned. With respect to plugging wells, the
predominant dump-bailing method was analyzed in a small but informative study in
Alberta, and the results indicated that it may be ineffective as the cement plug quality
was extremely poor in about half the wells. In addition to dump-bailing, there are a
number of other technologies, of varying degrees of development and use, which may
offer better performance. In terms of more conventional ones, it is recommended
that the balanced plug method, in which cement is emplaced between two packers
and develops superior strength, replace the dump-bailing method except in low-risk
wells, and that longer (~100 m) cement plugs be used in dump-bailing. Removing a
section of casing and annular cement at a caprock boundary to facilitate the improved
emplacement of a sealing material has been suggested to be a standard abandonment
practice. And bentonite-based plugging materials, which the nuclear waste industry
has investigated as a well-plugging material, should be considered. More novel
technologies include thermal sealing (melting casing, cement and rock to make a seal
across a caprock), molten material plugs (low-melting point metals and salts), and
casing expansion. As has been noted for the other wellbore topics, a major challenge
with the deployment of novel abandonment technologies is a lack of familiarity and/
or confidence by the industry and regulators in their performance, which in turn is
driven by a lack of independent testing. Thus, it is again recommended that testing
standards and methods be developed against which technologies can be evaluated
(where feasible), and that independent field-based R&D be supported, conducted and
made public.

Industry Knowledge, Best Practices and Regulations: Government regulations

prescribe minimum requirements governing oil and gas wells in Canada. Many oil
and gas exploration and production companies go above and beyond that required by
regulations by following best practices, and in the process achieve fewer instances of
wellbore leakage. Best practices (commonly termed Industry Recommended Practices
in the Canadian upstream oil and gas industry) play an important supporting role in
the regulatory environment. Best practices can, and should, be more descriptive, and
can cover more situations and descriptions than regulations. Best practices are more
easily updated than regulations and allow for evolution as additional knowledge and

Executive Summary vii

technology become available. Research and development is commonly led by service
and technology companies, as opposed to exploration and production companies, as
wellbore remediation is a source of revenue. As Canada is a mature basin, there are
multiple Canadian organizations that focus entirely or partly on wellbore leakage and
abandonment, including the Wellbore Integrity and Abandonment Society (WIA Society).

There are several barriers to the development and use of best practices to reduce
wellbore leakage. Sharing of industry knowledge, which underpins best practices, needs
to be improved to increase the understanding of what works. R&D used to develop
industry knowledge and support best practice development needs to be conducted
in a scientifically rigorous manner, instead of the typical trial and error approach, in
order to pinpoint the mechanisms that are actually responsible for improved wellbore
integrity. Such an approach will provide confidence to users, regulators and the public,
that they are effective in reducing wellbore leakage. Scientifically rigorous wellbore
integrity data should be considered as a valuable source of information to improve
wellbore regulations.

Other general recommendations not covered in the preceding chapters include: (1)
Developing regulatory consistency across the provinces; (2) Improving knowledge
amongst the oil and gas R&D community of funding options (e.g. tax credits, grants,
subsidies) to accelerate wellbore integrity R&D; (3) Increasing awareness in industry
of cost savings to be had from Doing it right the first time; (4) Training new technical
employees in reverse of the typical order to start their careers working on remediations
and abandonments, ensuring technical employees understand the costs and causes
of leakage so that they design and construct better wells; (5) Promoting multi-well
abandonment campaigns; and, (6) Promoting long-term abandonment planning with
adequate funding.

viii Technology Roadmap to Improve Wellbore Integrity – Summary Report

 Table of Contents
1. Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.1 Production of the Technology Roadmap to Improve Wellbore Integrity. . . . . . . . . . . . 5

2. Why and How do Wells Leak? A Primer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

3. Magnitude and Impacts of Wellbore Leakage . . . . . . . . . . . . . . . . . . . . . . . . 11
3.1 Background. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
3.2 Current Practices, Regulations and State of Knowledge. . . . . . . . . . . . . . . . . . . . . . . . 13
3.3 Knowledge Gaps and Recommendations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

4. Drilling and Completions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

4.1 Current Practices and Regulations in Well Operation. . . . . . . . . . . . . . . . . . . . . . . . . . 25
4.2 Problems Encountered with Current Wellbore Construction Practices. . . . . . . . . . . 27
4.3 Improving Operational Practices with Existing Technology. . . . . . . . . . . . . . . . . . . . . 32
4.4 Knowledge Gaps and Research Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . 34

5. Source Identification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
5.1 Current Practices and Regulations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
5.2 Problems with Current Operational Practices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
5.3 Improving Operational Practices with Existing Technology. . . . . . . . . . . . . . . . . . . . . 42
5.4 Knowledge Gaps and Research Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . 43

6. Remediation Strategies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
6.1 Current Practices and Regulations in Well Operation. . . . . . . . . . . . . . . . . . . . . . . . . 44
6.2 Problems with Current Operational Practices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
6.3 Improving Operational Practices with Existing Technology. . . . . . . . . . . . . . . . . . . . . 46
6.4 Knowledge Gaps and Research Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . 48

7. Abandonment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52
7.1 Current Practices and Regulations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52
7.2 Problems with Current Operational Practices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
7.3 Improving Operational Practices with Existing Technology. . . . . . . . . . . . . . . . . . . . . . 55
7.4 Knowledge Gaps and Research Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . 58

Table of Contents ix
8. Improving Industry Knowledge, Best Practices and
Regulations to Reduce Wellbore Leakage . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
8.1 Landscape of Wellbore Leakage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
8.2 Relationship Between Industry Knowledge, Best Practices and Regulations. . . . . . 64
8.3 Industry Knowledge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65
8.4 Best Practices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66
8.5 Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68
8.6 Additional Recommendations to Reduce Wellbore Leakage. . . . . . . . . . . . . . . . . . . 69

9. References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

x Technology Roadmap to Improve Wellbore Integrity – Summary Report

 List of Figures
Figure 1.1 Primary energy demand, reference and high carbon price (HCP) cases
(National Energy Board, 2017a). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Figure 2.1 Typical well casing diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Figure 2.2 Possible leakage pathways in the annulus of a hydrocarbon well.
(Based on Viswanathan et al. 2008). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Figure 3.1 Natural gas SCVF/GM well counts as of June 2, 2016 (from AER, 2016a). . . . . . . . . . . . . 14
Figure 3.2 Annual natural gas emissions for SCVF/GM (106 m3) as of June 2, 2016 with
2016 emissions extrapolated from the currently reported daily emission rate
(from AER, 2016a). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Figure 3.3 Average daily natural gas emission rate for serious SCVF/GM (m3/day)
as of June 2, 2016 (from AER, 2016a). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Figure 3.4 Average daily gas emission rate for non-serious SCVF (m3/day) as of June 2, 2016
(from AER, 2016a). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Figure 3.5 Typical pattern of vegetation impacts at the site of a naturally occurring gas seepage
(Noomen et al., 2012). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Figure 4.1 Schematic of cementing components.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Figure 4.2 Incomplete displacement of drilling mud and resulting cement and drilling
fluid channels (Watson et al., 2002) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Figure 4.3 Gas channels and gas pockets formed in set cement as a result of gas migration
(Watson et al., 2002). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Figure 4.4 Cement sheath failure and resulting cracks developed from pressure cycling
(Watson et al., 2002). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Figure 5.1 Profiles of the isotopic composition of carbon in n-alkane gases collected while
drilling a well in west-central Saskatchewan (Szatkowski et al., 2002).. . . . . . . . . . . . . . . 39
Figure 6.1 Seal Well alloy deployment tools with bismuth-tin alloy cast on the outside
of a cartridge heater (Spence and Lightbown, 2015). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
Figure 7.1 Examples of cased-hole abandonment for low-risk wells
(AER, 2016b).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

List of Figures xi
Acknowledgements
The Technology Roadmap to Improve Wellbore Integrity was a collaborative project that
involved a number of participants, as noted below, and that was jointly led by Andrew
Wigston and Dave Ryan (CanmetENERGY-Ottawa, Natural Resources Canada), and Jay
Williams, John Slofstra, Leah Davies, Chris Fuglerud, Blair Rogers, Mark Soper, Rose
McPherson, and Mike Mastalerz (Wellbore Integrity and Abandonment Society, formerly
the Canadian Society for Gas Migration). Together they defined the scope of the project;
managed the procurement of topic reports; organized the open workshop during which
the topic reports were presented; recruited members for, and managed the technical
review process; presented on the TRM at various workshops and meetings; and
managed the production of this summary report.

Thank you to Natural Resources Canada for providing all financial support for this
project through its EcoENERGY Innovation (EcoEII) Program, and Energy Innovation
Program (EIP).

We would also like to thank the authors of the topic reports, as listed below, who applied
their deep expertise and experience to produce concise yet informative documents that
highlighted issues impairing wellbore integrity and suggestions on how to improve it.
The considerable time they spent researching, writing, presenting and revising their
reports is reflected in the quality of the information and recommendations. A particular
thanks to Kirk Osadetz for his patience and graciousness in answering innumerable
questions about the impacts and magnitude of wellbore leakage.

Improving our Understanding of the Kirk Osadetz (Carbon Management Canada)

Magnitude and Impacts of Wellbore and Dr. Casey Hubert (University of Calgary)
Leakage
Improving Well Construction Christian Hamuli and Theresa Watson
Materials and Procedures to Reduce (T.L. Watson and Associates Inc.), and
Wellbore Leakage Dean Casorso and David Ewen
(Fire Creek Resources Ltd.)
Improving Wellbore Leakage Source Rose McPherson and Paul Pavlakos
Identification to Increase Remedial (Weatherford Canada)
Intervention Success
Intervention Strategies to Increase Jonathan Heseltine and Todd A. Zahacy
Wellbore Leakage Remediation (C-FER Technologies)
Success Rates
Improving Abandonment Processes Robert Walsh and Dru Heagle
(Geofirma Engineering Ltd.)
Improving Industry Knowledge, Jay Williams (Wellbore Integrity and
Best Practices and Regulations to Abandonment Society)
Reduce Wellbore Leakage

xii Technology Roadmap to Improve Wellbore Integrity – Summary Report

Thanks to Robert Walsh, Geofirma Engineering Ltd., for helping produce the
summary report.

Thanks to Saskatchewan’s Petroleum Technology Research Centre for allowing us to use

the following report, which was prepared for their CO2 User Project: Construction and
Abandonment Design for Life Cycle Wellbore Integrity, by Bisset Resources Consultants
Ltd., prepared by D.S. Belczewski.

Thanks to participants who attended the open workshop in Calgary, during which the
topic reports were presented. Your feedback helped to improve the final reports.

Thanks to Jeff Willick, Rick Peterson, Jamie Wills, Garry Gatrell, Bill Groves, and Herb
Kramer, who volunteered their time and expertise to conduct technical reviews of the
TRM topic reports. Their comments also served to improve the final reports.

Permission to reproduce figures, as attributed in the report, was graciously given by

the National Energy Board, Alberta Energy Regulator, Saskatchewan Geological Survey,
Elsevier, and the Society of Petroleum Engineers.

Acknowledgements xiii
1.
Introduction
Canada’s history of crude oil and natural gas production began in Lambton County,
southwestern Ontario, back in 1859 when James Miller Williams drilled a well
specifically looking for crude oil after having come across it in a shallow water well dug
a few years prior. This was followed by discoveries and production in nearly every other
Canadian province and territory. Between 1955 and 2017, 577,207 crude oil and natural
gas wells, for a total length of ~720,000 km, were drilled in Canada, of which 71% were
in Alberta (Canadian Association of Petroleum Producers, 2017).

Today, our combined conventional and unconventional crude oil and natural gas
resources make us a hydrocarbon energy superpower. British Petroleum’s 2017
Statistical Review of World Energy (2017) states that Canada has 10% of the world’s
proved crude oil reserves, which is the third largest, and 1.2% of the proved natural
gas reserves, which ranks us 15th; additionally, we were the fourth largest crude oil
producer and fifth largest natural gas producer in 2017.

The hydrocarbon industry in Canada is a major economic force that is active in twelve
of thirteen provinces and territories: in 2015, it contributed $19 billion to government
revenues, provided 533,000 jobs across the country in 2017 (Canadian Association of
Petroleum Producers, 2018), and made up 6.5% of our GDP in the same year (Statistics
Canada, 2018).

Hydrocarbons will continue to play an important role as the world transitions to a

less carbon-intensive energy supply. British Petroleum’s 2018 World Energy Outlook
(2018) projects that global energy demand will grow by about a third by 2040 to
544,284 petajoules. Natural gas use is expected to grow and meet about 25% of this
need; oil grows at a slower rate, plateauing near 2040, but will still provide about
25% of our needs. In Canada, the National Energy Board, in its 2017 energy supply
and demand projections, projects for its Reference Case that by 2040 we will require
14,170 petajoules, which is a 6.4% increase over 20166 (National Energy Board, 2017a;
Figure 1.1). On the supply side, it projects that crude oil production in Canada will
increase by 59% over 2016 levels by 2040, to 6.3 million barrels per day (MMb/d).
Of this, 4.5 MMb/d are from oil sands production and 2.9 MMb/d are from in situ
production. Natural gas production is also expected to increase from 2016 levels, going
from 431 million cubic metres per day to 480 million cubic metres per day as gas
prices rise.

According to the National Energy Board’s Reference Case, ~112,000 new wells are
estimated to be drilled between 2018 and 2040 to meet production demands from
conventional and tight and shale oil reservoirs (Appendix A.2.2 of National Energy
Board, 2017b), and ~29,500 to meet natural gas production (Appendix B2.1 of National
Energy Board, 2017c,). No estimates for in situ oil sands production are made.

6
The Reference Case is based on a current economic outlook, a moderate view of energy prices, and climate
and energy policies announced at the time of analysis.

1
Figure 1.1 Primary energy demand, reference and high carbon price (HCP) cases
(National Energy Board, 2017a).

The technology used to drill and construct wells has advanced considerably since 1859,
but the objectives remain the same: prevent the well from collapsing and control the
flow of fluids. A minor percentage of older wells leak because of material issues, and less
robust practices and regulations. However, even today, a small percentage of new wells
continue to experience wellbore leakage, which we define as the unintended migration of
fluids within or along the wellbore to the shallow subsurface and/or atmosphere. Natural
gas, which is mostly methane, is the predominant leakage fluid because it is buoyant and
drives to the surface; other fluids include saline water and oil. Drilling and constructing
wells remains a complex task, and is even more so today as deeper reservoirs are tapped,
kilometre-long horizontal wells are used, and wells are exposed to extreme heat and
pressure during fracking and thermal oil and gas stimulation processes.

Concerted regulatory and industrial efforts began to reduce the rate of well integrity
issues in the mid1980s (Watson and Bachu, 2009). However, wellbore leakage has
been the focus of considerable attention over the past number of years for several
reasons, and these belie the importance of continuing to strive to improve wellbore
integrity. Methane is a potent greenhouse gas (GHG), and both the federal and
provincial government(s) and industry have committed to reducing methane emissions
from the upstream oil and gas sector7. Concern about the potential for groundwater

7
For example, the recent Alberta Climate Change Advisory Panel report and Provincial Strategy
(Leach et al., 2015); the Federal Government’s proposed 40-45% reduction strategy for methane emissions
from the oil and gas sector relative to 2012 levels (Environment and Climate Change Canada, 2017); and
the consortium of the oil and gas producer members of the Oil and Gas Climate Initiative
(oilandgasclimateinitiative.com).

2 Technology Roadmap to Improve Wellbore Integrity – Summary Report

contamination from wellbore leakage has also been raised, including in the Council
of Canadian Academies Expert Panel’s report on Environmental Impacts of Shale Gas
Extraction in Canada (2014). There are also strong economic reasons to improve
wellbore integrity. Remediation8 costs and loss of production are costing the industry an
average of $150,000 per well in some circumstances, although they can be much higher
as evidenced by a well in British Columbia that cost $8 million to repair (Dusseault et
al., 2014). Remediation costs are especially burdensome for orphan well funds that are
managed by the provinces (CBC News, 2018). Leaking wells and older abandoned wells
may also inhibit or drive up the cost of developing heavy oil and bitumen reservoirs.
Such wells may not be able to tolerate the thermal stress that they are exposed to
during the use of steam-driven processes for extracting heavy oil and bitumen, and
may communicate oil to the surface, which may either preclude further development or
require expensive remediations (Munro, 2014a). Leaking wells are also being discovered
as new suburbs are built in previously rural land. Remediation costs for such cases
can be large, and activities severely disruptive to home owners, such as for the case
near Calmar, just outside of Edmonton, for which a house had to be purchased and
demolished to access the well and others relocated (Munro, 2014b).

Both the upstream oil and gas industry, and the federal and provincial government(s)
in Canada recognize the need to minimize the environmental impact of crude oil
and natural gas development while maintaining a globally competitive jurisdiction.
Improving wellbore integrity by constructing wells that are less likely to leak in the
first place, and by improving the success and reducing the cost of remediations and
abandonments, will help address both of these challenges.

Advances in well construction materials and processes, and our understanding of the
impacts and magnitude of wellbore leakage, continue to be made by industry, academia
and regulators working both independently and collaboratively. In Canada, there are a
number of organizations that are focused solely or partly on wellbore leakage, including
the Wellbore Integrity and Abandonment Society (WIAS, formerly the Canadian Society
for Gas Migration); the Western Regulators Forum, which brings together oil and gas
regulators from British Columbia, Alberta and Saskatchewan; Enform’s Drilling and
Completions Committee (DACC); and, the Canadian Standards Association (CSA).

In order to support and guide efforts to improve wellbore integrity, the federal
government’s Department of Natural Resources (NRCan) partnered with the WIA
Society to develop a Technology Roadmap to Improve Wellbore Integrity. The focus of
the technology roadmap (TRM) is on methane because it is the predominant leakage
fluid, and because of the focus on reducing GHG emissions; however, improvements to
wellbore integrity will serve to reduce leakage of all fluid types. While crude oil and
natural gas production is largely the domain of provinces and territories, working with
partners to address wellbore leakage fits within NRCan’s mandate “to enhance the
responsible development and use of Canada’s natural resources and the competitiveness of

8
Remediation refers to fixing leaks, and not cleaning up contaminated soil and groundwater, unless
otherwise indicated.

3
Canada’s natural resources products.” The WIA Society is an ideal partner: the Society’s
mission is to be the foremost community dedicated to designing, maintaining and
sustaining wellbore integrity. The society is collaborative as it is the industry group
with a membership comprised of regulators, academia, oil and gas exploration
and production companies, service and technology companies, and abandonment
consulting specialists.

Technology roadmaps are a strategic planning exercise used by industry and

government to bring together stakeholders to identify barriers to a desired future state
and formulate potential pathways to overcome them. NRCan has produced a number of
TRMs9. The focus of this TRM was to identify material- and process-related issues that
negatively impact wellbore integrity; determine which of these can be addressed using
known best practices; and suggest research and development (R&D) to address those
that can’t. The scope of the TRM covers the lifespan of a well, from wellbore design and
construction, leakage identification and remediation, and ultimately, abandonment.
Since there are a number of operators with very few wellbore integrity problems, the
TRM also focussed on determining how the sector can better gather, share and promote
the use of best practices.

Lastly, the TRM focussed on the issue of wellbore leakage magnitude and impacts, both
environmental and human health, including what knowledge gaps exist and how to
address them. While industry should continue to strive to construct wells that are less
likely to leak, it is also reasonable to pose the contentious question of: should all wells
with small leaks have to be remediated? Being cognizant of the reality that funds spent
improving environmental performance don’t always provide an economic return, that
Canada’s oil and gas exploration and production companies compete for investment in a
global environment, and that orphan well funds represent a significant cost to the public,
it is imperative to focus on practices that will provide the most cost-effective beneficial
environmental impacts.
The subject of wellbore integrity is large and diverse, incorporating a number of
engineering and scientific disciplines. The intent of the wellbore leakage TRM was not
to create an exhaustive document, but rather to provide a high-level assessment of
the issues and potential solutions. It is intended to foment and facilitate more detailed
discussions on developing solutions, and to guide R&D so that it is focussed on solutions
that will have the largest positive economic and environmental impact. A brief summary
of the TRM process follows.

Chapter 2 provides a primer on how wells are drilled and how they develop leaks.
Chapter 3 covers the magnitude and impacts of wellbore leakage. Chapters 4–7 cover
wellbore construction, leakage identification, wellbore remediation, and abandonment.
The last chapter discusses gathering, sharing, and promoting the use of best practices.

9
For full list visit: http://www.nrcan.gc.ca/energy/offices-labs/canmet/5765.

4 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 While the focus of this TRM is on oil and gas wells, the findings and recommendations
may be applicable to other industries that use wells, such as CO2 storage, nuclear and
other waste disposal, and geothermal energy. Conversely, some best practices from some
of these industries may improve wellbore integrity in the oil and gas industry. Some
authors knowledgeable of these other fields have captured this information in their
reports. Sharing information and practices both within and with other industries that
use wells will serve to improve wellbore integrity for all.

1.1 Production of the Technology Roadmap to Improve

Wellbore Integrity
The vast topic of wellbore leakage was broken down into six smaller topics to facilitate
the production of the TRM:
◗◗ What are the frequency, magnitude and effects of wellbore leakage?
◗◗ How can wells be better constructed to avoid or minimize leakage?
◗◗ How can leaks be better detected?
◗◗ How can the success rate of remediations be improved and costs be reduced?
◗◗ How can abandonments be improved to decrease the frequency and magnitude
of leaks?
◗◗ How can the gathering, sharing and implementation of industry best practices
be improved?

Reports were commissioned for each topic. Authors were from industry and academia.
For each report, a brief summary of current knowledge and/or practices and regulations
was presented, followed by a discussion of issues that adversely impact wellbore
performance. Each report concluded with recommendations on how they can be
addressed using current knowledge and/or practices, and how remaining knowledge
and technology gaps may be addressed with R&D. Draft reports were presented at an
open workshop that was hosted by the Wellbore Integrity and Abandonment Society
in Calgary in 2016, and which was attended by more than 80 people from industry,
regulatory bodies and academia. Draft reports underwent a rigorous review process. In
addition to feedback received at the workshop, each draft report was also reviewed by
a volunteer-based Technical Advisory Committee that consisted of specialists in each
subject area. A final third-party review of each revised report was contracted.

It needs to be noted that wellbore integrity is not a settled science... hence the need for a
TRM. While much information about wellbore integrity is published, and organizations
like the WIAS and others strive to capture and share information on what does and
doesn’t work, there are still uncertainties and differences of opinion about the efficacy
of materials and practices, and where they are or aren’t effective. Some of the answers
may be known but are kept in-house and used as a competitive business advantage. For
others, the studies just haven’t been done yet, or the results may be in question because
the study wasn’t done or verified by an independent party.

5
The authors of the topic reports have attempted to deal with this issue by providing a
balanced approach in which they emphasized or reported only data and information
that was substantiated. However, contrary opinions supported by less published and/
or anecdotal evidence is also reported where it was considered reasonable. Indeed,
reasonable contrary opinions are valuable in that they highlight uncertainties that may
warrant further investigation.

To provide a more user-friendly document, the topic reports have been summarized into
this Technology Roadmap to Reduce Wellbore Leakage summary report.

While the subject of wellbore integrity was broken into five technical topics, and one
on sharing information, there are not firm boundaries between these subjects. Thus, it
is inevitable that there is overlap between the reports. In writing the summary report,
the bulk of information on a given topic came from its respective report; however,
information was pulled from other reports where appropriate. The individual reports
are publicly available from NRCan’s TRM website10 and those interested in more detail
should consult them.

10
The topic-specific reports can be accessed through the Wellbore Integrity TRM page, which is found on
NRCan’s TRM webpage at: http://www.nrcan.gc.ca/energy/offices-labs/canmet/5765

6 Technology Roadmap to Improve Wellbore Integrity – Summary Report

2. Why and How do Wells Leak? A Primer
This chapter provides a primer on how wells are constructed and how leaks develop.
These topics are covered in much more detail in Chapters 4–7. However, this overview
will aid in understanding both these chapters and the proceeding chapter on the
magnitude and impacts of wellbore leakage (Chapter 3).

When wells are drilled through fluid-bearing formations, they create a new pathway,
allowing these fluids, particularly natural gas, which is more buoyant than saline water
or crude oil, to flow vertically across previously impervious formations. Hydrocarbon
wells are constructed to control and collect this flow, while preventing vertical crossflow
between formations, protecting freshwater aquifers and avoiding atmospheric emissions
of gas. For a minority of wells, failures occur during some stage of the well’s life, allowing
fluids to migrate outside of the casing.

To understand the causes and mechanism of wellbore leakage in hydrocarbon wells, it is

important to review how they are constructed. Well construction consists in sequentially
drilling a hole, setting casing and cementing it in place for successive planned boreholes.
Cement is placed in the annulus—the space between the casing and the wall of the
borehole, or between the casing and the previous casing in a sequence of nested
casings. Problems that contribute to wellbore leakage may occur at any of these phases.
The number of casings required is determined based on the total depth, anticipated
formation pressures, formation stability (or compatibility with drilling fluids) and cost.
As illustrated in Figure 2.1, a typical succession of hole and casing size for a deep well
consists of a conductor, surface, intermediate and production casing. For shallower
wells, the number of casing stages is reduced.

Fundamentally, wellbore leakage into aquifers or the atmosphere requires a source,

a pathway and a driving force. The source is typically a sufficiently permeable
hydrocarbon-bearing unit, while the driving force requirement is supplied by buoyancy
and reservoir pressure. Natural gas is the principle leakage fluid because it has a much
lower density, and thus greater buoyancy force, than crude oil or saline water. There
are numerous mechanisms and pathways that may contribute to the wellbore leakage
problem, but it is most often attributed to the failure of cement sheaths (annulus
cement) or cement plugs (in abandoned wells) to provide isolation. Failure of the
cement sheath to provide zonal isolation can result in annular pressure or flow. Common
names for this in Canada include Surface Casing Vent Flow (SCVF), if within the surface
casing annulus, or Gas Migration (GM), if outside of the outer casing string. In other
jurisdictions, the general term Sustained Casing Pressure (SCP) or Annular Pressure
Buildup (APB) are often used, which may refer to any annulus. In SCVF, natural gas
escapes directly from the well to the atmosphere via the surface casing vent (SCV). In
Western Canada, SCVs must be left open. This is in contrast to jurisdictions in the United
States where they must be kept closed. However, closing the SCV allows gas pressure
to build up in the annulus; the pressure can continue to build until it is greater than the
pressure in the surrounding shallow aquifer and gas flows into it.

