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Energy Resources Conservation Board

640 Fifth Avenue SW Calgary, Alberta Canada T2P3G4

Informational I "-s'*-^ Letter

TO: All Oil, Gas and Oil Sands Operators

7 February 1984

CASING CEMENTING - MINIMUM REQUIREMENTS ERCB GUIDE G-9 REVISION

The Energy Resources Conservation Board has revised Guide G-9, entitled Casing Cementing - Minimum Requirements. The new guide updates the shallowest formations that must be covered when cementing intermediate or production casing and revises the requirement for minimum compressive strength of cement.

COMPRESSIVE STRENGTH OF CEMENT BLENDS

Under the new guideline the use of fillers and/or additives in the cement system, when cementing production, intermediate, and liner casing, will be acceptable if the compressive strength of the mixture is at least 3500 kilopascals (kPa) after curing for 48 hours at the temperature of the uppermost potential hydrocarbon zone. The remaining column of cement to surface is exempt from this strength requirement. Curing times were lengthened to 48 hours to provide a more reasonable choice of blends at low temperature while still ensuring a good quality cement job .

There was little information available for compressive strength of cement blends at the low curing temperatures encountered in shallow formations. In co-operation with Halliburton Services, Dowell of Canada, Canadian FracMaster Ltd., and Nowsco Well Service Ltd., laboratory compressive strength tests were conducted on a number of common cement blends at low curing temperatures.

Based on those results the Board considers the common cement blends tabulated below capable of developing a compressive strength of at least 3500 kPa after 48 hours of curing time at the temperatures noted.

CEMENT BLENDS WITH COMPRESSIVE STRENGTHS OF AT LEAST 3500 kPa AFTER 48 HOURS CURING

CURING TEMPERATURE

(1)

10°C

20°C

0:1:0 0:1:2 0:1:4

(2)

0:1:0 0:1:2 0:1:4 1:1:0 1:1:2 2:1:0

0:1:0 0:1:2 0:1:4 1:1:0 1:1:2 2:1:0

NOTES : (1) The temperature of the zone shall be calculated using a temperature gradient as outlined in Guide G-9.

Many other cement blends commonly listed in the service company cementing handbooks do not meet the 48-hour compressive strength requirements at these lower temperatures and consequently these blends can only be used as filler cements. The ERCB considers the use of filler-type cements to be acceptable in the portion of the cement column above the required cement top, as outlined in Guide G-9, or more than 100 metres above the uppermost hydrocarbon bearing formation in wells that are cemented to surface. The use of any other special blends or types of cement must receive prior approval from the ERCB.

Additional copies of the guide are available, free of charge, from the Maps and Publications desk of the Energy Resources Conservation Board's Information Services Department on the main floor, 640 - 5 Avenue SW, Calgary, Alberta.

If you have any questions regarding the guide, please contact the

Drilling Section of the Board's Development Department, telephone 297-3151,

telex 03-821717.

(2)

1:1:2 signifies one absolute volume of flyash, one absolute volume of cement, and 2 per cent gel by total weight.

V. E. Bohme Board Member

c

Energy Resources 640 Fifth Avenue SW Conservation Board Calgary, Alberta Canada T2P3G4

Informational CSM Letter

To J All Planners, Municipal Authorities, 24 February 1984

Developers, Consultants, Surveyors, and Oil, Gas, and Pipeline Operators

PIPELINE RECORDS AVAILABLE

This informational lettev supersedes Informational Letter IL 83-5 dated 2 May 1983 which describes the various types of pipeline records available. Changes have been made to some of the records, primarily in the listing of oil and gas pipeline maps that are available, and the recording of low pressure gas distribution lines. These and other details regarding the use and availability of the Board's pipeline records are provided in the appendices .

Proper information concerning pipeline construction and operations should be an essential part of the investigative process in urban and resource development. For this reason the Board urges all responsible parties to make use of its pipeline records in order to avoid any potential problems .

Further information may be obtained by calling the Board's Records Centre

at 297-8190 in Calgary.

Board Member

APPENDIX I

DETAILS OF PIPELINE RECORDS

The Board's records generally contain details of all oil, gas, or hydrocarbon pipelines constructed in Alberta. Certain kinds of lines however are excluded from the Board's jurisdiction, hence are not shown in its records. In addition, there could be some pipelines constructed without the Board's prior knowledge or approval, but every effort is made to include all lines under Board jurisdiction.

Types of Pipelines in the Board's Records Oil lines Gas lines

Water lines (generally associated with oil and gas production)

Flow lines (oil, gas, and water in combination)

Liquid petroleum gas (LPG) lines (propane, butanes, condensate, ethane, ethylene)

Some rural gas distribution lines^

Pipelines under National Energy Board jurisdiction (limited records)

Types of Pipelines Not in the Board's Records Domestic water-supply pipelines

Water-supply and effluent pipelines for projects other than those approved under the Oil and Gas Conservation Act

Pipelines specifically excluded under the Pipeline Act^

1 All high pressure (greater than 700 kPa) lines are included, but only some low pressure lines are shown. The local gas distributor in the area (rural gas co-op, gas utility company, etc) should be contacted for current information. See Interim Directive ID 84-2 for further information.

2 See Appendix II.

2

Pipeline Township Drawings (Microfiche or Paper)

These show, by township and range, the approximate location of all pipelines permitted or licensed by the Board. Users are urged to check with the permittee or licensee for the exact location. The identity of the permittee or licensee, along with a general description of the type of pipeline, can be obtained by reviewing the Pipeline Licence Register in the Board* s Records Centre.

Pipeline township drawings are presently updated daily, and may be purchased on paper or microfiche, or may be viewed at the Board's Records Centre in Calgary.

Oil and Gas Pipeline Maps

The Board makes available a selection of maps showing the main oil and gas pipelines in Alberta. The maps are reproduced as blueline prints, revised monthly, and available from the Board as single copies or by subscription.

These maps are titled as follows:

"Oil and Gas Fields and Main Pipelines in Alberta"

"Main Gas Pipelines in Alberta"

"Main High Vapour Pressure Pipelines in Alberta"^ "Main Pipelines Edmonton Area"*^

"Designated Oil and Gas Fields and Oil Sands Deposits, Main Pipelines, Refineries and Gas Processing Plants, Alberta"^

Pipeline Permits or Licences (Microfiche or Paper; Plans not Included)

Permit or licence documents identify legal descriptions and technical details associated with pipelines. These documents may be examined or purchased at the Board's Records Centre.

3 A high vapour pressure (HVP) pipeline means a pipeline transporting hydrocarbons or hydrocarbon mixtures in the liquid or quasi-liquid state with a vapour pressure in excess of 240 kPa at 38^C.

4 Also available from the City of Edmonton, Engineering Department, Supervisor Drafting, 12th Floor, Century Place,

9803 " 102A Avenue, Edmonton, Alberta, T5J 3A3.

5 Reproduced in colour.

3

Computer Data Base (Tape Reels)

The Board maintains a complete data base of information on pipeline permits and licences. This data base contains information concerning pipeline status, location, substance transported, pipe specifications, and test data. Retrieval of information may be by permit or licence number, or pipeline operator.

There are varying charges for the use of this service, ranging from the outright purchase of tapes to retrieval or subscription. The Board retains all proprietary rights on all data sold. Copying files for resale is not permitted. General information concerning this data base is available from the Board's Data Processing Department at 297-2480 in Calgary.

