Athabasca Viking/Grand Rapids/Nisku Technical ... - Oil Reserve Inc.

Oil Reserve Inc. 

Resource study 

Viking, Grand Rapids, and Nisku Formations 

Athabasca, Alberta 

Effective date: March 31, 2012

Fifth Avenue Place 

600, 425 – 1 Street SW 

Calgary AB T2P 3L8 

Canada 

Tel: 403-648-3200 

Fax: 403-265-0862 

www.deloitte.ca 

June 28, 2012 


Suite 2, 880 – 16 th Avenue SW 

Calgary, Alberta 

T2R 1J9 

Attention: Mr. Frank van der Vliet 

RE: 




At your request and authorization, Deloitte & Touche LLP (“AJM Deloitte”) has evaluated the oil and gas 

resources located in the Athabasca area of Alberta, effective March 31, 2012. This report has been 

prepared for Oil Reserve Inc. (“ORI”). 

This report documents the results of our independent evaluation of the total un-risked prospective 

resource volumes. These volumes were estimated using stochastic techniques. The extent and character 

of ownership and all factual data supplied by Oil Reserve Inc. were accepted as presented (see 

Representation Letter attached within). 

This report contains forward looking statements including expectations of future capital expenditures. 

Information concerning resources may also be deemed to be forward looking as estimates imply that the 

resources described can be profitably produced in the future. These statements are based on current 

expectations that involve a number of risks and uncertainties, which could cause the actual results to 

differ from those anticipated. These risks include, but are not limited to: the underlying risks of the oil 

and gas industry (i.e. operational risks in development, exploration and production; potential delays or 

changes in plans with respect to exploration or development projects or capital expenditures; the 

uncertainty of resources estimates; the uncertainty of estimates and projections relating to costs and 

expenses, political and environmental factors), and commodity price and exchange rate fluctuation. 

A Boe conversion ratio of six (6) Mcf: one (1) barrel has been used within this report. This conversion 

ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does 

not represent a value equivalency at the wellhead.




Page 2 

This report has been prepared for the exclusive use of Oil Reserve Inc. This report is not to be 

reproduced, distributed or made available, in whole or in part, to any other person, company, regulatory 

body or organization without the complete content of the report and the prior knowledge and written 

consent of AJM Deloitte. AJM Deloitte hereby gives its consent to the use of its name and to the said 

estimates pursuant to Part 5 Section 5.7 Item (2) of NI 51-101. 

AJM Deloitte is independent of Oil Reserve Inc. as provided in the standards pertaining to the estimating 

and auditing of oil and gas resource information included in the Canadian Oil and Gas Evaluation 

Handbook, set out by the Society of Petroleum Evaluation Engineers (“SPEE”) and the Association of 

Professional Engineers, Geoscientists of Alberta (“APEGA”). 

It has been a pleasure to perform this evaluation for you, and we trust it is sufficient to meet your current 

requirements. Should you have any questions, please contact our office. 

Yours truly, 

Original signed by: “Douglas S. Ashton” 

Douglas S. Ashton, P. Eng. 

Associate Partner 

Deloitte & Touche LLP 

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92-B-14 92-H-4 92-H-1 82-E-2 82-F-3 82-G-4 82-G-1 R25 R18 R11 R5 R29 R22 

Kilometres 

0 100 200 300 

Legend 

0 100 200 

Miles 

Evaluated Property 


Property Location 

Effective March 31, 2012 

By : kma Date : 2012/06/27 

Scale = 1:7532564 Project : ori loc

Independent petroleum consultants consent 

The undersigned firm of Independent Qualified Reserves Evaluators and Auditors of Calgary, Alberta, 

Canada has prepared an independent evaluation of resources and value derived therefrom, of the 

Petroleum and Natural Gas assets of the interests of Oil Reserve Inc. according to the Canadian Oil and 

Gas Evaluation Handbook. If required, these resources and values were estimated using forecast prices 

and costs (before and after income taxes) according to the requirements of National Instrument 51-101 (NI 

51-101). The effective date of this evaluation is March 31, 2012. 

In the course of the evaluation, Oil Reserve Inc. provided AJM Deloitte personnel with basic information 

which included land, well and accounting (product prices and operating costs) information; reservoir and 

geological studies, estimates of on-stream dates for certain properties, contract information, budget 

forecasts and financial data. Other engineering, geological or economic data required to conduct the 

evaluation and upon which this report is based, were obtained from public records, other operators and from 

AJM Deloitte non confidential files. The extent and character of ownership and accuracy of all factual data 

supplied for the independent evaluation, from all sources, has been accepted. 

A “Representation Letter” dated June 22, 2012 and signed by both the Vice President Exploration and a 

Director was received from Oil Reserve Inc. prior to the finalization of this report. This letter specifically 

addressed the accuracy, completeness and materiality of all the data and information that was supplied to 

us during the course of our evaluation of Oil Reserve Inc.’s reserves and net present values. This letter is 

included within. 