7
In GM, since the natural gas is not confined within the outer casing string, it travels up
the cracks or gaps in the cement, sealing the annular space between the borehole and
outer casing string, and eventually into the surrounding rock, soil and groundwater in
the shallow subsurface. From there it may migrate to the atmosphere.

When SCVF/GM events are identified, depending on the leakage characteristics and the
operational or health/safety/environment (HSE) risks, investigation and remediation may
be required. Remediation must be conducted prior to permanent well abandonment.

Figure 2.1 Typical well casing diagram.

Wellbore integrity can be compromised by defective well construction, or as a result of

chemical and mechanical stresses (pressure, temperature) that damage the well during
the operational or abandonment phases (Carrol, 2016). During drilling and cementing,
problems that may lead to poor cement sheath and compromised casing integrity include
thread leaks between casing joints, fluid losses/low cement top, poor cement quality,
development of mud or gas channels in the cement, cement shrinkage, inadequate
filter cake removal, formation damage during drilling, or fractured cement (Carrol,
2016). These concerns can generally be addressed with improved drilling and cementing
practices during the well construction phase.

8 Technology Roadmap to Improve Wellbore Integrity – Summary Report

Leakage can also result from various events over the life of the well, often associated
with mechanical disturbances or pressure and temperature changes during production,
injection, stimulation or change out of wellbore fluids. These circumstances may cause
cement sheath cracking or cement debonding and micro-annulus formation. During
the operational (post-completion) phase, defects in well construction may develop into
problems such as dissolution-induced cement defects, formation of microannuli, chemical
degradation of cement, development of fractures in the annulus cement, and casing and
tubular corrosion. These types of failure may be addressed through management of
wellbore conditions (e.g. temperature and pressure) and the chemical and mechanical
properties of the cement (e.g. Young’s modulus, and tensile, shear and bond strengths)
(Watson et al., 2002). Potential leakage pathways are illustrated in Figure 2.2.

Natural gas leaking through a wellbore may originate from the target reservoir depth,
or most often from one or more thin, shallow- to intermediate-depth, non-commercial
natural gas-bearing formations. Gases from these sources may be either of biogenic or
thermogenic origin, or a combination of both (Dusseault et al., 2014). Isotopic analysis of
leaking hydrocarbons in the Western Canadian Sedimentary Basin showed that leaks are
typically from a shallow to intermediate source rather than the target reservoir (Rich et
al., 1995; Rowe and Muehlenbachs, 1999; Slater, 2010; Tilley and Muehlenbachs, 2011).
This agrees with the findings of Hammond (2016) where shallower but unproductive
natural gas-bearing zones were identified as the source of methane in groundwater.

Producing zones are often sealed with higher quality cement in a wellbore (Watson and
Bachu, 2009; Dusseault and Jackson, 2014). The cement adjacent to the reservoirs is
generally emplaced under high hydrostatic pressure (before setting), exceeding pore
pressures in the surrounding bedrock. This may promote loss of water to adjacent
formations, resulting in denser cement slurry and an improved seal (Dusseault and
Jackson, 2014), and inhibit gas influx during setting (at least initially). The opposite
is true of intermediate and shallow depth intervals, which may be sealed with lower
quality lead cement containing filler additives, which do not always generate good
primary seals (Watson and Bachu, 2008; Dusseault and Jackson, 2014). However,
this is not the case for thermal wells or many unconventional wells (Zahacy, personal
communication, 2018). Natural gas in the intermediate or shallow formations can seep
into the annulus surrounding the casing because of the poor seal the cement provides
between the borehole wall and the casing. Once in the annular space, it may migrate
upwards through pathways in the cement seal and potentially through permeable
formations or small fractures in formations adjacent to the wellbore.

9
Figure 2.2 Possible leakage pathways in the annulus of a hydrocarbon well.
(Based on Viswanathan et al. 2008).

10 Technology Roadmap to Improve Wellbore Integrity – Summary Report

3. Magnitude and Impacts of Wellbore Leakage
The objective of resource development, including hydrocarbon production, is to create
the conditions by which a resource can be profitably developed while minimizing the
environmental, human health and safety impacts to an acceptable degree. Within the
upstream oil and gas sector there are a number of sources of potential impact. The
impact depends on the source properties (e.g. what is the pollutant? How much and
where is it released to?), and the receptors (e.g. humans, vegetation, atmosphere)
and pathways to them (e.g. to atmosphere, groundwater). When devising acceptable
impact standards and mitigation strategies, it is important to take a big picture view
that considers other sources, both within and outside an industrial sector, that emit
the same pollutant and that have similar receptors and pathways. In this way, the
environment, and human health and safety will be protected in the most cost-effective
and impactful manner.
This chapter discusses the magnitude and impacts of wellbore leakage; it is a summary
of the Improving Our Understanding of the Magnitude and Impacts of Wellbore Leakage
report written by Kirk Osadetz (Carbon Management Canada) and Dr. Casey Hubert
(University of Calgary). It focuses on methane because that is the principal wellbore
leakage substance as described in Chapter 1. A brief background on the origin of
methane and migration pathways is discussed, followed by a summary of the current
state of knowledge about the magnitude and impacts of wellbore leakage. The chapter
closes with recommendations to address knowledge gaps.

3.1 Background
Crude oil and natural gas consist of hydrocarbon compounds, the simplest of
which is methane (CH4). Hydrocarbon compounds can result from both natural and
anthropogenic processes at the earth’s surface and below it, at a wide range of depths,
and from a variety of sources (e.g. cow belching, natural hydrocarbon seeps, wellbores
with leakage).

Organic and inorganic materials accumulate over geologic time spans. As this material
is progressively buried, it is exposed to increasing heat and pressure; non-burial-
related tectonic processes may also play a role. Crude oil and natural gas are generated,
provided the precursor organic material is exposed to the appropriate temperature
and pressure for a suitable period of time. This process is referred to as thermogenic
generation (Hunt, 1979). Crude oil and natural gas are more buoyant than water,
especially saline water, and have a natural tendency to migrate upwards through porous
rock, open fractures, and by diffusion. They continue to migrate until they come up
against geological features such as impermeable caprocks, below which they accumulate
as oil and gas deposits. Otherwise, they continue to migrate to the surface (Tissot and
Welte, 1984). Leaky hydrocarbon wells are also conduits for uncontrolled migration of
crude oil, and more commonly, natural gas.

11
Closer to the earth’s surface, and under anaerobic conditions below the surface of the
water table, biogenic processes can produce methane (e.g. Cheung and Mayer, 2009),
and possibly heavier hydrocarbons. Near the surface of the water table, and above it in
the unsaturated zone, methane can be converted to CO2 by methanotrophic bacteria.

The molecular composition of natural gas and the isotopic ratio of its carbon
constituents are indicative of the process by which it was generated, and thus, the depth
at which it was formed.

There are two types of biogenic methane production. Primary production results from
the microbial degradation of organic material from both natural and anthropogenic
accumulations. Secondary production results from the anaerobic microbial alteration
of thermogenic crude oil (Jones et al., 2008; Milkov, 2011). Secondary biogenic gas
is predominantly methane (Milkov, 2011), but also commonly contains ethane and
heavier hydrocarbon compounds (e.g. Huang, 2015; Osadetz et al., 1994). It is this type
of process that produced the heavy oil and bitumen that are abundant in Alberta, the
largest example being the Athabasca oil sands (Huang, 2015; Ibatullin, 2009).

In the Western Canada Sedimentary Basin (WCSB), methane is a ubiquitous component

of groundwater. Methane is also produced in near-surface environments, such as
wetlands (e.g. Conrad, 1996), and in landfills (e.g. Themelis and Ulloa, 2007). Methane
in the shallow subsurface can migrate directly to the atmosphere if its migration is not
constrained by a caprock. Other migration pathways include natural fractures and leaky
wells, both petroleum and groundwater types. There is significant evidence for much
natural vertical migration of natural gas, on geological time scales, into the atmosphere
from the WCSB (e.g. Huang, 2015; Humez et al., 2016a, b, c; Mayer et al., 2015). Other
migration pathways, both lateral and vertical, occur within the subsurface, giving rise to
petroleum accumulations and their biodegraded residues (Creaney et al., 1994).

On the surface of the earth, methane is produced from natural sources and processes,
such as wildlife, termites, wildfires, and ocean dynamics (Etiope et al., 2008), and
anthropogenic sources and processes, such as animal husbandry, petroleum production
and refining, transport, and other industrial processes.

Wellbore leakage from hydrocarbon wells has been implicated in the contamination
of groundwater in a small percentage of cases in Canada (e.g. Szatkowski et al., 2002;
Tilley and Meuhlenbachs, 2012). Considering the abovementioned variety of methane
sources (thermogenic, primary and secondary biogenic), and the complicated pattern
of migration pathways, it can be difficult to identify the source and pathway of
contamination. While compositional characteristics of a gas may indicate the potential
for contamination from leaky hydrocarbon wells, it would be desirable to conclusively
demonstrate contamination using chemical tracers and migration models, especially
since it is possible that the pumping of water from some water wells may be the process
that induces the flow of methane into the well water (Moore, 2012).

In Alberta, significant work characterizing the composition and isotopic characteristics

of SCVF and GM gases has been performed (Rowe and Muehlenbachs, 1999;
Muehlenbachs, 2010). However, most of the details are not readily publicly available.
SCVF and GM gas can have a variety or mixture of origins. About three quarters of

12 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 SCVF gas enters the well annulus from the geological successions above the production
zone. The remaining quarter of SCVF gases originates from the producing zone. This
ratio of source interval occurrence is similar for both vertical and horizontal wells
(Muehlenbachs, 2012). Although there are fewer data from GM sites (Rowe and
Muehlenbachs, 1999; Bachu, 2017), these too appear to originate predominantly from
the geological successions above the producing zone.

However, the attribution of source intervals for gas samples collected from soil and
groundwater samples (i.e. not collected directly from a hydrocarbon well or immediately
adjacent to it) can be difficult, especially when they do not originate from the producing
interval, as generally is the case (Muehlenbachs, 2012). Tilley and Muehlenbachs
(2012, their Figure 2) illustrated that there is a considerable range of gas composition
and isotopes in uncontaminated groundwaters. These challenges and uncertainties
regarding migration pathways are discussed in more detail in the next section.

3.2 Current Practices, Regulations and State of Knowledge

3.2.1 Testing requirements
Throughout Canada, wells must be tested or monitored for SCVF or GM after they are
drilled. New Brunswick and British Columbia require annual monitoring of all wells with
SCVF and GM.

The Alberta Energy Regulator (AER) regulates the petroleum industry, including
wellbore construction, testing, remediation and abandonment in Alberta. It requires
new wells to be tested for SCVF within 90 days of well construction and prior to
abandonment (AER, 2003). Gas migration testing is required in areas where GM is
common or where the impacts on vegetation, groundwater or safety are obvious.
Subsequent testing, monitoring and potentially remediation requirements depend on
the results of the initial test. A surface casing vent test (SCVT) consists of a stringent
bubble test. If the bubble test is positive, then flow rate and pressure are measured,
generally with a positive displacement meter and digital pressure recorder. Emissions
are reported in cubic metres per day or fractions thereof and are extrapolated to provide
daily rates and annual emission volumes. Monitoring for GM and estimating emission
rates is more difficult than SCVF because the flow is dispersed in the soil. Soil gas probes
or other similar instruments are used to detect the presence of natural gas. The results
are reported in parts per million or as a percentage of the lower explosive limit of
methane within a sample.
Surface casing vent flows are classified as serious, considered non-serious, or non-
serious. There are multiple criteria that may classify a leak as serious, including vent
flow rate greater than 300 m3/day; the presence of any of crude oil, saline water or
H2S in the vent flow; where the stabilized build-up pressure is over 9.8 kPa/m times
the surface casing setting depth; or if the SCVF is caused by a casing or wellhead
failure. Wells that are not cemented over the groundwater protection zone may be
“considered non-serious” if there are no water wells within one kilometre at depths
below the surface casing; otherwise they are serious. Serious wells must be immediately

13
 remediated to at least a non-serious condition. Non-serious wells must be monitored
annually for five years or until the leak ceases. Non-serious wells that become serious
must be immediately reported and remediated. Non-serious wells persisting past the
five-year monitoring period must be remediated at the time of abandonment. Leaky
wells and rates are systematically reported to the AER. Wells with GM are considered
serious if the flow creates a safety hazard at the site.

3.2.2 Number of leaky wells and emissions

Alberta began monitoring for SCVF and GM as early as 1910 (Watson and Bachu, 2007).
Since that time, around 25,000 wells have reported either SCVF or GM at some point in
their history. This represents about 5% of the almost 440,000 wells drilled in Alberta.
Among leaking wells, 89% reported an SCVF (5.8% of all wells); 10% reported GM
(0.66% of all wells), and 1% reported both (0.6% of all wells). By well type, the most
prone to leakage are inactive wells: 10.3% of all inactive wells have reported leakage.
Abandoned wells are next at 7.0% (Boyer, 2016). As of April 2018, there were around
72,400 inactive wells and 184,400 abandoned wells in Alberta (AER, 2018). In 2016,
10,326 wells were leaking (Figure 3.1). Non-serious wells composed 96.7% (9,989) of
these (AER, 2016a).

Figure 3.1 Natural gas SCVF/GM well counts as of June 2, 2016 (from AER, 2016a).

Figure 3.2 shows AER data for annual natural gas emissions for serious and non-serious
wells from 2000 to 2016 (extrapolated from data up to June 2, 2016). Figure 3.3 and
Figure 3.4 show, respectively, average daily natural gas emission rates for serious and
non-serious wells, considering both SCVF and GM. Surface casing vent flow and GM data
prior to 2000 is discussed by Watson and Bachu (2007).

The composition of gas from both SCVF and GM is not reported publicly, but based on
unpublished sources (Muehlenbachs, 2010), the AER estimates that SCVF is 95% to 99%
methane. Among non-serious wells, 31% report a gas rate that is too small to measure,
and thus a default value of 1 m3/day is used. These uncertainties and limitations
introduce some minor uncertainty into calculating annual and daily methane emission
rates, which are discussed further in the Knowledge Gaps section. However, given that
instances of GM are much less common than SCVF, it is considered reasonable to equate

14 Technology Roadmap to Improve Wellbore Integrity – Summary Report

“gas emissions” with “methane emissions.” While the 2016 average daily emission rate
for non-serious wells is ~13 m3/day, the median rate is most likely less than this, as can
be seen from the distribution of leakage rates for non-serious wells in Alberta between
2008 to 2013 as presented in Dusseault et al. (2014; their Figure 2.4) and for Alberta
and B.C. in Nowamooz et al. (2015; their Figure 7). As reported in Dusseault et al.
(2014), the average SCVF rate in B.C. is 9.6 m3/day, while the median rate was estimated
by the BC Oil and Gas Commission to be just 0.5 m3/day. For comparison: a cow emits
between 0.25 – 0.50 m3/day of methane (Johnson and Johnson, 1995); a typical oil-field
pneumatic device operating under field conditions near Fort. St. John in northeastern
B.C. emits ~0.2 m3/hr of fuel gas (The Prasino Group, 2013), which, assuming this is only
methane, equates to 4.8 m3/day.

Beginning in the mid-1980s, concerted regulatory and industry efforts began to reduce
the rate of well integrity issues (Watson and Bachu, 2009). As can be seen in Figure
3.2, total wellbore leakage emissions have been declining since 2008 and were 84.4
x 106 m3 of methane (~1.56 MtCO2e) in 2016—which represents a reduction of 19%
from the 2008 peak. This is attributable to a reduction in emissions from serious wells:
Figure 3.1 and Figure 3.3 show, respectively, that both the number and average daily
emission rate for serious wells have been declining since 2008.

For non-serious wells, their total annual emissions have increased slightly year over
year (Figure 3.2). This is in spite of a reduction in their average daily gas emission
rate (Figure 3.4). Thus, the increase in total annual emissions is accounted for by the
annually increasing number of wells and fewer abandonments (Figure 3.1). The decline
in average daily emission rate is partly attributable to improved well construction
practices, particularly cementing casing to surface (Boyer, 2016).

Environment and Climate Change Canada (ECCC) uses an estimation method to calculate
SCVF and GM emissions (ECCC, 2017c). For 2015, it estimated Canada-wide wellbore
leakage emissions to be 7.2 MtCO2e, and 5.0 MtCO2e for Alberta11 (A. Osman, personal
communication, July 24, 2018)12. There is obviously a significant difference between
Alberta’s well-based value of 1.56 MtCO2e and ECCC’s estimate of 5.0 MtCO2e. ECCC
reports both that there is a level of uncertainty in its method and that it is working on a
new methodology that incorporates new data supplied by the AER (ECCC, 2017b). The
discrepancy is discussed more in the Impacts and Magnitude report.

11
2016 results from ECCC’s National Inventory Report were not available at the time of writing, but wellbore
leakage emissions were provided by ECCC (A. Osman, personal communication, July 24, 2018) and are similar:
Alberta’s were 4.8 MtCO2e and Canada’s as a whole were 7.1 MtCO2e.
12
GHG emissions are reported to the Intergovernmental Panel on Climate Change (IPCC) according to a Common
Reporting Format. Surface casing vent flow and gas migration from both crude oil (of all types) and natural gas
wells are reported in the Energy category > Fugitive Emissions from Fuels sub-category > Oil and Natural Gas >
Natural Gas > Other – Accidents and Equipment Failures. The CRF code is 1.B.2.b.6.1. (see Table A3-13 in in ECCC’s
2017 National Inventory Report 1990-2015, Part 2). However, while ECCC calculates emissions specifically
for SCVF and GM, they are not reported individually in Canada’s National Inventory Reports. Instead, they are
combined with other fugitive emission sources within the Natural Gas category (i.e. 1.B.2.b), such as natural gas
production, processing, transmission, storage and distribution (i.e. CRF codes 1.B.2.b.2 through 1.B.2.b.5; see
Table A3-13). Table 3-9 in the 2017 National Inventory Report, Part 1, lists these combined emissions under
1.B.2.b. Natural Gas.

15
For comparison, 7.2 MtCO2e represents 4.3% of total upstream oil and gas sector
GHG emissions of 167 MtCO2e (ECCC, 2017c). Wellbore leakage emissions represent
13% of all fugitive emissions from the oil and natural gas sector, including upstream,
downstream and oil sands/bitumen (ECCC, 2017c).

Figure 3.2 Annual natural gas emissions for SCVF/GM (106 m3) as of June 2, 2016 with 2016
emissions extrapolated from the currently reported daily emission rate (from AER, 2016a).

Figure 3.3 Average daily natural gas emission rate for serious SCVF/GM (m3/day) as of
June 2, 2016 (from AER, 2016a).

16 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 Figure 3.4 Average daily gas emission rate for non-serious SCVF (m3/day) as of June 2, 2016
(from AER, 2016a).

3.2.3 Impacts
The impacts of methane are agnostic of the source—natural or anthropogenic. This
section discusses the impacts of methane on the environment and human health, with
specific reference to impacts from wellbore leakage where possible.

Climate: Methane is a potent GHG with a warming potential 28 times that of CO2
when considered over a 100year period (Intergovernmental Panel on Climate Change,
2013). Wellbore leakage, particularly SCVF, contributes to anthropogenic emissions of
methane, and as described in Chapter 1, both the federal and provincial government(s)
have committed to reducing methane emissions from the petroleum sector. Their
contribution relative to other sources of methane is discussed in the proceeding section
on recommendations.

Air quality and safety: There is no direct link to human or animal health for non-
safety-related exposure to methane itself (Jackson et al., 2011). The reaction of methane
with NOx species, primarily in urban settings, contributes to the concentration of
tropospheric ozone, which is a health hazard (West et al., 2006). However, in urban
areas, natural gas leakage tends to be related to distribution networks (Hamper, 2006;
Jackson et al., 2014). Methane is a flammable and potentially explosive gas (Harder et al.,
1965). However, the risks of this from wellbore leakage are considered remote because
existing regulations “set back” petroleum facilities from inhabited structures.

Potable groundwater quality: The Council of Canadian Academies 2014 study on

shale gas extraction identified wellbore leakage as a potential concern for impacting
groundwater quality and recommended that it be studied. Methane itself in groundwater
is not a hazard to human health. There is no Canadian or World Health Organization
standard for methane in drinking water (Health Canada, 2017; World Health
Organization, 2011), and methane contamination of groundwater is not a priority topic
for the International Association of Medical Geologists (Bunnell et al., 2007; Centeno et
al., 2016). However, the microbial oxidation of methane produces CO2, which can change

17
groundwater chemistry and result in the release of metals and other substances that
alter groundwater quality and potability (e.g. Kelly et al., 1985).These effects can be
profound and extensive over large areas, as observed in association with a spectacular
gas blow-out accident in an uncased hydrocarbon well in the United States (Kelly et al.,
1985). However, it must be emphasized that well construction practices in Canada would
make an accident of this magnitude extremely unlikely in Canada.

As described in the Background section, methane is a ubiquitous substance in many

potable groundwater aquifers and soils, especially so in sedimentary basins with
hydrocarbon and coal deposits, such as the WCSB. Its production and migration to the
shallow subsurface may be natural and/or anthropogenic. Implicit acknowledgement of
the widespread presence of methane in potable groundwater is indicated by Agriculture
Alberta, which provided a diagram for a methane separator for groundwater wells
(Alberta Agriculture and Forestry, 2017).

As described by Tilley and Meuhlenbachs (2012) and Meuhlenbachs (2012), there may
be a considerable range of gas composition and isotopic signatures in potable water
gas samples that may result from multiple sources and processes, even prior to oil and
gas development, and this makes attribution of the source of such gases difficult to
determine. In light of these points and for the purposes of this technology roadmap, we
consider contamination of a groundwater protection zone to be the anthropogenically
facilitated transport of a substance into a groundwater aquifer resulting from wellbore
leakage. Methane is the substance of most concern, because it migrates easiest and is by
far the most common component of SCVF and GM leakage.

In reality, any case of GM is essentially contamination of the groundwater protection

zone. However, GM effects are commonly localized in the immediate vicinity of the
well and often indicated by limited crop or vegetation stress (Godwin et al., 1990; Van
Stempvoort et al., 2005; Vidic et al., 2013). However, only a few cases of GM document
the impairment of drinking water protection zone as discussed below.

In Alberta and Saskatchewan, the limited studies on alleged groundwater contamination

resulting from wellbore leakage include Godwin et al. (1990), Szatkowski et al. (2002),
Van Stempvoort et al. (2005), and Tilley and Meuhlenbachs (2012). In some of these
studies, the presence of thermogenic gases in the groundwater protection zone was
attributed to wellbore leakage. It is likely that wellbore leakage was the source of all or
part of the thermogenic gas detected in these studies; however, these studies did not
examine or preclude the possibility that part of the contamination may be associated
with the production of the water wells themselves. Pumping down the column of water
in a water well reduces the hydrostatic pressure, which may enable methane to enter
the well from a local source such as one of the Cretaceous coal zones common in the
WCSB. Additional tools such as geochemical tracer studies, like those employed by
Darrah et al. (2014) and physical migration models (e.g. Praagman and Rambags, 2008),
were not used in any of these studies. In the future, it would be useful to perform more
comprehensive studies of potential contamination cases.

18 Technology Roadmap to Improve Wellbore Integrity – Summary Report

Heavier hydrocarbons like ethane are attributed currently, and commonly, to
thermogenic petroleum systems only (e.g. Brandt et al., 2014), and used as a tool to
support claims of wellbore and petroleum facility sources of methane emissions and
leakage. However, heavier hydrocarbon compounds occur commonly in “biogenic”
gases elsewhere (Zhang and Shuai, 2015), particularly secondary biogenic gases.
The possibility that these heavier hydrocarbons might have biogenic sources, or
that they might occur ubiquitously in secondary biogenic gases as a by-product of
the biodegradation of crude oils should also be considered (Huang, 2015; Osadetz
et al., 2018).

In other jurisdictions, GM facilitated by shallow fractures has been observed and

commented upon. However, the frequency of fractures increases towards the bedrock
surface and, except for the previously noted cases of contamination, GM issues in the
WCSB appear to have local impacts immediately adjacent to the wellbore.

Considering that in Alberta only 0.66% of wells developed GM issues, the question
is: has wellbore leakage resulted in pervasive contamination of the groundwater
protection zone? It is interesting to note that in Alberta, water well owners expressed
high levels of general concern about the potential for methane in water wells, but rated
methane as their most infrequent water quality issue with their own domestic wells
(Summers, 2010).

Considering the relatively small number of documented cases of aquifer contamination

and the substantial but still infrequent number of cases of GM into the GW protection
zone, the risk of groundwater contamination from GM is still considered small given
the number of combined cases of groundwater protection zone contamination and GM
relative to the nearly 530,000 hydrocarbon wells drilled in Western Canada.

Vegetation: Vegetation can exhibit impacts as a result of methane migration into the
groundwater protection and vadose zones of soil. In the vadose zone, plant health
may be negatively impacted by methane at high concentrations, as can be seen by
zones of dead or damaged vegetation surrounding wells with GM and also at natural
seeps (Figure 3.5). The effects of anthropogenic and natural methane seepage are
indistinguishable (Noomen et al. 2012). The impacts are rarely due to methane asphyxia,
but more commonly due to CO2-induced stress or asphyxia resulting from the microbial
oxidation of methane (Hoeks, 1972; Davis, 1977; Drew, 1991). There have been several
attempts to determine correlations between GM flux and the plant health impacts (Smith
et al., 2005; Steven et al., 2006). However, no quantitative recommendations related to
GM rate were developed due to the conclusion that GM impacts are complicated by many
independent factors including, but not limited to, soil composition and characteristics,
meteorological conditions, the microbial flora, and the plant species (Smith et al.,
2005; Steven et al., 2006). Vegetation may also be impacted as a result of changes to
groundwater quality arising from reactions occurring in an aquifer contaminated by
methane, as described previously. These are reflected by crop or vegetation impacts
near leaking wells, which sometimes result in plant mortality (Godwin et al., 1990; Van
Stempvoort et al., 2005; and Vidic et al., 2013).

19
 Figure 3.5 Typical pattern of vegetation impacts at the site of a naturally occurring gas
seepage from Noomen et al. (2012, their Figure 4). In the centre of the seep, vegetation is
either absent or attenuated. This is surrounded by a halo of “green vegetation” that gives way
to “background” vegetation. The affected area has a radius of about 30 m; a person is shown
scale on the left.

