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Heavy Oil And Oil Sands Operations

Industry Recommended

Practice (IRP)

Volume 3 - 2002

Sanctioned

2002 - 01

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This document as well as future revisions and additions are available from:

Enform

1538 25 Avenue NECalgary, Alberta

T2E 8Y3

Phone: (403) 250-9606Fax: (403) 291-9408

Website: www.enform.ca

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Table of Contents

3 Heavy Oil And Oi l Sands Operat ions ...................................................... 1

3.0 Acknowledgement And Scope.................................................................. 1

3.0.1 Acknowledgement And Disclaimer.......................................... 13.0.2 Forward ......................................................................................... 43.0.3 Scope ............................................................................................ 7

3.0.4 Introduction................................................................................... 93.0.5 Heavy Oil And Oil Sands Criteria And Definitions................103.0.6 References ................................................................................. 17

3.1 Drilling ..................................................................................................... 18

3.1.1 Scope .......................................................................................... 183.1.2 Well Control Systems For Low Risk Heavy Oil / Oil SandsWells ...................................................................................................... 193.1.3 Well Control Systems For Moderate To High Risk Heavy OilWells ...................................................................................................... 303.1.4 Ghost Hole And Sidetrack Wells ......................................... 473.1.5 Cementing Of Casing ............................................................... 50

3.1.6 Thermal Casing And Casing Connections ............................ 583.1.7 Horizontal Well Guidelines....................................................... 743.1.8 Environment And Drilling Waste Management ....................823.1.9 References ................................................................................. 92

Appendix A Blow-Out Preventer Diagrams .................................. 96Appendix B Line System Pressure Loss Diagrams ..................103Appendix C Diagrams of Typical Bop System Pressure Loss Vs.Minimum Surface Casing Or Conductor Pipe Depth Requirements .. .................................................................................................... 110

Appendix D- Example Wash-over Remedial Cement Program .122Appendix E Thermal / Mechanical Relationship Diagrams for

Common Grades of Oilfield Casing................................................... 124Appendix F Environmental Cracking Mechanisms ...................139Appendix G Horizontal Well Stick Diagram ............................. 141

Heavy Oil And Oil Sands Operations Table of Contents i

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3.2 Well Servicing........................................................................................ 1423.2.1 Scope ........................................................................................ 1423.2.2 Definitions ................................................................................. 1423.2.3 Service Rigs ............................................................................. 1443.2.4 Continuous Rod Rigs .............................................................. 1603.2.5 Snubbing Units ........................................................................ 1623.2.6 Pressure Trucks ...................................................................... 1643.2.7 Flush-By Units.......................................................................... 1653.2.8 Environment, Health, And Safety ......................................... 171

Appendix 1 Servicing Blowout Prevention Systems-Class 2A ...176Appendix 2 Primary Recovery Well H2S Release Rate

Determination........................................................................................ 177Appendix 3 Alberta Department of Environment.......................... 178

3.3 Production Equipment And Procedures............................................. 181

3.3.1 Scope ........................................................................................ 1813.3.2 Definitions ................................................................................. 1823.3.3 Surface Equipment (Single Well Battery) ............................ 1843.3.4 Lease Dikes.............................................................................. 1873.3.5 Lease Size And Equipment Spacing .................................... 1883.3.6 Gathering And Treating Equipment ...................................... 1893.3.7 Sour Criteria And Requirements ........................................... 1923.3.8 Fired Equipment ...................................................................... 1933.3.9 Wellhead Design ..................................................................... 196

3.4 Measurement And Accounting ............................................................ 205

3.4.1 Scope ........................................................................................ 2053.4.2 Measurements Needs ............................................................ 2063.4.3 Production Reporting .............................................................. 2093.4.4 Well Testing.............................................................................. 2203.4.5 Sampling ................................................................................... 2353.4.6 Pro-Ration Factors .................................................................. 238

Appendix 1 Suggested Method of Test Duration Determination .240

Heavy Oil And Oil Sands Operations Table of Contents ii

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3 Heavy Oil And Oil Sands Operations

Recommended By

Associations

Canadian Association of Oilwell Drilling Contractors

Canadian Association of Petroleum Producers

Petroleum Services Association of Canada

Small Explorers and Producers Association of Canada

3.0 Acknowledgement And Scope

3.0.1AcknowledgementAnd Disclaimer

This Industry Recommended Practice (IRP) is a set of best

practices and guidelines, compiled by knowledgeable andexperienced industry and government personnel and is intended

to provide the operator with advice regarding HEAVY OIL AND

OIL SANDS OPERATIONS.

Heavy Oil And Oil Sands Operations 1

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DACC The IRP was developed under the auspices of the Drilling andCompletions Committee (DACC).

DACC is a joint industry/government committee established to

develop safe, efficient and environmentally suitable operating

practices for the Canadian oil and gas industry in the areas ofdrilling, completions and servicing of wells. The primary effort

is the development of IRP's with priority given to:

development of new IRPs where non-existent proceduresresult in issues because of inconsistent operating practices;

review and revision of outdated IRPs particularly where newtechnology requires new operating procedures; and

provide general support to foster development of non-IRP

industry operating practices that have current application to a

limited number of stakeholders.

IRP Flexibility The recommendations set out in this IRP are meant to allowflexibility and must be used in conjunction with competent

technical judgment. It remains the responsibility of the user ofthe IRP to judge its suitability for a particular application.

Legislation If there is any inconsistency or conflict between any of therecommended practices contained in the IRP and the applicable

legislative requirement, the legislative requirement shall prevail.

If there is any inconsistency or conflict between any of therecommended practices contained in the IRP and the applicable

legislative requirement, the legislative requirement shall prevail.


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Accuracy &Disclaimer

Every effort has been made to ensure the accuracy and reliability

of the data and recommendations contained in the IRP.

However DACC, its subcommittees, and individual contributors

make no representation, warranty, or guarantee in connection

with the publication or the contents of any IRP recommendationand hereby disclaim liability of responsibility for loss or damage

resulting from the use of this IRP, or for any violation of any

legislative requirements.

SanctioningOrganizations

This IRP has been sanctioned (sanction = review and support ofthe IRP as a compilation of best practices) by the following

organizations:

Alberta Energy and Utilities Board

Alberta Human Resources and Employment

British Columbia Workers Compensation Board

Canadian Association of Oilwell Drilling Contractors

Canadian Association of Petroleum Producers

International Coil Tubing Association

Manitoba Industry, Trade and Mines

National Energy Board

Northwest Territories and Nunavut Workers Compensation

Board

Petroleum Services Association of Canada

Saskatchewan Industry & Resources

Saskatchewan Labour

Small Explorers and Producers Association of Canada


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3.0.2 Forward This document is a revision of Alberta Recommended Practice(ARP) Volume 3 Heavy Oil and Oil Sands Operations

(1)

published in 1991. The work is a result of a joint industry andregulatory body sub-committee of the Drilling and Completions

Committee (DACC). The sub-committee included

representation from Canadian Association of Petroleum

Producers (CAPP), Canadian Association of Oilwell DrillingContractors (CAODC), Alberta Energy and Utilities Board

(AEUB, EUB), Occupational Health and Safety (OH&S),

Petroleum Services Association of Canada (PSAC) and SmallExplorers & Producers Association of Canada (SEPAC).

This revision is necessary to:

update ARP Volume 3 to reflect current practices,procedures, and equipment used in developing and

producing Heavy Oil/Oil Sands reserves,

(1)Definitions of terms specific to this document may be found

in Section 3.0.4.

streamline regulatory/industry procedures and application

processing, and

convert ARP Volume 3 to an Industry RecommendedPractice (IRP) Volume 3 that recognizes a Canadian

composite of minimum standards for exploration,development and production of Heavy Oil/ Oil Sands

reserves1,

.


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The purpose of this document is to recommend specific

standards and operating procedures that should be considered

the minimum acceptable for a given application.

This document addresses issues specific to the exploration,

development, and production of Heavy Oil and Oil Sandsreserves by primary, secondary, and tertiary - Enhanced Oil

Recovery (EOR) methods. This IRP is not intended to apply to

conventional production or critical sour wells.

The IRPs for Heavy Oil and Oil Sands Operations stress the

importance of standards and safe operating procedures to protect

workers and the public and to minimize environmental riskduring the entire life of the producing asset. They are intended

to complement existing documentation and regulation.