A field inspection and environmental/safety assessment of the properties was beyond the scope of the 

engagement of AJM Deloitte and none was carried out. The “Representation Letter” received from Oil 

Reserve Inc. provided assurance that no additional information necessary for the completion of our 

assignment would have been obtained by a field inspection. 

The accuracy of any reserve and production estimates is a function of the quality and quantity of available 

data and of engineering interpretation and judgment. While reserve and production estimates presented 

herein are considered reasonable, and adhere to the COGE Handbook and NI 51-101 (as applicable), the 

estimates should be accepted with the understanding that reservoir performance subsequent to the date of 

the estimate may justify revision, either upward or downward. 

Revenue projections presented in this report are based in part on forecasts of market prices, current 

exchange rates, inflation, market demand and government policy which are subject to uncertainties and 

may in future differ materially from the forecasts herein. Present values of future net revenues documented 

in this report do not necessarily represent the fair market value of the reserves evaluated herein. 

PERMIT TO PRACTICE 

Deloitte 

Permit Number: P-11444 

The Association of Professional Engineers 

and Geoscientists of Alberta

Certificate of qualification 

I, D. S. Ashton, a Professional Engineer, of the 6 th Floor, 425 – 1 st Street S.W., Calgary, Alberta, Canada 

hereby certify that: 

1. I am an associate of Deloitte & Touche LLP (“AJM Deloitte”), which did prepare an evaluation of 

certain oil and gas assets of the interests of Oil Reserve Inc. The effective date of this evaluation 

is March 31, 2012. 

2. I do not have, nor do I expect to receive any direct or indirect interest in the properties evaluated 

in this report or in the securities of Oil Reserve Inc. 

3. I attended the University of Calgary and graduated with a Bachelor of Science Degree in 

Chemical Engineering in 1992; that I am a Registered Professional Engineer in the Province of 

Alberta; and I have in excess of nineteen years of engineering experience. 

4. I am a Qualified Reserves Auditor as defined in the Canadian Oil and Gas Evaluation Handbook, 

Volume 1, Section 3.2. 

5. A personal field inspection of the properties was not made; however, such an inspection was not 

considered necessary in view of information available from the files of the interest owners of the 

properties and the appropriate provincial regulatory authorities. 

Original signed by: “D. S. Ashton” 

D. S. Ashton, P. Eng. 

June 22, 2012 

Date


I, D. L. Horbachewski, a Professional Geologist, of the 6 th Floor, 425 – 1 st Street S.W., Calgary, Alberta, 

Canada hereby certify that: 

1. I am an employee of Deloitte & Touche LLP (“AJM Deloitte”), which did prepare an evaluation of 

certain oil and gas assets of the interests of Oil Reserve Inc. The effective date of this evaluation 

is March 31, 2012. 



3. I attended the University of Calgary and graduated with a Bachelor of Science Degree in Geology 

in 1999; that I am a Registered Professional Geologist in the Province of Alberta; and I have in 

excess of twelve years of geological experience. 




Original signed by: “D. L. Horbachewski” 

D. L. Horbachewski, P. Geol. 

June 22, 2012 

Date


I, L. J. Machula, a Professional Geologist, of the 6 th Floor, 425 – 1 st Street S.W., Calgary, Alberta, Canada 

hereby certify that: 

1. I am an employee of Deloitte & Touche LLP (“AJM Deloitte”), which did prepare a detailed 

analysis of certain oil and gas assets of the interests of Oil Reserve Inc. The effective date of this 

evaluation is March 31, 2012. 



3. I attended the University of Calgary and graduated with a Bachelor of Science in Geology in 

2002; that I am a Registered Professional Geologist in the Province of Alberta; and I have in 

excess of four years of experience in geological exploration and evaluations of Western Canadian 

and International oil and gas fields. 




Original signed by: “L. J. Machula” 

L. J. Machula, P. Geol. 

June 22, 2012 

Date

Evaluation procedure 

Definitions and methodology 

Effective as of March 2012 

© Deloitte & Touche LLP and affiliated entities.

2 

Table of contents 

Definitions 

 

 

Procedure 

Resource and reserve definitions 

Resource and reserve estimation 

Production forecasts 

Land schedules and maps 

Geology 

Royalties and taxes 

Capital and operating considerations 

Price and market demand forecasts 

Glossary of terms 


3 

Procedure 

AJM Deloitte has prepared estimates of resources and reserves in accordance with the process published in 

The Canadian Oil and Gas Evaluation Handbook (COGEH), Volume 1, 2 nd Edition. The reader is referred to 

the Handbook for a complete description of the particular process quoted as follows. 

Resources or reserves evaluation 

A “Resources or Reserves Evaluation” is the process whereby a qualified reserves evaluator estimates the 

quantities and values of oil and gas resources or reserves by interpreting and assessing all available 

pertinent data. The value of an oil and gas asset is a function of the ability or potential ability of that asset to 

generate future net revenue, and it is measured using a set of forward-looking assumptions regarding 

resources or reserves, production, prices, and costs. Evaluations of oil and gas assets, in particular reserves, 

include a discounted cash flow analysis of estimated future net revenue. 