3.3 Knowledge Gaps and Recommendations

3.3.1 How many wells are actually leaking and how much?
There are a number of reasons that the AER’s database may either overestimate or
underestimate the number of leaking wells and their emissions. During remediation
of serious wells, about half report “die out” as the final repair action, but owners
don’t immediately update the reduced flow rate to the AER until the well is deemed
non-serious (some of these cases are likely due to wellhead issues and not downhole
leakage). Some, and possibly many, non-serious wells die out during or subsequent to
the five-year monitoring period, but operators don’t update the database for cost or
administrative reasons, and the well is thus assumed by the regulator to emit at the
previously reported rate. Some industrial sources reported that as many as 20% of
their older non-serious wells ceased leaking without any remediation. In contrast, wells
that tested with no leakage at rig release, or which were drilled prior to the testing
requirement, may be leaking now, as evidenced by the fact that such leaks are discovered
at the time of abandonment. Among non-serious wells, 31% report a gas rate that is too
small to measure, which means that the default value of 1 m3/day is used even though
flow rates as low as ~0.1 m3/day can be obtained (AER, 2016a).

Additionally, some SCVF rates are observed to be intermittent, variable, and sometimes
reducing or disappearing over time (Watson, 2007); although this might also mean that
emissions at a well are under-estimated. Thus, SCVF is sometimes not observable within
the testing period (Alberta Innovates—Technology Futures, 2015). Watson (2007) found
that some wells develop them later in life. Dusseault and Jackson (2014) postulate that
they may develop in previously competent cement because of stresses imposed during
wellbore integrity tests. Gas migration incidents occur much less frequently than SCVF;

20 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 however, quantifying leakage from GM is much more difficult. Thus, there appears to be
sufficient motivation to re-examine the methane emissions database.

Recommendations to address knowledge gap: In order to better constrain the

number of hydrocarbon wells that have leakage, and the magnitude of their emissions,
the following recommendations are proposed:

Conduct a census of non-serious wells: This type of census isn’t required for jurisdictions
like British Columbia and New Brunswick, which require annual monitoring of all wells.
However, for Alberta and similar jurisdictions, it would resolve many of the knowledge
gaps noted above, and potentially reduce (or increase) both the number of leaky wells
and emissions that are on the book. It could also help inform a selective remediation
program that targets the currently largest leaking inactive wells that are unlikely to
ever be returned to production, as well as inform other more cost-effective methane
reduction options. Lastly, this type of data is required to better understand what made
a well leak in the first place (including whether the leak is the result of casing failure,
which is easier and less expensive to fix), and thus develop tools and regulations to
address the underlying issue.

Determine temporal variations in well emissions: It is known that emissions from natural
seeps fluctuate in response to environmental conditions. These same conditions may
impact emissions from both SCVF and GM. Investigating SCVF and GM over a significant
duration and under the various operating conditions a well may be exposed to would
improve the accuracy of emissions estimates and inform monitoring requirements.
Including a component to use and compare various GM monitoring methods would also
help inform emissions estimates and monitoring practices. It would also help determine
what impact near-surface environmental properties, such as seasonal water table height
and frost level, have on GM emissions, and could inform well construction practices.

Compare improved emissions data against “top-down” emissions data: Data from both
of the above recommendations could be used to compare against “top-down surveys”
(i.e. atmospheric total hydrocarbon content surveys conducted by planes and/
or drones), which commonly detect methane concentrations that are greater than
“bottom-up” surveys based on equipment and process inventories (e.g. Johnson et al.,
2017). This would help determine the source of discrepancies and inform methane
reduction strategies.

3.3.2 When is remediating non-serious wells prior to abandonment a cost-

effective way for the petroleum sector to reduce methane-related
GHG emissions to the atmosphere?
The AER and other regulators require that wells with either GM or serious SCVF rates
be remediated immediately. Non-serious wells must be remediated at abandonment,
but the regulator may require their repair prior to this. Operators may temporarily stop
production from a well because it is currently uneconomic, placing it on inactive status.
Inactive wells are the most prone to leakage (AER, 2016a). While some wells may be
brought back on line, the majority are likely to never be economic again (Muehlenbachs,
2017). The cost to abandon a well is a major reason why many well owners indefinitely

21
delay abandoning inactive wells (Muehlenbachs, 2017), and remediation costs
contribute to this practice.

An option to reduce methane emissions is an accelerated or required abandonment

of inactive wells that are unlikely to ever be economic again and that are the largest
emitters of their type. However, from a cost-benefit standpoint, one should evaluate
the efficacy and cost benefit of an accelerated abandonment strategy considering that
the average cost to fix a well (including any related production losses) is estimated to
be $150,000 (Dusseault et al., 2014). In the Lloydminster area, remediation costs for
one corporation are $600,000 per well (Dusseault et al., 2014). Additionally, the use
of vented caps on abandoned wells is an implicit acknowledgement that leakage may
occur in abandoned wells, including those that were remediated before abandonment.
Thus, it might be more cost effective to simply tax the emissions from minor emission
sources and employ those funds to more effectively reduce methane emissions from
other sources. For example, both the International Energy Agency’s (IEA) World Energy
Outlook 2017 report (IEA, 2017) and the Pembina Institute/Environmental Defense
Fund study of Canada’s upstream petroleum industry (Environmental Defense Fund and
Pembina Institute, 2015) list a number of key methane-emitting sources and abatement
technologies. Both these studies suggest that in North America, 20% to 45% of total oil-
and gas-related methane emissions could be eliminated using technologies that have no
overall net costs or even provide a financial return (IEA, 2017). While the elimination
of methane emissions could result in increased gas sales and higher revenues, the
perspective of most operating companies is that the total costs of the required
equipment replacement and facilities down-time to achieve these emission reductions
will entail real costs to operators. The IEA report does not include wellbore leakage
methane emissions in this group and the EDF/Pembina Institute used a Texas well leak
detection and repair model to infer wellbore integrity issues in its study.

It is worthwhile to consider the impacts, costs and benefits of methane emission

reductions from the upstream oil and gas sector in comparison with methane emissions
from other anthropogenic sources in order to determine the net benefit of making
the reduction of upstream petroleum industry emissions a priority. Total methane
emissions in Canada in 2015 amounted to 102 MtCO2e and accounted for 14% of total
GHG emissions (Environment and Climate Change Canada, 2017b). Forty-two percent
(42.8 MtCO2e) were from fugitive sources in oil and natural gas systems (Environment
and Climate Change Canada, 2017b). Wellbore leakage emissions are predominantly
composed of methane13, and thus the 7.2 MtCO2e calculated by ECCC for wellbore
leakage emissions can be considered to represent ~7% of Canada’s total methane
emissions in 2015. Methane emissions from agriculture in 2015 were 29 MtCO2e (28%
of total), and those from landfills were 22 MtCO2e (22% of total) (Environment and
Climate Change Canada, 2017b).

13
CO2 is a common constituent of natural gas, and thus wellbore leakage. According to ECCC, Canada-wide
emissions from wellbore leakage in 2015 were estimated to be 0.0562 Mt CO2, and 0.2862 Mt methane, for
a total of 7.2124 MtCO2e. Methane, based on a global warming potential of 25, as used by ECCC, makes up
7.156 Mt, or 99% of this. Thus, it is reasonable to compare methane emissions from wellbore leakage to
other sources of methane emissions.

22 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 In some cases, it may be more effective for the upstream oil and gas industry, or for that
matter other anthropogenic emitters, to pay into a fund that would be spent obtaining
the largest reduction of Canadian anthropogenic methane emissions as a function
of cost.

Recommendation to address knowledge gap: In order to achieve significant and

cost-effective GHG reductions related to methane emissions, we propose the following:

Form a methane reduction strategy working group: The group would be tasked with
examining, from a GHG emissions perspective, the cost and benefits of remediating non-
serious inactive wells prior to abandonment in order to develop, if suitable, a process
by which a GHG-based decision on remediation can be made. Data from the proposed
well census, temporal variability, and top-down vs. bottom-up studies would help inform
this task.

The output of such an exercise could include a table of “cost per cubic metre of methane
reduction (or CO2 equivalent)” for the suite of methane reduction options available
across the entire petroleum sector. Armed with this knowledge, it may be suitable
to consider a levy on methane emissions, as opposed to strict prescriptive control
standards and regulations, so that efforts and funds can be directed to those reduction
efforts that are most cost effective.

It may also be suitable to consider the application of these funds to achieve more
efficient methane emissions reductions in other industrial sectors where the cost-
benefit may be greater. This is a reasonable approach considering that the GHG impacts
of methane are agnostic of the source and best achieved as cost-effectively as possible.

3.3.3 In consideration of other natural and anthropogenic sources, is there

an acceptable leakage rate into soil and groundwater protection zones
for non-serious wells with GM?
The public has a right to expect, and regulations to require, that the quality of
groundwater upon which they may rely is not impaired by wellbore leakage, and that
the effects of leakage on vegetation are not unacceptable. However, given that there
exist multiple sources of methane in the shallow subsurface and that methane may
migrate to the shallow subsurface via natural pathways in addition to leaky wells, it is
proposed that it is reasonable to consider the effects of GM in light of these observations
to determine if an acceptable GM rate exists. The effects of methane on groundwater
quality and vegetation, as described previously, are highly dependent on the methane
concentration, vegetation type and aquifer properties. Despite the number of GM
instances in Alberta, there are few alleged GW contamination cases. The small number
of contamination cases reflects the effective action of GM remediation efforts. It may be
that the rate of leakage for the majority of wells is such that the effects are negligible or
indistinguishable from those occurring due to other sources of methane, and this may
speak to the capacity of aquifers to tolerate or “process” certain amounts of methane.

23
Recommendations to address knowledge gap: In order to determine if there is an
acceptable GM leakage rate, we propose a field-based research program that would
answer the following questions:
◗◗ What is the contribution of methane from wellbore leakage into a groundwater
protection zone (including the vadose zone above the groundwater) relative to
other non-wellbore leakage-related sources of methane (e.g. primary and secondary
biogenic methane, thermogenic methane that has migrated via natural processes)?
Such studies will require the application of multiple methods of investigating
GM and methane distribution in the subsurface, including the use of chemical
tracers (e.g. Darrah et al., 2014) and physical migration models (e.g. Praagman and
Rambags, 2008).
◗◗ What is the impact of methane on groundwater quality and biota in the study areas,
and how is it related to aquifer properties (e.g. mineral, gas, water composition),
soil properties (e.g. composition, microbial community), vegetation type, and
other factors?
◗◗ The Alberta Agriculture website14 provides plans for water well natural gas separators.
What are the circumstances and what is the magnitude of the methane emissions that
result from the operation of potable groundwater wells; in other words, what are the
contributions of water wells to atmospheric methane emissions?

Such a program must take into account the cumulative impacts of wellbore leakage
and potential leakage resulting from potential future development. Armed with
data resulting from such a research program, it is likely feasible to develop a risk-
management strategy that accounts for site-specific properties to determine if
acceptable, and perhaps higher than currently permitted, SCVF or GM rates exist that
ensure the impacts from wellbore leakage are acceptable. The application of this process
may result in the non-requirement to fix some wells with GM and SCVF which would
currently have to be addressed. This would have a number of beneficial impacts: orphan
well associations would be able to abandon more wells for less money, which would
reduce their funding shortfall. It may also facilitate the abandonment of uneconomic
inactive wells (i.e. those likely to never come back on line) as the cost to an owner to
abandon them is reduced and more manageable. As noted by Lucija Muehlenbachs
(2017), “The financial burden of abandoning a well officially is no doubt why Alberta
producers delay doing so as long as possible.” Also, regulators might consider applying
a levy or tax for the right to emit methane via GM and/or SCVF), and the funds from
such a levy could be applied to reduce methane emissions elsewhere in a more cost-
effective manner. Lastly, this type of knowledge would allow regulators to develop a
ranking of leaky wells to remediate in order to fix those that are causing the largest
detrimental impacts.

14
https://open.alberta.ca/dataset/217842a8-0e36-4002-9331-06293f2c8ec5/resource/0523e4c4-
d946-42ff-b848-6bfbbc0678a6/download/35386312006agri-factsmethanegaswellwater.pdf.

24 Technology Roadmap to Improve Wellbore Integrity – Summary Report

4. Drilling and Completions
This section discusses the materials and processes used in well construction,
summarizing the full TRM report entitled Improving Well Construction Materials and
Procedures to Reduce Wellbore Leakage, which was a compilation of reports from Fire
Creek Resources Ltd. (Dean Casorso and David Ewen) and Bisset Resources Consultants
Ltd. (D.S. Belczewski)15. Well construction is critical because the details of how a well is
constructed determine the ability of the well to maintain hydraulic isolation between
geological strata. Improving well construction will reduce the need for expensive
remediation in the future. The well construction process commences with the well
design, followed by equipment and material procurement and mobilization, drilling and
completion of the well, and finally job closing activities including SCVF/GM testing.

4.1 Current Practices and Regulations in Well Operation

The design of a well involves a multidisciplinary collaboration between drilling
engineers, geologists and reservoir or production engineers with a focus on the well’s
objective and target formation location. Design parameters include hole size, directional
planning if applicable, casing and connections, cement slurry design, drilling fluid,
centralization, fluids pumping rates, and scratcher deployment. All of these design
choices may impact zonal hydraulic isolation. Numerical modelling may play a role in the
design process, but many of the input parameters are subject to problems of availability
and/or uncertainty, which can be partially mitigated by using a sensitivity analysis. The
main objectives during drilling are to ensure removal of cuttings, prevent exchange of
drilling fluids with the formation, promote borehole stability, and allow a satisfactory
rate of penetration.

After a particular stage is drilled (surface, intermediate or production) to the desired

casing setting depth, the drilling mud is circulated to move fluids from bottom to surface
to remove all drill cuttings prior to running casing. Long circulation times should be
avoided to decrease the risks of borehole instability. It is recommended, particularly in
deviated wells, to increase pumping rates to create turbulent flow, while taking care to
avoid inducing a fracture. After circulation, casing strings are connected and run into the
well. Before and during running of the casing, the centralization plan is typically revised,
and connection make-up torque, fluid levels and trip-in speed are monitored. The
threaded connections must be able to provide a pressure barrier between the internal
and external fluids. Once the casing is landed at the desired depth, drilling fluid is
pushed out the borehole, displaced by a spacer or scavenger fluid. Figure 4.1 illustrates
the cementing components.

15
The Bisset Resources Consultants Ltd. Report, entitled Construction and Abandonment Design for Life Cycle
Wellbore Integrity, was prepared for the Petroleum Technology Resource Centre’s (Regina, Saskatchewan)
CO2 User Project, and was graciously provided to NRCan to assist with the Technology Roadmap to Reduce
Wellbore Leakage.

4. Drilling and Completions 25

Spacer fluids are used to flush out drilling fluid products in the wellbore that are
incompatible with proper curing of cement. Spacers generally have low viscosity, which
enhances turbulent flow. If the drilling fluid is required to be at high density for either
well control or wellbore stability reasons, the spacer fluids may be weighted to avoid
major changes in bottomhole pressure. Greater spacer volumes ahead of the cement
slurry are generally beneficial for improving removal of mud and filter cake, which is
gradually eroded by the flowing spacer fluid. However, increased exposure time to low
viscosity and generally less inhibitive spacer fluid increases the likelihood of wellbore
instability and collapse around the casing string. For areas where wellbore stability is an
issue, reduced volumes of spacer fluid may be a better choice.

After circulating the spacer fluid, cement slurry is pumped into the well, displacing the
fluid within the well, and replacing it with cement. With conventional cementing down
casing (as opposed to inner string or reverse cementing), before pumping cement,
a wiper plug (bottom plug) is installed in the casing. This plug travels in front of the
cement, cleaning the inside of the casing, and preventing the cement from mixing
with the fluid inside the casing. The cement slurry flows to the bottom of the wellbore
through the casing, until the bottom plug reaches the float collar, just above the bottom
of the hole. The pump pressure is increased until a diaphragm within the bottom plug
ruptures, allowing the cement to flow through to the bottom of the hole, around the base
of the casing and up the annulus of the well. After the appropriate volume of cement
has been pumped (based on the estimated volume of the annulus, plus an excess), the
second wiper plug (top plug) is pushed down the casing by a displacement fluid, and
pumping continues until the top plug meets (‘bumps’) the bottom plug. The cement now
fills the annulus, and is allowed to set, creating a seal to prevent fluid flow between the
formations penetrated by the well. The cement also protects the casing from corrosion
and increases mechanical stability.

A cement blend must be designed specifically for the casing string, depth, temperature,
pressure and ultimate use of that portion of the borehole. The surface casing cement
program is typically a very basic design. Generally, the surface casing cement has no
special additives and no special spacers are used because the surface hole is drilled with
gel chem mud systems and the geometry of the hole isn’t an issue because surface inter­
vals are typically vertical. However, the importance of avoiding gas migration through
casing cement column and within the surface casing/surface hole annulus is important.

If a casing pressure test is required after the top cement plug bumps the bottom plug,
it should be done before the cement has gained significant gel strength to reduce any
disturbance of the bond between the casing and cement. Alternatively, the pressure test
can be done after the cement has gained sufficient compressive strength. Section 25.9.3.2
of DACC’s Industry Recommended Practice #25: Primary Cementing (DACC, 2017) notes
that, usually, a minimum compressive strength of 500 psi (~3500 kPa) is required before
drilling out the casing shoe. The CSA’s Z625-16 Well Design for the Petroleum and Natural
Gas Industry Systems is stronger: Section 6.3.3 states that “The casing shoe shall not be
drilled out until the cement has reached sufficient compressive strength (3500 kPa) to
allow safe drilling operations or following the elapsed time specified by the authority
having jurisdiction. Regardless of the drill out time, the cement shall have a compressive
strength of at least 3500 kPa after 48 hours at formation temperature.” (CSA, 2016)

26 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 Figure 4.1 Schematic of cementing components.

4.2 Problems Encountered with Current Wellbore

Construction Practices
Typical drilling problems include well control situations where formation fluids invade
the borehole (kicks), loss of circulation where the drilling fluid invades a penetrated
formation, and borehole instability. Borehole instability is the undesirable condition in
the open hole which results in the open hole gauge size and shape and/or its structural
integrity being compromised. Drilling problems may be severe enough that they lead to
a complete loss of the well.

4. Drilling and Completions 27

Connection failure, in conjunction with annular cement failure, can result in gas or liquid
escaping from inside of the casing and manifesting as a surface casing vent flow or gas
migration. The proper selection of casing connections, based on the mechanical load,
pressure, temperature and chemistry, is critical to ensure casing integrity. For instance,
the BC Oil and Gas Commission (2015) issued a reminder that high pressures associated
with hydraulic fracturing down casing with American Petroleum Institute (API) Long
Thread and Coupling connections could compromise the casing integrity and lead to
SCVF. Vignes and Aadnoy (2010) showed that 2% of 406 Norwegian offshore wells
had integrity failure due to casing connection or collapse (King, 2012). An additional
concern is the proper application of thread compound to API connections. The thread
compound is an integral part of the connection seal. It is applied while casing is run in
the hole, often by a rig member with limited training, and with little oversight during the
application. Testing of connections while running casing is seldom done.

Uncemented sections of the annulus are a major cause of SCVF, GM, and casing failure
due to external corrosion (Dusseault, 2014; Watson, 2007; Carrol, 2016; Chafin, 1994;
Hetrick, 2011). Unintended low cement top, when there are no cement returns at
surface, may result from lost circulation, leak-off or an underestimated annular volume
(Hetrick, 2011). Lost circulation can result during cementing due to excessive effective
circulating densities, which cause the formation to fracture due to high pressures. In
wells that do not have multi-arm caliper surveys conducted prior to cementing, the
annular volume may be underestimated because the calculation generally uses the
gauge borehole diameter and some rule of thumb excess. This practice can severely
underestimate the volume when wells have significant borehole washout. In some cases,
wells may be designed with low cement due to the inability of deeper zones to withstand
the hydrostatic pressure of a full cement column, lack of regulatory requirements
to cement into the next string of casing (or to surface), or economic considerations.
Technologies to assist in full column cement placement are available. These include
stage cementing or external casing devices, such as cement baskets, which may help to
reduce cement fall back.

The placement of cement requires the displacement of residual drilling fluids in the
wellbore. Based on experience and observations over many years, some extreme
examples of cement channeling are believed to be a direct result of incompatible
residual fluids in the annulus coming in contact with either the tail or especially the lead
cement slurry (Agbasimalo, 2012).

When preparing cement slurry, cement bulk tanks feed the dry cement powder and
mix water into the cement pumping unit. In such a system, holding the cement density
steady in an on-the-fly or jet-cone mixer requires an experienced operator. Maintaining
the correct density of the cement slurry at the tail end of the job can be very difficult due
to low levels in the bulk tank, no ability to gauge tank levels, cement powder hang-up in
the tank, and complications from humidity resulting in lower feed rates of the cement
powder. The result is a poor-quality cement around the casing shoe, the location where
cement integrity is most critical.

Installing BOPs or pressure testing can cause casing movement before adequate
cement compressive strength has developed and may cause a microannulus to develop

28 Technology Roadmap to Improve Wellbore Integrity – Summary Report

(DACC, 2016). Formation leak-off pressure tests conducted to ensure the casing shoe
has adequate strength may expand the casing and may create a microannulus when
the casing is unloaded and the pressure drops (Boukheifa, 2005; Bois, 2011). Drilling
ahead, perforating, or performing stimulation treatments such as hydraulic fracturing
too soon after a well is cemented can also cause cement sheath failure. CSA Z625-16
recommends waiting on cement before drilling out until a minimum of 3500 kPa (500
psi) compressive strength has been developed (CSA, 2016). Establishing adequate
compressive strength may be complicated in long cemented intervals where there is a
large temperature differential between the top and bottom of the interval. Because the
rates of hydration and curing are highly temperature dependent, compressive strength
may be adequately developed at the bottom of the well where temperatures are higher
but may be inadequate at shallower depths at lower temperatures (Witt, 2016).

A relatively common practice that may result in the formation of a microannulus is the
use of high-density displacement fluid to displace the cement slurry. This occurs quite
often in wells where high-density fluid is used for both the section of the well that is
being cased and for drilling the section of the well that is below the casing currently
being run, generally in deeper wells. This might be done because it may be operationally
simpler to continue using the fluid when drilling out and avoid circulating out a different
type of displacement fluid from the well. High-density displacement fluids increase the
risk of creating or enlarging a microannulus because the casing balloons when exposed
to a high differential between internal and external pressures. Thin-walled casing strings
suffer more from this effect than do thick-walled casing strings. The cement sets with
the casing expanded and when the pressure is reduced after the high-density fluid is
replaced with a lighter fluid, the casing retracts pulling the casing away from the cement
sheath and creating a microannulus.

Even where drilling problems are not an issue, connections do not fail and the entire
annulus is cemented, wells may still leak. The reason is that cement placement in a deep
borehole, particularly in the annular space outside the casing, is difficult. There are a
large number of things that can go wrong, leading to poor sealing against gas movement.
The potential problems that may affect the integrity of hydrocarbon well annuli (both
during production and post-abandonment) are outlined in Dusseault et al. (2014),
where wellbore integrity problems leading to gas migration were divided into short-
term and longterm issues. According to them, short-term issues affecting the cement
sheath include:
◗◗ Improper drilling mud and cement slurry design: Results in cement that is unable to
provide an adequate seal, regardless of the care and quality control during cement
placement.
◗◗ Inadequate mud removal: This causes poor bonding of cement to borehole walls, or
mud contamination of the cement slurry, which can result in reduced pumpability,
reduced compressive strength, prevention of slurry gelation, and creation of channels
or voids as embedded mud dehydrates (Figure 4.2).
◗◗ Eccentric casing placement: This contributes to poor mud removal and is a particular
problem for deviated (and horizontal) wells.

4. Drilling and Completions 29

◗◗ Invasion of gases or liquids during setting: This may occur if cement does not maintain
sufficient hydrostatic pressure until the slurry has developed sufficient gelation
or strength to resist gas invasion. This is a function of slurry design and wellbore
conditions (Crook and Heatherman, 1998) (Figure 4.3).

And, long-term issues affecting the cement sheath include:

◗◗ Operating stresses, including cyclic pressure and/or thermal stresses: These cause
expansion or contraction of the casing and cement sheath, and stress relaxation
(or creep) at elevated temperature and stress, which may result in debonding and
development of cracks or a microannulus. Casing expansion has also been shown to
cause axial and radial tensile, shear or compressive fractures in the cement sheath
and permanent (plastic) deformation. These issues are acute in high-temperature
enhanced oil recovery or hydraulic fracturing wells (Figure 4.4).
◗◗ Cement shrinkage: This may be due to the expulsion of water into permeable
formations, autogenous shrinkage due to the reduced volume of cured cement, or
perhaps osmotic dewatering. This can greatly reduce the radial confining stress,
resulting in the development of a microannulus. This issue was studied quantitatively
in a recent modelling study by Oyarhossein and Dusseault (2015), which confirmed
the validity of this conceptual model of microannulus development.
◗◗ Corrosion and cement degradation: Steel casing corrosion diminishes the mechanical
integrity of the casing and may lead to leakage problems. Degradation of the cement
sheath may also enhance pathways caused by corrosion, drilling damage, cement
shrinkage, or others.

Figure 4.2 Incomplete displacement of drilling mud and resulting cement

and drilling fluid channels. Over time, the gels in the drilling fluid well
shrink, forming a gas flow path in the annulus (Watson et al., 2002).

30 Technology Roadmap to Improve Wellbore Integrity – Summary Report

Figure 4.3 Gas channels and gas pockets formed in set cement as a result of gas migration
(Watson et al., 2002).

Figure 4.4 Cement sheath failure and resulting cracks developed from
pressure cycling (Watson et al., 2002).