The practices recommended are based on engineering judgment,

accepted good practices, and experience. The establishment of

these minimum standards does not preclude the need for

industry to exercise sound technical judgment in the applicationof these practices.

The subcommittee does not endorse the use of any particular

manufacturers product. Any descriptions of product types or

any schematics of components, which bear resemblance to aspecific manufacturers product, are provided strictly in the

generic sense.


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Within IRP Volume 3, additional sources of information and abibliography of references are found at the end of each section.

The current editions of reference specifications, standards, and

recommended practices were used when this 1999 revision was

undertaken. As these documents are updated and revised, thesections of the IRPs referencing them may require revisions. In

addition, as new knowledge, equipment, and procedures are

developed this document will require updating.

Suggestions for revisions to this document should be forwardedto the Drilling and Completions Committee (DACC). This jointindustry/regulatory committee is responsible for the periodic

updating of this and other IRPs.


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3.0.3 Scope The purpose of this IRP Volume 3 - Heavy Oil and Oil SandsOperations is to provide guidance in the development andproduction of Heavy Oil and Oil Sands reserves within Canada.

This is accomplished by outlining current practices and setting

minimum standards that encourage operating in a safe and

environmentally sound manner. The focus is on practices,equipment, and procedures that are unique to Heavy Oil and Oil

Sands operations. Although they are not a primary focus, the

issues of hydrocarbon conservation, equity, and environment arementioned in the Measurement Section IRPs as they provide

necessary understanding of measurement needs.

Drilling recommendations are made with regard to:

blowout prevention (BOP) systems

ghost-holes and side-tracks

cement design and operations

casing string design

horizontal well guidelines, and

drilling waste management.

Servicing recommendations are made with regard to:

blowout prevention systems

servicing equipment including coiled tubing rigs, snubbing

rigs, flush-by units, pressure trucks, and tanks

health, safety, and environment, and

well abandonment.


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Producing recommendations are made with regard to:

wellhead design

oil and gas gathering and treating

production equipment including fired vessels, and

environmental protection.

Measuring and accounting recommendations are made with

regard to:

purpose and need for measurement

well test design and equipment

sampling requirements, and

reporting requirements.


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3.0.4 Introduction Heavy oil production occurs along the Alberta andSaskatchewan border near Lloydminster and in many other areas

of both provinces. For the purpose of this IRP, Heavy Oil is

defined as oil or bitumen having a density of 920 kg/m3or

greater oras designated by the governing body (i.e. as perSpacing Area E in Saskatchewan).

The intent of the Industry Recommended Practices for HeavyOil and Oil Sands Operations is to enhance operating

consistency within industry through the establishment ofminimum standards and procedures. The IRPs outlined clarifyand document good practices and procedures employed by

various Operators and Service Companies within Heavy Oil and

Oil Sands areas. Many of these practices and standards are theresult of numerous refinements over the years. It is hoped they

will reduce the variety of exemptions and differences in

equipment and procedures used by the Operators.

These IRPs have been thoroughly reviewed and endorsed by

industry. Since IRPs are meant to allow flexibility, competent

technical judgment is still necessary when establishingappropriate equipment and procedures for Heavy Oil and Oil

Sands Operations. One must always consider the nature of the

product to be produced and the need for environmentalprotection and safety. While strict legal enforcement of the IRPs

is not desired, the subcommittee believes that these practicesplace considerable onus on the legally responsible party to

comply or otherwise provide a technically equivalent or better

method.


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3.0.5 Heavy OilAnd Oil SandsCriteria AndDefinitions

In developing the Industry Recommended Practices for HeavyOil and Oil Sands Operations, the DACC Subcommittee

provides the following list of definitions deemed necessary for

clarification of the discussion of Heavy Oil and Oil Sands

development and production.

3.0.5.1 CrudeBitumen

Crude bitumen is a naturally occurring, viscous, hydrocarbon

mixture consisting mainly of compounds heavier than pentane.

It may also contain sulfur compounds and in its naturally

occurring state will not flow into a wellbore. For the purposes ofthis IRP, Crude Bitumen includes hydrocarbons within declared

Oil Sands Areas.

3.0.5.2 Buffer Well A buffer well is a well with a bottom-hole location in proximityto an active secondary recovery or tertiary (EOR) project and islocated between the proposed well(s) to be drilled and the

project area. In proximity is defined as 1.0 kilometer in Alberta

and 1.6 kilometers in Saskatchewan. A greater distance may berequired based upon performance history or other factors.

Note The term buffer well is used in the drilling and servicing IRPswhere Operators should account for potential pressure and

temperature effects of secondary or EOR projects from adjacent

areas in their drilling or servicing operations. Other factors toconsider are outlined in definitions 3.0.4.7 through 3.0.4.11.


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3.0.5.3 Heavy Oil Heavy Oil is defined as a crude oil product that has a density

greater than 920 kg/m3at 15Coras designated by the

governing body (i.e. as per Spacing Area E in Saskatchewan).

Note The density of 920 kg/m3was selected as an appropriate cut-off

for operating practices appropriate for Heavy Oil wells. Oil of

this density or greater tends to be more viscous due to smallerpercentages of volatile hydrocarbons and higher percentages of

asphaltenes. Industry has used this density in defining the

equipment and operating requirements for the majority of HeavyOil and Oil Sands wells in Canada.

3.0.5.4 In-SituOperation

In-situ operation means:

A scheme or operation ordinarily involving the use of wellproduction operations for the recovery of crude bitumen from

oil sands, or

A scheme or operation designated by a regulatory body as an in-

situ operation, but does not include a mining operation.

3.0.5.5 Oil Sands Oil Sands are defined as:

sands and other rock materials containing crude bitumen

the crude bitumen contained in these rock materials, and

any other material substances, other than natural gas, inassociation with that crude bitumen or those sands and other

rock materials referred to in subclauses (i) and (ii)3.


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3.0.5.6 Oil SandsArea

In Alberta, an area defined by an EUB order declaring it an Oil

Sands area.

Note The EUB Informational Letter IL 84-74

and Amendment IL 89-3

5designate the following three Oil Sands Areas (OSA):

Order No. OSA 1 and 1A - Athabasca

Order No. OSA 2 - Peace River

Order No. OSA 3 - Cold Lake

ERCB ST 38 - Atlas of Albertas Crude Bitumen Reserves

1990 Edition.

3.0.5.7 Oil ShaleArea

In Saskatchewan, an area where oil shale or tar sand existsfrom which oil shale products may be produced or any such

other substance that the minister may define as oil shale.

3.0.5.8 Heavy OilArea

In Alberta, an area defined by an EUB order declaring it a

Heavy Oil area.

In Saskatchewan, an area defined by SEM that is geologic

horizon and area specific.


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3.0.5.9 PrimaryRecovery Well

A primary recovery Heavy Oil / Oil Sands well is defined as a

well that:

operates at a reservoir pressure and temperature equal to or

less than the original reservoir pressure and temperature atpool discovery, and

does not operate within a secondary recovery scheme

(3.0.4.9), enhanced oil recovery scheme (3.0.4.10), or

within a production- affected area (3.0.4.11).

Note This definition varies from that found in AEUB ID 91-36

dealing with Heavy Oil / Oil Sands operations. The current ID

91-3 will need to be revised.

In Alberta, Informational Letter IL 85-127regulates well

spacing in primary recovery schemes.

3.0.5.10SecondaryRecovery Well

A secondary recovery Heavy Oil / Oil Sands well is defined as

a well that:

operates under an artificial pressure maintenance schemewith injection temperatures less than 100

oC, and

does not operate within an enhanced oil recovery scheme

(3.0.4.10).

Note This definition varies from that found in AEUB ID 91-36

dealing with Heavy Oil/Oil Sands operations. The current ID91-3 will need to be revised.


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3.0.5.11Enhanced OilRecovery (EOR)or Tertiary Well

An enhanced oil recovery or tertiary Heavy Oil / Oil Sands well

is defined as a well operating within a scheme that:

enhances oil recovery by the injection of fluids other than

water or water at temperatures greater than 100oC, and

that alters the viscosity of the oil or increases the formationpressure as a result of fluid injection.

Note Currently, this definition is not found in AEUB ID 91-36

dealing with Heavy Oil / Oil Sands operations. The current ID91-3 will need to be revised.

In Alberta, Informational Letter IL 86-098regulates steam

stimulation procedures for single wells.