Other Sources of Information

Additional information about pipelines under the Board's jurisdiction may be obtained from a number of other reference documents and reports. This information is more general in nature, but could provide useful background and direction in the planning process.

A catalogue of publications, maps, and services (Guide G-1) , and copies of legislation. Interim directives, informational letters, and special reports are available at the Board's Records Centre in Calgary.

Digitized by the Internet Arcliive in 2015

https://arcliive.org/details/energyresources1984112

APPENDIX II PIPELINES SPECIFICALLY EXCLUDED UNDER PIPELINE ACT

Except as otherwise provided In the Pipeline Act, the Act applies to all pipelines In Alberta other than

(a) a pipeline situated wholly within the property of a refinery, processing plant, coal processing plant, marketing plant or manufacturing plant,

(b) a pipeline for which there Is In force

(I) a certificate, or

(II) an order exempting the pipeline from a certificate,

Issued or made by the National Energy Board under the National Energy Board Act (Canada) ,

(c) that portion of a distribution system for the distribution of gas to consumers In a city, town or village that Is within the boundaries of the city, town or village,

(d) a pipe transmitting gas or oil for use as fuel from a tank that Is situated wholly within the property of a consumer and the Installations In connection with that pipe,

(e) a gas Installation within the meaning of the Gas Protection Act, or

(f) a boiler, pressure vessel or pressure piping system within the meaning of the Boilers and Pressure Vessels Act.

Energy Resources Conservation Board

640 Fifth Avenue SW Calgary, Alberta Canada T2P3G4

Informational i il84-3

To: All Oil, Gas, Coal, and Pipeline Operators

12 April 1984

All Purchasers of ERCB Computer Data Files COMPUTER DATA SALES

The Board has received various queries from current and potential purchasers of ERCB computer-processable data files, which indicate there may be some misunderstanding regarding the subsequent release of the acquired data by purchasers to their respective clients.

Under the policy stated in the "ERCB Publications, Maps and Services Catalogue" Guide G-1 , dated January 1984, all computer-processable data files are sold by the ERCB on the condition that the ERCB retains proprietary rights on all data sold. Purchasers, including commercial Service Bureaus, may use the files to select and process data for internal or client use. Such client usage may involve specialized retrievals leading to the release of small portions of the files in computer-processable media to a client. Copying of a complete file, or a large portion thereof, for resale is not permitted.

The Board recognizes that due to changing technology and needs, and resource limitations, some potential purchasers may find it advantageous, and indeed necessary, to engage a Service Bureau to re-format or otherwise pre-process the ERCB data files before they can be installed on their own facilities.

For these reasons, the Board altered its policy effective 1 March 1984, as follows:

1. If the initial purchaser or commercial Service Bureau is a subscriber to an ERCB computer-processable file, it may, upon authorization from the ERCB, provide to a client a complete copy of the file, or a large portion thereof, to be installed on the client's facilities under any mutual financial arrangement with the client, provided that:

(a) the client first purchases from the ERCB the right to use the file, covering both initial copy and updating by the original purchaser or commercial Servic Bureau, at a discounted price of 75 per cent of the regular catalogue-quoted rate for a file obtained directly from the ERCB, and

(b) the client specifies the name of the original purchaser or commercial Service Bureau from whom the file is to be obtained.

2

2. Purchasers of full files, including commercial Service Bureaus, may

continue to use the files to select and process data for internal or client use, as described in the second paragraph of this letter, without any further compensation to the ERCB from either party.

Attachment A contains the standard conditions of sale for ERCB data files.

Attachment B contains a summary of the current prices of the major ERCB data files and update services.

If you require further information related to the ERCB data files please contact:

Co-ordinator, Computer Data Sales Data Processing Department Energy Resources Conservation Board Telepiione (403) 297-2480

H. ANTONIO Manager

Data Processing Department

ATTACHMENT A

STANDARD CONDITIONS OF SALE FOR ERCB DATA FILES

RIGHTS

o The ERCB retains the proprietary rights on all data sold.

o Purchasers of ERCB data files are permitted to use the files to select and process data for internal or client use and to release copies of small portions of the files on computer media, that result from specialized retrievals, to their clients.

o Purchasers of ERCB data files are not permitted to release copies of full files or substantial portions of the files on computer media without prior written authorization from the ERCB.

o Arrangements may be made to obtain an initial copy and/or an update service for a full ERCB file or a substantial portion of an ERCB file from another purchaser, provided an authorization is received from the ERCB prior to the data transfer. The subsequent purchaser must apply to the ERCB for the authorization and must name the supplier in the application. The ERCB fee for granting the authorization will be based on a discount on the price charged for the similar ERCB service.

DISCLAIMER

o The ERCB makes no representation, warranties or guarantees, expressed or implied, including without limitation any warranties of merchantability or fitness for the intended use with respect to the data files.

o The ERCB accepts no responsibility whatsoever for any inaccuracy, errors, or omissions in the data files.

o The ERCB shall not be responsible for any conversion, installation,

improvement to the data files, or other matter related to the data files nor any cost associated therewith.

o

The ERCB does not guarantee the continuing availability of any data or the consistency of the transfer record format.

ATTACHMENT

1984 PRICES FOR MAJOR ERCB DATA FILES

DATA FILE OBTAINED FROM

ERCB

3rd PARTY

General Well Data File

initial purchase quarterly update monthly update

Historical Well Production/Injection Data File

initial purchase

annual update

semi-annual update

quarterly update

monthly update

$40 000 4 000 4 800

500 000 200 500 000

$30 000 3 000 3 600

$ 4

875 750 900 125 250

Core Analysis File

initial purchase quarterly update

$15 000 1 500

$11 250 1 125

MAY 1 5 1984

Energy Resources Conservation Board

640 Fifth Avenue SW Calgary, Alberta Canada T2P3G4

Informational Letter

IL84-4

(4)

To: All Oil and Gas Operators

7 May 1984

INCENTIVE EXPLORATORY WELLS DRILLED UNDER THE EXPLORATORY DRILLING INCENTIVE REGULATION, 1983, AND EXPLORATORY DRILLING INCENTIVE REGULATION, 1984

This letter supersedes Informational Letters IL 83-9 and IL 82-8 issued on 25 August 1983,

Informational Letter IL 83-9 described the procedures employed by the Board when certifying and processing an incentive exploratory well under the 1981 and 1983 versions of the Exploratory Drilling Incentive Regulation. Sections 1 to 4 of this informational letter reiterate these procedures in the context of the 1983 and recently issued 1984 versions of this regulation. In addition to the revised regulation references, the definition of a "significant occurrence of crude oil or gas" has been modified slightly and re-worded for clarification. The references to the 1983 regulation will continue to apply for several months, until all wells drilled under that regulation have been processed.

Informational Letter IL 83-8 pertained to the pre-licensing appraisals made for industry relative to incentive exploratory wells drilled under the 1983 regulation. The information in that letter has been up-dated to conform with the 1984 regulation, and incorporated into this letter under section 5. The procedures and fee have not been changed.

To obtain a full description of all Board-administered aspects of the Exploratory Drilling Incentive System, this letter should be reviewed in concert with the 1983 and 1984 versions of the Exploratory Drilling Incentive Regulation, copies of which may be picked up from the Department of Energy and Natural Resources at either Room 807, J. J. Bowlen Building, Calgary, or the Exploration Review offices, 3rd floor, Victoria Place, 10009 - 108 Street, Edmonton.