4. Drilling and Completions 31

 4.3 Improving Operational Practices with Existing Technology
The following recommendations can be made to improve well construction practices,
with a goal of reducing rates of surface casing vent flow and gas migration:
◗◗ Run open-hole log suite including x-y caliper log in all wells in order to assess
hole geometry and conditions in the wellbore. X-Y caliper logs will indicate areas of
washout or narrowing, important when planning where additional centralization may
be required. Knowledge of problem areas may also help determine where to remediate
if leakage does occur. The caliper log allows a better estimate of the required cement
volume, reducing the risk of a low cement top.
◗◗ Dusseault et al. (2014) commented that better centralization may be the most cost-
effective method to reduce wellbore leakage in new wells. Poor centralization seems
to contribute to gas leakage in many wells, especially deviated and horizontal wells.
According to Dusseault et al. (2014), Shell Canada has been using one centralizer
per casing joint in vertical sections of its wells in the Montney and Duvernay plays in
Alberta and British Colombia, improving the quality of primary completions. Borehole
information along with deviation surveys should be used to simulate the most effective
centralization program. Care should be taken to ensure that centralizers are properly
installed and that field operations follow all protocols.
◗◗ Pipe rotation is the most effective physical method to remove drilling mud,
particularly in high-angle sections of the hole where the pipe and cuttings lie on
the low side of the hole. Without rotation, the active flow area is over the top of the
pipe and cuttings bed. It is nearly impossible to remove this cuttings bed without
mechanical agitation. Rotation causes a “viscous coupling” effect that pulls the cuttings
up into the active flow area and enables their removal (Mims and Krep, 2003). It is
also effective at removing mud in well sections where the casing is close to the wall of
the wellbore (Zulqarnain, 2012). Studies within the industry have shown that rotation
is more effective than reciprocation under most conditions (Nelson and Guillot,
2006). The most significant barrier to casing rotation is the fear of over-torqueing and
fatigue development of casing connections while rotating (Xie et al., 2011). Advances
in controlled drilling, computer modelling software, and the ability of drilling rigs to
limit rotary torque make pipe rotation increasingly feasible. In some deviated wells
pipe rotation may not be advisable, but in these situations improved centralization,
fluid flushes, spacers and pump rates must be designed to compensate for the lack of
pipe movement.
◗◗ Ensure casing design accurately identifies the loads that the well will be exposed
to throughout the life cycle and specify connections that will withstand these loads
throughout the life of the well. Other possible improvements could include testing of
casing connections while running in, improved training of rig crews for running of
API and non-API connections, and increased use of premium connections in a broader
category of wells.

32 Technology Roadmap to Improve Wellbore Integrity – Summary Report

◗◗ Remove mill varnish from casing prior to running. Sandblasting roughens the
surface of the casing and improves the chance of direct contact of cement to the casing
wall surface, which can significantly improve the cement bond with the casing wall
(Carter and Evans, 1964). Transporting and sandblasting casing may be inconvenient
but is less so if done in larger batches.
◗◗ Utilize well integrity management systems to allow designers to assess the risks
associated with the well construction and future operations (International Standards
Organization [ISO], 2017; DACC, 2012). The AER has a requirement for integrity
management systems for pipeline construction and operations but there is no similar
requirement for wells.
◗◗ Implement longer wait on cement times. Loading the cement prior to full-strength
development can lead to the formation of a microannulus between the casing and
cement sheath. Not all jurisdictions have regulations requiring wait on cement time
or cement strength development prior to drilling out the previous casing shoe, before
BOP removal, or before completion operations commence.
◗◗ Limit the use of high-density displacement fluids wherever possible. High‑density
displacement fluids increase the risk of creating or enlarging a microannulus because
the casing balloons when exposed to a high differential between internal and
external pressure. The cement sets with the casing expanded, and when the pressure
is released, the casing retracts and a microannulus is created between the casing
and cement.
◗◗ Follow all best practices for cement design and where possible, use cements that
have more resilience in both compression and tension. Mandating cement properties
other than compressive strength, such as tensile strength, time to development,
maximum fluid loss, or minimum transition time, might also improve zonal isolation.
◗◗ Cement full length or, at a minimum, well into the previous casing string. It is best
practice to cement at least 50 m past the previous casing shoe, and where possible
to surface. There may be some advantages to limiting the cement height inside
the previous casing to facilitate repairs on shallower casings. Whether this benefit
outweighs the risk of corrosion in the uncemented casing is unknown.
◗◗ Pump rates during cement placement should be as high as possible to have flow
in the turbulent to near turbulent regime, to assist in mud and cuttings removal.
Very high displacement rates should be tempered by the potential risks associated
with high pumping rates, such as hole wash-out, loss of circulation and/or creation
of an annular pack-off with cuttings or sloughing shales. To improve cement flow
characteristics, various blend additives such as turbulence inducers (friction reducers)
can be added. While it may not be possible to achieve full turbulent flow by altering
the rheology of cement slurries, reduced gel strengths and low shear rate rheology will
induce eddies and other irregular flow patterns that aid in mud removal.
◗◗ Alternative cement/sealant designs (e.g. resins) in key caprock and aquitard layers,
cement additives to increase elasticity/ductility, pre-flush/pre-treatment (e.g. with
silicates) to improve cement placement and reduce leak-off.

4. Drilling and Completions 33

 ◗◗ Pumping additional cement volume past any given point in the wellbore will
increase the areal percentage of cement, while simultaneously reducing the areal
percentage of residual filter cake and fluids such as mud, hydrated drilling fluid, spacer
fluids and formation fluids. Increasing the cement volume remains one of the best
methods for contributing to a good quality cement job.

The oil and gas industry has prepared and widely distributed many publications
regarding best practices for addressing wellbore leakage. These best practices are
based on years of scientific research and field implementation. A sample of these
recommended practices and standards follows.
◗◗ Drilling and Completions Committee (Enform) IRP 3: In Situ Heavy Oil
Operations – An Industry Recommended Practice (IRP) for the Canadian Oil and
Gas Industry, Volume 03 – 2012: Addresses casing design, cement design, cement
placement, operational integrity and other special considerations for thermally
produced wells.
◗◗ Drilling and Completions Committee (Enform) 24: Fracture Stimulation – An
Industry Recommended Practice (IRP) for the Canadian Oil and Gas Industry, Volume
24 – 2016: Addresses well integrity issues associated with high pressures in the
casing. The recommendations for well integrity assessment could be used prior to
loading the casing and cement sheath in the construction phase.
◗◗ Drilling and Completions Committee (Enform) IRP 25: Primary Cementing – An
Industry Recommended Practice (IRP) for the Canadian Oil and Gas Industry, Volume
25 – 2017: This IRP supports the findings of this review in terms of centralization and
pipe movement and should be relied upon to achieve wellbore integrity.
◗◗ Canadian Standards Association CSA Z625-16: Well design for petroleum and
natural gas industry systems: This standard provides an exceptional guide to well
design for conventional and deviated wells, offering an excellent list of standards and
best practices. The standard also discusses a design philosophy to ensure wellbore
integrity.

4.4 Knowledge Gaps and Research Recommendations

Our literature review and interviews have identified several areas of new technology
and research that could be pursued. These include:
◗◗ Cement additives, elastomers, fibers: Fibers and elastomers may help cement self-
heal after it has been compromised. These added components react with migrating
hydrocarbons or aqueous fluids to expand and seal off small leaks. Cavanagh et al.
(2007) presented data showing closure of a 100micron microannulus within 6 hours,
despite a differential pressure up to 5.3 MPa/m. Additives that increase the resilience
of cement may also be beneficial in achieving longterm sealing after cyclic well
loads—a promising candidate is microporous spongy carbon (Zhou, 2015).
◗◗ Placement techniques: Slow-rate cementing and vibration post placement have
shown promise in reducing SCVF and GM in shallow wells. However, the techniques

34 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 have been employed while ensuring other best practices are in place (i.e. no
independent control), warranting further investigation to better understand these
success stories. Heating of displacement fluid or circulating warm fluid to increase
wellbore temperatures and accelerate cement setting times may be beneficial
in shallow wells with low temperatures. However, this technique could enhance
microannulus formation due to thermal strains.
◗◗ Pipe movement: Pipe movement is identified as an important practice in
establishing wellbore integrity but is often not used (especially rotation). Concerns
regarding pipe fatigue, torque limits and inadequacy of available equipment lead
field operators to make the decision not to move pipes. The use of API connections
may also be a source of concern. Upfront fatigue/damage analysis supported by
lab data and better communication between engineering and field personnel
regarding the risks of pipe movement may allay some fear. More use of semi-
premium and premium connections would enhance confidence in this practice.
◗◗ Swellable casing attachments: Swellable technology shows promise in the
reduction of SCVF and GM. External casing packers (ECP) have been used in the
industry for over 70 years (Webber, 1949). Traditional ECPs used cement, mud or
another fluid to inflate an annulus-sealing element, but are not always deployable
(Bonett, 1996). Swelling rubber bonded to the casing (swellable ECPs) can work
in well conditions that limit the application of traditional ECPs. The elastomers
swell when exposed to a particular fluid, sealing microannuli or open mud channels
(Carrion, 2011). Swelling rubbers function autonomously, swelling multiple times if
re-exposed to the activation fluid. More research is warranted to develop products
designed to swell in specific instances, such as in contact with gases like methane, CO2
and H2S or specific water chemistries.
◗◗ Simulation: Simulation programs with user-friendly interfaces employing typical,
easily acquired inputs should be developed for engineers to use in the design stage
and for field personnel to quickly assess changes required in centralization plans, and
to determine the forces exerted on the casing during reciprocation and rotation.
◗◗ Centralizer design and installation: A survey of the literature and interviews
with operators suggests that the barriers to proper use of centralization include
the lack of information to accurately simulate centralizer placement, reliance on
rules of thumb, lack of training, lack of specifications for installation, and poor
centralizer design. Based on the concerns raised by field staff, research on improved
centralizer design and installation processes is recommended.
◗◗ Risk-based well integrity management: Development of risk-based well integrity
management systems that would be implemented and enforced by regulators should
be investigated (ISO, 2017).

The preceding list is helpful, but this review has identified some significant barriers to
the use of new technologies and best practices. These barriers are generally operational
or economical, under regulatory regimes that specify minimum standards that do not
meet the integrity needs of specific wells.

4. Drilling and Completions 35

Economically, the impact of the additional time needed to drill a well is significant.
Generally, drillers are paid per metre drilled per time and encouraged to use low-cost
well construction materials, and technologies and practices that may not consider long-
term well integrity. The pressure to drill wells as inexpensively as possible results in the
shortest wait-on-cement times, the most inexpensive cement additives to meet pumping
criteria, limited logging, application for waivers wherever possible, and the infrequent
use of premium casing connections.

Generally, there is little consequence to an operator that has constructed a well with
poor integrity. Wells with ‘nonserious’ SCVF or GM are allowed to produce, and repair
is put off into the future until abandonment. Regulations that include penalties for
operating a well with compromised integrity could provide an incentive to follow known
best practices.

36 Technology Roadmap to Improve Wellbore Integrity – Summary Report

5. Source Identification
This section is a summary of the TRM report entitled Improving Wellbore Leakage
Source Identification to Increase Remedial Intervention Success, produced by Rose
McPherson and Paul Pavlakos of Weatherford Canada, Calgary, Alberta. Accurate source
identification is critical to achieving a successful remedial intervention. For instance, if a
remedial attempt is placed too far above the source formation, build-up of pressure from
greater depth can exceed the local confining stress and result in breakout/seepage to
formations or degradation and eventual breakdown of the remedial seal. If the remedial
seal is placed below the actual source zone, the intervention will have no remedial
impact and can jeopardize casing integrity. Sources of migrating gas are commonly at
intermediate depths between production zone and base of groundwater protection.
Typical long-term gas flow rates produced by intermediate formations are on the order
of 1.0 m3/day. Low flow rates make source identification difficult. In this section the
current state of technologies is summarized, knowledge gaps are identified, and new
avenues of research to improve source identification are proposed.

5.1 Current Practices and Regulations

Current industry practice is to assess source rock, cap rock, fluid movement and flow
path of the leaking fluid, but with minimal to no data collection effort. Formation log
information and drilling history can be used for potential source identification, as can
information from offset wells. Information such as kicks, lost circulation and tight hole
while drilling will provide information regarding where high permeability intervals
exist in the wellbore. Investigation of cuttings, mud gases, mud conditioning prior to
cementing, hole deviation and well cementing charts can also provide clues to identify
the source interval.

The available methods used for active source identification can be divided into three
categories: (1) acoustic energy measurements; (2) carbon isotope measurements; and,
(3) formation evaluation measurements.

5.1.1 Acoustic energy

Turbulence in flowing fluid generates sound. A downhole noise logging tool can
measure the acoustic profile of the wellbore to characterize flow in the annulus. In this
method, a conventional hydrophone is suspended downhole in the wellbore fluid and
acoustic measurements are taken at a series of locations, requiring several minutes at
each level. This method was adapted for identifying behind-casing leaks in the 1970s,
(Maslennikova et al., 2012). An increase in noise amplitude or frequency magnitude
of the recorded signal may be interpreted as fluid movement due to a source zone
(Maslennikova et al., 2012). Leaks behind the casing can have a distinct frequency
structure that permits discrimination between two-phase and single-phase flow
regimes, and an order of magnitude estimation of the leak rate. This interpretation is
confounded by the fact that turbulent flow through a restriction or a change in flow path
can also create sound downhole.

5. Source Identification 37
 Hydrophone technology from the 1970s has significant limitations in low-flow
environments. Recently, hydrophones with broader frequency bandwidth, higher
frequency resolution and increased sensitivity have become available, allowing for
“spectral noise logging” (Aslanyan and Davydov, 2012). Another new technology is the
geophone noise survey, which consists in deploying an array of sensors downhole and
collecting measurements throughout the length of the wellbore. The tools are designed
with a hydraulic backup arm that extends to clamp each sensor against the inside of the
well casing, acoustically coupling the instrument to the pipe, increasing data quality
and improving measurement sensitivity. Consequently, geophones are not as vulnerable
to low frequency noise contamination and maintain vertical resolution in the low-end
spectrum. First arrival times between sensors can be used to determine the direction
of vertical flow behind the pipe. Fiber optic Digital Acoustic Sensing (DAS) tools employ
similar measurement principles and are also being used for the detection of wellbore
leakage (Hull et al., 2010). The sensors are comprised of fiber optic material wrapped
into a physical coiled length, effectively creating a hydrophone but with increased
sensitivity and measurement fidelity.

5.1.2 Carbon isotopes

Carbon isotope measurements may be used to identify sources of gas migration.
Microbial gases are created by bacterial activity in near-surface soils (Szatkowski et al.,
2002). Thermogenic gases are generated by elevated temperature and pressure acting
on organic materials at much greater depths. There are two stable isotopes of carbon:
12
C with relative abundance of 98.89%, and 13C with relative abundance of 1.11%. By
comparing the ratio of abundance between 13C and 12C isotopes in a sample with that
of a laboratory-derived standard, the unique isotopic composition (or carbon isotope
fingerprint) is characterized. Individual geological formations have distinct carbon
isotope fingerprints that vary systematically with depth. Typically, a more negative 13C
abundance in the sample indicates a younger, shallower depth of origin. Isotope analysis
for wellbore leakage involves comparing the delta value in a production sample with
that of a leakage gas sample. It is possible to identify the migrating fluid’s formation of
origin using this method (Rich et al., 1995; Szatkowski et al., 2002; Figure 5.1). Isotopes
of sulfur, oxygen, and hydrogen are also useful for source identification (e.g. Rostron and
Arkadakskiy, 2014) but are not typically used because there is much less information on
their stratigraphic and geographic values than there is for carbon isotopes.

38 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 Figure 5.1 Profiles of the isotopic composition of carbon in n-alkane gases
collected while drilling a well in west-central Saskatchewan (Szatkowski et
al., 2002). By comparing the isotopic signature of gas samples collected
from SCVF and GM to that from gas samples collected during the drilling of
the well or a nearby offset well, it may be possible to identify the source (and
depth) of the leakage gas.

5.1.3 Formation evaluation

Formation evaluation systems (or geophysical logs) were first introduced in the 1930s
for the purpose of identifying lithology and formation properties by logging the open
hole. For economic or operational reasons, not all wells have lithological data from open-
hole logs. Consequently, cased hole formation evaluation techniques were developed in
the 1980s to identify areas of gas storage and by-passed pay (Elkington et al., 2006). The
use of gamma ray, neutron, density and sonic measurements allows for the classification
of wellbore fluid characteristics, petro-physical features and lithology. In the context of
leak source identification, these methods can be used to identify gas-bearing formations
with potential to be the source of wellbore leakage. These measurements also provide
information identifying the caprock formation over which to place the remedial
intervention in order to most effectively isolate the source horizon. One advantage to
logging in a cased hole is that invasion of drilling mud fluids at the time of open-hole

5. Source Identification 39
 logging will dissipate as gas gradually migrates back into permeable formations near
the well. Gas bearing zones that may have been masked when logged in an open hole
will become more apparent in cased hole logs one to two weeks after the casing has
been installed.

5.2 Problems with Current Operational Practices

Historically, wellbore leakage intervention has been executed with minimal planning,
which usually results in ineffective identification of the leakage source and leak
remediation. The efficacy of the remediation is influenced by the available methods of
source zone identification, but these also have limitations, as enumerated below.

5.2.1 Acoustic energy

Hydrophone tools were originally designed to detect flow rates on the order of 100 m3/
day or greater, much higher than the typical rate of wellbore leakage seen in Alberta
today (<1.0 m3/day). They are not sensitive enough to produce reliable results at low
rates, and are susceptible to low frequency noise contamination from sources at surface
(Maslennikova et al., 2012). These problems are further complicated by variations
between service companies in their data acquisition process, hydrophone quality and
tool maintenance. All contribute to the perceived lack of quality in the conventional
noise log for annular flow at low volumes. Additionally, the calculations for predicting
the flow rate from noise amplitude are idealized for specific geometries and known rates
that are not likely to be replicated in field applications.

For spectral hydrophone measurements, the discrete frequency bandwidths assigned

to characterize flow types are sensitive to flow path geometry and are not always
clearly defined. Completion elements can produce uncharacteristically high frequency
signatures where poor perforations, packer leaks or casing leaks are present. Frequency
varies with flow conduit size and structure. Flow channels can be interrupted by
impediments such as cement or formation constrictions, making interpretation difficult.
Reservoir fractures may also exhibit frequency characteristics similar to borehole fluid
flow or completion elements.

There has been limited experimental testing of geophone response in a laboratory

facility; designations of vertical and horizontal flow regimes are based on interpreted
field results.

5.2.2 Carbon isotopes

There are a number of issues confounding the use of carbon isotope fingerprints to
identify sources of wellbore leakage emissions. The isotopic signature of methane can
be altered in the sub-surface due to oxidation and production mechanisms. Oxidizing
bacteria preferentially consume the lighter isotopes in methane gas, also affecting
ethane isotopic compositions. Propane and butane signatures can often violate the
expected order of enriched 13C content in co-generated gases by means of reversed
13
C/12C partitioning (Chanton et al., 2005; Rich et al., 1995). The addition of heat in
thermal developments can fractionate isotopes, causing their composition to vary.

40 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 Surface sample collection techniques, interpretation methods and machine calibration
discrepancies can impact analytical results. Sample acquisition may be done using
specially designed bags that require timely processing to prevent sample degradation.
Pressurized canisters may also be used, but these require sufficient pressure to be filled,
a difficult threshold to satisfy given the low flow rates and pressures typical of GM/SCVF.
To ensure the concentration of gas in the sample is adequate with respect to the amount
of air contamination requires proper training of field personnel.

Isotopic signatures should be compared to samples from the same well—collected from
mud gas during drilling. If such samples are not available, wellbore leakage samples
may be compared to samples taken from sufficiently close offset wells. The leakage
sample origin may be incorrectly identified if fingerprint data is not available within an
adequate range. In wells with multiple sources, the isotopic analysis will yield only a
value identifying the oldest or deepest source. A comprehensive, standardized database
of production horizon isotopic fingerprints does not currently exist for all areas that
have wellbores.

5.2.3 Formation evaluation

Formation evaluation in a cased hole is more challenging than in an open hole. For
through-casing density and acoustics, pre-job planning and consultation with the
wireline service provider is necessary to ensure that the wellbore conditions are
favourable. Quality checks should include a comparison of the cased hole responses to a
nearby well with open-hole logs, and looking for standard log signatures distinguishing
clean formations from shales. Under ideal conditions, it is possible to relate cased-hole
gamma ray, neutron, density and sonic log responses to those in the open hole, but ideal
conditions are not always available.

Acoustic tools will not work in a gas-filled borehole due to extreme signal attenuation.
In general, a liquid-filled wellbore is also required for a neutron tool, although there
are air-filled-hole corrections. These corrections may not always work, so the borehole
should be filled with liquid if possible. It is also recommended for the casing to be fluid
filled for pulsed neutron capture logging. Gas bubbles inside the liquid-filled wellbore
can affect measurement accuracy.

Penetration depth is a problem for a number of through-casing logs. For instance, the
measurement depth for a neutron log is 9” – 12”, and even shallower for density logs.
The general consensus is that the density data will be valid in a cased hole when the
distance between the tool and formation (standoff) is limited to 1.5” – 2.0” (Ellis et al.,
2004; Odom et al., 1999; Sherman and Locke, 1975). For pulsed neutron capture, the
depth of investigation is similar to that of the neutron tool, though some of the newer
tools with longer detector spacings are capable of up to 14”. Density measurements are
also very susceptible to hole washouts and rough hole conditions.

In acoustic logging of a cased hole, a secondary requirement is that there must be

good cement bonding between the casing and formation, otherwise the compressional
wave may respond to only casing or cement. For all logs, wellbore configuration and
mechanics need to be understood and carefully characterized. Large wellbores and
casing can limit the effectiveness of the measurements.

5. Source Identification 41
 5.3 Improving Operational Practices with Existing Technology
Current regulations do not specify which source identification technologies to use but
do state that acceptable methods include noise/temperature surveys, gas analysis
and logs (Alberta Energy and Utility Board, 2003). Best practices for identification of
wellbore leakage source zone and intervention interval should include the combined
implementation of all tools and technologies currently available to identify fluid
movement, escape path, and source zone. Formation evaluation logs identify zones
potentially contributing to wellbore leakage gas, while acoustic measurements and
isotopic analysis aid in source-zone identification. Cement bond logs can improve the
identification of apparent annuli, voids or channels, and can be used for interpretation of
acoustic measurements.

Patience must be practised when creating the intervention strategy. Baseline

information gathering prior to repair is extremely valuable. It may take several months
for gas stored within the wellbore or other shallow zones to dissipate from the well. This
is often mistaken for a failed repair attempt. Recording a stabilized pressure build-up on
the vent before starting an intervention and comparing to post-remedial build-ups can
indicate that an additional intervention is not required. Quick turnaround time to save
on rig costs can limit the quality of the interpretation, leading to intervention failure and
multiple interventions. This can result in remedial costs reaching into the millions of
dollars on a single well.

5.3.1 Acoustic energy

Acoustic energy measurements have the ability to identify gas and liquid movement
behind casing and isolate-contributing horizons. However, two aspects of acoustic
measurements that need to be better understood in order to improve source
identification are the effects of turbulent fluid movement through the escape path and
background noise contribution. To mitigate these issues, operators should obtain a
current high-resolution cement bond log (to assess variability of the flow path) and
perform an assessment of possible sources of acoustic interference (to account for or
minimize background noise). Conventional hydrophone tools should not be used to
identify sources of fluid migration if the flow rate is relatively low. To create consistent
and repeatable results from well to well, a standardized data acquisition procedure
should be established.

5.3.2 Carbon isotopes

Similarly, standardized sampling and testing procedures are needed to improve
carbon isotope measurements. Current databases have questionable samples that
may add significant error to the interpretation of new samples. Samples that have
been quality controlled should be added to an openly available carbon isotope
database. A comprehensive database of known horizons, preferably single interval
production sample fingerprints, will greatly increase the effectiveness of carbon
isotope measurements.

42 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 5.3.3 Formation evaluation
Formation evaluation data is used to identify the caprock when choosing the
intervention interval in the wellbore, and also to identify potential gas-bearing zones.
Formation evaluation data does not differentiate which horizon is actively contributing
to wellbore leakage. Open-hole and caliper logs provide excellent data and, when
available, an open-hole analysis should be performed to identify source zones. Any
existing open-hole logs should be compared to the through-casing logs to identify the
most likely source contributors, namely non-commercial gas zones that were saturated
during drilling and were not recognizable on open-hole logs.

5.4 Knowledge Gaps and Research Recommendations

The following knowledge and technology gaps have been identified as needing more
research and development through the application of lab or field studies:
◗◗ Acoustic energy measurements: The minimum flow rate that can be accurately
detected with each acoustic energy technology should be identified, especially for
conventional hydrophones, which continue to be used inappropriately in low-flow
settings unsupported by the original research (McKinley et al., 1973). Research
should assess the effect of background noise, clearly define the depth of investigation,
quantify the effect of multiple casing strings on the effectiveness of the tools,
and determine which technologies are best suited for specific areas or wellbore
environments. Studies to determine the effects of data acquisition procedures on the
measurement quality would be valuable, as would a comparison of the effectiveness
of distributed acoustic sensing versus other techniques. Technology and methods to
accurately measure acoustic data in larger diameter wellbores are also needed.
◗◗ Isotopic analysis: Future research efforts should focus on determining the effects
of improper sample collection, improper processing and time delays in testing. The
effectiveness of current sample collection techniques, procedures and containment
methods should be studied. Changes in isotopic composition as gas travels from source
horizon to shallow subsurface horizons and to surface should be quantified and the
temperature threshold for isotopic fractionation in thermal environments should be
assessed. Finally, comprehensive fingerprint databases with samples of all producing
horizons should be developed for hydrocarbon producing regions.
◗◗ Formation evaluation: For formation evaluation, an examination of the effects of
borehole size and varied lithology on measurement accuracy would be useful, as
would a method to differentiate formation gas storage from annular gas storage.
Techniques for accurate formation evaluation logs in larger boreholes with multiple
casing strings would be valuable.

5. Source Identification 43
6.
Remediation Strategies
This section provides an overview of the current state of wellbore remediation, focusing
on regulations, technologies and experience in several of the key hydrocarbon-producing
regions of the world, while focusing on the Canadian experience. It is a summary or the
TRM report entitled Intervention Strategies to Increase Wellbore Leakage Remediation
Success Rates, produced by Jonathan Heseltine and Todd Zahacy of C-FER Technologies,
Edmonton, Alberta.

6.1 Current Practices and Regulations in Well Operation

Regulations governing repair of a leaky well are often not prescriptive. They usually
describe broad objectives and do not specify details on where, when and how a leaky
well should be remediated. This is reasonable given that each well tends to have unique
requirements. The regulations tended to focus on the classification and reporting
requirements rather than potential risks or repair methods and are often specific to
the local jurisdiction and type of well (e.g. onshore versus offshore). Several of the
guidelines and regulations reviewed for this study recommended a risk-based approach
to well leakage classification, management and remediation, especially the oil-producing
countries in the North Sea region. Most regulations appear to allow for some leakage (or
pressure management) during the well’s production life, but require complete isolation
for abandonment (AER, 2003).