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3.0.5.12Production

Affected Area

A production-affected area is defined as the area around a well

where it is proven or reasonable to assume that formation

pressure, temperature, or rock properties have been sufficientlyaffected as to cause abnormal pressure, temperature, or flow

conditions.

Note Operators are responsible for establishing the anticipated size,shape, and orientation of the production-affected area in thevicinity of a new project and use this in well planning. Some

factors that influence the size of the production-affected areaare:

volume of fluid production

volume of sand production

volume of fluid injection

injection pressure

local reservoir geology, and

zone(s) of enhanced permeability

Each of the above factors can be quantified except zone(s) ofenhanced permeability. The key to addressing this factor is to

understand that enhanced permeability within a formation

can occur as a result of:

natural or artificial fractures

zones of greater fluid mobility such as gas or water legs

sand production, and

inter-well communication such as injector to producer.


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Where possible, an excellent measure can be achieved by

evaluating existing (offset) wells between the expected

production-affected area and the well to be drilled or serviced.Pressure and temperature surveys of offset wells can be used to

determine the effectiveness of efforts to restore formation

conditions to normal or to establish the perimeter of the

production-affected area. It is prudent to remain cautious, asthe absence of abnormal conditions at offset wells only infers

normal conditions surrounding them.

In Saskatchewan, SEM typically uses a minimum distance of

1.6 kilometers as a starting point for evaluating existing

(offset) wells between the expected production-affected areaand the well to be drilled or serviced.

3.0.5.13Development Type Setting

In Alberta, a development-type setting is one that has a

minimum of three offset wells each in a different direction

from the proposed location and within 1.5 km. of eachother. The offset wells must be drilled to the same target

depth, or deeper, than the proposed well.

In Saskatchewan, SEM requires an oil well to be within 0.8

kilometers of a producing or producible well in order toreceive a development classification.


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3.0.6 References 1 AEUB Oil Sands Conservation Act, Chapter O-5.5 of theStatutes of Alberta, 1985

2Saskatchewan Energy and Mines guidelines, policies and

regulations are derived from the following:

SEM Mineral Resources Act, 1985

SEM Oil and Gas Conservation Act

SEM Oil and Gas Conservation Regulations, 1985

3Alberta Recommended Practices Volume 3: Heavy Oil and

Oil Sands Operations - 1991

4AEUB Informational Letter IL 84-7: Declaration of Oil Sands

Areas to Facilitate Orderly Leasing and Stable Regulation

July 1984

5

AEUB Informational Letter IL 89-3: Amendment of theAthabasca Oil Sands Areas April 1989

6AEUB Interim Directive ID 91-3: Heavy Oil/Oil Sands

Operations March 1991

7AEUB Informational Letter IL 85-12: Oil Sand Primary

Production: Well Spacing Primary Recovery Scheme

Approvals July 1985

8

AEUB Informational Letter IL 86-9: Approval Procedures forSingle Well Steam Stimulation Tests in Oil Sands Areas

September 1986


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3.1 Drilling

3.1.1 Scope The scope of the Drilling Section considers:

site selection, preparation, and reclamation

drilling, casing, and cementing of the well

safety and environment management, and

horizontal wells.

The issue of well control is addressed extensively within this

section due to the varied drilling conditions found within HeavyOil and Oil Sands Areas.

Section 3.1.2 addresses Low Risk Wells where waivers

from governing regulations may be appropriate. ALow

Risk well is briefly defined as a well with low gas flowpotential being drilled in an area with minimal drilling

problems.

Section 3.1.3 addresses Moderate to High Risk Wells

where unaltered governing regulations are deemed moreappropriate. A Moderate to High Risk Well is briefly

defined as a well with potential for a high gas flow rate,

significant drilling problems, and/or thermal operationsnearby.


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3.1.2 WellControl SystemsFor Low RiskHeavy Oil / OilSands Wells

This subsection addresses the requirements for surface casing

or conductor pipe1, appropriate blowout preventer, flare line,

and flare tank or pit for Low Risk Heavy Oil / Oil Sandsdrilling.

3.1.2.1 SurfaceCasing orConductor Pipe

Design LowRisk Well

In Alberta, AEUB Guide 8: Surface Casing Depth Minimum

Requirements 1sets out guidelines for determining if a reduced

depth of surface casing is appropriate for Oil Sands core holes

and Oil Sands evaluation wells. Further, Interim Directive 91-3:Heavy Oil / Oil Sands Operations 2address surface casing

waivers for Heavy Oil areas. The requirements of both

regulations are consolidated into these IRPs with the desire to

reduce the numberof surface casing waiver applications provided

the following general criteria are satisfied:

The proposed well terminates at less than 950 meters true

vertical depth, less than 15 meters below the base of the

Lower Cretaceous formation, and is within a designated

Heavy Oil/Oil Sands area.

The proposed well is located in or adjacent to a development-

type setting 2.

The maximum absolute open flow (AOF) gas rate from offsetwells does not exceed 113 103m3/day.

There is an absence of problems such as over-pressuredformations (i.e. >10.2 kPa/m gradient), severe lost

circulation, kicks, blows or blowouts, or artesian water

flows within three (3) kilometers of the proposed well.


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In Saskatchewan, the bulk of Heavy Oil production occurs from

the Mannville Group in what is defined as Spacing Area E. A

schedule of area specific conditions is part of the Ministers order

governing each designated spacing area. These conditions allow

(within reason) the department to approve certain operations to

be conducted in a specific area that may not be allowed in

another spacing area. For the Heavy Oil Area, Schedule 4 of

Spacing Area E reads as follows:

Unless otherwise ordered by the Minister, the use of surface

casing and blowout prevention equipment shall be at the

discretion of the Operator, with respect to all wells drilled to

or serviced in the Mannville Group, and located north ofTownship 43 and south of Township 55.

SEM highly recommends surface casing or conductor pipeequipped with proper blowout prevention equipment be utilized

while drilling or servicing all wells located within the portion

of Spacing Area E as defined above. However, an Operatormay chose not to do so provided the following conditions are

met:

The surface elevation of the proposed wellbore is greater

than 579 meters. The proposed wellbore is outside the area that has been

defined as the Tangleflags Hazard Area.

The proposed wellbore is a minimum of 1.6 kilometers from

any enhanced recovery scheme.

The proposed wellbore is not being drilled for gas

production.

With the exception of that portion of Spacing Area E

designated the Tangleflags Hazard Area (i.e. Townships 50,

51, 52 Ranges 22,23,24,25,26W2M), standard provincial

surface casing regulations are applicable for all wells having asurface elevation less than 579 meters.


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Within the Tangleflags Hazard Area all wells must have aminimum of 107 meters of surface casing and unless otherwise

approved (for geologic reasons), those wells having a surface

elevation less than 564 meters require a minimum of 137meters of surface casing.

1Surface casing lengths of 20 30m are commonly referred to

as Conductor Pipe.

2See definition in section 3.0.4.13.

3.1.2.2 SurfaceCasing OrConductor PipeRequirement Low Risk Wells

IRP 3.1.2.2.1 To determine if surface casing may be replaced by 20 mTVD of conductor pipe, the following data must be

gathered, evaluated for potential risk by a technically

competent person, and recorded for confirmation.

Geology

All zones from surface to total depth indicating

porous or permeable zone(s).

Record of gas potential in the hydrocarbon-bearing

zone(s). If no gas potential exists, an isopach map

showing the expected extent of any adjacent

productive zone(s) should be available upon request.

If gas potential exists, evidence of whether the

maximum AOF gas rate from the offset wells

exceeds 113 103m3/day should be available uponrequest.


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Thermal Schemes

Method of hydrocarbon recovery.

Perimeter of any enhanced oil recovery scheme or

production-affected area (see definitions 3.0.4.11 and

3.0.4.12 respectively) within three (3) kilometers of

the proposed well.

Temperatures and pressures from offset wells.

Bottom-hole distances to active steaming or

production-affected areas. Volume of steam injected to date.

Frequency and duration of cyclic operations.

Time required for a steamed area to cool once it has

been produced.

Temperature and pressure in the production cycle at

which it is safe to drill.


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Operations

Record of drilling operations from surface to total

depth for a representative sample of offset wells

within a three (3) kilometer radius.