2

1 DEFINITIONS

In this informational letter,

(a) "incentive exploratory well" means a well certified by the Board as an incentive exploratory well under either the 1983 or 1984 regulation;

(b) "pre-existing well", in relation to an incentive exploratory well, means

(i) a well drilled or deepened under a certificate issued before the date and the time of the issuance of the certificate that pertains to the drilling or deepening of the incentive exploratory well, or

(ii) an uncertified well that was spudded before the date and time of the issuance of the certificate that pertains to the drilling or deepening of the incentive exploratory well;

(c) "Class A interval" and "Class B interval" means the respective intervals of depth of an incentive exploratory well that qualify for credit or money equivalent considerations under Schedules N and 0 of the 1983 regulation, and Schedules R and S of the 1984 regulation, depending on which regulation is applicable;

(d) "qualifying interval" means the total Class A interval and/or Class B interval determined by the Board at an incentive exploratory well;

(e) "significant occurrence of crude oil or gas" means

(i) the deepest occurrence of crude oil or gas penetrated by a well cased or completed for current or eventual production purposes, except where the occurrence:

• had been produced, depleted, and abandoned before 1 April 1984, or

• on the basis of demonstrated pressure or production deterioration during an initial testing or production period is, in the opinion of the Board, either incapable of production through the existing or repositioned completed interval, or capable of such production only at substantially diminishing rates, or

(ii) the deepest occurrence of crude oil or gas penetrated by an abandoned well that, in the opinion of the Board, warrants being cased for current or eventual production purposes,

or

(iii) the deepest occurrence of crude oil or gas penetrated by an evaluation well that, in the opinion of the Board, would warrant being cased for current or eventual production purposes if the well had been drilled as a conventional well;

(f) "4.8-kilometre area" means the area of a circle, having a radius of 4.8 kilometres, that is centred at the bottom-hole location of the incentive exploratory well;

(g) "2.4-kilometre area" means the area of a circle, having a radius of 2.4 kilometres, that is centred at the bottom-hole location of the incentive exploratory well.

2 CERTIFICATION OF AN INCENTIVE EXPLORATORY WELL

The Board will certify a well to be drilled or deepened for oil or gas that, at the time of licensing or certificate renewal, satisfies either condition (a) or (b), below:

(a) located more than 4.8 kilometres from any pre-existing well that penetrated a significant occurrence of crude oil or gas, or

(b) located less than 4.8 kilometres from a pre-existing well that penetrated a significant occurrence of crude oil or gas, but intended to be drilled at least 150 metres below the base of the deepest significant occurrence of crude oil or gas.

3 DETERMINATION OF INTERVALS OF DEPTH QUALIFYING FOR CREDIT

For each incentive exploratory well, the total interval that qualifies for credit or money equivalent considerations will be determined and classified into Class A and/or Class B categories, in accordance with the following procedures. These procedures are illustrated in Figure 1.

3.1 Total Qualifying Interval

(a) If no pre-existing well penetrated a significant occurrence of crude oil or gas in the 4.8-kilometre area, the qualifying interval will be the interval extending from the total depth of the incentive exploratory well up to ground level.

(b) If a pre-existing well penetrated a significant occurrence of crude oil or gas in the 4.8-kilometre area, the qualifying interval will be the interval extending from the total depth of the incentive exploratory well up to the deepest of:

4

ground level at the incentive exploratory well, or

150 metres below the depth that, in the opinion of the Board, corresponds to the depth to the base of the deepest significant occurrence of crude oil or gas penetrated by any pre-existing well in the 4.8-kilometre area, or

if spudded on or after 1 April 1983 and before 1 November 1983, the base of the member or formation deemed by the Board to contain the deepest oil sands deposit underlying the location at which the incentive exploratory well is drilled.

3.2 Class A and Class B Intervals

(a) The Class A interval, if any, determined for an incentive exploratory well is that part of the total qualifying interval that is deeper than the total depth of the deepest pre-existing well in the 2.4-kilometre area.

(b) The Class B interval, if any, determined for an incentive exploratory well is that part of the total qualifying interval that is duplicated by a pre-existing well in the 2.4-kilometre area.

3.3 Miscellaneous Considerations

(a) When determining the distance between an incentive exploratory well and a pre-existing well, the Board bases its determination on the two wells* bottom-hole locations, rather than their surface locations, and it may require a directional survey to establish one or both of the bottom-hole locations.

(b) When determining the qualifying interval, if any, and the Class A or Class B components thereof, the Board will normally recognize the measured depth at both the incentive exploratory well and each influencing well. But where a well deviates significantly from the vertical, its true vertical depth may be considered.

(c) Any reasonably thick occurrence of carbonate rock containing medium or high grades of crude bitumen will be deemed to constitute an "oil sands deposit" within the meaning of this letter and Schedules N and 0 and section 9(c) of the 1983 regulation.

(d) Where a whipstocked hole is drilled, and where parts of the whips tocked and original holes occupy a common depth interval, only one of the holes over the common depth interval is eligible for Class A or B status.

5

4 DRILLING AREAS

The Foothills, Plains, Northern, and Central Areas, as defined under Schedule P of the 1983 regulation and Schedule T of the 1984 regulation, are outlined on Figure 2.

In the event that a discrepancy exists between Figure 2 and Schedule P or T, the latter governs. ^

5 PRELIMINARY APPRAISALS BEFORE LICENSING

(a) An operator may, in writing, ask whether or not a hydrocarbon i occurrence penetrated between specified depths in a named non-confidential well is deemed by the Board to constitute a "significant occurrence of crude oil or gas" within the meaning and purpose of section 1(e) of this informational letter, and section 9(b) and Schedules R and S of the 1984 regulation. A fee of $40 will be charged for each hydrocarbon occurrence appraised.

(b) An operator may also ask, in writing, whether or not a specific well is inside or outside the "4.8-kilometre area" or "2.4- kilometre area" associated with the anticipated incentive exploratory well. Such an inquiry should specify the legal descriptions and the known and expected bottom-hole co-ordinates of both the existing well and the anticipated incentive exploratory well. A fee of $40 will be charged for performing each distance determination associated with this type of an inquiry.

Written requests for a preliminary appraisal are to be directed to the Board's Geology Department and accompanied by a cheque for the required amount, payable to the Energy Resources Conservation Board.

All operators are reminded that the Board is not obligated to honour a preliminary appraisal for an anticipated incentive exploratory well when it officially determines or redetermines the qualifying interval pursuant to section 6(l)(a) or section 7(3) of the 1984 regulation. The preliminary appraisal may be deemed invalid where circumstances change before the official determination is made, where additional information is obtained, or where an error in the appraisal is later detected.

6

Any questions regarding the matters outlined in this letter may be directed to the Incentives Section in the Board's Geology Department at 297-8227 or 297-8398.