The process for repairing leaks in the annulus of hydrocarbon wells generally involves
four steps: (1) identifying the source and a suitable depth for intervention (addressed
in Section 5); (2) developing communication (access) to the source/leakage path; (3)
sealing the leak; and, (4) verifying operational success. In most traditional methods,
communication with the casing-casing or casing-formation annulus is required in
order to inject a sealant to plug the leak. Communication is most commonly established
by perforating the casing and typically also penetrating the cement sheath and near-
wellbore formation layer. Such perforation methods include jet perforation with
shaped explosive charges, bullet perforation, abrasive jetting, and high-pressure fluid
jet perforation. Other methods for gaining annular communication include casing
punching, abrasive cutting (such as circumferential slots, as described by Saponja
(1999), and section milling. Considerations when choosing a method include the
selected remediation sealant, sealant placement method, wellbore depth interval, radial
penetration, and wellbore completion design and casing diameter.

Squeeze placement is the most common method used to place the selected sealant
material. The application of an overbalanced pressure on the sealant forces it
into perforations, annuli and voids. With Portland cement, the pressure against a
permeable formation results in leak-off and causes the slurry to dehydrate, building an
impermeable filter cake. A ‘circulation’ squeeze is similar, with the goal of circulating
cement into a channel behind the casing through two sets of perforations. Controlled
fracture squeezes have also been successfully applied in calcareous caprock formations
penetrated with circumferential jet-cut slots (Saponja, 1999). The practice of squeeze

44 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 placement of sealant materials, such as fine particle Portland cements, is generally
well developed. The choice of an appropriate method and materials will depend on the
downhole environment (geometry, fluids, geology, etc., Watson, 2004; Slater, 2010).
Following penetration through the casing and out into the formation, water is commonly
injected to clean up the penetrations and to develop a water-permeable communication
path to aid in sealant placement. Slater (2010) suggests ultra-low rate pumping of
Class G Portland cement at sufficient pressure to create a network of micro-factures to
access and fill all available voids, with pumping continuing until the cement slurry has
thickened to discourage gas influx and migration.

In many well completions, the casing is not cemented to the surface or even into the next
casing shoe. While this condition presents a potential path for fluid movement, Ness and
Gatti (1995) noted that remediation is generally more successful, compared to a fully
cemented annulus, since access to the large annular flow path is more easily achieved.

6.2 Problems with Current Operational Practices

Remediation of the annular cement sheath has often proven to be difficult. For example,
Saponja (1999) and Wojtanowicz et al. (2001) noted that squeeze cementing success
rates were typically only about 50%, both for Husky’s wells in the Lloydminster region
of Alberta and for offshore wells in the Gulf of Mexico, respectively. A similar number
was recently suggested at a workshop on Western Canadian operations (Alberta
Innovates—Technology Futures, 2015). Anecdotal evidence indicates that costs of
cement remediation can vary from as low as tens of thousands of dollars to millions
or tens of millions on problematic wells (Society of Petroleum Engineers [SPE]/CSGM,
2015; Dusseault et al., 2014; Watson et al., 2002). Inadequate identification of the leak
source and poor communication with the annular leak path are two of the primary
reasons for unsuccessful remedial operations. Remediation materials and methods are
also closely linked with well abandonment, as in order to abandon wells with identified
behind-casing flows or leaks to surface, these flows must first be eliminated.

Operators and service companies are faced with many decisions during remedial job
planning and execution. While industry-recommended practices exist, such as the
DACC Primary and Remedial Cementing Guidelines (DACC, 1995), the Best Practice
Guidelines for Remedial Cementing provided within Well Cementing (Nelson and Guillot,
2006) and field experience described by Slater (2010), it appears that planning of
the remedial operation often relies on the experience of the operator and cementing
service companies.

The proper position for an effective seal is also controversial. Current requirements for
remedial sealing involve squeezing cement into the leak source formation to stop gas
migration at the source. However, the source zone can be difficult to locate (as described
in the preceding chapter) and it may be difficult to push cement into the small flow paths
(Saponja, 1999) and out into the formation, depending on the petrophysical properties
of the rock. As a result, some experts promote the idea of re-establishing a caprock
seal above the contributing source zone (e.g. Saponja, 1999), while others contend
that caprock repairs are often ineffective, being too far above the source location, and

6. Remediation Strategies 45
 prone to damage by pressurized fluid (e.g. Perry, 2005). Cement may also not be an
ideal material for caprock sealing, as the cement particle size and viscosity inhibits the
injection of cement into small fissures and microannuli.

6.3 Improving Operational Practices with Existing Technology

In addition to Portland cement, there are a number of alternate materials being used
and developed for annular remediation of leaking wells. These materials include resins
and other polymers, silicates, geomaterials, salts and metals. There are several potential
benefits of these materials. Many have better sealing properties, including lower
permeability, higher tensile strength, lower Young’s modulus and improved casing bond.
Better fluid rheology and particle size distribution (or no particles) allows many of
these materials to be more readily squeezed into small channels. Finally, many of these
materials exhibit improved longterm stability—they are claimed to be less sensitive to
temperature, load, corrosion or other forms of chemical degradation.
◗◗ Resins are among the most widely used alternate sealant materials (Gamache,
1993). Most of these resins are synthetic thermosetting polymers that are mixed as a
liquid prior to pumping and undergo an exothermic cross-linking chemical reaction
to become a solid. They are commercially available and development for downhole
sealing applications is ongoing. According to Jones et al. (2013), some resins were
previously incompatible with water, limiting their application. However, newer
water-compatible resins have now been applied successfully in the field. The heat
tolerance and durability of resins are still unproven for certain applications, such as
high temperature thermal recovery wells. C-FER Technologies (Heseltine, 2016) is
conducting research to assess the high temperature performance of various resins.
The Alberta Energy Regulator is currently investigating the potential risks these
materials may pose if used above the base of groundwater protection (CSGM, 2016).
◗◗ Pressure-activated sealants are materials that polymerize when subjected to a
sudden drop in pressure. Rusch et al. (2004) describe several case studies where
such materials were used to seal microannular- or microcrack-sized flow paths to
remediate leaking wells. Various placement methods are possible, including placement
down the annulus from surface, a costeffective approach compared to methods
requiring casing perforation and dedicated downhole tubulars. This approach may
provide a method to remediate annular flow to surface while maintaining the casing
pressure integrity. However, it should be noted that blocking the flow near surface
could result in cross flow between permeable zones downhole or breakdown at
the casing shoe. Alberta Energy Regulator Interim Directive ID 2003 01 states that
pumping any type of fluid down the annulus is not an approved repair option (AER,
2003).
◗◗ Sodium silicate is a general term for a synthetic inorganic colloidal compound
composed of negatively charged, nano-sized silicate particles that can be pumped
ahead of cement (or other remediation sealants) into very small fissures (such as
a microannulus) that even fine particle cement blends may not be able to access.
Sodium silicate has been used to remediate gas flow problems for decades (Herring
et al., 1984; Borchardt, 1992). The silicate reacts with its surroundings to form a

46 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 silica/silicate-based plug that will block the flow of gas or liquids by precipitation,
polymerization, bonding to cement and clogging of pores.
◗◗ Metal alloys with relatively low melting points have been proposed to replace
cement in remedial and well-plugging applications. Such materials would be injected
in a molten state and then cool and solidify once placed. In one proposed approach, a
bridge plug is set and a molten bismuth-tin (Bi-Sn) alloy is squeezed into perforations
at pressures below the fracture pressure (Spencer and Lightbown, 2015; Figure 6.1).
The alloy remaining in the wellbore is then milled out. The suggested benefits of metal
sealants include strength, durability, low permeability and volumetric expansion
upon setting. For such seals, it is suggested that the material be placed over an
interval of impermeable caprock, not the permeable source formation. This appears
to contravene Interim Directive 2003 01 (AER, 2003), which notes that the sealant
should be placed at the leak location.

Figure 6.1 Seal Well alloy deployment tools with bismuth-tin alloy cast on the outside of
a cartridge heater. The technology can be used to both seal wells for abandonment and
remediate leaky wells. In either application, the tool is lowered onto a mechanical bridge
plug and the heater is turned on. The second image is of a wellbore analogue system with
an alloy-filled perforation (Spencer and Lightbown, 2015).

◗◗ Various clastic and geo-materials have been proposed for well leakage remediation,
including grouts, clays and silica-based materials. For example, Saasen et al. (2011)
describe the use of an unconsolidated silica material for well abandonment plugging.
The material’s particle size distribution is carefully controlled and, with water as a
bond between the grains, yields a very low permeability barrier (less than 1 mD). Such
materials are non-shrinking, self-healing and removable. While suggested as an option
for wellbore plugging, such materials are also apparently suitable as a behind-casing
barrier (Sandaband, 2016).

6. Remediation Strategies 47
 ◗◗ Permanently expanding the casing is proposed to remediate microannular flow
paths. Kupresan et al. (2014) describe a lab test where expandable casing technology
was used to shut off annular flow. In the tests, an inner casing with a manufactured
microannulus was expanded beyond its yield point with an expansion cone drawn
through the test specimen. Pressure testing showed isolation up to 690 kPa (100
psi) differential over the 24inch-long specimens. They noted that the expansion of
the inner pipe caused the fully hydrated and set cement to change into a “paste like”
state that could be easily crushed. The cement later “rehydrated” into a mechanically
competent material. A tapered cone mechanical expansion system for remediation
of behind-pipe casing flow through micro-annuli, termed the ‘SMART Tool’, is also
described by Duncan et al. (2016).

6.4 Knowledge Gaps and Research Recommendations

6.4.1 Regulatory
Most oil and gas regulations in Canada require immediate action when wellbore leakage
conditions equal or exceed prescribed flowrates, fluid types and pressure buildup rates.
Requirements based on fluid type and buildup pressure may be more easily justified, but
the requirements based on a specific gas flowrate at one point in time do not appear to
consider potential variabilities due to sampling/testing practices (Dusseault et al., 2014)
or the leak from a risk-based perspective. A review of these prescriptive regulations may
be warranted to determine whether there should be additional considerations when
classifying leaks to identify the optimal course of action considering the risks. A risk-
based assessment that considers both the likelihood and consequences of undesirable
events associated with leakage and remediation might be more appropriate. Such an
approach is described in OGP Draft 116530 2 and Norwegian Oil and Gas Association
Recommended Guidelines for Well Integrity No 117 (NOGA, 2011). The primary goal of
such a risk assessment initiative is to establish acceptable leakage conditions. To provide
a context for risk assessment, rates could be compared to other socially accepted natural
and man-made methane sources (e.g. agriculture) (Dusseault et al., 2014).

Risk-based assessments and regulations have several benefits: (1) they allow for
innovation in the development of remedial methods and materials, which can lead to
more effective technologies and reduced costs; (2) they are flexible and can be applied
to diverse situations; and (3) by identifying key risks, limited resources can be applied
most effectively. While allowing greater flexibility and innovation, regulations requiring
fully risk-based decisions have drawbacks. It can be difficult to accurately quantify all
risks. In addition, various stakeholders may have different risk tolerances. The best
approach may be to provide an approved prescriptive remediation option but allow for
risk-based management or innovative solutions to wellbore leakage events. In such a
scenario, the regulator may need to establish a thorough structure and benchmark the
risk-based approach. Many jurisdictions allow operators to apply for an exemption to
prescriptive regulations, with justification. Though not specific to oil and gas, an example
of such a regulation can be found in Ontario’s Brownfields Regulation, which governs
the management of contaminated sites (Ontario, 2017). This regulation prescribes

48 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 generic standards for contaminant remediation, while allowing an alternative risk-based
standard that can take into account site-specific characteristics.

A risk-based assessment of wellbore leakage will likely require input from a wide range
of industry stakeholders to develop the risk framework, create necessary models,
facilitate workshops and interviews, and develop workflows or software tools.

6.4.2 Industry Recommended Practice (IRP) for remediation

Regulations generally provide very limited technical guidance for wellbore remediation.
Some practical guidelines do exist (Watson et al., 2002; Slater, 2010), but are not
comprehensive. This suggests that the industry should consider the development of an
Industry Recommended Practice (IRP) to assist operators and regulators in evaluating
and classifying leaking wells and identifying options for remediation. This approach
is common in the industry, where regulations state the minimum requirements
and technical guidelines to provide assistance for planning, decision making and
conducting operations.

Remedial practices were to be discussed in API RP 65-3 Practices to Prevent or Remediate

Annular Casing Pressure, although it appears that this document is not yet available
to the public (API, 2006). The Drilling and Completions Committee (DACC) plans to
establish practices for remedial cementing in the future (DACC, 2016). An expanded
remedial cementing IRP, preferably supported by broadly shared industry data, would
be beneficial to provide additional information on intervention and remediation topics
such as:
◗◗ Decision making and management processes associated with remediation (e.g. risk-
based flow chart or ranking considerations);
◗◗ Choosing an appropriate cement slurry or sealant material;
◗◗ Determining appropriate remedial job parameters (rate, pressure, method and
completion);
◗◗ Source identification methods;
◗◗ Identifying and selecting an appropriate depth interval for perforation/remediation;
◗◗ Alternate methods for repair and management of wellbore leakage;
◗◗ Descriptions of available alternate materials or methods for downhole remediation
and where they should be considered or avoided. Note that the regulations reviewed
generally refer to Portland cement as a squeeze material although the AER appears to
be accepting of alternate materials, if proven to be suitable (CSGM, 2016);
◗◗ Considerations for specific well applications (multi-stage fracturing, thermal recovery
wells, storage wells, CO2 sequestration wells, geothermal wells, etc.);
◗◗ Data collection, validation, management and application (e.g. consistent parameters
and methods for determining success rates, tracking costs and consequences); and,
◗◗ Post-job assessments and long-term well management.

One challenge often noted in the industry related to the development of remediation
and/or abandonment guidelines is that there is significant variation across applications
and thus a need for specific case-by-case practices, materials and technologies. As

6. Remediation Strategies 49
 a result, there is concern that the effort to create a comprehensive IRP may be too
great or the resulting IRP may be too generic to be useful. In this case, an IRP for well
remediation may provide only guidance on the decision-making process, rather than
prescriptive requirements or specific “step-by-step” instructions. Such a guideline may
also expand on other sections examined with this TRM, such as leak source location and
measurement of leakage rates.

6.4.3 Technology gaps

Remediation of wellbore annular leaks often requires multiple costly attempts—
typically cement squeezes. Materials and methods that improve short-term and long-
term success rates would provide economic and environmental benefits. Development
of remediation and abandonment technology has lagged behind other areas such as
drilling, completion and production, likely in part because it does not generate revenue
(National Petroleum Council [NPC], 2011). Nevertheless, novel methods and materials
are being investigated and developed. These include improved methods for establishing
hydraulic communication with the leak path and placement of sealants. Many of
these technologies appear promising, warranting further research or funding. These
technologies must meet a large number of operational and functional requirements, as
well as Health, Safety and Environment (HSE) regulations during blending, placement,
post-placement, and after well abandonment. Government and industry should consider
developing protocols and methods to consistently assess and qualify the suitability
of these technologies. This would benefit product vendors, users/operators, and
regulators. For example, the United Kingdom Oil and Gas Guidelines on Qualification of
Materials for the Suspension and Abandonment of Wells (Oil & Gas UK, 2012) considers
the qualification of materials other than Portland cement for wellbore abandonment.
While aimed at abandonment materials (typically for plugging tubulars), many of
the objectives and requirements are similar for annular remediation materials. The
guidelines provide a starting point for establishing qualification standards of remedial
material properties and methods.

For qualification of equipment and placement methods, large-scale functionality tests

may be employed (similar to API and ISO protocols and standards available for packers,
bridge plugs, connections, and float equipment). However, existing qualification
procedures may not be applicable to all new technologies or methods. Development
and qualification may rely on engineering analysis or numerical simulation in addition
to physical testing. For example, with the casing expansion methods for microannulus
remediation under development, consideration should be given to determining the
proper amount of expansion for given tubular/cement/formation scenarios. Over-
expansion could potentially result in cement cracking, making a leaking well and
associated risks more severe. Numerical modelling could be used to understand the
sensitivity to various parameters (e.g., Duncan et al., 2016). Determining microannulus
size in the field may require the development of novel measurement methods, for
example by wellbore testing or logging.

It should be noted that in the test described by Kupresan et al. (2014), an outer pipe
provided considerable confining pressure on the cement during expansion. If this
technique is to be used for cement sheaths against weak or shallow formations, the

50 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 performance should be evaluated where significantly less confining pressure is possible
or expected. At the TRM Workshop (CSGM, 2016), it was noted that new technologies
based on this concept are being developed in Canada. One such method being developed
by Suncor (Duncan et al., 2016) was recently presented; it described the numerical
design optimization and lab validation of a casing expansion method.

Qualification methods (e.g. small-scale material testing, modelling, large-scale testing)

may initially be established to address a particular technology and field application.
Where applicable, these methods may later be developed into broad industry standards.
The qualification of methods and materials requires a thorough understanding of the
downhole environment, which includes geology, leak path geometry, temperature,
pressure, load profiles and chemical composition. The development of improved
methods to evaluate and document these downhole conditions and include these
considerations in the technology qualification is suggested.

Remediation of caprock leakage is of potential interest in some wellbore applications

such as the underground storage industry and possibly to other CO2 sequestration and
thermal recovery operators. This area appears to require additional research and the
development of suitable methods and materials. Some jurisdictions allow for the control
and remediation of annular pressure using surface methods, such as injecting down the
annulus. A review of these alternative methods and associated risks is suggested.

6.4.4 Remedial data analysis and sharing

Wellbore leakage is an industry-wide problem. Improvements in remediation efficiency,
success rate, reliability and cost would benefit all stakeholders. The outcome of remedial
efforts (such as squeeze cementing) depends on many factors. Given the large number
of variables, improvements to the process of leaky well remediation have generally
been made after a lengthy and costly trial and error approach. The industry may benefit
from a consistent method of tracking and sharing information related to wellbore
remediation. If this effort results in improved performance, accelerated development
and reduced costs, operators may be motivated to share both successes and failures. A
data analysis and sharing platform would provide a method for thorough, consistent
post-remediation assessments and long-term tracking across the industry. Such an
industry database could be developed by the regional or national regulators or through
a shared industry initiative managed by a third party (AER, 2017).

Dusseault et al. (2014) noted that there has likely been an under reporting of
unsuccessful remedial attempts. As a result, the industry does not have a thorough
understanding of which methods work best and, equally important, those that do not.
Tracking of successes and failures would provide statistical information, perhaps leading
to better understanding of the problems, accelerate technological improvements, and
provide valuable inputs to industry guidelines, recommended practices and risk-based
assessments. The sharing of information may take the form of a shared, searchable
database that tracks key parameters. This database could also contain other well
integrity data to serve a larger purpose.

6. Remediation Strategies 51
7.
Abandonment
The goal of wellbore abandonment is to restore the low permeability of the caprock
formation preventing fluid migration in the wellbore and near wellbore region. The
following sections identify general methods of wellbore abandonment and problems
with the current approach, and make recommendations for future research. This is
a summary of the TRM report entitled Improving Abandonment Processes, which was
written by Robert Walsh and Dru Heagle, Geofirma Engineering, Ottawa, Ontario.

7.1 Current Practices and Regulations

When crude oil and natural gas drilling began in the mid-nineteenth century, there
was no regulation regarding abandonment of a well at the end of its production, and
operators could simply walk away from an open hole in the ground. In the 1890s,
plugging and abandonment regulations were instituted in some jurisdictions, with
the goal of protecting production zones from flooding by freshwater (Pennsylvania
Department of Environmental Protection, 2000). Typically, earlier plugging operations
were designed to prevent the loss of crude oil and natural gas to other formations,
to protect the resource, not the environment. In the United States, early regulations
enabled wells to be plugged with “brush, wood, rocks, paper and linen sacks, or a variety
of other handy items that would serve to hold a sack of cement” (NPC, 2011), which is
consistent with anecdotal information regarding re-abandonment operations on wells
drilled before 1950 in Alberta and Ontario. As regulations improved, cement became a
required material for sealing the producing intervals and the top of the wellbore. Over
time, plugging regulations have progressed to describe the specific intervals at which
cement should be placed and the types of materials allowed between the cement plugs.
The basic technology associated with the plugging and abandoning of wells has not
changed significantly since the 1970s (NPC, 2011).

7.1.1 Current oil and gas abandonment practices

An abandoned wellbore commonly comprises a surface casing that extends below the
base of potable groundwater protection and a production string, or multiple production
strings, that access the target formation. The annular spaces between casing and
formation, and between different casing strings, are cemented or at least partially
cemented. The typical abandonment approach is to emplace cement plugs (typically
API Class G cement), which may be supported by mechanical plugs, within the casing
or in the open hole if the well is uncased (e.g. core and delineation wells). To properly
abandon a well, the well operator must design an abandonment program that identifies
wellbore integrity issues, crude oil and natural gas zones, groundwater zones, and
cement integrity. The basic steps of the modern abandonment process are described
as follows:

52 Technology Roadmap to Improve Wellbore Integrity – Summary Report

1. Test for SCVF/GM: Hydrocarbon wells may develop wellbore leakage either over
time or relatively soon after construction. In Alberta, prior to conducting a surface
abandonment, a surface casing vent flow test is conducted to determine if gas,
liquid or any combination of substances is escaping from the casing vent assembly
(AER, 2003). If such a leak is identified, the problem must be remediated prior to
abandonment (see Section 4).
2. Prepare the wellbore: Before abandonment, production tubing, downhole pumps
and packers must be removed. Following removal of downhole equipment, the
borehole must be cleaned, by flushing the wellbore with a circulation fluid—typically
water. If sealing an uncased well, it is important to remove the mud and mud cake
from the zones of the wellbore where cement will be emplaced. In a cased borehole,
hydrocarbons should be removed to ensure the casing is water wet, allowing cement
to bond to the casing.
3. Plugging: Cement plugs in open holes or within cemented casing are emplaced under
a variety of conditions and using various methods. Cements can be placed in single or
multiple stages in the borehole depending on the requirements. In uncased boreholes,
the most common method for cement plug placement is the balanced plug method. In
Alberta and other Canadian jurisdictions, cased wells classified as low risk are usually
plugged by dump bailing 8 m of cement on a bridge plug installed in the casing (AER,
2016b; Figure 7.1). In addition to cement plugs, mechanical plugs such as bridge
plugs and cement retainers play a role in stopping fluid flow in a wellbore. Where
there is no cement behind the casing, or the cement has been identified as inadequate,
it may be necessary to remediate the annulus cement to isolate permeable zones (see
Section 6). Testing is required to ensure that the plug is placed at the proper level and
provides adequate isolation of permeable zones.
4. Cut and Cap: The final field-step of the abandonment process is to cut and cap the
well. Typically, the casing string must be cut off a minimum of 1 metre below the final
grade of the site. Before the well is cut and capped, the presence of wellbore leakage
must be determined, as described above. In Alberta, a vented cap is required to
prevent pressure buildup in the abandoned well. Other jurisdictions, especially in the
United States, require a sealed cap.

7. Abandonment 53
 Figure 7.1 Examples of cased-hole abandonment for low-risk wells (AER, 2016b).

7.2 Problems with Current Operational Practices

Abandoned well failure modes can be divided into two broad categories: (1) inadequate
sealing and leakage of plugs within the casing; and, (2) inadequate sealing of the
(usually cemented) annulus, outside of the casing. The following sections discuss both
possibilities.

7.2.1 Inadequate sealing of the annular space

As discussed in previous sections, the failure of annulus seals is primarily the result of
poor mud displacement during cementing, gas migration into cement during setting,
microannulus or stress crack formation during operation, or autogenous shrinkage
during cement hydration, leading to the formation of a microannulus (Dusseault et
al., 2000; Zhang and Bachu, 2011). Nygaard (2010) observed that cased wells seem
to be more prone to leak than drilled and abandoned open-hole wells, and injection
wells were more leak-prone than production wells. Research suggests that permeable
interfaces (microannuli) or problems with cement placement are responsible for the
creation of permeable flow pathways in the cement sheath, rather than degradation
of the cement itself (Duguid et al., 2013; Gasda et al., 2013; Crow et al., 2009). Based
on current abandonment practices, problems with the cement sheath may continue to
impact wellbore integrity post-abandonment. Even if a bridge plug set inside the casing
never degrades, the cement plug inside the casing provides a durable seal and the casing
never corrodes, an inadequately sealed cement sheath will still allow fluids to migrate.

54 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 7.2.2 Inadequate plugs inside the casing
In a study of abandonments in Alberta by Watson (2005), fourteen abandoned wells
were investigated to determine the long-term effectiveness of wellbore abandonment
methods. Less than half of the wells had been abandoned for more than 15 years, and
only three had been abandoned for more than 20 years. The small sample cannot be
considered statistically representative of the population of wells, but the results are
nevertheless instructive. Of the re-entered wells, two wells had SCVF upon re-entry,
but GM was not detected in any well. Only 60% of the wells had corrosion inhibition, a
requirement at that time they were abandoned. Only 50% of the wells had the required
cement cap on top of the bridge plug. The investigators state that there was evidence
that the cement plug was placed, but never developed sufficient compressive strength,
and was circulated out of the hole upon re-entry. The one open-hole cement plug
encountered in the investigation did not meet the minimum requirement that it extend
15 m below the surface casing shoe, though a plug log run at the time of abandonment
indicated that it did extend to the required depth (before setting). Encouragingly, all of
the mechanical bridge plugs set in the casing were still providing an effective seal at the
time of re-entry.

This study highlights two potential problems with how wellbore abandonment is
practised today. The lack of inhibition in a large number of wells suggests that regulatory
requirements were not being met. The extremely poor-quality cement in 50% of the
dump-bailed plugs also suggests that the proper cement placement procedure was
not being followed. The authors estimated that 10% of these plugged wells would
fail over the long term and recommended using a balanced plug method or setting a
retainer and squeezing the cement as better alternatives. In a recent communication,
the author of the abandonments study (Watson, 2005) asserted that it is not possible
to consistently achieve good-quality dump-bailed cement plugs because the method is
fundamentally unsound (Watson, personal communication, 2016). If we take as a given
that dump-bailed cement plugs frequently provide no mechanical strength or hydraulic
barrier (because in many cases the cement does not even set), it might make more
sense to change the recommended approach for wells categorized as low risk. Watson
advocates using only mechanical bridge plugs in low-risk wells (i.e. sweet shallow gas),
and that much longer (~100 m) cement plugs be circulated into place in higher risk
abandonments.

7.3 Improving Operational Practices with Existing Technology

There is a great deal of existing technology that can be used to improve the performance
of abandoned wells, reducing the rate of GM and SCVF, and improving the durability of
well sealing systems. This section briefly summarizes various options.

7.3.1 Improving completions

Existing technology can be used to improve the performance of abandoned wells, and
this begins during installation of the casing, long before the well is abandoned. This topic
is covered in Section 4.