Types of hole problems by well location and geologic

zone (i.e. depth) that includes:

severe lost circulation

artesian water flows

hole sloughing

kicks

blows and blowouts

abnormal pressures (>10.2 kPa/m)

low cement tops

Intermediate casing setting depth above or into the

production zone if a horizontal well.

Record from offset wells that the conductor casing

will be set into a competent formation.

Cementing method to be used when setting

Map of the area showing:

e locations of the

e

ed areas

conductor casing.

surface and bottom hol

proposed well(s) and the offset wells in th

researched area

production-affect

surface water bodies

surface developments


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IRP 3.1.2.2.2 Once a l lysis has been completed

d

ter than one (1) kilometer

in a LOW RISK production-affected

di igent technical risk ana

as per IRP 3.1.2.2.1, the replacement of surface casing by a

20 m TVD depth of conductor pipe may be suitable if:

All regulatory criteria (see IRP 3.1.2.2.1) are met an

appropriate regulatory body approval is obtained (i.e.

Surface Casing Waiver).

The proposed well is grea

from an enhanced oil recovery scheme. A lesser distance

may be acceptable with appropriate technical

justification.Drilling is with

area (see definition 3.0.4.11).

The conductor casing is set in a competent, non-porous

formation.

Note Generally, Surface Casing Waivers are granted in development-type settings and also in certain production-affected areas.

d to

contain the pressure at the casing shoe that results from the

for

The appropriate depth of conductor pipe is the depth require

flow of 113 103m

3/day of gas through the conductor casing,

BOP stack, and flare line. A maximum formation leak-offpressure gradient of 5 kPa/m was used to calculate the

conductor casing shoe depth. The 20 mdepth is adequate

all surface-casing sizes greater than or equal to 219 mmprovided the flare line diameter is 152 mm (see IRP 3.1.2.4.1).


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Avoid setting the conductor in sand or gravel that may result in

washouts or failures at the conductor shoe. Offset data should

indicate the conductor casing is set in a formation that iscapable of supporting a full column of water (i.e. 9.8 kPa/m

gradient). If drilling fluid is lost upon drilling out the

conductor, then surface casing must be set.

The design criteria used to determine the conductor casing

setting depth may lead to a serious well control situation if

proper well control procedures are not followed. The flow mustbe opened fully to the flare line without restriction. Normal

well killing procedures utilizing the application of backpressure

while circulating out the kick may result in a failure at theconductor casing shoe. Prior to drilling, clear communication of

the potential hazards and action plan is required for all drilling

personnel to supplement general well control training.

IRP 3.1.2.2.3 When planning a group or pad of wells, if the offsetinformation within the researched area is limited or of poor

quality, then the first well should be drilled applying

conventional surface casing requirements. The informationgained from drilling this well, may then be used to

determine the surface casing or conductor pipe

requirements for subsequent wells.

Note All available evidence, such as drill cuttings, drillingconditions, and electric logs, should be considered when

determining the risk of setting a shallow conductor casing seat.


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3.1.2.3 BlowoutPreventerRequirement Low Risk Wells

IRP 3.1.2.3.1 If surface casing is replaced by a 20 mTVD depth ofconductor pipe, then a Class 1A (Diverter) BOP System (see

Appendix A - Figure 2) shall be installed. The Class 1A

BOP system shall have a successful daily function test of its

annular preventer and a once per well test of the fullopening valve

2.


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3.1.2.4 Flare LineAnd Flare TankRequirement Low Risk Wells

IRP 3.1.2.4.1 When the Class 1A (Diverter) BOP stack specified in IRP3.1.2.3.1 is used, the flare line inside diameter shall be a

minimum of 152 mm and the line shall be free from bends

when possible.

The flare line length is dependent upon the Sandface

Absolute Open Flow (AOF) potential of the offset gas wells

as follows:

AOF Gas Rate

(103m3/ day)

Flare Line Length

(m)

Flare Tank or Pit

< 28 25 Flare Tank

28 113 35 Flare Tank

> 113 Class 1A not allowed Flare Pit


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Note The large 152 mm flare line diameter is necessary to reduce theback pressure exerted on the shallow conductor casing shoe

when diverting flows of drilling fluids and formation solidsthrough the flare line. Experience has shown that 89 mm and

114 mm flare lines are prone to plugging and freezing. It is

noted that nominal six inch (152 mm) diameter line pipe of

Schedule 40 or less satisfies the minimum inside diameterrequirement.

The ideal flare line is straight. When bends are absolutelynecessary, the following configurations are acceptable:

90obends using blocked tees (i.e. tees equipped with bull

plugs to cushion flows around the turns), and

long radius flexible hoses3.

In each configuration, a minimum number of turns are

recommended with zero to four commonly found within theindustry. Notable disadvantages are the susceptibility of long

radius turns to wash-outs while right-angle turns are more

prone to plugging.

The pressure loss incurred by additional bends is very small in

the systems being recommended4. For example, at flows of 113

103m

3/day, the pressure loss in a 152 mm diameter by 50 m

long flare line with four 90obends is 3.5 kPa (0.5 psi) greater

than a similar line with no bends (see Appendix B Figures 1to 7).


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The recommended flare line lengths are derived from an

industry study5that accounts for both the effects of gas

dispersion and radiant heat generated at the flare line exit.Dispersion of gas is enhanced upon exiting a 2 m high flare

tank as opposed to a ground level earthen pit and results in a

shorter flare line length. The radiant heat evolving from a

burning flare, increases with AOF gas rate and results inincreased flare line lengths. Use of a flare tank is not

recommended when Gas AOF Rates exceed 113 103m

3/day.

In Saskatchewan, it is noted that SEM regulations stipulate

flare lines terminate in a tank or pit a minimum of 45 m from

the wellbore.

IRP 3.1.2.4.2 When using a flare tank, it must have a minimum height oftwo (2) meters. The flare tank should be adequately

designed to resist heat damage should ignition of the flow be

required. Baffles located at the tank inlet are

recommended to limit tank erosion and liquid losses from

the tank. The flare tank should be adequately attached to

the flare line.

Note The use of a flare tank may be desirable to:

reduce lease sizes in conjunction with reduced flare line

lengths (see IRP 3.1.2.4.1)

improve the mobility of the flaring system on multi-well pads

enhance environmental clean-up.

Refer to AEUB Informational Letter IL 98-3: Minimum

Standards for Flare Tanksxand General Bulletin GB 98-13:

Minimum Standards for Flare Tanks3for additional informationon flare tanks.


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3.1.3 WellControl SystemsFor Moderate ToHigh Risk HeavyOil Wells

This subsection addresses well control design considerations,surface casing requirements, and BOP equipment needs for

Moderate to High Risk wells drilled in Heavy Oil / Oil Sands

areas. (If a Heavy Oil / Oil Sands well is designated asModerate to High Risk, conventional regulations with respect

to surface casing setting depths apply.)

3.1.3.1 WellControl SystemsFor Moderate To

High Risk HeavyOil Wells

In Heavy Oil / Oil Sands areas, high-risk conditions and

different hydrocarbon recovery mechanisms complicate wellcontrol design. This has resulted in different BOP system

selections especially when the risks involved in drilling aproposed well are uncertain. To provide a basis for makingrecommendations on suitable BOP configurations for Heavy

Oil / Oil Sands areas, the following discussion begins with the

primary reasons for well control and progresses to the currently

regulated BOPs and their distinguishing features.


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Blowout prevention systems are necessary to protect drilling

personnel, drilling equipment, and the environment from

avoidable damage caused by exploiting hydrocarbon resources.When selecting an appropriate BOP configuration, it is

important to consider the complete BOP system and match this

to the risks inherent in the drilling process. Since all BOP

systems have limitations, it is necessary to balance theselimitations with the needs of the Contractor, Operator, and

Regulator. It is the Operators responsibility to define a safe

BOP system for a proposed drilling operation. After agreeingupon the risks involved and the BOP system selected, it is the

responsibility of the Contractor to provide a working BOP

system and adequately trained personnel capable of dealingwith expected well control problems that might arise. It is the

Regulators responsibility to audit operations to ensure current

regulatory requirements are being met and to facilitate anyfuture regulatory changes that may arise from advances in

drilling practices, procedures, or equipment. It is suggested that

current regulations follow upon these premises in arriving at a

minimum set of guidelines for drilling new wells.