ENERGY RESOURCES CONSERVATION BOARD

Attachments (2)

CASE 1 lEW

CASE 2 lEW

CASE 3

■d^ lEW

I

CLASS A

I

I I

[f I

I I

[CLASS B

I

I

I

CLASS A

CLASS B

2.4 I < 4.8 km ►]

CASE 4

CASE 5

<[)- lEW

CASE 6 * A lEW

.CLASS I A I

|J2>4km |<< U 4Jkm

A

lU

PRODUCTIVE' WELL

CLASS B

1 I

CLASS A

I

LEGEND

UNPRODUCTIVE WELL

i I I I

INCENTIVE EXPLORATORY WELL

lEW

1

DEEPEST^'SIGNIFICANT OCCURRENCE OF CRUDE OIL OR GAS"- - - -

km , m

KILOMETRES, METRES

FIGURE 1 DETERMINATION OF CLASS A AND CLASS B INTERVALS UNDER THE 1983 AND 1984 REGULATIONS

IL84-4

IL84-4

MAY 2

Energy Resources Conservation Board

640 Fifth Avenue SW Calgary, Alberta Canada T2P3G4

Informational Letter

I IL84-5

To: All Oil and Gas Operators

16 May 1984

CLASSIFICATION OF WELLS DRILLED FOR OIL AND GAS IN ALBERTA

During the past few weeks, the recently issued OIL ROYALTY EXEMPTION REGULATION (the regulation) has prompted enquiries regarding the classification of wells. The regulation provides for certain royalty exemption benefits for the crude oil produced from the "exploratory meterage" at an "eligible well". According to the regulation an "eligible well" is one which, when licensed, is classified by the Board as a new-field wildcat, new-pool wildcat, deeper pool test, or outpost well. A development or shallower pool test well, on the other hand, is not an "eligible well" and therefore does not qualify for royalty exemption except under the circumstances stated in sections 5 and 6 of the regulation.

The purpose of this letter is to describe the well classification system used by the Board and to outline the policies and procedures used when it classifies wells in accordance with that system. This letter should be reviewed in conjunction with the regulation and Energy and Natural Resources Information Letter 84-5, copies of which are available from that department at either the 8th floor. Petroleum Plaza, North Tower, 9945 - 108 Street, Edmonton, or Room 807, J.J. Bowlen Building, Calgary.

1 DESCRIPTION OF THE WELL CLASSIFICATION SYSTEM

Below is a description of the Lahee Well Classification System. The system has been used by the Board for some 20 years to provide a standard basis for compiling drilling statistics .

1.1 Exploratory Category

The exploratory category consists of the following four classes of wells. A well licensed under this category contains "exploratory meterage" from ground level to total depth except under the circum- stances described in sections 1(c) (ii) and 4(2) of the regulation.

(a) A new-field wildcat well (NFW) is a well located at a considerable distance beyond the limits of known pools and drilled in a geological environment where oil or gas has not yet been discovered.

2

(b) A new-pool wildcat well (NPW) is a well located at a relatively considerable distance outside the limits of known pools, or drilled in a geological environment where other pools have been found but where, in the Board* s opinion, the complexities in the geological conditions are such that searching for a new pool is hazardous. The objective of a new-pool wildcat well is the discovery of a new pool in an area known to contain oil or gas.

(c) A deeper pool test well (DPT) is a well located within the established or expected limits of a pool or pools and drilled with the objective of searching for undiscovered oil or gas below the deepest such pool. As indicated in section 1(g) (ii) of the regulation, only the interval from the base of the deepest established pool to total depth qualifies as "exploratory meterage" at a deeper pool test.

(d) An outpost well (OUT) is a well drilled with the objective of extending, by a considerable distance, a pool already partly developed. Its original objective is the producing or producible pool, although it may be completed or abandoned at a higher or lower stratigraphic horizon. It is far enough from the expected limits of the pool to make its outcome uncertain but it is not far enough to be designated as a wildcat. If it is successful in its original objective, it will add materially to the productive area of the pool. It is not the Board's normal practice to apply the outpost classification to a well located less than two drilling spacing units from the nearest well in the pool. Such a well is usually classified as a development well.

1.2 Development Category

The class of well licensed under this category is defined below. It does not contain the "exploratory meterage" referred to in the regulation, except under unusual circumstances.

A development well (DEV) is a well drilled with the objective of further exploiting the productive zone of a pool in an area which has already been essentially proved capable of production from this pool. Such a well may be inside the pool as already outlined by wells, or it may be a relatively short distance outside these limits. On the basis of this definition, the Board normally assigns the development classification to an "edge well" located close to the recognized productive boundary of a pool. Further- more, the development classification may be employed by the Board where the well is to be drilled slightly deeper than the target pool, especially where the strata to be penetrated have little or no hydrocarbon-bearing potential below that pool.

3

A sixth class of well, known as a "shallower pool test", is recognized as a part of the exploratory category under the Lahee Well Classifica- tion System. A shallower pool test is a well located within the known or expected limits of an established pool and drilled with the objective of exploiting a pool thought to exist above the established pool. Such a well, however, is normally classified by the Board as a development well because, before the well is spudded, the existence of the target pool has usually been confirmed by the up-hole portion of adjacent wells.

2 IMPLEMENTATION OF THE WELL CLASSIFICATION SYSTEM - POLICIES AND PROCEDURES

' ~> *

2.1 Technical Considerations

(a) When classifying a well the Board takes into account such considerations as the geological objectives and projected total depth of the well, the geological conditions and known existence of hydrocarbons in the area in which the well is to be drilled, and, in its judgement, the general degree of the risk of failure involved.

(b) The Board makes no distinction between the type of hydrocarbon (oil or gas) in known pools when it classifies a well.

(c) Board-designated pool orders (G orders) have no bearing on the classification assigned to a well, although they do affect its confidential status. Such orders are disregarded for well classification purposes because they may not have been issued for nearby pools, or because their boundaries have not been updated to reflect current knowledge regarding the areal extent and continuity of the pools.

(d) The outcome of a well, whether successful or unsuccessful in encountering oil or gas, has no bearing on the classification initially assigned to the well.

2.2 Administrative Considerations

(a) The Board classifies a well at the time it is licensed. It recognizes, however, that according to established Lahee concepts, the classification of a well is intended to take into account the conditions that are known when the well is spudded.

(b) Where closely spaced wells are licensed simultaneously or within a short period of time, the Board may redetermine their classifica- tions in light of the knowledge that became available between their licensing and spudding dates. If warranted, the wells may be reclassified as development wells.

4

(c) The assigned well classification is recorded on both the issued well licence and the daily listing of well licences, and it is published and maintained on the records associated with the well.

(d) The Board, on its own initiative, may amend the classification of a well to accommodate an amendment to the well licence, to reflect failure to comply with the intentions recorded on the well licence application, or to provide for the correction of an obvious clerical error. For example, the classification may be amended if the well does not reach the projected total depth recorded on the well licence.

(e) The Board may classify the second and subsequent wells drilled after the discovery of a new pool as development wells, if they meet the meaning of the definition.

(f) When it classifies a well, the Board does not take into account the impact of the classification on the Oil Royalty Exemption System, the Alberta Petroleum Incentives Program, or any other regulatory consideration. Furthermore, to ensure consistency and impartial- ity, the Board does not entertain technical representations or opinions from the licensee concerning the classification of its well.

3 MISCELLANEOUS MATTERS

3.1 Discovery Pool Status

Item 2.1(c) of this letter states that Board-designated pool orders have no bearing on the classification of a well. Similarly, G orders are not intended to be used as a criterion for determining whether a pool qualifies as a "discovery pool" or an "established pool" under the regulation. A published pool outline does not necessarily reflect up- to-date pool development or the current interpretation of its areal extent.