7. Abandonment 55
 7.3.2 Casing removal/annulus sealing
Recognizing that many of the problems in wellbore abandonment occur behind the
casing, a number of authors have suggested that milling out or otherwise removing a
section of casing and annulus cement should become a standard practice in wellbore
abandonment (Gray et al., 2007; Carlsen and Abdollahi, 2007). As early as 1999, Husky
Oil (Saponja, 1999) proposed an “economical cap rock repair” solution to the problem
of gas leakage which relied on milling out slots and then fracking with liquid cement
to induce horizontal fractures cutting off gas migration, regardless of the local stress
regime. This type of remedial method is controversial, as discussed in Section 6.2.

7.3.3 Mechanical plugs

Two common types of mechanical plugs are bridge plugs and cement retainers. Bridge
plugs are typically made of cast iron with an elastomer sealing element. Bridge plugs are
effective for sealing the wellbore from upward gas migration, to minimize penetration
by gas of a cement plug during setting, and to minimize contamination of the overlying
cement plug. Bridge plugs can be designed to be easily drillable or made to be more
permanent. It may be possible to obtain copper bridge plugs for greater corrosion
resistance. Cement retainers are used to form the top seal of a plug and allow cement
to be emplaced below the retainer. Cement retainers are effective when higher cement
pressures are required to plug zones (Slater, 2010). They are typically made of drillable
material to enable re-entry of wellbore as needed. Once the tool is set in the well,
cement can be pumped through the retainer to squeeze cement. Once the cement is
squeezed below the retainer, the tubing is retracted and a mechanical flap closes to seal
the cement below the retainer. Cement may be placed on top of a retainer to provide a
more complete seal. Arguably, a cement retainer topped by a concrete cap could also be
used to emplace a bentonite slurry, perhaps with suspended particles of compressed
bentonite.

7.3.4 Improving cement

Cement and cementing practices used in completion and plugging and abandonment
of crude oil and natural gas wells have improved over the past few decades, and there
are constantly new developments in cement technology. This topic is considered in
Section 4.

7.3.5 Bentonite and other sediment-based materials

Historically, bentonite-based drilling mud has been used to plug many wells, relying on
the downward pressure exerted by the weight of the mud column and the gel strength of
the mud. Sodium bentonite pellets have become more commonly used to seal wellbores
since 2000, especially in more shallow wells (i.e. ~500 m deep). Swelling clays offer
advantages over cement, including the ability to swell, deform and self-seal. In many
cases, bentonite may also be a more economical sealing material than cement, though
it may be difficult to emplace at the correct depth before it swells. Under specific
conditions, the use of bentonite pellets to plug wells in the Bakersfield and Coalinga
Districts of California is approved.

56 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 Sandaband® is a ‘dry’ mix of bentonite clay, barite, and up to 75% quartz sand that has
been used in the North Sea for well plugging applications (Saasen et al., 2011). Adding
water and viscosifiers with dispersants to the mixture results in a plastic-like material
(Bingham plastic) that behaves as a liquid when pumped but then returns immediately
to a solid when at rest. Sandaband is incompressible and gas-tight, does not shrink
or fracture, and appears to be chemically stable over time. Although barite has a low
solubility, there may be a longterm loss of barite through diffusion of dissolved barite.

Quellon HD is a commercially available bentonite mixture made of bentonite pellets

(~90%) and magnetite (~10%) (AMEC, 2014). The magnetite increases the density of
the mixture. Before hydration, the bulk density of the Quellon-HD pellets is 1,400 kg/
m3, increasing to 1,880 kg/m3 after hydration in the borehole. In laboratory tests, the
permeability of Quellon HD under a compaction pressure of 190 kPa and a differential
pressure 100 kPa was 6x10-19 m2 (0.0006 mD). Quellon HD has been pumped into
boreholes without problems. Interactions between magnetite and the iron casing have
not been assessed in the available references.

Sealing systems for nuclear waste repositories, including abandoned site

characterization boreholes, have focused significantly on bentonite as a sealing material
(AMEC, 2014). Many organizations responsible for sequestration of nuclear waste have
studied bentonite-based seals. As a typical example, the SKB design requires seals to
have a life of at least 100,000 years and has focused on smectite-rich natural bentonite
MX80 because of the low permeability and the longevity of the clay’s desired properties,
particularly the fact that, unlike cement, bentonite will not crack over time.

7.3.6 Resins
Resin-based sealants may be used for applications that require a relatively high
mechanical strength. The resins may also be more elastic than cement and may be
better suited for situations with varying pressure and temperature (see Section 4.3).
Pumpable resins have a controllable range of density, viscosity and curing time, and are
reported to be impermeable to gas flow. Resins are not sensitive to hydrogen sulphide
or carbon dioxide and do not degrade like cement may. Long-term resistance to elevated
temperature, however, is unknown (Heseltine, 2016).

There are three general categories of resins, including epoxies, phenolics and furans,
each with advantages and disadvantages. Epoxy resins typically have the greatest
bonding strength but relatively fast curing times. Phenolic resins typically have higher
thermal stability and easier to control curing time, but have higher viscosity and greater
health, safety and environmental concerns. Furan resins allow better control over
resin maturation time compared with epoxy resins and lower viscosity, allowing better
penetration of narrow fissures and pores, but may shrink during curing.

Resin applications are typically carried out in low volumes due to the relatively high
cost per volume and because the immature resin is viscous and can be placed only
at a slow rate, which is complicated given the fairly fast curing time. The subsurface
temperature is another significant factor affecting curing time. The immature resins are
highly reactive, which may cause a problem if the resin is injected into the formation and
geochemical reactions inhibit the polymerization (curing) reactions. Resins also have a

7. Abandonment 57
 high unit cost and if the resin cures prematurely, then the tubing used to inject the resin
will likely have to be decommissioned. Resins have been used in proprietary blends
with cements and are used with other plugging materials to create a sealing system for
a borehole. Solid fillers, such as silica flour or calcium carbonate, may be added to resin
mixtures to reduce cost, increase mixture density or provide higher thermal stability.

7.4 Knowledge Gaps and Research Recommendations

Sealing materials for well abandonment must create a seal that is effective over the long
term. The sealing material will likely have to be pumpable to emplace the material at
the necessary depth in the borehole and the material will need to have a low viscosity
before it sets or cures so that the plug is able to access and seal small pathways that may
exist outside of the casing. The material must have a sufficient strength to withstand
subsurface pressures but must also be flexible enough to deform as required and
maintain a bond with the casing and bedrock. The material should maintain enough
strength and not shrink while it cures (or afterwards) so that gas channels or other
permeable pathways cannot form. Over the long term, the seal must be resistant to
corrosion, expansion and contraction, as well as thermal degradation. The material
should also be mixable with additives to control the density and set time of the mixture
and should be usable in sufficient volumes to create a long enough seal.

In addition to the ongoing development of the materials described in Section 7.3,

a number of innovative technologies, at various stages of development, have been
identified. These potential options are briefly summarized here:
◗◗ Thermal sealing is the application of very high temperatures downhole to heat and
melt casing, cement sheath and rock, forming what is presumably a homogeneous and
impermeable seal after it cools and solidifies. Baker Hughes (2015) proposes the use
of a high-powered laser run in on a wireline. Interwell (2015) is developing a method
in which it ignites a heat-generating thermite mixture that generates temperatures
of up to 3,000°C downhole. In August 2016, Interwell tested this technology in two
wells in Alberta. Approaches involving molten rock have also been assessed for sealing
wells for deep well disposal of radioactive waste. Gibb and Travis (2015) describe the
development of a “rock welding” technique in which downhole electrical heating was
used to melt crushed granitic rock taken from the host formation. According to the
authors, this forms a continuous seal virtually identical to the host rock. Unanswered
questions include: (1) Could contraction and cracking of the molten mass during
cooling be a problem? (2) Does a thermally damaged zone develop in the surrounding,
unmelted rock formation? (3) Could boiling pore water or expanded pore fluids in
very low permeability formation material, such as caprock shale layers, hydraulically
fracture adjacent rocks?
◗◗ Molten materials that solidify to form a seal have been proposed by a number
of authors. Nygaard (2010) endorsed using a molten metal alloy that expands
slightly upon cooling for sealing wells at the Wabamun CO2 Sequestration Project.
Kunz (2016) proposed the use of a molten salt mixture as a seal for borehole
abandonment. As discussed in Section 6.3, a report by Spencer and Lightbown
(2015) evaluated Bismuth-Tin alloys as a plug material. The alloy evaluated in this

58 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 report had a melting point of 138°C. To place the seal, solid Bismuth-Tin alloy can
be placed on or in a wireline electrical resistance heating tool. Because the alloy
expands slightly (~1%) when it solidifies, it should form a tight seal against the
borehole walls, assuming adequate pressure is applied to the plug during cooling
(Figure 6.1). This method has been field tested, with reportedly successful results.
In an alternate method, Bisn Tec (2014) proposed the use of a thermite heat
source to melt Bismuth/Germanium alloys to form plugs in deep boreholes.
◗◗ Casing expansion uses a packer-like or other device to apply enough pressure to the
inside of the casing to permanently expand it, compressing the cemented annulus and
closing any microannuli. Kupresan et al. (2014) examined the use of expandable casing
technology and found that a modest amount of expansion was able to effectively seal
the microannulus. They reported that five days after the expansion, the damaged
cement “re-hydrated” into a solid state, regaining its strength. Whether this effect
occurs in much older cement in a wellbore environment is unknown. Winterhawk
Well Abandonment (2016) is developing a well abandonment technology that will
use casing expansion to close the microannular leakage pathway while also leaving
a durable plug inside the casing. The technology uses an expanding ring packer and
modified asphalt (manufactured for road construction) to form the seal. In laboratory
testing, casing expansion of 0.4 mm has been achieved.
◗◗ Engineered biomineralization is a technique that takes advantage of the ability of
microbes to change the chemistry of their environment as they metabolize a food
source. Cunningham et al. (2014) described lab-scale experiments in which the
permeability of fractured and intact Berea sandstone under very high pressures
(1100 psi) was reduced by more than two orders of magnitude following repeated
applications of a solution containing bacteria, urea and dissolved calcium. A follow-
up paper by Phillips et al. (2016) described the results of a field test of this method
in which injectivity was reduced by a factor of approximately four. The advantages
of this approach are that the injected solution can reach much smaller fissures than
cement due to its much lower viscosity and smaller particle size (the microbes are
2-5 µm in diameter). The disadvantage seems to be the requirement for multiple
applications over a number of days, and the uncertain durability of the calcium
carbonate precipitate as the pore fluid reverts to natural conditions once a food source
is withdrawn. Nevertheless, this method is still in an early stage of development
and seems to offer some promise for sealing small permeable features, such as
microannuli.
◗◗ Bentonite placement in boreholes is an ongoing area of research (see Section
5.3.5). Although bentonite has excellent properties for creating borehole seals, one
of the challenges associated with bentonite is how to emplace it at the desired depth
and with sufficient swelling pressure to create a low permeability seal across the
borehole. Another challenge with bentonite is the decreasing swelling potential
with the increasing water salinity. The more saline the groundwater, the less the clay
swells, which may result in an incomplete, relatively permeable seal. However, with an
adequate design, it should be possible to create an effective bentonite-based seal even
in a saline environment.

7. Abandonment 59
There are many requirements for a good sealing material or combination of materials.
As highlighted in the previous sections of the report, there are many methods,
techniques and materials that hold promise for improving wellbore abandonments,
and there is a substantial amount of research and development looking at new methods
and materials for plugging and abandonment. The problem is that these materials
are not moving from the development stage and niche applications into wider usage.
Even alternative approaches that have existed for some time have not gained wide
adoption. This suggests that there is a certain amount of conservatism and perhaps
reluctance among operators and regulators, and that this may be inhibiting progress in
improving standard abandonment methods. This skepticism may be warranted by a lack
of independent and publicly available assessment of the claims made by commercial
oilfield service companies or entrepreneurs, and a lack of testing and endorsement
by regulatory authorities. However, there are no standard test procedures that can
be used to qualify a given plugging technology, although UK Oil and Gas Guidelines on
Qualification of Materials for the Suspension and Abandonment of Wells (Oil & Gas UK,
2012) provide standards to qualify alternate materials for wellbore abandonment.

If standards are developed, materials can be tested for specific properties such as
mechanical strength, corrosion resistance, ductility, long-term durability, and other
properties. It may be difficult to develop clear standards based on our current level of
understanding of key processes in plugging and abandonment. For new systems, such
as the casing expansion plug or the biomineralization technique, it will not be possible
to develop a standard suite of tests to qualify these systems. These technologies need
independent assessment using well-designed testing programs, such as independently
supervised field trials comparing the performance of current and new well
abandonment techniques. Furthermore, leakage at a particular well cannot be predicted
a priori; these trials should occur in formations where there is a high probability of
leakage (for instance, the Lloydminster area might be appropriate) and with a sufficient
number of wells to provide statistically meaningful results.

The results of this assessment should be made public. Such third-party R&D would
greatly improve industry practice because it would be based on proven results
rather than informed intuition. Properly designed, independent research would
also provide a justification for regulators to endorse and allow new abandonment
methods. Development and validation of numerical models of wellbore plugging and
abandonment systems should be part of any independent research program, for use as a
tool to aid in the early evaluation of new methods. Such independent tests would likely
identify technology gaps for investigation in a second phase of R&D.

The deep geological sequestration of carbon dioxide and radioactive waste has
resulted in research into the long-term performance of abandonment techniques
for boreholes in these settings. It may be possible to apply the work carried out in
carbon dioxide and nuclear waste sequestration to provide workable and economic
solutions to abandonment practices in the oil and gas industry. In and near nuclear
waste repositories, borehole sealing approaches typically follow a multi-component,
multiple barrier seal design. This design philosophy might inspire new approaches to
improve the robustness of hydrocarbon well abandonment seals, while keeping costs
under control.

60 Technology Roadmap to Improve Wellbore Integrity – Summary Report

8. Improving Industry Knowledge,
Best Practices and Regulations to Reduce
Wellbore Leakage
This section provides information on how to reduce wellbore leakage by improving the
generation of industry knowledge, transferring and sharing this knowledge, including
in formalized best practices documents, and how regulations can be improved by
both industry knowledge and best practices. Industry knowledge, best practices16
and regulations have a hierarchal relationship. Industry knowledge is a collection of
processes and technology established by either research and development, or trial
and error methodology. Best practices, such as those developed by the Drilling and
Completions Committee (DACC) Industry Recommended Practices (IRPs), and the
Canadian Standards Association (CSA), are initially started by gathering industry
knowledge by willing and pertinent stakeholders to formalize the knowledge into a
publicly available document. Regulations, both provincial and federal, are typically the
minimum threshold or standard for compliance acceptance.

Historically, getting any large industry, including the oil and gas industry, to cooperate
and share knowledge is highly improbable. Exploration and production (E&P)
companies are in competition with each other to retain perceived competitive
advantages, lower costs and improve rates of return. E&P companies are segmented by
types of production, differing well types and provincial boundaries with regulations that
are not unified across Canada.

In the wellbore leakage domain within the oil and gas community, the competitive
advantages are greatly reduced by the requirement to remediate leaking wells
in an efficient and cost-effective manner. As an E&P company solves its wellbore
leakage issues, there is a corresponding reduction in liabilities, which does lead to an
improvement in shareholder value.

This is a summary of the TRM report entitled Improving Industry Knowledge, Best
Practices and Regulations to Reduce Wellbore Leakage.

8.1 Landscape of Wellbore Leakage

There are four major segments of stakeholders with respect to wellbore leakage:
the general public; the oil and gas industry; research and development groups;
and government regulators. This diverse group of stakeholders makes efficient
communication difficult.

16
The term best practice(s) is used here as a general term to describe formally documented practices
recommended by the industry and is equivalent in purpose to other terms such as Industry Recommended
Practices.

8. Improving Industry Knowledge, Best Practices, and Regulations to Reduce Wellbore Leakage 61
 8.1.1 Wellbore leakage knowledge and information groups
In addition to these four main segments, wellbore leakage knowledge and information
groups can be sorted into the following categories:
◗◗ Wellbore leakage interest groups
◗◗ Industry groups that cover wellbore leakage
◗◗ Abandonment interest groups

Wellbore leakage interest groups are quite limited due to the specificity of the
subject. The Canadian Society for Gas Migration (CSGM), now called the Well Integrity
and Abandonment (WIA) Society, was created to address leaky wells. The CSGM’s
mandate was to share industry knowledge and technology to reduce and eliminate
wellbore leakage. In 2017, the CSGM expanded its scope to include well integrity and
abandonments with the associate name change. Petroleum Technology Alliance Canada
(PTAC), through its Alberta Upstream Petroleum Research Fund (AUPRF), provides
industry-directed funding through a volunteer levy that is collected by the Alberta
Energy Regulator (AER).

As in any industry, there are informal groups that gather to discuss problems in that
industry. These are often difficult to find and may be part of informal networks that
will be discussed in the Industry Knowledge section.
Industry groups that will cover wellbore leakage as part of their general coverage to
members are societies and associations such as the Canadian Association of Petroleum
Producers (CAPP), the Canadian Heavy Oil Association (CHOA), the Petroleum Services
Association of Canada (PSAC), the Canadian Institute of Mining, Metallurgy and
Petroleum (CMI), PTAC, the Canadian Well Logging Society (CWLS) and the Society for
Petroleum Engineers (SPE).

Abandonment interest groups would include both the WIA Society and PTAC/
AUPRF, as discussed above. Abandonment interest groups would typically include
wellbore leakage topics in Canada. Wellbore leakage is usually handled at time of well
abandonment, as discussed in a later section.

The industry groups listed above would also cover abandonment topics when the
interest of their memberships dictates.

8.1.2 Overview of industry segments in wellbore leakage

The upstream oil and gas industry in Canada is split into three major segments with
respect to wellbore leakage:

Exploration and production (E&P) companies acquire the right to drill for
hydrocarbons from the respective government body. E&P companies vary in size, from
very small or micro junior up to global super major. This diversity of size is unique to
Canada as most other countries have their hydrocarbon production dominated by global
super majors. Historically, E&P companies have placed minimal attention on repairing
surface casing vent flows and abandonments since this business segment was viewed as
a cost centre with no revenue generation.

62 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 Service and/or technology Companies in the Canadian upstream oil and gas industry
are often considered to be the drivers of technological growth. This is especially true for
the wellbore leakage segment. Service companies view the wellbore leakage segment
as an opportunity for revenue generation that is reasonably stable in an industry where
other service segment activity is highly variable in response to commodity pricing.

Abandonment consultants are often relied upon to fix wellbore leakage. Wellbore
leakage is typically handled by the abandonment business unit of the E&P company.
The majority of wellbore leakage is categorized as non-serious and repair can be
deferred to abandonment. Until the last few years, most abandonment teams consisted
of consultants with specialized skill sets. The specialization included both knowledge of
the abandonment, gas migration and surface casing vent flow regulations, and executing
field operations.

8.1.3 Large and small E&P company differences

Large and small E&P companies have inherent differences that arise from the way
companies need to operate their businesses. When it comes to wellbore leakage, all
companies have issues dealing with this problem.

There is a perception by the general public that the larger E&P companies are the most
advanced and innovative due to large research and development budgets. While this may
be true for the exploration and production segment of the industry, the R&D budget has
rarely filtered down to the abandonment segment.

Large E&P companies have an inherent disconnect between senior management and the
abandonment business unit. This disconnect is due to layers of management between
the two groups and a corporate structure that is not conducive to communication
around abandonments and wellbore leakage.

In the last three years, large E&P companies have made improvements to their wellbore
leakage and abandonment management due to the following reasons:
◗◗ Changes to regulations and financial accounting that requires fiscal accountability to
the liabilities of corporate assets (asset retirement obligations).
◗◗ Dedicated abandonment business team leads that have a strong voice and access to
senior management.
◗◗ Willingness to change the status quo and to apply continual business improvement
practices that are common to other parts of the upstream oil and gas industry and
other businesses.

There is a perception that small Canadian E&P companies are dodging their
responsibility for wellbore leakage and abandonments. This perception is enhanced by
the recent news of bankrupt smaller E&P companies and the media attention applied
to the ballooning count of orphan wells. The number of orphan wells greatly increased
following the oil price crash that began in late 2014 as all companies in the oil industry
struggled to stay profitable.

8. Improving Industry Knowledge, Best Practices, and Regulations to Reduce Wellbore Leakage 63
 Smaller companies can be leaders in the abandonment and wellbore integrity field.
As the saying goes, necessity is the mother of invention. When balance sheets were
impacted with more realistic liabilities for abandonments, smaller companies had to
became much more innovative.

Smaller companies that have had innovators on abandonment teams have been very
successful in reducing their company’s liabilities. These innovators have worked with
other companies, suppliers, as well as industry organizations such as the WIA society
and PTAC to create efficient and successful abandonment campaigns. An excellent
example is listed in the main Best Practices report.

8.2 Relationship Between Industry Knowledge, Best Practices

and Regulations
Industry knowledge is primarily developed by both E&P companies and service/
technology companies. Experimentation on new processes and technologies becomes
industry knowledge with time. The challenge with industry knowledge is ensuring
the experimentation is properly understood, documented and verified. Future success
hinges on understanding what has been previously accomplished. An analogy for
industry knowledge is Alpha Testing in the software design industry.

Best practices are formalized documents that provide guidance to the industry. Best
practices have general acceptance from the industry as they are formulated from
industry knowledge. These practices can evolve and adapt as additional research/
data becomes available. An analogy for best practices is Beta Testing in the software
design industry.

In the past as regulations were initially developed, there was a strong reliance upon
industry knowledge. Today, most of the industry has some form of regulation for each
stage of the well life cycle. To create new or update existing regulations using industry
knowledge alone is not possible due to the societal pressures that include the public’s
and non-governmental organizations’ (NGO) concern regarding the industry’s social
license to operate. Industry knowledge is not enough to provide an adequate reason or
sufficient evidence to change regulations.

The inclusion of industry knowledge in best practice documentation allows feedback

from industry stakeholders and ensures proper science and experimentation has
occurred. Best practices are a way to implement processes and, in some cases,
technology that is superior to the mandatory regulations. To continue with the software
design industry analogy, we move from Alpha Testing to Beta Testing.

Once best practices are formally documented, the documentation should be used to
update the regulations to meet the current needs of industry and society.

64 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 8.3 Industry Knowledge
Industry knowledge is developed by both E&P companies and service/technology
companies. This information is passed through E&P company mentorship or from
service/technology companies looking to implement their processes and/or technology
improvements for the E&P companies.

8.3.1 Industry knowledge concerns

◗◗ Lack of knowledge sharing: Remediation and abandonment teams rarely take time
to formally share knowledge such as presentations and papers at industry events.
This knowledge is commonly kept in-house, is often not formally documented, and is
passed by word of mouth from mentor to mentee.
◗◗ Lack of scientific rigour: The biggest issue with industry knowledge is the lack
of a disciplined scientific process to validate the results of the trial and error
experimentations. When success is perceived to occur, this success is not well
understood. Additional experimentation then occurs at other companies trying to
replicate the success. Duplication of this experimentation causes the wellbore leakage
path to improvement to be inefficient. Rarely is the experimentation subjected to peer
review, other than a short presentation at one of the technical societies. A critical part
of the process of turning industry knowledge into a best practice is the validation of
the trial and error experimentation that formed the industry knowledge.
◗◗ Outdated industry knowledge: Industry knowledge, due to the two points above, is
not subject to continued review and improvement. This has resulted in the continued
use and promotion of ineffective and outdated industry knowledge.

8.3.2 Recommendations to improve industry knowledge

Two key recommendations for sharing industry knowledge are additional collaboration
during the creation process, and sharing the new information.

Facilitating collaboration to improve the creation of industry knowledge: Often the

trial and error method of creating industry knowledge is self-contained in the E&P path
or the service/technology company. Collaboration between E&P and service/technology
companies would be a more efficient and cost-effective path to the common goal of
reducing and repairing wellbore leakage. Recommendations to facilitate this are:
◗◗ Facilitation of multiple parties that are usually in competition with each other will
require a distinct neutral third party to make the collaboration a success and keep the
project on track.
◗◗ Collaboration must include E&P companies, service/technology companies and
consultants. Exclusion of any party would both decrease the value of the collaboration
and provide a barrier to adoption of the industry knowledge.

8. Improving Industry Knowledge, Best Practices, and Regulations to Reduce Wellbore Leakage 65
 Improving the sharing of new industry knowledge: Once companies have success,
new industry knowledge information should be shared via technical presentations,
formal papers or word of mouth. By sharing this knowledge, it will allow for additional
groups to build on initial successes as well as identify areas where initial successes do
not apply. Formal papers will also be able to be peer reviewed. Recommendations to
achieve this include:
◗◗ Technical knowledge sharing can occur at both internal E&P information sharing and
at industry conferences or industry society meetings.
◗◗ The Canadian upstream oil and gas industry needs to increase the amount of formal
papers through a recognized wellbore leakage entity, like the SPE, to share industry
knowledge within the country and internationally.
◗◗ Companies may be hesitant to share knowledge because they are worried about
increased scrutiny from the regulator. In order to improve knowledge sharing, it
is recommended that regulators not use knowledge sharing as an opportunity to
target specific companies, provided such companies conducted their activities as
per  egulations.
◗◗ In addition to protecting knowledge sharing, additional incentives for E&P companies
on related topics that would reduce immediate cost while improving long-term
efficiencies should be considered. These incentives should be constructed around
activities related to wellbore leakage, such as abandonment timeliness, area-based
closures or orphan well payments.

8.4 Best Practices

8.4.1 Best practices concerns
Wellbore leakage currently has little documentation on best practices for prevention and
remediation. Most “considered” best practices are decades old. These old best practices
are significantly outdated and should no longer be considered effective.

An example of outdated best practices is the common practice of running a noise/

temperature log to acquire data on source identification. This practice originated
from “The Structure and Interpretation of Noise from Flow Behind Cemented Casing”
(McKinley et al., 1973) on noise logging and is considered to be the current standard by
industry personnel that are not intimately involved in wellbore leakage.

The technology and process presented in the McKinley paper should be consider the
absolute minimum data collection required. Most abandonment engineers using the
methods in the McKinley paper have not fully understood this paper. The paper is based
on wellbore leakage in California from the early 1970s. Only one of the example wells
had confirmed cement to surface. Often wells of this vintage in California had only
the bottom section of the well cemented. In addition, the example wells had very high
flow leakage rates. These types of wells would be an anomaly in Canada with modern
well construction. These outdated practices have been improperly handed down from
mentor to mentee without consideration of changes in industry, including the evolution
of combining technology with process.