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Four (4) conditions often exist in Heavy Oil / Oil Sands areas

that present concerns when designing an appropriate well

control system. These are:

Potential high gas flow rates (up to 283 103m3/day(10MMSCFD)) from shallow sandstone formations

Potential lost circulation in depleted reservoirs and in the

Devonian formations

Inability to hard shut-in typical formation pressures (4-5

MPa) at the typical surface casing depths (approx. 100 m), and

Drilling within thermal (EOR) project areas.

Given the above challenging conditions, it is evident that

proper well control requires the ability to safely divert

potentially prolific gas flows while maintaining the integrity ofthe BOP system including the surface casing shoe. Faced with

this objective, this committee proposes the following IRPs,

taking into account the risks inherent in well control situationswhere high gas flow rates are possible.


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3.1.3.2 SurfaceCasingRequirement Moderate To HighRisk Wells

IRP 3.1.3.2.1 Surface casing should be run if any of the following conditionsare expected while drilling:

The proposed well terminates at a true vertical depth of 950

m or greater or more than 15 m into the Devonian formation. The proposed well is located outside a development-type

setting.

The maximum AOF Gas Rate from offset wells is 113 103

m3/day or greater.

There is potential for a formation pressure gradient >10.2

kPa/m, severe lost circulation, kicks, blows or blowouts, or

artesian water flows within three (3) kilometers of the

proposed well.

Drilling is not within a low risk production-affected area

(including certain secondary recovery and enhanced oil

recovery schemes).

The design of the surface casing must allow control of themaximum anticipated formation pressures by conventional

well control methods.

Note The primary objective of surface casing is to aid in well control. Asecondary function is to provide groundwater protection.Regulations now permit surface casing depths that frequently donot cover all potable water zones being utilized by surrounding

landowners or industry. In these cases, the objective ofgroundwater protection is transferred to the next casing string.

This highlights the importance of prudent decision-making

regarding surface casing setting depths given the expected drillingconditions in the subsequent intermediate or main holes.


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3.1.3.3 BOPSystemRequirement Moderate To HighRisk Wells

Prior to presenting the various BOP systems used in Heavy Oil/ Oil Sands areas, the following general IRPs serve as

guidelines for proper BOP selection.

IRP 3.1.3.3.1 Due to the shallow surface casing and conductor pipesetting depths in Heavy Oil / Oil Sands areas, all BOP

systems should be considered well control devices which

will divert any well flows away from the rig.

IRP 3.1.3.3.2 Special well control practices should be considered whendrilling wells with potentially prolific gas rates from

shallow formations. Rig personnel should be made aware of

the need to safeguard the integrity of the surface casing

shoe.


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IRP 3.1.3.3.3 When drilling in production-affected areas, considerationshould be given to upgrading the BOP system to match the

risks inherent in the proposed drilling operation. If the

offset information within the researched area is limited or

of poor quality, then extra precautions may be warranted

on the first well(s) drilled. The information gained from

drilling initial project well(s) may then be used to determine

requirements for subsequent wells.

Note Operators may need to satisfy Regulators that the conditionswithin a production-affected area have been adequatelyresearched to identify the risks. The presence of observation

or buffer well data between potential sources of pressure or

temperature and the proposed well are useful in determining the

production-affected area.

Operators should consider lessening the risk of drilling within a

production-affected area by reducing pressures and / ortemperatures. Where abnormally low pressures are

encountered, loading the surrounding wells with lease crude

may help limit loss of circulation.


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3.1.3.4 BOPSystem Types

And Applicat ions

The various BOP systems currently used to drill in Heavy Oil /

Oil Sands areas and their main advantages and disadvantages

are outlined in Table 1below.

Table 1 Blow Out Preventer Comparison

Blow Out Preventer Comparison Table Heavy Oil/Oil Sands Areas

BOP Class Class 1

(Diverter)

Class 1A

(Diverter)

Class 2 SEM

Tangleflag,

EUB Class 3

& EUB HighHazard

Class 3

Modified EUB Class 3

Effort to Rig-Up/Pressure

Test

Low Low Medium Medium Medium

Shut-In

Capability

No No Limited

byMACP*

Limited by

MACP

Limited by MACP

Risk of

Exceeding

MACP*

Medium Low Medium Medium Medium

Ability to Re-

Circulate

Kill Fluid

No No Yes Yes Yes

BOP System

Pressure Loss


BOP SystemPlugging

Tendency


Redundancy

in Shut-In

Capability

No No No No Yes


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BOP Class Class 1

(Diverter)

Class 1A

(Diverter)

Class 2 SEM

Tangleflag,

EUB Class 3

& EUB

High

Hazard

Class 3

Modified EUB Class 3

Drilling Rig

Height

Limitations

No No No No Yes

Potential for

BOP CoolingLoop

No No No No Yes

Recommended

For

Low/Med/High

Risk Well

Low Low/Medium Medium Medium Medium/High

*MACP = Maximum Allowable Casing Pressure

After assessing the risk of drilling a proposed well, the information in this table can aid

in selecting the most suitable BOP system. Additional insights into proper BOP

selection may be gained from the following summary of each BOP system.


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EUB Class 1 andClass 1A(Diverter) BOPSystems

EUB Class 1 and Class 1A (Diverter) BOP Systems

The EUB Class 1 and 1A BOP Systems (see Appendix A Figures 1 & 2) are commonly referred to as Diverters as this

describes their capability as a well control device. These BOP

designs allow diversion of any well flows and prevent a hardshut-in of the well. This design safeguards the integrity of the

conductor pipe or surface casing shoe and minimizes the

chance of loss of well control with flows outside the surface

casing.

The EUB Class 1 BOP system was regulated mainly to

accommodate drilling in low risk Surface Mineable Areas. Thedrilling of shallow (i.e.

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The Class 1A BOP differs from the Class 1 in that the flare line

diameter is larger (152 mm versus 89 mm or 100 mm) to

accommodate higher rate gas kicks with lower back pressure atthe surface casing or conductor shoe. The larger flare line

diameter reduces the pressure losses through the system and

lessens line plugging. In Section 3.1.2 of these IRPs, it is

proposed that the Class 1A BOP system is appropriate to

drill wells with Maximum AOF Gas Rates up to 113 103

m3/day.

In Saskatchewan, the EUB Class 1 and 1A BOP Systems

would be considered an acceptable option only in Spacing

Area E while drilling a well classified by SEM as a

structure test hole or an oil shale core hole. Further, the

SEM requires two valves be installed on all casing bowls

while drilling operations are being conducted.

EUB Class 2 BOPSystem

EUB Class 2 BOP System

The EUB Class 2 BOP system (see Appendix A Figure 3) isdesigned to accommodate shallow depth drilling (

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In Saskatchewan, the EUB Class 2 BOP System is an

acceptable option for non-Tangleflags and non-EOR wells

within Spacing Area E if two minor changes are made asfollows:

two valves are installed on the surface casing bowl

two additional valves are installed in the manifold (see

manifold set-up in Appendix A Figure 5).

Drilling conditions in Heavy Oil / Oil Sands areas (and otherparts of Western Canada) present two significant disadvantages

for Class 2 BOPs. Firstly, the reservoir pressures are high

enough that complete shut-in is not possible at the typicalsurface casing depths. Secondly, a combination of a potentially

high gas flow rate, a shallow surface casing setting depth, and

an 89 mm flare line place severe limitations on the ability tosafely divert a well flow. The 89 mm flare line diameter

creates significant pressure losses and potential line plugging

concerns.

Heavy Oil / Oil Sands wells often have the surface casing set atapproximately 100 meters. Based upon typical formation leak-off tests, this limits hold-back pressure to approximately 1.8

MPa (i.e. 100m x 18 kPa/m FLOT) which is much lower than

the typical formation pressure of 35 MPa. Therefore, the well

cannot be safely shut in unless sufficient wellbore fluid is inplace to overbalance the formation pressure. Experience gained

in handling actual kicks from high rate shallow gas formations

reveals that wellbore fluid is often totally displaced as theMACP would be exceeded if the well was choked.


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System pressure losses for typical well configurations using an

89 mm flare line (see Appendix C Figures 1, 4, 7, and 10) are

in the range from 900 to 1150 kPa. This equates to a pressuregradient of 9.0 to 11.5 kPa/m at the surface casing shoe. These

gradients fall below the range of typical formation leak-off tests

in Heavy Oil / Oil Sands areas (i.e. 15 to 18 kPa/m) but do not

leave much capability to choke a well. These typical

conditions make the Class 2 BOP system of limited use for

Heavy Oil / Oil Sands areas where high rate gas flows are

possible.