3.2 Prognostic Well Classifications

Before a potential well is licensed, an operator may enquire, in writing, as to the classification the Board would assign to the well if it were licensed at the time of the enquiry. The letter of enquiry shall state the location and intended total depth of the potential well, and the names of the anticipated productive and terminating formations. The enquiry shall be accompanied by a cheque, payable to the Energy Resources Conservation Board, in the amount of $50 for each prognostic well classification requested.

The prognostic well classification determined by the Board will not necessarily coincide with the official classification assigned at the time of licensing, particularly where additional subsurface information becomes available between the enquiry and spudding dates.

5

3.3 Review of a Well Classification

An operator may, in writing, request the Board to review any prognostic or normal well classification determined after 1 April 1984. The letter should indicate the change being requested and include any arguments or evidence to support the proposed change. For any well licensed between 1 April and 1 June 1984, the request must be directed to the Board before 30 June 1984. In the case of a well licensed on or after 1 June 1984, the request must be directed before 14 days following the spudding date of the well. For each review requested, a fee of $75, payable by cheque to the Energy Resources Conservation Board, is charged at the time the request is made. The payment will be refunded where, in the opinion of the Board, a Board-committed clerical error had been the cause of the review being requested.

The review will be conducted by a senior member of the Board's staff, whose decision will be conveyed to the enquirer in writing.

Any questions regarding this letter may be directed to the Geology Department of the Board at 297-8212 or 297-8201.

ENERGY RESOURCES CONSERVATION BOARD

Energy Resources Conservation Board

640 Fifth Avenue SW Calgary, Alberta Canada T2P3G4

Informational Letter

IL 84-6

TO: All Energy Operators

MINED OIL SANDS BITUMEN PROCESSING TECHNOLOGY INTRODUCTION

In accordance with its obligations to ensure orderly, efficient development of energy resources in Alberta consistent with sound environmental protection, the Alberta Energy Resources Conservation Board (ERCB) has stressed the need for improved extraction and upgrading technology for the processing of mined oil sandsl»2»3,4^ Also, the ERCB recognized that a considerable lead time would have to be provided between basic laboratory research and field demonstration testing and the anticipated time of commercial implementation in future mined oil sands projects.

This informational letter pertains to the above subject matter and specifically is for the purpose of announcing the release of a report entitled "Oil Sands Bitumen Extraction Process Evaluation" prepared by Dynawest Projects Ltd. for the ERCB.

BOARD OBJECTIVES

In the Board's view, the desirable target for crude bitumen extraction effi- ciency from mined ore would be 95 per cent by mass or higher. Operating experience at the two existing plants, Suncor and Syncrude, has generally confirmed that the Clark hot water process when applied to ore grades below 10 per cent bitumen by mass results in recoveries less than 90 per cent by mass. The result is not only lower than desirable bitumen recovery, but also tailings accumulation rates disproportionately larger than for the higher grade ores.

1 "In the Matter of an Application of Shell Canada Ltd. and Shell Explorer

Ltd,^ under Part 8 of the Oil and Gas Conservation Act", ERCB Report 74-H.

2 "In the Matter of an Application of Petrofina Canada Ltd., Pacific

Petroleums Ltd., Hudson's Bay Oil and Gas Company Ltd., Murphy Oil Co. Ltd., and Candel Oil Ltd., under Part 8 of the Oil and Gas Conservation Act", ERCB Report 74-X.

3 "In the Matter of an Application of Home Oil Co. Ltd. and Alminex Ltd.

under Part 8 of the Oil and Gas Conservation Act", ERCB Report 75-H.

4 "Alsands Fort McMurray Project", ERCB Report 79-H.

2

This experience, along with a knowledge of the relationship between fresh water requirements and extraction efficiency, has convinced the Board that a process which could consistently achieve 95 per cent by mass or greater extraction efficiency would simultaneously enhance bitumen recovery, improve environmental management, and probably increase economic returns.

DYNAWEST BITUMEN EXTRACTION PROCESS EVALUATION

With those potential benefits in mind, the Board has continued to prompt investigation and demonstration of improved extraction technology. Its most recent endeavour in this regard is release of a report prepared by Dynawest Projects Ltd. The report describes and presents results of investigations which commenced some two years ago under the direction of the ERCB Management Committee chaired by Dr. R. N. Houlihan.

The ERCB retained Dynawest to undertake a detailed investigation of promising extraction processes and the potential timing of their commercial implemen- tation. The study was executed in three stages: a general review to identify potential improved extraction techniques, a preliminary appraisal of more advanced processes, and detailed study of selected processes. In the initial stage, Dynawest conducted a general review of published and patented bitumen extraction technology and identified 33 processes for consideration. Processes not being actively developed or for which data were not available were rejected after initial evaluation. For the remaining processes, data were obtained from developers, a technical evaluation was undertaken and each process was checked against screening criteria. The list of processes was screened to eleven which appeared to have potential and were supported by laboratory or field demonstration testing and also met certain criteria including: tested on Athabasca bituminous sands, ability to process low grade ore, improved hydrocarbon recovery and energy efficiency, potential to reduce environmental impact, potential for scale-up, and detailed material and energy balance data support. The detailed study included an assessment of the potential for technical and economic merit of the selected processes and requirements and proximity of commercial application.

5 "Bitumen Resources of Alberta: Converting Resources to Reserves" ,

N. A. Strom and R. B. Dunbar. The Future of Heavy Crude and Tar Sands, McGraw-Hill Inc., 1981.

6 "Bitumen Resources of Alberta: Recovery and Conversion to Synthetic Oil

Supply", N. Strom, R. B. Dunbar and F. J. Mink, Petroleum Society of CIM, Paper No. 80-31-08, May 1980.

3

The final draft report was reviewed on a confidential basis by an external review panel , composed of knowledgeable persons primarily from the oil sands industry, who provided valuable input and made recommendations for further work. It was the concensus of the review panel that the report was a valuable assessment of extraction technology and that some investigations should be extended using a collaborative industry approach. Certain limitations of the detailed study were also pointed out including such issues as inter- relationship of the utilities plant and process facilities, limited examination of modified hot water processes, and only preliminary review of solvent processes. However, the review panel recommended that major modifications to the study be left to a subsequent study.

ABSTRACT

The study evaluated alternative processes for extraction of bitumen from mined oil sands. A preliminary technical evaluation of possible processes was first undertaken and then selected processes were subjected to detailed evaluation.

The first phase of the study involved an evaluation of each alternative process against a base case hot water extraction process. Material balance and energy efficiency calculations were made for a medium grade Athabasca bituminous sand (10 per cent bitumen by mass). Consideration was given to the proven ability of processes to increase resource recovery and energy efficiency and to reduce environmental problems compared to the base case. The future commercial and scale-up potential for the processes were also assessed.

The first phase resulted in the identification of seven alternatives to be considered for detailed study of which three were subjected to detailed investigation. These alternatives and the base case are listed below by process type:

• Hot Water Extraction - Base Case '

• Modified Hot Water Extraction

- Two Stage Flotation Process

- RTR Process

• Direct Retorting

- Taciuk Process

- Lurgi Process

7 The Select Review Panel comprised:

Dr. M. Cantle, Canstar Oil Sands Ltd.

Dr. D. W. Devenny, Gulf Canada Resources Inc.