66 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 In addition to outdated practices, the creation of best practices takes significant time
and resources. The author has seen IRPs with timelines of more than four years from
initiation to completion and significant time investment. Who should be responsible for
managing the cost of the best practices process?

The creation of new best practices on wellbore leakage must follow a standardized
process that emphasises collaboration across stakeholders. The process of establishing
best practices should utilize industry knowledge, technology development and science,
as described in the following section.

Once best practices are crafted, they need to be communicated to the industry.
Communication to industry needs to incorporate the reasons why the best practices
should be followed. The best practices will often incur additional front-end costs;
however, these costs will be offset by improved efficiencies and lower full life cycle
well costs. The initial higher front-end costs will be a hurdle for some E&P companies,
especially in the current low commodity price environment. The reasons for change
must be clearly communicated to the industry to ensure the adoption of the new
best practices.

8.4.2 Recommendations to improve best practice production processes

The first step in creating a best practice is defining which area will be addressed
by it. With respect to wellbore leakage, there should be best practices (i.e. industry
recommended practices) for drilling, cementing, completion, remediation and
abandonment. For example, the recently released DACC IRP Volume #25, Primary
Cementing (Drilling and Completions Committee, 2017) addresses primary cementation
on new wells.

Preparation of a best practice will involve collaboration between E&P companies,

service/technology companies, industry associations and regulators. A facilitator, such
as DACC or CSA, will often be required to keep the project on track. Industry knowledge
is amalgamated and vetted by the best practices steering committee. The best practices
consortium decides which pieces of the process needs to be documented and where
there should be flexibility in the process to incorporate future improvements.

In crafting a best practices process for wellbore leakage, stakeholders would include
the following four distinct groups: industry, regulators, facilitators, and industry
associations. Of the four stakeholders listed, E&P companies need to be major
stakeholders as these companies have ownership of the wells. It is important, especially
in the area of wellbore leakage, that E&P companies are not the only industry voice.

In the Canadian wellbore leakage space, service/technology companies are often the
leaders in conducting R&D, resulting in technology improvements and pushing process
boundaries for improvement.

Industry associations and societies must be consulted very early in the best practices
process. The industry associations know which of their members have the highest
knowledge of processes and technology.

8. Improving Industry Knowledge, Best Practices, and Regulations to Reduce Wellbore Leakage 67
 8.5 Regulations
The majority of oil and gas activity is located within provincial boundaries and falls
under the responsibility of the individual provinces. The provincial regulators are
responsible to the people of the respective provinces who “own” the resources.

In 1938, Alberta’s regulator, the Petroleum and Natural Gas Conservation Board, was
established to steward the province’s resources. This first regulator was to ensure that
the oil and gas industry was held accountable to acceptable practices. Regulations were
initially drafted from the available industry knowledge. Provincial regulations, in most
situations, should be considered the minimum requirement for compliance.

Regulations are slow to change and will become outdated as the industry evolves. As
an example, the first drilling and cementation regulation, established in 1938, did not
consider that drilling would occur horizontally.
An area of concern, in addition to the need to evolve regulations, is that the regulations
may differ between provinces—an issue for E&P companies with wells in more than one
province.

8.5.1 Regulations summary

In summary, regulations need to be updated to the current needs of the industry to
allow for efficient improvement of wellbore integrity. The updates to regulations should
be validated by data gathered following the scientific process. This is different from
industry best practices. Industry best practices can be the result of trial and error and
may not have been validated by science.

The oil and gas industry is still in its infancy when conducting and documenting science
on wellbore leakage. In addition, there is currently no process to present validated
science to update regulations. This lack of a process to modernize the regulations
through the use of science is a significant barrier to reducing wellbore leakage.

8.5.2 Recommendations for improving regulations

Regulations are difficult to change due to their nature. Historically there have been
regulation changes that have caused unintended consequences and therefore regulators
must consider the environmental impacts, industry economics, public perception and
the sustainability of the resource. The modification and development of new regulations
needs to be based on scientifically rigorous data.

The upstream oil and gas sector already participates in wellbore integrity science.
However, industry perception is that there is limited interest and willingness on the part
of regulators to consider modifying regulations based on such science (provided it was
conducted in a scientifically rigorous manner).

In order to incent the industry to conduct and share the results of its wellbore integrity
studies, regulators must develop a framework to evolve regulations as understanding of
the wellbore integrity science is increased.

68 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 As an example, data have been supplied to a regulator demonstrating that the GHG
emissions associated with repairing non-serious leaks on remote wells are significantly
more than the wells would emit if left venting at ultra low rates. There is currently no
provision in the regulations to consider this type of scenario, and thus all leaks have to
be fixed regardless. In order to effectively reduce wellbore leakage-related emissions, it
is recommended that leaky wells be prioritized so that the largest emitters are repaired
first, and that repair-related emissions be considered to determine if remediating the
well is even worthwhile.

8.6 Additional Recommendations to Reduce Wellbore Leakage

The previous three sections provided recommendations on reducing wellbore leakage
by improving the development of industry knowledge, best practices/industry
recommended practices, and regulations. The previous chapters of the TRM provided
recommendations on reducing wellbore leakage during a specific phase of a well’s life
cycle. Below are a number of other recommendations that are more general in nature.

8.6.1 Communication of best practices

One of the largest issues in most industries is the process of disseminating industry
knowledge and best practices efficiently. The upstream oil and gas industry in Canada
should be considered as extremely conservative. There will be an internal resistance to
change. Formal documentation of industry knowledge and incorporating this knowledge
into a best practices document will greatly improve the acceptance of better practices.

As seen throughout the TRM, the current state of industry knowledge is quite extensive.
There is, of course, additional knowledge to be gained, tested and validated, since
every industry should strive for continuous improvement as has been highlighted in
the TRM reports on drilling and completions, source identification, remediations, and
abandonments.

A key recommendation to reduce wellbore leakage in the short and long term is to
increase communication between stakeholders. Sharing of industry knowledge, followed
closely by the creation of best practices, is the most efficient way to a quick win for both
the industry and the environment.

8.6.2 Developing regulatory consistency amongst provinces

Provincial jurisdiction for the upstream oil and gas industry has the unintended
consequence of regulations that can significantly differ between provinces. Varied
provincial regulations make operating in multiple provinces less efficient for the
industry when companies are required to follow different regulations.

In addition, the cost of adherence differs for E&P companies when regulations are
different. This cost will impact the financial considerations of oil and gas development,
providing an advantage to one province over another. This advantage may also coincide
with a potential cost to the environmental impact of oil and gas development.

8. Improving Industry Knowledge, Best Practices, and Regulations to Reduce Wellbore Leakage 69
 The western provinces are collaborating more often than ever before. The Western
Regulator Forum was held on February 8 and 9, 2017. This forum included E&P
companies, service/technology companies, NRCan, CSGM/WIA Society Executives, as
well as regulator representation from Alberta, British Columbia, Saskatchewan and the
National Energy Board (NEB).

The recommendation is to bring upstream oil and gas jurisdictions in Canada into close
alignment with respect to regulations. Additional communication between regulators
plus collaborative forums with stakeholders will create meaningful discussions on the
best path forward for reducing wellbore leakage by aligning regulations.

8.6.3 Increase and fully utilize funding for research and development
Research and development is undertaken by academia, E&P companies, and service/
technology companies. All three contribute to solving wellbore leakage issues in
different ways. The TRM is to provide a current snapshot of the wellbore leakage in
the upstream oil and gas industry. The hope is that a coordinated effort will make the
additional changes necessary to efficiently solve the issues surrounding leaky wells.

Canada has numerous tax credits, grants and subsidies available; these are detailed
in the full Best Practices report. While academia understands most funding options
available to them, oil industry companies do not. Funding will be required from both the
industry and governments to accomplish the TRM goals. In addition, as mentioned in the
R&D section of the Best Practices report, there are additional avenues to provide funding
which will assist the upstream oil and gas industry in reducing wellbore leakage.

Communication of R&D funding options is a recommendation. A related

recommendation is to provide wellbore leakage-specific funding into a combined pool
from federal, provincial, NSERC and industry sources with a long-term commitment (10
years+) that will enable the recommendations from the TRM to be fully realized. This
funding pool should be handled by an independent party that has the ability to facilitate
all stakeholders and coordinate the TRM R&D recommendations.

8.6.4 Full life cycle project analysis

In most industries, budgets are compartmentalized to provide a reasonable amount
of autonomy to individual teams. The oil and gas industry is no different. The drilling
and completions team’s budget is kept separate from the production and abandonment
budgets.

A consequence of separate budgets and incentives in siloed organizations is that

teams are discouraged from considering the cost of the entire life cycle of wells in
their planning and execution. When a well is not drilled or completed properly, there
may be additional remediation and abandonment costs. These costs can be significant,
especially if there is a surface casing vent flow on deep wells that have internal
hardware. The author has personally worked on wells that have cost millions of dollars
per repair attempt.

Raising awareness within the upstream oil and gas industry of the high cost of well
integrity failure is a recommendation of this report.

70 Technology Roadmap to Improve Wellbore Integrity – Summary Report

 8.6.5 New employee training and education
An additional suggestion for reducing wellbore leakage is to have new technical oil and
gas employees exposed to the industry in reverse, rather than the current practice of
starting at the beginning of the well life cycle in the drilling department. Starting a new
engineer in training (EIT) in the abandonment department prior to moving to other
areas of the oil and gas business gives the new employee a unique perspective on how
all of the other phases of the well life cycle impact abandonments. The drilling and
completion phases are the two biggest expenditures of an oil and gas well and have the
most impact on the cost of abandonments. Wells that are poorly drilled or completed
will cost orders of magnitude greater to abandon.

8.6.6 Multi-well abandonment programs

Another key component of efficient abandonment campaigns is the ability to treat the
campaign as a multi-well project instead of individual wells. The author has seen good
multi-well campaigns from both large and small operators as well as the exact opposite
results for both company sizes. Larger companies have more abandonments and
therefore it should be easier for them to have bigger multi-well abandonments. Having
more abandonments does not mean that a multi-well program is well executed.
A recommendation for improving abandonment efficiencies is to provide the
abandonment team, whether it is composed of consultants or an internal team, a
significant role or voice in the long-term viability of the company. Too often, companies
prioritize drilling and completion of new wells when they also need to understand the
cost of managing their assets to end of life.

8.6.7 Dedicated abandonment teams versus part-time employees

and consultants
To be effective, E&P companies need to have personnel dedicated to abandonments.
At smaller and intermediate companies, this dedication does not need to be a full-time
employee with 100% of their time dedicated to abandonments; however, the personnel
must have a primary focus on reducing wellbore leakage and abandonments. There
is specific technical knowledge with respect to wellbore leakage repair at time of
abandonment. Dedicated personnel will be able to learn and develop this knowledge to
continually improve the process.

8.6.8 Long-term abandonment planning versus short-term compliance

Successful abandonment projects require adequate funding and significant detailed
planning. There needs to be a long-term plan (5 years +) to ensure efficiency. Regulators
need to shift their thinking to offer more flexibility to allow E&P companies, especially
larger companies, to efficiently manage long-term abandonment projects. However,
E&P companies must be held accountable to their long-term plans on a yearly or even
better, on a biannual basis. Long-term plans must have adequate funding, regardless of
commodity pricing.

8. Improving Industry Knowledge, Best Practices, and Regulations to Reduce Wellbore Leakage 71
9.

References
American Association of Petroleum Geologists. 2015. Datapages/Search and Discovery
Article #90213 CSPG Chemical Source Neutron-Density Versus Dual-Burst Pulsed
Neutron Decay Log – A Comparison of Cased Hole Wireline Results. CSPG/CSEG/
CWLS Convention 2004, Innovation, Collaboration, Exploration: Building to the
Future, Calgary, AB, Canada, May 31-June 4, 2004.

Agbasimalo, N. 2012. Experimental Study of the Effect of Drilling Fluid Contamination on

the Integrity of Cement-Formation Interface. Louisiana State University. Louisiana
State University.

Alberta Agriculture and Forestry. No date. Module 8 – Protecting Your Well From
Contamination. http://www1.agric.gov.ab.ca/$department/deptdocs.nsf/all/
wwg413/$file/waterwells_Module8.pdf.

Alberta Energy Regulator. 2003. Isolation Packer Testing, Reporting, and Repair
Requirements; Surface Casing Vent Flow/Gas Migration Testing, Reporting, and
Repair Requirements; Casing Failure Reporting and Repair Requirements. Interim
Directive ID 2003-01, January 30.

Alberta Energy Regulator. 2016a. Surface Casing Vent Flow and Gas Migration – Natural
Gas Emissions Rates (Draft Copy), June 2016, 10 p.

Alberta Energy Regulator. 2016b. Directive 020, Well Abandonment (March 2016).

Alberta Energy Regulator. 2017. Western Regulatory Forum (WRF): Workshop on

Suspended and Abandoned Well Integrity. AER Calgary. February 2017.

Alberta Energy Regulator. 2018. ST37: List of wells in Alberta – Monthly Updates.
Accessed April 2018. Available from https://www.aer.ca/providing-information/
data-and-reports/statistical-reports/st37.

Alberta Innovates—Technology Futures. 2015. Summary Report of the Workshop on

“Gas Migration along Wellbores.” Report to CanmetENERGY, March 12, 2015, 13 p.

AMEC Foster Wheeler (AMEC), 2014. Sealing Deep Site Investigation Boreholes: Phase 1
Report, AMEC, Oxfordshire, UK (prepared for Radioactive Waste Management Ltd).

American Petroleum Institute. 2006. Annular Casing Pressure Management for Offshore
Wells. API Recommended Practice 90, First Edition, August.

Aslanyan, A., Davydov, D. 2012. Spectral Noise Logging SNL-6 Technical Overview. TGT
Oilfield Services: Webpage https://tgtoil.com/products/snl-6/. Accessed: 21 Sept.
2016.

Bachu, S. 2017. Analysis of gas leakage occurrence along wells in Alberta, Canada, from
a GHG perspective – Gas migration outside well casing, International Journal of
Greenhouse Gas Control, Volume 61, June 2017, pp. 146-154.

72 Technology Roadmap to Improve Wellbore Integrity – Summary Report

Baker Hughes Incorporated. 2015. Laser Plug and Abandon Method. United States
Patent Application Publication US 2015/0152708 A1, United States Patent Office,
Washington, D.C.

BC Oil & Gas Commission. 2015. Managing Surface Casing Vent Flows with Casing
Connections. Kelowna: British Columbia O&G Commission-Industry Bulletin 2015-
2016-June 19th.

Bisn Tec Ltd. 2014. Heat Sources and Alloys for Use in Downhole Applications,
International Patent Application WO 2014/096857 A2, World Intellectual Property
Organization, Geneva, Switzerland.

Bois, A. G.-M. 2011. SPE-124719-How to Prevent Loss of Zonal Isolation Through a

Comprehensive Analysis of Microannulus Formation. Society of Petroleum Engineers
(SPE), 13-31.

Bonett, A. P. (1996, Spring Nil Day). Getting to the Root of Gas Migration. Oilfield Review,
pp. 36-49.

Borchardt, J. 1992. In-situ gelation of silicates in drilling, well completion and oil
production. Colloids and Surfaces 63: 189-199.

Boukheifa, L. M.-D. 2005. SPE-87195-Evaluation of Cement Systems for Oil and Gas Well
Zonal Isolation in a Full-Scale Annular Geometry. Society of Petroleum Society (SPE),
44-53.

Boyer, G., 2016. In-situ well integrity seminar/workshop, Calgary, June 30, 2017, Alberta
Energy Regulator, 23 p.

Brandt, A.R., G. A. Heath, E. A. Kort, F. O’Sullivan, G. Pétron, S. M. Jordaan, P. Tans, J.

Wilcox, A. M. Gopstein, D. Arent, S. Wofsy, N. J. Brown, R. Bradley, G. D. Stucky, D.
Eardley, R. Harriss and others. 2014. Methane Leaks from North American Natural
Gas Systems. Science.

British Petroleum. 2017. BP Statistical Review of World Energy, June 2017. 66th Edition.
Retrieved from https://www.bp.com/en/global/corporate/energy-economics/
statistical-review-of-world-energy/downloads.html.

British Petroleum. 2018. BP Energy Outlook 2018 edition. BP Energy Economics.

Retrieved from bp.com/energyoutlook.

Bunnell, J.E., R.B. Finkelman, J.A. Centeno, O. Selinus, 2007. Medical Geology: A globally
emerging discipline. Geologica Acta, Vol.5/3, pp. 273-281.

Canadian Association of Petroleum Producers. 2016. Retrieved from https://capp.ca/

publications-and-statistics/statistics/statistical-handbook.

Canadian Association of Petroleum Producers. 2017. Technical Report – Statistical

Handbook for Canada’s Upstream Petroleum Industry, October 2017.

Canadian Association of Petroleum Producers. 2018. Canadian Economic Contribution.

Retrieved from https://www.capp.ca/canadian-oil-and-natural-gas/canadian-
economic-contribution.

9. References 73
Carlsen M. and J. Abdollahi. 2007. Permanent abandonment of CO2 storage wells. Sintef
report 54523200.

Carrion, C. A. (2011). SPE-163084-Elastic Self-Sealing Cement and Swellable Packer Tool

Provides Competent Zonal Isolation to Withstand the Stress Regimes During the Life
of the Well: Ecuador Case History. South American Oil and Gas Congress (pp. 1-11).
Maricaibo, Venezuela: Society of Petroleum Engineers.

Carter., L. G., and Evans., G. W. (1964, Feb). A Study of Cement-Pipe Bonding. Journal of
Petroleum Technology, pp. 157-160.

Cavanagh, P., Johnson, C.R., LeRoy-Delage, S., DeBruijn, G., Cooper, I., Guillot, D., Bulte, H.
and Dargaud, B. 2007. Self-Healing Cement – Novel Technology to Achieve Leak-Free
Wells. SPE/IADC Drilling Conference, Amsterdam, The Netherlands, February, SPE/
IADC 105781.

CBC News. Feb 21, 2018. Orphan well clean-up costs could sting Alberta taxpayers if
regulator loses court battle. Retrieved from http://www.cbc.ca/news/business/
alberta-orphan-wells-1.4543559.

Centeno, J.A., Finkelman, R.B., Selinus, O. 2016. Medical Geology: Impacts of the
Natural Environment on Public Health. Geosciences 2016, 6(1), 8 p.; doi:10.3390/
geosciences6010008.

Chafin, D. 1994. Sources and Migration Pathways of Natural Gas in Near-Surface Ground
Water Beneath the Animas River Valley, Colorado and New Mexico. Denver: U.S.
Geological Survey-Water-Resources Investigations Report 94-4006.

Chanton, J., Chaser, L., Glaser, P., and Siegel, D. 2005. Carbon and hydrogen isotopic
effects in microbial methane from terrestrial environments, in: Stable isotopes and
biosphere-atmosphere interactions, edited by: Flanagan, L. B., Ehleringer, J. R., and
Pataki, D. E., Elsevier Academic Press, London, pp. 85–105.

Cheung, K. and Mayer, B. 2009. Chemical and Isotopic Characterization of Shallow

Groundwater from Selected Monitoring Wells in Alberta: Part 1: 2006-2007.
Retrieved from http://www.assembly.ab.ca/lao/library/egovdocs/2009/
alen/173473.pdf.

Conference Board of Canada. 2011. Greenhouse Gas (GHG) Emissions. http://www.

conferenceboard.ca/hcp/details/environment/greenhouse-gas-emissions.aspx.

Conrad, R. 1996. Soil Microorganisms as contollers of atmospheric trace gases (H2, CO,
CH4, OCS, N2O, and NO). Microbiological Reviews, v.60/4, pp. 609-640.

Council of Canadian Academies. 2014. Environmental Impacts of Shale Gas Extraction

in Canada. Ottawa (ON): The Expert Panel on Harnessing Science and Technology to
Understand the Environmental Impacts of Shale Gas Extraction, Council of Canadian
Academies.

74 Technology Roadmap to Improve Wellbore Integrity – Summary Report

Creaney, S., Allan, J., Cole, K. S., Fowler, M. G., Brooks, P. W., Osadetz, K. G., Macqueen R.
W., Snowdon, L. R., Riediger, C. L. (1994). Chapter 32: Petroleum generation and
migration in the western Canada Sedimentary Basin; in G. Mossop and I. Shetsen
(compilers); Geological Atlas of the Western Canada Sedimentary Basin. Canadian
Society of Petroleum Geologists and Alberta Research Council, Calgary and
Edmonton, pp. 455-470.

Crook, R. and J. Heatherman. 1998. Predicting potential gas-flow rates to help determine
the best cementing practices, Drilling Contractor, November/December: pp. 40-43.

Canadian Standards Association. 2016. CSA Z625-16 Well design for petroleum and
natural gas industry systems. Toronto, Ontario: CSA Group.

Canadian Society for Gas Migration. 2016. Technology Roadmap Workshop. Hanover
Building, Calgary. June 28.

Cunningham, A.B., A.J. Phillips, E. Troyer, E. Lauchnor, R. Hiebert, R. Gerlach, and L.

Spangler. 2014. Wellbore leakage mitigation using engineered biomineralization.
Energy Procedia 63: 4612-4619.

Darrah, T.H., Vengosh, A., Jackson, R.B., Warner, N.R. and Poreda, R.J. 2014. Noble gases
identify the mechanisms of fugitive gas contamination in drinking-water wells
overlying the Marcellus and Barnett Shales Proceedings of the National Academy of
Sciences, 111 (39) 14076-14081; published ahead of print September 15, 2014.

Davis, S. H. 1977. The effect of natural gas on trees and other vegetation. Journal of
Arboriculture, v. 3/8, pp. 153-154.

Drew, M.C., 1991. Oxygen deficiency in the root environment and plant mineral
nutrition, in: Jackson, M.B., Davies, D.D., Lambers, H. (Eds.), Plant Life Under Oxygen
Deprivation. SPB Academic Publishing, The Hague, pp. 303–316.

Drilling and Completions Committee Alberta. 1995. Primary and Remedial Cementing
Guidelines. April 1995.

Drilling and Completions Committee. 2012. IRP-3: In Situ Heavy Oil Operations. Volume
03 – 2012. Enform Canada, Edition #3.2, November 2012. Calgary. Enform.

Drilling and Completions Committee. 2016. IRP # 25: Primary Cementing. Volume 25 –
2016 (Draft). Calgary. Enform.

Drilling and Completions Committee. 2017. IRP # 25: Primary Cementing. Volume 25 –
2017. Edition 1.0. January 2017. Enform.

Duncan, G., Young, S., Graham, J., Crockett, M. and Tymko, D. 2016. Remediation of
Surface Casing Vent Flows for Thermal Wellbores. SPE Thermal Well Integrity and
Design Symposium, November 29 – December 1, Banff, AB.

Dusseault, M. B., M. N. Gray, and P.A. Nawrocki. 2000. Why Oilwells Leak: Cement
Behaviour and Long-Term Consequences. Society of Petroleum Engineers, SPE
64733.

9. References 75
Dusseault, M. J. 2014. Seepage Pathway Assessment for Natural Gas to Shallow
Groundwater During Well Stimulation, in: Production and After Abandonment.
Environmental Geosciences Volume 21 Number 3-ISSN 1075-9565, pp. 107-126.

Dusseault, M. and R.E. Jackson. 2014. Seepage pathway assessment for natural
gas to shallow groundwater during well stimulation, in production, and after
abandonment, Environmental Geosciences 21(3):107-126.

Dusseault, M., R.E. Jackson and D. MacDonald. 2014. Towards a Road Map for Mitigating
the Rates and Occurrences of Long-Term Wellbore Leakage. Retrieved from http://
geofirma.com/wp-content/uploads/2015/05/lwp-final-report_compressed.pdf.

Elkington, P. A. S., Pereira, A., and Samworth, R. 2006. A Novel Cased Hole Density-
Neutron Log – Characteristics and Interpretation. Society of Petroleum Engineers.
doi:10.2118/101078-MS.

Ellis, D., Luling, M. G., Markley, M. E., Mosse, L., Neumann, S., Pilot, G., Stowe, I. 2004.
Cased-Hole Formation-Density Logging – Some Field Experiences, SPWLA 45th
Annual Logging Symposium held in Noordwijk, The Netherlands, June 6–9, 2004.
SPWLA-2004-G.

Environmental Defense Fund and Pembina Institute. 2015. Economic Analysis of

Methane Emission Reduction Opportunities in the Canadian Oil and Natural Gas
Industries. Calgary, 117 p., https://www.pembina.org/reports/edf-icf-methane-
opportunities.pdf.

Environment and Climate Change Canada. 2017. Proposed methane regulations

(June 2017). Retrieved from http://ec.gc.ca/lcpe-cepa/default.
asp?lang=En&xml=BF68F2B3-03F9-4B3D-B5A9-1D5BC0A25A21.

Environment and Climate Change Canada. 2017b. National Inventory Report 1990-2015:
Greenhouse Gas Sources and Sinks in Canada. Part 1.

Environment and Climate Change Canada. 2017c. National Inventory Report 1990-2015:
Greenhouse Gas Sources and Sinks in Canada. Part 2.

Environment and Climate Change Canada. 2017d. National Inventory Report 1990-2015:
Greenhouse Gas Sources and Sinks in Canada. Part 3.

Environmental Defense Fund and Pembina Institute. 2015. Economic Analysis of

Methane Emission Reduction Opportunities in the Canadian Oil and Natural Gas
Industries. Calgary, 117 p., https://www.pembina.org/reports/edf-icf-methane-
opportunities.pdf.

Etiope, G., Lassey, K. R., Klusman, R. W., and Boschi E. 2008. Reappraisal of the fossil
methane budget and related emission from geologic sources. Geophysical Research
Letters, Vol. 35, L09307, doi:10.1029/2008GL033623.

Etiope, G. 2015. Natural gas seepage. The Earth’s hydrocarbon degassing. Springer,
p. 199.

Alberta Energy and Utilities Board. 2003. Interim Directive 2003-01, Alberta Energy and
Utilities Board, January 30, 2003.

76 Technology Roadmap to Improve Wellbore Integrity – Summary Report

Gamache, M.T. 1993. Resin Use in the Petroleum Industry of California. California
Department of Conservation, Sacramento, California, Report No. 1.

Gibb, G.F. and K.P. Travis. 2015. Sealing Deep Borehole Disposals of Radioactive Waste
by “Rock Welding.” Conference on International High Level Radioactive Waste
Management, Charleston, SC, April 12-16, 2015.