Note System pressure losses are also presented for typical wellconfigurations with a 152 mm flare line (see Appendix C -

Figures 2, 5, 8, and 11) and with a 203 mm flare line (see

Appendix C - Figures 3, 6, 9, and 12).

EUB Class 3 andSEM TangleflagsBOP System

EUB Class 3 and SEM Tangleflags BOP Systems

The EUB Class 3 BOP system (see Appendix A Figure 4) is

designed to accommodate medium depth drilling (750 m to1800 m), provide well flow diversion and hard shut-in

capabilities, and provide the ability to re-circulate to kill a

flowing well. This well control system is appropriate when lowrate gas or oil flows are encountered and sufficient surface

casing is run to provide significant holdback pressures at the

casing shoe.


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The Saskatchewan Energy and Mines (SEM) Tangleflags BOP

system (see Appendix A Figure 5) is similar to an EUB Class

3 BOP except for:

a second casing bowl valve (all flanged)

two additional valves in the manifold system, and

a slightly larger flare line diameter (76.2 mm versus 75 mm).

This BOP system provides the same benefits as the EUB Class

3 BOP as noted previously.

With respect to Heavy Oil / Oil Sands areas, the disadvantages

listed in the Class 2 section apply for both the EUB Class 3 andSEM Tangleflags BOPs. These two BOP configurations are

of limited use for Heavy Oil / Oil Sands areas where high

rate gas flows are possible.


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EUB High HazardArea BOP System

EUB High Hazard Area BOP System

The EUB High Hazard Area BOP system (see Appendix A Figure 6) is a modified Class 3 BOP regulated as per AEUB

Interim Directive 92-17. This regulation was necessitated due to

an increase in frequency of kicks and associated serious wellcontrol incidences in the Cessford area of Southern Alberta. It

requires a second 89 mm flare line from the casing bowl and

was mandated to provide redundancy in the event of a washout

of the primary line. Further, a minimum surface casing settingdepth of 180 m was mandated to provide sufficient holdback

pressures at the casing shoe to allow choking during efforts to

kill a flowing well.

In Saskatchewan, this BOP configuration is not acceptable to

SEM for drilling in the Tangleflags Hazard Area.

With respect to Heavy Oil / Oil Sands areas, the disadvantages

listed in the Class 2 section once again apply for the EUB High

Hazard Area Class 3 BOP. The second 89 mm flare lineprovides insignificant reduction in pressure loss if both lines are

opened together. However, it provides additional time for wellkilling operations if the primary flare line washes out. This

BOP configuration is more suitable for Heavy Oil / Oil

Sands areas where high rate gas flows are possible but is of

limited use as previously noted.


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Modified EUBClass 3 BOPSystem

Modified EUB Class 3 BOP System

The Modified EUB Class 3 BOP system (see Appendix A -Figure 7) is designed to up-grade the Class 3 BOP to provide

redundancy in the shut-in capability and in the well killing

system without using the casing bowl valves. Drilling rigsubstructure height restrictions frequently prevent the use of the

second spool required below the bottom pipe rams in this

configuration. This well control system is appropriate when low

rate gas or oil flows are encountered and sufficient surface orintermediate casing is run to provide significant holdback

pressures at the casing shoe.

In Saskatchewan, use of the Modified EUB Class 3 BOP is

acceptable for use throughout Spacing Area E provided the

bleed-off line size has a minimum 76.2 mm I.D. or a secondbleed-off line of 75 mm I.D. is connected to the drilling spool.

For Heavy Oil / Oil Sands areas, this BOP has the same

disadvantages listed in the Class 2 system when dealing withhigh rate gas kicks. However, this limitation can be alleviated

by installing a second flare line on the second spool. This BOPalso has the advantage of using the bottom spool to cool the

BOPs in the event a high temperature well flow is

encountered. This BOP is best suited for drilling medium to

high-risk EOR wells in Heavy Oil / Oil Sands areas.


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3.1.3.5 BOPSystem Examples

Given the above discussion, the following BOP system

suggestions are made for some typical drilling conditions found

in Heavy Oil/Oil Sands areas. These suggestions are a startingpoint for encouraging a thorough technical review of the

drilling risks when planning a well.

Example 1 Formation pressure exceeds 10.2 kPa/m and a full surfacecasing string is run. There remains a fundamental concern inmaintaining the integrity of the surface casing shoe.

If there is no expectation of encountering a high rate gas zone,then an EUB Class 1A BOP is recommended. (This requires

regulatory approval.)

If a high rate gas zone is potential, a Modified EUB Class 3

BOP complete with a second spool and second 89 mm flare line

is recommended. It is noted that the EUB Class 2, SEM

Tangleflags, and all EUB Class 3 BOPs meet regulations.Caution should be exercised given the known limitations of

these BOPs. The installation of a second 89 mm flare line onthe surface casing bowl may be considered

Example 2 There is potential for severe loss of circulation.

If there is no expectation of encountering a high rate gas zone,

then an EUB Class 1A BOP is recommended. (This requires

regulatory approval.)

If a high rate gas zone is expected, the same discussion as inExample 1 applies.


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Example 3 There is an expectation of encountering a high rate gas zone inexcess of 113 10

3m

3/day.

A Modified EUB Class 3 BOP complete with a second spooland second 89 mm flare line is recommended. Additional

thought should be given to discerning the appropriate surface

casing setting depth. It is noted that the EUB Class 2, SEMTangleflags, and all EUB Class 3 BOPs meet regulations.

Caution should be exercised given the known limitations of

these BOPs. Installation of a second 89 mm flare line on the

surface casing bowl may be considered appropriate.

After appropriate risk analysis, it may be argued that an EUB

Class 1A BOP is appropriate given the frequency ofencountering well control problems in a specific area. (This

requires regulatory approval.)

Example 4 Drilling is to occur within an EOR, thermal, or production-affected area.

A Modified EUB Class 3 BOP complete with a second spool toallow installation of a cooling loop should be considered.Consideration should also be given to running of intermediate

casing and a high temperature float within the drill string. If an

intermediate casing string is set due to the expectation ofencountering abnormal pressure and high temperature, then a

cooling loop is recommended.


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3.1.4 Ghost Hole AndSidetrack Wells

In Heavy Oil / Oil Sands areas, frequent use of directional

drilling techniques to exploit shallow depth reservoirs has led to

an increased frequency of planned sidetrack wells andunplanned ghost-hole wells. These are of particular concern in

production-affected areas. This subsection defines sidetrack and

ghost-hole wells and provides recommendations for dealingwith these when encountered.

3.1.4.1 Definit ions A sidetrack is defined as any wellbore that departs from the

main wellbore and creates a second wellbore.

A ghost-hole is defined as a sidetrack that cannot be re-entered.

3.1.4.2 Drill ingPractices

IRP 3.1.4.2.1 When drilling directional wells where the dogleg severityexceeds 12

o/30m or wells with unstable formations, a wiper

trip back into surface casing is recommended prior to

entering a hydrocarbon-bearing zone.

Note Sidetrack wells can be easily initiated while:

Rotating off bottom in hole sections with high dogleg severity(i.e. > 12 o/30m),

Drilling formations such as unconsolidated glacial till orconglomerates, sloughing shales, or poorly cemented

sandstones,

Reaming stringers of dense formation especially when drilling

with a top drive.


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IRP 3.1.4.2.2 Surface or intermediate casing should be run acrossformations with serious formation instability.

3.1.4.3AbandoningSidetrack Wells

IRP 3.1.4.3.1 Any sidetrack well that allows communication betweenadjacent porous formations (including surface aquifers)

must be abandoned according to the appropriate regulatory

guidelines.

Note The appropriate regulatory body must be notified and approvalreceived prior to commencing abandonment operations on any

sidetrack or ghost-hole well. (For example, in Alberta refer to

EUB Guide 20 - Well Abandonment Guide8).


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3.1.4.4 RecordingGhost HoleWells

IRP 3.1.4.3.1 A ghost-hole well that penetrates more than one porousformation must be reported to the appropriate regulatory

body and a copy of the directional survey should be

included.

IRP 3.1.4.3.2 A ghost-hole well that penetrates an EOR zone and is alsoin communication with another porous zone should be

isolated from the radius of influence of the EOR scheme.