Mr. D. K. Faurshou, CANMET

Mr. D. Komery, Shell Canada Resources Ltd.

Mr. L. C. Stephenson, Esso Resources

Dr. R. Schutte, Syncrude Canada Ltd.

Mr. L. R. Turner, AOSTRA

Mr. I. Webster, Suncor Inc.

4

• Solvent Extraction

- SESA Process

- Dravo Process

• Oleophilic Sieve - Kruyer Process

Although all of the processes identified in the first phase were of keen interest to the ERCB, budget limitations forced it to limit detailed evaluation to four cases only. Thus, the second phase consisted of a detailed comparative evaluation of the following four selected processes:

• Hot Water Extraction - Base Case

• Modified Hot Water Extraction - Two Stage Flotation Process

(Developer: Syncrude Canada Ltd.)

• Direct Retorting - Taciuk Process

(Developer: UMATAC Industrial Processes Ltd.)

• Oleophilic Sieve - Kruyer Process

(Developer: Oleophilic Sieve Development of Canada Ltd., Kruyer Research and Development Ltd., and J. Kruyer Oil Corporation)

Each process was compared with the base case to determine the relative technical and economic advantages and disadvantages of the processes. A direct comparison of alternative processes was not attempted nor would it be feasible as each process is at a significantly different level of development for actual commercial operations.

A commercial design was conceptualized and evaluated for each process. The design was broadly based on the proposed Alsands Project, corresponding to an upgrader feed rate of some 25 000 cubic metres per calendar day of upgrader bitumen.

Of the processes studied, the Taciuk Process is considered to have the best long-term potential. The development of this promising process would depend on successful scale-up, which would have to be proven by field demonstration.

The Two Stage Flotation Process, a proprietary technology held by the Syncrude consortium, uses mainly conventional technology, and would require a short time frame for commercialization. The commercial development of this process would be of relatively low risk but would require successful demonstration of equipment scale-up and confirmation that the process can achieve high recovery from low grade ore.

Tailings disposal requirements for all of the alternative processes remain largely unproven. Tailings disposal costs represent a significant initial capital cost, similar to that for the extraction plant itself, and operating costs are also high. Although tailings transportation has been investigat further study including research and development in this area seems necessary.

8 "Athabasoa Oil Sande, Tailings Disposal Beyond Surface Mineable Limits" , A report for the Energy Resources Conservation Board, Alberta Energy and Natural Resources and Alberta Environment, Hardy Associates (1978) Ltd., January 1979.

5

Among the alternative processes that were not for budget reasons brought forward to the second phase, the following may be noted: the RTR process has been evaluated at a demonstration plant at the Suncor site and detailed results have been filed with the ERCB under confidential retention rules. Some limited off-site testing on Athabasca bituminous sands has been conducted by Lurgl, but this was not done under ERCB approval and no Information has been filed with the ERCB. Laboratory bench scale testing of the SESA and Dravo processes has been performed and In the course of the Dynawest study some of this Information was reviewed on a confidential basis. As In the case of the Lurgl work ^ however, most of this work has been performed outside of Alberta and the ERCB did not have the opportunity to monitor It.

Copies of the final public report on the study may be obtained at a cost of $50.00 from the Maps and Publications Counter (ERCB), 640 - 5 Avenue S.W., Calgary, Alberta, telephone 297 - 8328. The report may also be viewed at the ERCB Library.

Any questions regarding this matter should be directed to the ERCB*s Oil Sands Department at 297-3235.

N. A. Strom Board Member

CANADl^N.A

jf^JfO ^ ^ IPC /Si-

Energy Resources Conservation Board

640 Fifth Avenue SW Calgary, Alberta Canada T2P3G4

Informational Letter

IL84-7

TO: All Oil, Gas, and Oil Sands Operators

DECLAKATION OF OIL SANDS AREAS TO FACILITATE ORDERLY LEASING AND STABLE REGULATION

As in situ operations in oil sands and heavy oil areas has continued to expand, especially in the past two years, the problem of distinguishing extra-heavy oil from bitumen has loomed ever-larger. Developments in the Lindbergh, Elk Point, and Bonnyville areas - a sort of transition region between clearly identified bitumen as at Cold Lake and clearly identified extra-heavy oil as at Lloydminster - have lead to potential ambiguities in lease ownership rights. To resolve this difficulty and to foster sustained orderly development, the Energy Resources Conservation Board (ERCB) and Alberta Energy and Natural Resources (AE&NR) concluded that classifying the occurrences as either crude bitumen or conventional heavy oil, but not both, within a specified gross geological zone, would be propitious.

The recently issued Oil Sands Conservation Act provides the Board the authority to deem heavy hydrocarbon occurrences to be crude bitumen even if the substances do not completely match the general definition "in its naturally occurring viscous state, will not flow to a well".

On the above basis and with the objectives of facilitating orderly leasing and stable regulations, the ERCB has deemed the hydrocarbon substance, with the exception of natural gas and coal, found in certainl geological zones from the top of the Mannville formation through to the base of the Woodbend formation in the Athabasca, Cold Lake, and Peace River areas, as shown in the attached Figure 1 to be oil sands. The accompanying Oil Sands Area Orders (OSA) have been issued for this purpose. It is our expectation that these area outlines will only occasionally require adjustments because the oil sands have already been extensively outlined by drilling.

1 The specified zones are set out in Orders No. OSA 1, 2, and 3 which will be issued simultaneous with this IL.

2

In addition to the province-wide OSA declarations, the ERCB believes there would be advantages for administrative convenience to identify sub-areas or sectors of the very large oil sands occurrences using local geographic names. Adoption of the many local field names now used for gas fields in portions of the OSA areas was considered but found to be too irregular and detailed to be convenient. Thus, for example, the Cold Lake OSA has been classified into the sectors as shown on Figure 2, the objective being a more ready understanding of the location of a particular development project. The sector outlines can be adjusted in future as developments evolve.

As a matter of related information. Oil Sands Deposit Orders (OSD) , which are prepared by the ERCB Oil Sands staff, reflect crude bitumen occurrences as confirmed by geological data from drilled wells. OSDs include the geological zones and show area extent of the crude bitumen occurrences on a fairly detailed basis. The ERCB staff will continue to map and update these interpretations based on drilling data. Conventional heavy crude oil accumulations which adjoin and are in the same geological zones as the crude bitumen such as in the Lindbergh area will now be removed from existing oil pool G order designations and included within the appropriate OSD orders. As mentioned previously, in accordance with the Oil Sands Conservation Act^, these extra-heavy crude oil accumulations will now be combined with and called crude bitumen reserves. The rules for exploitation of these resources will then be as in other oil sands areas except that a matter such as well spacing density and pattern probably will be by SU Order designation recognizing in part the previously established con- ventional heavy oil rules for development.

Inquiries should be directed to the Board's Oil Sands Department, Mr. W. A. Mayer (297-8576), telex 03-821717.

N. A. Strom Board Member

2 The Oil Sands Conservation Act, recently enacted as chapter 0-5.5 of the Statutes of Alberta, 1983, enables the ERCB by order, with respect to a zone within a specified area set out in the order, to declare any hydrocarbon substance, except natural gas and coal, to be oil sands if the ERCB is satisfied:

(a) that the zone adjoins or is in reasonable proximity to an oil sands deposit, and

(b) that to do so would be in the interest of the orderly, efficient, or economic development of :

(i) the hydrocarbon substance, or

(ii) the bitumen in the oil sands deposit referred to in clause (a) .