Godwin, R., Abouguendia, Z., Thorpe, J. 1990. Lloydminster Area Operators Gas Migration
Team Response of Soils and Plants to Natural Gas Migration from Two Wells in the
Lloydminster Area, Saskatchewan Research Council, E-2510-3-E-90, 85 p.

Gopal, K., Tripathy, S., Bersillon, J.-L., Dubey, S. P. 2007. Chlorination byproducts, their
toxicodynamics and removal from drinking water, Journal of Hazardous Materials,
Volume 140, Issues 1–2, 9 February 2007, Pages 1-6, ISSN 0304-3894.

Gray, K., E. Podnos, and E. Becker. 2007. Finite Element Studies of Near-Wellbore Region
During Cementing Operations: Part I. Production and Operations Symposium, 31
March–April 2007, Oklahoma City, Oklahoma, U.S.A. SPE 106998.

Hammond, P.A. 2016. The relationship between methane migration and shale-gas well
operations near Dimock, Pennsylvania, USA, Hydrogeology Journal 24(2): 503-519.

Hamper M. J. 2006. Manufactured Gas History and Processes. Environmental Forensics,

7:1, 55-64, DOI: 10.1080/15275920500506790.

Harder, A.H., Whitman, H.M., and Rogers, S.M. 1965. Methane in the freshwater aquifers
of southwestern Louisiana and theoretical explosion hazards: Department of
Conservation, Louisiana Geological Survey, and Louisiana Department of Public
Works Water Resources Pamphlet no. 14, 22 p.

Health Canada. 2017. Guidelines for Canadian Drinking Water Quality – Summary Table.
Water and Air Quality Bureau, Healthy Environments and Consumer Safety Branch,
Health Canada, Ottawa, Ontario.

Herring, G.D., J.T. Milloway, ARCO Alaska Inc., and W.N. Wilson. 1984. Selective Gas Shut-
off Using Sodium Silicate in the Prudhoe Bay Field, AK. SPE 12473. Presented at the
Formation Damage Control Symposium, Bakersfield, CA, Feb 13-14, 1984.

Heseltine, J.L. 2016. Evaluation of Alternate Cements for Thermal Wells. Presentation at
SPE Thermal Well Integrity and Design Symposium. Banff, Canada, November 1.

Hetrick, L. 2011. Well Integrity Case Study. EPA Hydraulic Fracturing Study Technical
Workshop #2 (p. 36). Washington, D.C.: United States Environmental Protection
Agency (EPA).

Hoeks, J. 1972. Changes in composition in soil air near leaks in natural gas mains. Soil
Science, v. 113, pp. 46-54.

Huang, H. 2015. Recognition of sources of secondary biogenic gases in the oil sands
areas, Western Canada Sedimentary Basin. Bulletin of Canadian Petroleum Geology,
pp. 20-32.

9. References 77
Hull, J. W., Gosselin, L., and Borzel, K. 2010. Well Integrity Monitoring and Analysis
Using Distributed Acoustic Fiber Optic Sensors. Society of Petroleum Engineers.
doi:10.2118/128304-MS.

Humez, P., Mayer, B., Ing, J., Nightingale, M., Becker, V., Kingston A., Akbilgic, O., Taylor, S.
2016a. Occurrence and origin of methane in groundwater in Alberta (Canada): Gas
geochemical and isotopic approaches. Science of the Total Environment, v. 541, pp.
1253-1258.

Humez, P., Mayer, B., Nightingale, M., Ing, J., Becker, V., Jones, D., and Lam, V. 2016b.
An 8-year record of gas geochemistry and isotopic composition of methane
during baseline sampling at a groundwater observation well in Alberta (Canada),
Hydrogeology Journal, February 2016, Volume 24, pp. 109-122, DOI 10.1007/
s10040-015-1319-1.

Humez, P., Mayer, B., Nightingale, M., Becker, V., Kingston, A., Talylor, S., Bayegnak,
G., Millot, R., and Kloppmann, W. 2016c. Redox controls on methane formation,
migration and fate in shallow aquifers. – Hydrology and Earth System Sciences, 20
1-19.

Hunt, J. M. 1979. Petroleum Geochemistry and Geology. W. H. Freeman and Co., San
Francisco, 617 p.

Ibatullin, T.R. 2009, SAGD performance improvement in reservoirs with high solution
gas-oil ratio. Oil and Gas Business, 9 p., http://www.ogbus.ru/eng/.

International Energy Agency. 2017. World Energy Outlook. International Energy Agency.
Paris, France.

Intergovernmental Panel on Climate Change. 2013. Summary for Policy Makers, in:
Climate Change 2013: The Physical Science Basis. Contribution of Working Group I
to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change
[Stocker, T.F., D. Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A. Nauels, Y.
Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge University Press, Cambridge, United
Kingdom and New York, NY, USA, 1535 pp, doi:10.1017/CBO9781107415324.

International Standards Organization. 2017. 16530-1:2017 Petroleum and natural gas

industries –- Well integrity – Part 1: Life cycle governance.

Interwell Technology AS. 2015. Method of Well Operation, United States Patent
Application Publication US 2015/0034317 A1, United States Patent Office,
Washington, D.C.

Jackson, R. B., Down, A., Phillips, N. G., Ackley, R. C., Cook, C. W., Plata, D. L., Zhao, Z. 2014.
Natural gas pipeline leaks across Washington D.C., Environmental Science and
Technology. v. 48/3, pp. 2051–2058, DOI: 10.1021/es404474x.

Jackson R.B., B Rainey Pearson, SG Osborn, NR Warner, A Vengosh. 2011. Research and
Policy Recommendations for Hydraulic Fracturing and Shale‐Gas Extraction. Center
on Global Change, Duke University, Durham, NC. Retrieved from https://nicholas.
duke.edu/cgc/HydraulicFracturingWhitepaper2011.pdf.

78 Technology Roadmap to Improve Wellbore Integrity – Summary Report

Johson, M.R., Tyner, D.R., Conley, S., Schwietzke, S., Zavala-Araiza, D. 2017. Comparisons
of Airborne Measurements and Inventory Estimates of Methane Emissions in the
Alberta Upstream Oil and Gas Sector. Environmental Science Technology 2017 51
(21), 13008-13017 DOI: 10.1021/acs.est.7b03525.

Jones, D.M., Head, I.M, Gray, N.D, Adams, J.J., Rowan, A.,K., Aitken, C.M., Bennett, B., Huang,
H., Brown, A., Bowler, B.F.J., Oldernburg, T., Erdmann, M., Larter, S.R. 2008. Crude-oil
biodegradation via methanogenesis in subsurface petroleum reservoirs. Nature. v.
451, 10 January 2008. doi:10.1038/nature06484.

Jones, P.J., London, B.A., Tennison, L.B. and Karcher, J.D. 2013. Unconventional
Remediation in the Utica Shale Using Advanced Resin Technologies. SPE Eastern
Regional Meeting, Pittsburgh, Pennsylvania, USA, August, SPE 165699.

Kelly, W.R., Matisoff, G. and Fisher, J.B. 1985. The effects of a gas well blow out on
groundwater chemistry. Environ. Geol. Water Sci 7: pp. 205-213. doi:10.1007/
BF02509921.

King, G. K. 2012. Cement Evaluation Methods to Prove Isolation of Barriers in Oil and Gas
Wells: Should a Cement Bond Log (CBL) Be Run or Required in Every Well? George
E King Consulting: http://gekengineering.com/Downloads/ Free_Downloads/
Cement_Bond_Log_(CBL)_Overview-DRAFT-2.docx.

Kunz, D. 2016. Eutectic salt abandonment plug for wellbores, Canadian Patent
Application CA 2828241 A1, Canadian Intellectual Property Office, Ottawa-Hull,
Canada.

Kupresan, D., J. Heathman, and M. Radonjic. 2014. Experimental Assessment of Casing

Expansion as a Solution to Microannular Gas Migration. Society of Petroleum
Engineers. IADC/SPE Drilling Conference and Exhibition, 4-6 March, Fort Worth,
Texas, USA. SPE-168056-MS.

Leach, A., Adams, A., Cairns, S., Coady, L., and G. Lambert. 2015. Climate Leadership
Report to Minister, Alberta Climate Leadership Panel, https://www.alberta.ca/
documents/climate/climate-leadership-report-to-minister.pdf.

Mayer, B., P. Humez, V. Becker, M. Nightingale, J. Ing, A. Kingston, C. Clarkson, A. Cahill, E.

Parker, J. Cherry, R. Millot, W. Kloppmann,K. Osadetz and D. Lawton. 2015. Prospects
and Limitations of Chemical and Isotopic Groundwater Monitoring to Assess the
Potential Environmental Impacts of Unconventional Oil and Gas Development.
Procedia Earth and Planetary Science, v. 13, pp. 320-323.

Maslennikova, Y. S., Bochkarev, V. V., Savinkov, A. V., and Davydov, D. A. 2.012. Spectral
Noise Logging Data Processing Technology. Society of Petroleum Engineers.
doi:10.2118/162081-MS

McKinley, R. M., Bower, F. M., and Rumble, R. C. 1973. The Structure and Interpretation
of Noise from Flow Behind Cemented Casing. Society of Petroleum Engineers.
doi:10.2118/3999-PA.

9. References 79
Milkov, A.V. 2011. Worldwide distribution and significance of secondary
microbial methane formed during petroleum biodegredation in conventional
reservoirs. Organic Geochemistry. v.42 (2011) pp. 184-207. doi:10.1016/j.
orggeochem.2010.12.003.

Mims, M. and Krep, T. 2003. Drilling Design and Implementation for Extended Reach and
Complex Wells. K&M Technology Group, LLC. Houston, Texas.

Moore, T.A. 2012. Coalbed methane: A review. International Journal of Coal Geology. v.
101 pp. 36-81. doi: 10.1016/j.coal.2012.05.011.

Muehlenbachs, K. 2010, Lessons from the Isotopic Analyses of Surface Vent Flow Gas,
Western Canada Basin (abstract). GeoCanada 2010 Joint Annual Meeting, Calgary.
4 p., http://cseg.ca/assets/files/resources/abstracts/2010/0965_GC2010_
Lessons_from_the_Isotopic_Analyses.pdf.

Muehlenbachs, K. 2012, Identifying the Sources of Fugitive Methane Associated with

Shale Gas Development, updated with new data, January 2012, 36 p., Original
presented on November 14, 2011 at “Managing the risks of shale gas: Identifying
a pathway toward responsible development” held at Resources for the Future,
Washington, DC. http://www.rff.org/files/sharepoint/Documents/Events/
Seminars/111114_Managing_the_Risks_of_Shale_Gas/Mulenbachs%20Nov%20
14FINAL.pdf.

Muehlenbachs, L. 2017. 80,000 Inactive oil wells: A blessing or a curse? The School of
Public Policy, University of Calgary. SPP Briefing Paper. Volume 10, Issue 3, February
2017.

Munro, M. (2014a, December 9). Part 3: Trouble Beneath Our Feet – Energy wells can
‘communicate’ and ‘sterilize’ the landscape. Edmonton Journal.

Munro, M. (2014b, December 8). Part 2: Trouble Beneath Our Feet – Trying to plug the
leak in Calmar, Alberta. The Edmonton Journal.

National Energy Board. 2017a. Canada’s Energy Future 2017. Energy Supply and
Demand Projections to 2040. Cat. No. NE2-12/2017E-PDF. ISSN 2292-1710.

National Energy Board. 2017b. Canada’s Energy Future 2017 Supplement: Conventional,
Tight and Shale Oil Production. Appendix Data and Figures. Available from https://
www.neb-one.gc.ca/nrg/ntgrtd/ftr/2017cnvntnll/index-eng.html.

National Energy Board. 2017c. Canada’s Energy Future 2017 Supplement: Natural Gas
Production. Appendix Data and Figures. Available from https://www.neb-one.gc.ca/
nrg/ntgrtd/ftr/2017ntrlgs/index-eng.html.

National Petroleum Council. 2011. Plugging and Abandonment of Oil and Gas Wells.
Prepared by the Technology Subgroup of the Operations & Environment Task Group,
September 15.

Nelson, E. B. and Guillot, D. 2006. Well Cementing. J. Smith, Ed., Second Ed.,
Schlumberger.

80 Technology Roadmap to Improve Wellbore Integrity – Summary Report

Ness, I. and Gatti, A. 1995. Gas Migration Remediation Process Development. Annual
Technical Meeting of the Petroleum Society of Canada, Calgary, Alberta, June 7-9,
Paper No. 95-87.

Noomen, M. F., Harald M.A. van der Werff, Freek D. van der Meer. 2012. Spectral and
spatial indicators of botanical changes caused by long-term hydrocarbon seepage
Ecological Informatics v.8, pp. 55–64.

Norwegian Oil and Gas Association (NOGA). 2011. Norwegian Oil and Gas Recommended
Guidelines for Well Integrity. No. 117, Revision 4, June 6.

Nowamooz, A., J.-M. Lemieux, J. Molson, and R. Therrien. 2015. Numerical investigation
of methane and formation fluid leakage along the casing of a decommissioned shale
gas well. Water Resources Research, 51, 4592–4622, doi:10.1002/2014WR016146.

Nygaard, R. 2010. Well Design and Well Integrity – Wabamun Area CO2 Sequestration
Project (WASP), Energy and Environmental Systems Group, University of Calgary.
OGCI 2015: https://www.oilandgasclimateinitiative.com/.

Odom, R. C., Paul, P., Diocee, S. S., Bailey, S. M., Zander, D., Gillespie, J. J. 1999. Shaly
Sand Analysis using Density-Neutron Porosities from a Cased-hole Pulsed Neutron
System. Society of Petroleum Engineers. doi:10.2118/55641-MS.

Oil & Gas UK. 2012. Guidelines for the Suspension and Abandonment of Wells. The
United Kingdom Offshore Oil and Gas Industry Association Limited, Issue 4, July.

Ontario. 2017. Environmental Protection Act, Ontario Regulation 153/04, Records

of site condition — part XV.1 of the act. https://www.ontario.ca/laws/
regulation/040153, accessed November 2017.

Osadetz, K.G., Snowdon, L.R. and Brooks, P.W. 1994. Oil families in Cdn. Williston Basin
(SW Sask.). Bull. Cdn. Pet. Geol., 42/2:155 177.

Osadetz, K.G., Mort, A., Snowdon, L.R., Lawton, D.C., Chen, Z., and Saeedfar, A. 2018.
Western Canada Sedimentary Basin petroleum systems: A working and evolving
paradigm, in: D. Eaton and P. K. Pedersen (eds.) Low-permeability resource plays of
the Western Canada Sedimentary Basin: Defining the sweet spots. Interpretation,
Volume 6, Issue 2 (May 2018). SE63-SE98. doi.org/10.1190/INT-2017-0165.1.

Oyarhossein, M. and M. Dusseault. 2015. Wellbore Stress Changes and Microannulus

Development Because of Cement Shrinkage, presented at the 49th US Rock
Mechanics/Geomechanics Symposium held in San Francisco, CA, USA, 28 June-1 July
2015.

Pennsylvania Department of Environmental Protection. 2000. Pennsylvania’s Plan for

Addressing Problem Abandoned Wells and Orphaned Wells (DEP Document No.
550-0800-001), Pennsylvania Department of Environmental Protection – Bureau
of Oil and Gas Management, http://www.elibrary.dep.state.pa.us/dsweb/Get/
Version-48262/, accessed May 2016.

9. References 81
Perry, K.F. 2005. Chapter 9: Natural Gas Storage Industry Experience and Technology:
Potential Application to CO2 Geological Storage. Carbon Dioxide Capture for Storage
in Deep Geologic Formations – Results from the CO2 Capture Project, Vol. 2, Thomas,
D.C. and Benson, S.M. (Eds.), Elsevier B.V., Amsterdam, The Netherlands, pp. 815825.

Phillips, N. G., Robert Ackley, Eric R. Crosson, Adrian Down, Lucy R. Hutyra, Max
Brondfield, Jonathan D. Karr, Kaiguang Zhao, Robert B. Jackson. 2013. Mapping
urban pipeline leaks: Methane leaks across Boston, Environmental Pollution, Volume
173, pp. 1-4, ISSN 0269-7491, http://dx.doi.org/10.1016/j.envpol.2012.11.003.

Phillips, A.J., A.B. Cunningham, R. Gerlach, R. Hiebert, C. Hwang, B.P. Lomans, J. Westrich,
C. Mantilla, J. Kirksey, R. Esposito, and L. Spangler. 2016. Sealing with Microbially-
Induced Calcium Carbonate Precipitation: A Field Study, Environmental Science &
Technology 50(7): 4111-4117.

Praagman, F. and Rambags, F. 2008. Migration of Natural Gas through the Shallow
Subsurface: Implications on the surveillance of low-pressure pipelines, M.Sc. thesis,
University of Utrecht.

Reagan, M. T., G. J. Moridis, N. D. Keen, and J. N. Johnson. 2015. Numerical Simulation of

the Environmental Impact of Hydraulic Fracturing of Tight/Shale Gas Reservoirs on
Near-Surface Groundwater: Background, Base Cases, Shallow Reservoirs, Short-Term
Gas and Water Transport, Water Resources Research 51 (4):2543-2573.

Rich, K., K. Muehlenbachs, K. Uhrich, and G. Greenwood. 1995. Carbon Isotope

Characterization of Migrating Gas in the Heavy Oil Fields of Alberta, Canada. SPE
International Heavy Oil Symposium, 19-21 June, Calgary, Alberta. SPE-30265-MS.

Rostron B.J., Arkadakskiy S. 2014. Fingerprinting “stray” formation fluids associated

with hydrocarbon exploration and production. Elements, August 2014, v. 10 p. (4)
291-296.

Rowe, D. and K. Muehlenbachs. 1999. Isotopic fingerprints of shallow gases in the

Western Canadian sedimentary basin: Tools for remediation of leaking heavy oil
wells. Organic Geochemistry, 30: 861–871.

Rusch, D.W., Sabins, F. and Aslakson, J. 2004. Microannulus Leaks Repaired with
Pressure-Activated Sealant. SPE Eastern Regional Meeting, Charleston, West Virginia,
USA, September, SPE 91399.

Saasen, A., S. Wold, B.T. Ribesen, T.N. Tran, A. Huse, V. Rygg, and A. Svindland. 2011.
Permanent Abandonment of a North Sea Well Using Unconsolidated Well-Plugging
Material. SPE Drilling and Completion, 26(3): 371-375. SPE-133446-PA.

Sahakian, A. B., Jee, S. R., Pimentel, M, 2010. Methane and the Gastrointestinal Tract.
Digestive Diseases and Sciences, v. 55/8, pp. 2135-2143.

Sandaband. 2016. Sandaband Material. July 17, Available from: http://www.sandaband.

com/files/93bafb43-7a6d-4828-90a4-efe8fee065de.pdf.

82 Technology Roadmap to Improve Wellbore Integrity – Summary Report

Saponja, J. 1999. Surface Casing Vent Flow and Gas Migration Remedial Elimination
–New Technique Proves Economic and Highly Successful. Journal of Canadian
Petroleum Technology, Special Edition 1999 38 (13), paper 95-86.

Sherman, H. and Locke, S. 1975. Effect of Porosity on Depth of Investigation of Neutron

and Density Sondes. Society of Petroleum Engineers. doi:10.2118/5510-MS.

Slater, H.E. 2010. The Recommended Practice for Surface Casing Vent Flow and Gas
Migration Intervention. SPE Annual Technical Conference and Exhibition held in
Florence, Italy, 19–22 September 2010. SPE 134257.

Smith, K. L., Colls, J. J., and Steven, M. D. 2005. A facility to investigate effects of elevated
soil gas concentration on vegetation. Water, Air and Soil Pollution, v. 161, pp. 75-96.

Society of Petroleum Engineers/Canadian Society of Gas Migration. 2015. Gas Migration

and Challenges – Identification and Treatment Workshop. Banff. May 2015.
Spencer, H. and V. Lightbown. 2015. Permanent Sealing of Greenhouse Gas Emitting
Wells Final Outcomes Report, CCEMC Project C110113. Climate Change and
Emissions Management Corporation.

Statistics Canada. March 2, 2018. Gross domestic product at basic prices, primary
industries. Retrieved from http://www.statcan.gc.ca/tables-tableaux/sum-som/
l01/cst01/prim03-eng.htm.

Steven, M. D., Smith, K. L., Beardsley, M. D., and Colls, J. J. 2006. Oxygen and methane
depletion in soil affected by leakage of natural gas. European Journal of Soil Science.
V. 57, pp. 800-807.

Summers, R., 2010. Alberta water well survey – Report prepared for Alberta
Environment, University of Alberta, 106 p. http://aep.alberta.ca/water/programs-
and-services/groundwater/documents/AlbertaWaterWellSurvey-Report-Dec2010.
pdf.

Szatkowski, B., Whittaker, S., Johnson, B. 2002. Identifying the Source of Migrating
Gases in Surface Casing Vents and Soils Using Stable Carbon Isotopes, Golden Lake
Pool, West-central Saskatchewan. Summary of Investigations 2001, Volume 1,
Saskatchewan Geological Survey, Sask. Industry and Resources, Misc. Rep. 2002-4.1,
pp. 118-125.

Themelis, N. J. and Ulloa, P. A. 2007. Methane generation in landfills. Renewable Energy,

v. 32, pp. 1243-1257.

The Prasino Group. 2013. Final report for determining bleed rates for pneumatic devices
in British Columbia. December 18, 2013.

Tilley, B. and K. Muehlenbachs. 2011. Fingerprinting of gas contamination groundwater

and soil in a petroliferous region. Proceedings from International Network of
Environmental Forensics Conference, Cambridge, UK, July 25-27, 2011.

Tissot, B. P. and Welte, D. H. 1984. Petroleum Formation and Occurrence: Second and
Revised and Enlarged Edition, Springer Verlag, Berlin, 699 p.

9. References 83
Van Stempvoort, D., Maathuis, H., Jaworski, E., Mayer, B., Rich, K. 2005. Oxidation
of Fugitive Methane in Ground Water Linked to Bacterial Sulfate Reduction.
Groundwater. V. 43/2, pp. 187–199.

Vidic, R. D., Branteley, S. L., Vandenbossche, J. M., Yoxtheimer, D., Abad, J. D. 2013, Impact
of shale gas development on regional water quality. Science, v. 340, 1235009 pp.
826-835. DOI: 10.1126/science.1235009.

Vignes, B, and B.S. Aadnoy. 2010. Well-Integrity Issues Offshore Norway. SPE Production
& Operations. 25. 10.2118/112535-MS.

Viswanathan, H. S., Pawar, R. J., Stauffer, P. H., Kaszuba, J. P., Carey, J. W., Olsen, S. C., . .
. Guthrie, G. D. 2008. Development of a hybrid process and system model for the
assessment of wellbore leakage at a geologic CO2 sequestration site. Environmental
Science and Technology, 42(19), 7280-7286. DOI: 10.1021/es800417x

Watson, T.L. 2004. Surface Casing Vent Flow Repair – A Process. Petroleum Society
of Canada Canadian International Petroleum Conference, June 810, Calgary, AB.
PETSOC-2004-297.

Watson, T. 2005. Wellbore Re-Entry Investigation for Abandonment Evaluation, Revision

2. Alberta Energy and Utilities Board.

Watson, T., Getzlaf, D. and Griffith, J.E. 2002. Specialized Cement Design and Placement
Procedures Prove Successful for Mitigating Casing Vent Flows – Case Histories. SPE
Gas Technology Symposium. Calgary, Alberta. SPE 76333.

Watson, T., 2007. Alberta Oil and Gas Regulations – The Key to Wellbore Integrity. Third
Wellbore Integrity Network Meeting, Santa Fe, New Mexico, March 13, 2007. http://
slideplayer.com/slide/8756935/.

Watson T.L. and Bachu S. 2007. Evaluation of the potential for gas and CO2 leakage along
wellbores, SPE 106817, 11 p.

Watson, T. and S. Bachu. 2008. Identification of wells with high CO2-leakage potential
in mature oilfields developed for CO2-enhanced oil recovery. Richardson, Texas:
Society of Petroleum Engineers, SPE 112924.

Watson, T. and S. Bachu. 2009. Evaluation of the potential for gas and CO2 leakage along
wellbores. SPE Drilling and Completion, 24(1):115–126. SPE 106817.

Webber, J. (1949). Fundamental Forces Involved in the Use of Oil Well Packers.
Petroleum Transactions, AIME, 271-278.

West, J.J., Fiore, A.M., Horowitz, L.W., Mauzerall, D.L. 2006. Global health benefits of
mitigating ozone pollution with methane emission controls. Proceedings of the
National Academy of Sciences U.S.A. 103, 3988e3993.

White House, 2014. Climate Action Plan – Strategy to Reduce Methane Emissions. The
White House, Washington, USA. https://obamawhitehouse.archives.gov/sites/
default/files/strategy_to_reduce_methane_emissions_2014-03-28_final.pdf.

84 Technology Roadmap to Improve Wellbore Integrity – Summary Report

Winterhawk Well Abandonment Ltd. 2016. Thermo-Mechanical Abandonment Tool
(TMAT) Technology Information Session. PTAC Technology Information Session,
February 16, 2016.

Witt, C. P. (2016, May 16). Senior Cement Engineer, Stingray Well Solutions. (D. Ewen,
Interviewer).

Wojtanowicz, A. K., Nishikawa, S. and Rong, X. 2001. Diagnosis and Remediation of

Sustained Casing Pressure in Wells. U.S. Department of Interior, Herndon, Virginia,
Final Report, July 31.

World Health Organization. 2011. Guidelines for Drinking-water Quality. Fourth Edition.
World Health Organization. ISBN 978 92 4 154815 1.

Xie, J., Fan, C., Tao, G. and Matthews, C. M. 2011. Impact of Casing Rotation on Premium
Connection Service Life, in: Horizontal Thermal Wells. World Heavy Oil Congress,
Paper WHOC11-558, Edmonton, Canada, March.
Zhang, S., and Shuai, Y., 2015. Geochemistry and distribution of biogenic gas in China.
Bulletin of Canadian Petroleum Geology, v. 63, i. 1, pp. 53-65.

Zhou, C. G. (2015). AADE-15-NTCE-05-Microporous Spongy Carbon as Compressibility/

Elasticity Enhancer. American Association of Drilling Engineers (AADE), 1-7.

Zulqarnain, M. (2012). Simulations of the Primary Cement Placement in Annular

Geometries During Well Completions Using Computational Fluid Dynamics (CFD).
Louisiana State University, Petroleum Engineering. New Orleans: Louisiana State
University.

9. References 85