Note A discussion between the Regulatory Body and the Operatorshould take place and a monitoring program or altering of the

EOR scheme may be necessary.


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3.1.5 CementingOf Casing

This subsection addresses cementing design and practices

specific to Heavy Oil / Oil Sands areas. As well, it references

documents that outline good cementing practices in general.

3.1.5.1 GeneralCementingConsiderations

The importance of obtaining a good primary cement job in anywell cannot be over-emphasized. Operators should be familiar

with the bookletPrimary and Remedial Cementing

Guidelines9published by the Drilling and Completion

Committee (DACC) in April 1995 and distributed by Enform.

This comprehensive guide was issued to combat an increase inincidences of gas migration in Alberta. It recommendsprocedures for proper cement design, testing, and job execution

for both primary and remedial cementing.


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Further to this guide, the following good practices are added:

Where cement returns to surface are required, a positivemethod of hole volume determination is prudent. This can be

accomplished in different ways:

Use of markers (dyes or sawdust) while conditioning

the well or in pre-flushes during the cement job,

Use of more sophisticated caliper logs, or

Referencing near offset wells and using similar excessvolumes.

Adequate hole conditioning prior to cementing is prudent. The

drilling fluid yield point, viscosity, and density should be aslow as practical to allow easier displacement of the mud by

cement. Circulating until the shaker is clean is also a typicalindicator of a properly conditioned hole.

Within the guide, it is recommended that cement jobs beconducted at turbulent flow rates where possible to enhance

drilling fluid displacement. When this is not possible (e.g.thixotropic cement blends), then mechanical aids to centralize

and move the casing become more important.

In Alberta, the Operator should also reference EUB Guide G-

9: Casing Cementing Minimum Requirements10and EUBGuide G-20: Well Abandonment Guide.

In Saskatchewan, the Operator should reference Section 34 ofthe SEM Oil and Gas Conservation Regulations, 1985.


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3.1.5.2 PrimaryCementing InHeavy Oil / OilSands Areas

For wells that are to be subjected to thermal operations,

thermal cement blends should be used to cement surface,

intermediate, and production casing full length.

Note Thermal cement is formed by reducing the Bulk Lime (CaO) toSilica (SiO2) ratio of non-thermal cement. The C:S Ratio (as

abbreviated by cement chemists) of a thermal cement is 1.0 orless and is normally obtained by the addition of 35% (by weight

of cement) or more fine Silica Sand or Silica Flour to thePortland cement.


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IRP 3.1.5.2.2 For wells drilled in Heavy Oil / Oil Sands areas that havepotential to become part of a thermal scheme in future,

thermal cement blends should be used to cement production

casing full length.

IRP 3.1.5.2.3 For wells drilled in Heavy Oil / Oil Sands areas that haveNO potential to become part of a thermal scheme in future,

production casing should be cemented using thermal

cement that extends a minimum of 30 vertical meters above

and below any potential thermal zone.

Note This recommendation covers the case where advances intechnology may expand the use of thermal recovery methodsbeyond the Operators current vision.

This recommendation follows current regulations in Alberta.This adequately protects the cement sheath from the negative

effects of elevated temperatures from the heated zone if the

well remains in a static state. Cementing in this manner may

disqualify the well as a producer or injector. A well that is notthermally cemented full length will require regulatory approval

prior to becoming active within a thermal scheme.The prudent

Operator would be expected to develop a method ofsafeguarding the integrity of the full length of cement sheath

prior to commencing thermal production or injection on this

well.


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IRP 3.1.5.2.4 For wells requiring intermediate casing:

To initiate a horizontal well completion, or

To provide well control in situations such as penetration of a

shallow gas or an enhanced oil recovery zone caution shouldbe exercised to protect the cement sheath. It is recommended

the cement develop a compressive strength of 3500 kPa priorto continuing drilling operations that would jeopardize theintegrity of the cement job.

Note In Saskatchewan, the SEM requires a minimum of 8 hourswait-on-cement time prior to testing the casing / BOPs orcommencing drilling below the casing shoe in Spacing Area

E.


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3.1.5.3 RemedialCementing

Prior to performing a remedial cement job in a Heavy Oil /Oil

Sands well, the following considerations should be weighed:

The main goal is isolation of water, gas, and oil zones.

It is desirable to maintain the integrity of the productioncasing when designing a remedial cement job especially in

thermal wells.

The presence of uncemented intervals, especially within the

annular space between casing strings, has led to casing failuresas trapped fluid expands under thermal conditions. This canoccur in a remedial top-up cement job.

It is desirable to have a thermal cement sheath completely to

surface on all wells to be thermally operated.

IRP 3.1.5.3.1 For all Heavy Oil / Oil Sands wells, if cement returns tosurface are not achieved, then the cement top must be

confirmed to determine if remedial cementing is required.

The cement top log and proposed remedial cementing

program must be submitted to the regulatory body prior to

placing the well on production.

IRP 3.1.5.3.2 For all non-thermal Heavy Oil / Oil Sands wells, if cementreturns are proven to be 15 m or more inside the surface

casing, then remedial cementing is not required. This

requires regulatory body approval.

IRP 3.1.5.3.3 For all thermal Heavy Oil / Oil Sands wells, if cementreturns to surface are not obtained, then remedial

cementing may be required. This is to be determined in

consultation with the regulatory body.


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Note In Saskatchewan, SEM approval is required prior tocommencing remedial cement programs and/or placing a well

on production after remedial cementing has taken place.

The need for remedial cementing will be determined based

upon the specific well conditions and the considerations noted

above.

Cementing all casing strings with thermal cement lessens the

impact of a low cement top that is above the previous casing

shoe (especially on a thermal well).

For thermal wells, remedial cementing using a tubing string run

into the annulus is discouraged. If the Operator is unable toconfirm the absence of fluid above the cement top, then trapped

fluid can cause casing collapse when steamed and should be

avoided.

For thermal wells, one suggested remedial cementing method

requires washing over the production casing to the top of

cement and re-cementing leaving the washover string in place.This requires sufficient annular space between casing strings

and care that the integrity of the production casing ismaintained. An example program outlining this method is

shown in Appendix D.

For non-thermal wells, remedial cementing using a tubing

string run into the annulus may be acceptable if it can reach thecement top. A second possible method requires perforating the

production casing at the cement top and circulating cement to

surface. Implementing these methods may place limitations on

the well as a future thermal producer or injector.


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3.1.5.4 Open HoleWell

Abandonment

IRP 3.1.5.4.1 Wells drilled within Heavy Oil / Oil Sands areas that are orhave potential to become part of a thermal scheme should

be abandoned using a thermal cement blend. Thermal

cement should be set a minimum of 15 vertical meters

above and below the thermal zone(s).

Note AEUB Guide G-20 specifies standard abandonment programsfor Alberta.

In Saskatchewan, SEM approval of all abandonment programs

is required prior to commencing abandonment operations.


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3.1.6 ThermalCasing AndCasingConnections

3.1.6.1Introduction

Steam stimulation operations in Heavy Oil / Oil Sands areas of

Western Canada present unique challenges for thermal well

casing design. The high temperatures required for effectivesteam stimulation and the cyclic nature of some thermal

operations can result in casing stresses that exceed yield in bothcompression and tension. Further, the wells may operate in acorrosive environment at both high and low temperatures.

Finally, some wells may operate at high temperatures for

extended periods during the injection phase. Given these varied

conditions, conventional design practices (that limit casingstresses to some fraction of the yield value and may specify

corrosion resistant alloys) are not as applicable to thermal

wells.

The following recommended practices are intended to aid in

selecting or designing a production casing string for use inthermal, steam stimulation operations in Western Canada. The

maximum well temperature and pressure considered was 350oC

and 16.5 MPa, respectively. The practices cited strike a balancebetween mechanical properties and corrosion resistance.

Although individual casing grades and connections are noted,

no single design is stated as the successful one for thermal

service since the type of service will determine the qualities ofa successful design.


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The recommended practices focus on the production casing (or

intermediate casing in the case of a horizontal well). A thermal

casing design is not required for the surface casing as this stringtypically is run only to maintain hole stability or assist in well

control.