FIGURE 2 COLD LAKE OIL SANDS AREA -SECTORS

CANADIANS

Energy Resources Conservation Board

640 Fifth Avenue SW Calgary, Alberta Canada T2P3G4

Informational IL 84-8

Letter

TO:

All Operators In the Walnwright Field

2 August 1984

WAINWRIGHT POOL BOARD ORDER Misc 7416

The purpose of this letter is to bring to the Operators* attention that a number of wells have been or are being produced in violation of the terms of Board Order Misc 7416. The order requires that no production be taken:

o from a well 180 days after the first production from the Wainwright Wainwright Pool has been taken, unless enhanced- recovery operations are approved, and

o from a well which produces in any month at an average gas-oil ratio, expressed in cubic metres per cubic metre, in excess of 180, and shall remain shut in for the balance of its exemption period, unless the Board authorizes, in writing, special production tests.

All wells listed on the attachment shall be shut in immediately and shall remain shut in until such time as enhanced-recovery operations are approved.

Indefinite or interim exemption from this order may be granted, upon written request to the Board's Oil Department (Attention: Mr. K. G. Sharp).

0. A. Bray, pVEng Manager Oil Department

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CANADIANA

Energy Resources 640 Fifth Avenue SW Conservation Board Calgary, Alberta Canada T2P3G4

Informational Letter

TO: All Operators and All Well 7 August 1984

Servicing Contractors

COMPLETION AND SERVICING OF SOUR WELLS

Reference is made to the recently issued Lodgepole Blowout Inquiry - Phase 2, Decision Report D 84-5. Appendix 5 to that report is a draft interim directive (ID) regarding blowout prevention at sour wells. It included a definition of a critical sour well and a special requirement that completion and servicing operations at critical sour wells will not be permitted without prior consent from the Board.

This letter is to remind all operators and service contractors that this special requirement also applies to existing wells that fall into the critical sour well category defined in the draft interim directive. Before consent is given to proceed with the completion and servicing operations at such a well, the Board must be satisfied with those matters addressed in special requirements 1 to 5 inclusive and 7 of the draft interim directive, except that they apply to completion and servicing operations at an existing well rather than drilling operations for a new well.

Special requirement 1 will be considered already fulfilled if either of the following criteria has been met:

1. The licensee of the critical well has previously filed with the Board a satisfactory emergency procedures plan for the well which specifically covers the completion and/or servicing operations, or

2. A satisfactory emergency procedures plan for a gas plant and/or other associated facilities has been filed with the Board which:

(i) includes the critical well, and

(ii) specifically covers any completion and/or servicing operations which may take place for the facilities included in the plan.

2

The Board is also prepared to consider a comprehensive field completion /ser- vicing procedures plan. This plan should address each special requirement (numbers 2 to 5) on a field basis. The approval of a comprehensive field or area plan would then satisfy the consent requirement any time the holder of the approval completed or serviced a critical sour well in that field.

Special requirement 7 will apply such that a complete inspection will be required prior to commencing completion or servicing operations, immediately after installation of the blowout prevention (BOP) stack. The Board's Area Office must be notified at least 48 hours ahead of time so that staff may participate if judged appropriate.

For the purposes of this matter, completion includes all subsurface operations required to put the well on production which are not included in the drilling plan. Servicing includes any operation requiring removal of the well head or any stimulation operation.

Manager

Development Department

c=->-

Energy Resources 640 Fifth Avenue SW Conservation Board Calgary, Alberta Canada T2P3G4

Informational r IL 84-10

Letter

TO: All Oil and Gas, Oil Sands, Pipeline, Coal, and Hydro and Electric Operators

ERCB MAILING LIST POLICY

This letter supersedes Informational Letter IL 80-18 issued on 24 July 1980.

The ERCB mailing list is designed to disseminate useful information to industry in a timely and economic manner and to mail out information which is not readily available in any other form. The Board's mailing system and policy are as follows:

1 The system allows industry to request the items it needs to receive. Each type of publication or document mailed from the Board has its own list (see Appendix I attached).

2 Each company is required to maintain its status on the lists. A letter will be sent annually to each company on Board mailing lists requesting confirmation of its need for each item. If confirmation is not received, the mailing will be discontinued.

3 All requests for placement on mailing lists must be made in writing to the Assistant Manager, Administrative Services. ERCB .

4 Board orders and approvals for oil and gas will only be mailed to parties on the field operator mailing lists. Coal, pipeline, and hydro and electric orders and approvals will not be distributed on mailing lists. All Board orders and approvals are available in the Records Centre. Oil and gas orders are summarized in the monthly Summary of Orders and Approvals, which is available free of charge on a mailing list basis.

The market demand order (MD) is available on a mailing list basis, but Board approval is required to receive same, and the list is restricted to oil and gas operators in Alberta.

2

5 Each company must maintain its status on the field operator mailing lists. In order to receive Board orders, approvals, and notices for any oil or gas field, you must notify the Board that you are an operator or other interested party in that field. New fields can be added to your records by written notification to the Board at any time. Only one copy of any document is mailed on field lists.

6 Extra copies of free documents cost the Board and industry added expense in paper, printing, mailing, and handling. The Board encourages industry to evaluate the number of copies requested and to consolidate mailings to one department within the company.

7 The address must include:

correct company name correct street address and mailing address city, province or state postal or zip code.

If necessary for internal mail delivery, it may include the department name or person *s title. However, due to the volume of staff changes, it MAY NOT INCLUDE A PERSONAL NAME.

Dated at Calgary, Alberta, on 26 September 1984

V. E. Bohme Board Member

3

ERCB MAILING LIST POLICY APPENDIX I to IL 84-10

INFORMATION AVAILABLE FREE ON MAILING LISTS Name Description

1 GB General Bulletin to all "operators"

in the oil, gas, oil sands, pipeline, coal, or hydro and electric industries reporting Board announcements of short-term interest.

2 IL Informational Letter to all

"operators" in the oil and gas, oil sands, pipeline, coal, or hydro and electric industries outlining new Board policy affecting operations.

Available lists:

1 oil, gas J oil sands, pipeline;

2 coal;

3 hydro and electric.

3 ID Interim Directive to all "operators"

in the oil, gas, oil sands, pipeline, coal, or hydro and electric industries which documents changes to official requirements for operations.

^n Interim Directive (ID) announces and prescribes new ERCB policy and requirements. The new policy is normally incorporated into the appropriate regulations at a later date.

Available lists:

1 oil, gas, oil sands, pipelines;

2 coal;

3 hydro and electric.

4

Name

4 Publication Notice

5 Field Operator Lists

6 Summary of Orders and Approvals

7 Tabulation of Nominations and Crude Oil Requirements

8 Proration Hearing Notice

9 MD Order

10 Field and Pool Code List

Description

All annual publications, decisions, revisions to Acts and regulations, and other Board publications are announced by Publication Notice.

Board orders, approvals, and notices pertaining to a particular oil and gas field may be requested by operators and others directly concerned with that field. Notify the Board in writing of fields of interest.

A summary of all oil- and gas-related Board orders and approvals issued the previous month. Orders of interest can be picked up at the Records Centre.

Monthly summary of purchasers* nominations for crude oil in Alberta, issued after monthly proration-to- market-demand hearing. List restricted to purchasers of Alberta oil.