Once the pertinent operating conditions such as temperature

range, pressure range, number of thermal cycles, and wellbore

environment are defined, an Operator should be able to design a

production casing that is appropriate for the intended service.This will require an understanding of the effects of thermal

cycling on the properties of the casing selected. Once a casing

design has been selected, each Operator will require a programto ensure that operating practices to protect the integrity of the

installed production casing are followed. This program is to

include:

monitoring of well operations,

methods of detecting casing failures, and

response plans for potential casing failures.

Work to outline the specifics of this program will be progressed

by another sub-committee.


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3.1.6.2 GeneralDesignConsiderations

For casing design purposes, it is assumed that the production

casing is supported full-length by a thermal cement sheath. This

support is essential for minimizing the potential for casingcollapse or buckling during thermal operation. Cementing of

the production casing is covered in IRP Section 3.1.5.

Thermal well casing typically yields in compression and may

yield in tension, thus, accurate determinations of the peak

compressive and tensile stresses, and the number of thermal

cycles expected are essential to properly designing the casingstring. Recent testing has provided data that shows the

Thermal-Mechanical relationship of stress with temperature

and thermal cycles for different casing grades (see Appendix E- Figures 1 through 6). This empirical data is preferred over

theoretical data derived from thermal well design papers11 & 12

that failed to recognize that stress relaxation could occur atsignificantly lower temperatures than existed in thermal wells.

The casing grade must have good resistance to environmentalcracking since the casing may operate in an acid gas (H2S and

CO2) or caustic steam environment for part of itsservice.1

133,,1144,,1155&&1166

The casing connection must provide good structural integrity

and sealability. The connection should be as strong as orstronger than the pipe body and provide an adequate seal at the

maximum compressive and tensile loads expected. Connection

strength is a function of connection design (e.g., threadformand wall thickness) and material grade. Sealing capability is a

function of the connection design (e.g., thread design or metal-

to-metal seal employed) and installation (e.g., thread compoundand make-up position and torque).


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3.1.6.3 DesignRequirements

This sub-section will outline the design parametersrecommended to select a production casing and connection that

is appropriate for service in thermal wells. Some discussion of

limitations will accompany each parameter as deemednecessary. In Saskatchewan, unless otherwise approved by

SEM, all casing and casing connections must meet or exceed

API specifications.

IRP 3.1.6.3.1 A production casing design must consider the temperaturerange and number of thermal cycles to which a thermal

well will be subjected. Similar to pipeline designs thatconsider displacement- or strain-controlled loading, a

thermal well casing design must accept limited plastic

strain.

Note In most thermal wells, a production casing string will undergoplastic strain, stress relaxation, and cyclic hardening. Thecasing grade selection must balance the impacts of these

factors.

Figures 1 through 6 in Appendix E show the thermal-mechanical relationships for API K-55, L-80, N-80, and C-95

casing grades for some temperature ranges. As demonstrated by

these plots, empirical data must be utilized to define thestrength properties of materials undergoing thermal cycling.

As demonstrated by Figures 1 through 6 in Appendix E,conventional design factors that typically restrict casing stresses

to 85% of yield are not applicable to thermal wells.


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IRP 3.1.6.3.2 If the production casing is expected to exceed yield duringoperation, a casing grade with the following properties is

recommended:

The Y/T ratio of yield strength (MPa) to tensile strength(MPa) is less than or equal to 0.90,

The casing grade has a strain hardening rate comparable to

API L-80 Type 1 or K-55.

For the casing grade selected, the well should be operatedwithin the temperature or thermal cycling limits imposed

by cyclic hardening such that the final imposed stresses are

within the casing design parameters.

Note Figure 1 of Appendix E illustrates the thermal-mechanicalrelationship of cemented API K-55 and L-80 grade casings

through one thermal cycle. A detailed discussion of the

temperature/stress cycle is also included in Appendix E.

Figure 2 of Appendix E illustrates typical Stress/Strain Curves

for API K-55, L-80, N-80, and C-95 grade casing. Theminimum and maximum yield strength and ultimate tensile

strength of each grade is also indicated.

Figures 3 through 6 of Appendix E illustrate the thermal-

mechanical relationships of cemented API K-55, L-80, N-80,

and C-95 grade casings over some temperature ranges.

The operator should obtain a copy of the mill certificates toconfirm that the casing chemistry and (cold) mechanical

properties are within the desired limits.


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IRP 3.1.6.3.3 The minimum recommended burst pressure rating for theproduction casing is the maximum rated discharge pressure

of the steam generator.

Note Although pressure relief valves are typically installed on thegenerators, designing for the maximum discharge pressure

provides an operational safety factor.

Consider lowering the burst rating if high axial stresses are

expected when the internal to external casing pressure

differential is high.

Wellhead pressure requirements are covered in IRP 3.3.9.1.1

and IRP 3.3.9.2.1. It is noted here that the pressure rating forthe wellhead may be less than the boiler rating if pressure-

limiting equipment is installed to protect the wellhead from

maximum steam generator pressures. Consideration should alsobe given to temperature de-rating of the wellhead dependent

upon the anticipated operating temperatures.


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IRP 3.1.6.3.4 The minimum recommended collapse pressure rating forthe production casing is the maximum fracture pressure of

any formation penetrated by the well.

Note If free liquid is trapped between the production casing orcement and the formation, when heated to steaming

temperatures this liquid should expand and fracture into the

formation rather than collapse the casing.

Material properties play a critical role in determining the

collapse resistance of tubulars. At the relatively low diameter tothickness (D/t) ratios of casing products, collapse is usually in

the yield or plastic collapse zones as defined by API. However,

the theoretical basis for the API formulas does not account for

post-yield material behavior, making the collapse formularelatively conservative for strain hardening materials such as

API K-55 grade steel. At tensile loads close to or exceeding

yield, the API bi-axial collapse design guideline (Henky-vonMises maximum strain energy of distortion theory of yielding)

17is of limited use for thermal well casing design. The engineer

must rely upon a combination of the API uni-axial collapseguideline, and limited bi-axial test data at moderate to large

tensile loads.18, 19, 20, 21 & 22

Consider de-rating the collapse rating if high axial stresses are

expected when the external to internal casing pressure

differential is high.


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IRP 3.1.6.3.5 The casing design must consider the operating environmentto which the well will be subjected. Resistance to

environmental cracking is important to the success of a

thermal well casing design.

The highest API minimum specified yield strengthrecommended for thermal well production casing is 550 MPa

(80 ksi)

The casing hardness should be limited to a Rockwell C value

of 22 or less.These recommendations are based upon several years of

thermal operating experience.

Note Environmental cracking includes sulfide stress cracking (SSC),stress corrosion cracking (SCC), and hydrogen induced

cracking (HIC) for the purposes of this IRP. A detaileddiscussion of environmental cracking mechanisms and typical

casing testing recommendations is found in Appendix F.

High strength' steel (i.e. steel with a minimum specified yield

strength greater than 550 MPa or 80 ksi) is not recommendedfor thermal service. Although high strength steel is less likely

to yield in thermal service it is more susceptible to sulfide stresscracking and can have a very limited capacity to absorb

thermally induced strain.

For corrosive environments, API L-80 grade casing is preferred

to N-80. L-80 has a controlled yield strength (i.e. an upper

limit of 95 ksi is specified by API). N-80 does not have acontrolled yield and its allowable yield strength can be as high

as 110 ksi.


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IRP 3.1.6.3.6 If operating conditions exist that may lead to environmentalcracking or salt deposition; the wellbore environment

should be controlled to protect the integrity of the

production casing. Development of an operational

procedure is recommended in IRP 3.3.6.5.1.

Note Regardless of the casing grade selected, environmentalcracking can still occur. Thus, operating procedures arerecommended to safeguard the casing. Several options are

outlined below. It is noted that one item from each section isdeemed sufficient to control each corrosion mechanism.

1) When potential for Sulfide Stress Cracking or HydrogenInduced Cracking exists, consider:

purging acid gases from the annulus, through the

perforations, with nitrogen,

circulating produced fluids through the annulus to break

the annular gas column and allow more basic (i.e.higher pH) fluids to coat the casing,

injecting inhibitors to provide a protective film against

the casing, or

installing a production packer in the tubing string toisolate the production casing from the operating

environment.


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2) When potential for Salt Deposition and Internal Pittingexists, consider:

avoiding aggressive venting for extended periods in

wells with high water production, or

periodically circulating produced fluids through the

annulus to dissolve salt plugs that may be forming.

3) When potential for Stress Corrosion Cracking exists,

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