Notice of monthly proration-to-market- demand hearing for crude oil. List restricted to media and purchasers of Alberta oil.

Monthly Board order establishing production for each crude oil pool based on the market demand. List restricted to oil and gas operators in Alberta. Board approval required.

Monthly list of codes for fields and pools; to be used in completing various production and statistical report forms (ie, S - reports).

5

Name

Description

11 Geological Formations and Markers

- alphabetic and numeric lists

List of geological formation names and their codes to assist in interpretation of the Board's Basic Well Data file. Formation codes must be used on the S-4 form.

12

13

Licensee and Agent Code list - alphabetic and

Licensee and Agent Code list - numeric

List of names, addresses, and codes of well licensees or their agents; issued quarterly. Codes are used in completing production and statistical report forms, and in the Board's Production-Injection Data file.

14 Permits and Licences

Permits and licences are available to permittees, licensees, and others

directly concerned with:

1 gas or ethane removal;

2 industrial development (petrochemical ) ;

3 coal;

4 hydro and electric.

15 Rural Electrification Approvals

Sale and transfer of REAs are available.

Energy Resources 640 Fifth Avenue SW Conservation Board Calgary, Alberta Canada T2P3G4

Informational r.^^ Letter ""^"^

To: All Oil, Gas, Oil Sands, 29 October 1984

and Gas Plant Operators

APPROVAL, MONITORING, AND CONTROL OF SULPHUR STORAGE SITES

Alberta Environment (AE), Alberta Energy and Natural Resources (ENR), and the Energy Resources Conservation Board (ERCB) have reviewed the existing approval system and inspection procedures for sulphur handling facilities. This Informational Letter summarizes the responsibilities of each agency and the current guidelines for installing and operating sulphur handling facilities.

I New Facilities

Applications for new or modified primary sulphur handling facilities^ associated with sour gas plants are to be sent to the Gas Department of the ERCB. Applications for new or modified primary sulphur handling facilities associated with primary crude bitumen upgrading plants are to be sent to the Oil Sands Department of the ERCB. Primary sulphur handling facilities have been and will continue to be approved as part of an application for a gas processing scheme pursuant to the Oil and Gas Conservation Regulations or an oil sands processing plant pursuant to the Oil Sands Conservation Act. It is intended that distinct approvals or licences would not be issued for these facilities.

Approvals and regulation of secondary sulphur handling facilities are the sole responsibility of AE. Applications for new or modified sec- ondary sulphur handling facilities are to be sent to the Standards and Approvals Division of AE.

1 This and other terms are defined in Section V.

2

It Is expected that operators will select sites for primary and second- ary sulphur handling facilities and design and operate such facilities in a manner that minimizes environmental impact on the surrounding area. Particular emphasis is to be placed on minimizing sulphur dust emissions, minimizing the release of entrained gases, and preventing releases of contaminated waters to surface or ground-water systems.

II Modification of Existing Facilities or Operations

Primary sulphur handling facility operators who are contemplating major changes in mode of operation are to notify either the Oil Sands or Gas Department of the ERCB (whichever is appropriate) in advance, outlining the changes in operations and addressing action that will be taken to minimize the potential for environmental impacts. The ERCB will then refer this notice to the appropriate divisions within AE or ENR. A major change in mode of operation would include, but is not limited to:

(i) commencement of sulphur block recovery by any method,

(ii) development of a new block or stockpile,

(iii) installing new or additional prilling, slating, or forming facilities,

(iv) recovery of contaminated sulphur or sulphur base pad, and

(v) final clean-up of sulphur product.

Notification of changes to mode of operations at a secondary sulphur handling facility are to be made to the Standards and Approvals Division of AE.

Ill Facility Operation Responsibility

The operator of a primary sulphur production facility will be deemed responsible for clean-up, reclamation, and rehabilitation of the primary sulphur handling facilities site and any off-site rehabilita- tion effort required as a result of the operation of the primary sulphur handling facilities, regardless of ownership of the sulphur being handled or stored. The operator of a primary sulphur handling facility shall be the company recognized by the ERCB in its respective approvals, and in the case of public lands, includes the lessee as defined in the Public Lands Act.

3

IV Monitoring and Corrective Action

The ERCB Is the primary contact for operations. Inspection, and cor- rective action at the site of primary sulphur handling facilities. Where off-site monitoring by the operator, AE, or ENR Indicates undesirable environmental Impacts are occurring, the ERCB will be the contact agency respecting Initiation and Inter-agency co-ordination of corrective action, ,

AE Is the primary contact and co-ordinating agency for operations. Inspection, and corrective action at the site of secondary sulphur handling facilities.

Specific off-site air, water, and soli monitoring requirements are a direct responsibility of AE. In addition, the following on-site matters should be dealt with directly between operators of primary sulphur handling facilities and AE:

(I) all systems that discharge liquid waste off-site to surface,

(II) ground-water systems, and

(III) site decontamination and reclamation.

ENR manages the publicly-owned resources of timber, public land, fish, and wildlife In Alberta. In addition to approving surface uses of public lands, ENR will become Involved through the respective lead agency for sulphur handling facilities In any matters that have or may Impact these resources. Including problem identification.

V Definitions

For the purpose of this Informational Letteri

(a) sulphur production facility means any facility producing sulphur at a sour gas plant or a crude bitumen upgrading plant,

(b) primary sulphur handling facility means any location, structure, or equipment which Is associated directly with and proximal to a sulphur production facility and which handles, stores, forms, remelts, or loads sulphur, and

(c) secondary sulphur handling facility means any location, structure, or equipment which receives sulphur from a sulphur production facility or from a primary sulphur handling facility for the purposes of handling, storing, forming,

4

remeltlngy or loading sulphur and Is located a significant distance from the facility from which It receives Its sulphur or operates by virtue of an approval Independent of the sulphur production facility.

V. E. Bohme Board Member

Energy Resources Conservation Board

W. Solodzuk Deputy Minister Alberta Environment

F. W. McDou^l

Deputy Minister, Renewable Resources Alberta Energy and Natural Resources

4f

Energy Resources Conservation Board

640 Fifth Avenue SW Calgary, Alberta Canada T2P3G4

Informational Letter

23 November 1984

To: All Oil, Gas, and Oil Sands Operators

SURFACE CASING AND LOGGING REQUIREMENTS tJEW DISPOSAL AND INJECTION WELLS

There has been an increase in the number of wells proposed for disposal or injection service, and the Energy Resources Conservation Board (the Board) is concerned with the possibility of casing failures, zonal communication, or contamination of fresh water aquifers because of inadequate well completions. To minimize the potential for problems of this nature, the Board has revised its requirements with respect to injection and disposal well completions. Effective immediately, except in cases where specific exemption for a well or a project is granted by the Board, the following are required:

• minimum of 180 metres of surface casing in all newly drilled injection or disposal wells, and

• cement bond, cement evaluation, and casing inspection logs in all proposed injection and disposal wells in accordance with the attached table.

The Board will consider applications to amend or waive the logging requirements

where the applicant can prove cement or casing integrity based on other available information, or where the Board is satisfied that circumstances

warrant it. In addition, the Board may require one of these logs to be run and

submitted as part of an application for an amendment to an existing disposal or injection approval.

Questions concerning this matter may be directed to the Board's Development Department at 297-8283.

Development Department

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