Reserves audit 

A “Reserves Audit” is the process carried out by a qualified reserves auditor that results in a reasonable 

assurance, in the form of an opinion, that the reserves information has in all material respects been 

determined and presented according to the principles and definitions adopted by the Society of Petroleum 

Evaluation Engineers (“SPEE”) (Calgary Chapter), and Association of Professional Engineers and 

Geoscientists of Alberta (“APEGA”) and are, therefore free of material mis-statement. 

The reserves evaluations prepared by the Corporation have been audited, not for the purpose of verifying 

exactness, but the reserves information, company policies, procedures, and methods used in estimating the 

reserves will be examined in sufficient detail so that AJM Deloitte can express an opinion as to whether, in 

the aggregate, the reserves information presented by the Corporation are reasonable. 

AJM Deloitte may require its own independent evaluation of the reserves information for a small number of 

properties, or for a large number of properties as tests for the reasonableness of the Corporation’s 

evaluations. The tests to be applied to the Corporation’s evaluations insofar as their methods and controls 

and the properties selected to be re-evaluated will be determined by AJM Deloitte, in its sole judgment, to 

arrive at an opinion as to the reasonableness of the Corporation’s evaluations. 


4 

Reserves review 

A “Reserves Review” is the process whereby a reserves auditor conducts a high-level assessment of 

reserves information to determine if it is plausible. The steps consist primarily of enquiry, analytical 

procedure, analysis, review of historical reserves performance, and discussion with the Corporation’s 

reserves management staff. 

“Plausible” means the reserves data appear to be worthy of belief based on the information obtained by the 

independent qualified reserves auditor in carrying out the aforementioned steps. Negative assurance can be 

given by the independent reserves auditor, but an opinion cannot. For example, “Nothing came to my 

attention that would indicate the reserves information has not been prepared and presented in accordance 

with principles and definitions adopted by the SPEE (Calgary Chapter), and APEGA (Practice Standard for 

the Evaluation of Oil and Gas Reserves for Public Disclosure). 

Reviews do not require examination of the detailed document that supports the reserves information, unless 

this information does not appear to be plausible. 


5 

Resource and reserve definitions 

The term “resources” encompasses all petroleum quantities that originally existed on or within the earth’s 

crust in naturally occurring accumulations, including Discovered and Undiscovered (recoverable and 

unrecoverable) plus quantities already produced. Accordingly, total resources are equivalent to Total 

Petroleum Initially-In-Place (“PIIP”). 

Total Petroleum Initially-In-Place (“PIIP”) is that quantity of petroleum that is estimated to exist 

originally in naturally occurring accumulations. It includes that quantity of petroleum that is 

estimated, as of a given date, to be contained in known accumulations, prior to production, plus 

those estimated quantities in accumulations yet to be discovered (equivalent to “total resources”). 

Discovered Petroleum Initially-In-Place (equivalent to discovered resources) is that quantity of 

petroleum that is estimated, as of a given date, to be contained in known accumulations prior to 

production. The recoverable portion of Discovered Petroleum Initially-In-Place includes Production, 

Reserves, and Contingent Resources; the remainder is unrecoverable. 

Production is the cumulative quantity of petroleum that has been recovered at a given date. 

Reserves are estimated remaining quantities of oil and natural gas and related substances 

anticipated to be recoverable from known accumulations, as of a given date, based on: the analysis 

of drilling, geological, geophysical, and engineering data; the use of established technology; and 

specified economic conditions, which are generally accepted as being reasonable. Reserves are 

further classified in accordance with the level of certainty associated with the estimates and may be 

sub-classified based on development and production status. Refer to the full definitions on Reserves 

in Section 5.4 of COGEH. 

Contingent Resources are those quantities of petroleum estimated, as of a given date, to be 

potentially recoverable from known accumulations using established technology or technology under 

development, but which are not currently considered to be commercially recoverable due to one or 

more contingencies. Contingencies may include factors such as economic, legal, environmental, 

political and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent 

resources the estimated discovered recoverable quantities associated with a project in the early 

evaluation stage. Contingent Resources are further classified in accordance with the level of 

certainty associated with the estimates and may be sub-classified based on project maturity and/or 

characterized by their economic status. Refer to COGEH and Figure 5-1. 


6 

Unrecoverable is that portion of Discovered and Undiscovered PIIP quantities which is estimated, 

as of a given date, not to be recoverable by future development projects. A portion of these 

quantities may become recoverable in the future as commercial circumstances change or 

technological developments occur; the remaining portion may never be recovered due to the 

physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks. 

Undiscovered Petroleum Initially-In-Place (equivalent to undiscovered resources) is that quantity 

of petroleum that is estimated, on a given date, to be contained in accumulations yet to be 

discovered. The recoverable portion of Undiscovered Petroleum Initially-In-Place is referred to as 

Prospective Resources; the remainder as Unrecoverable. 

Prospective Resources are those quantities of petroleum estimated, as of a given date, to be 

potentially recoverable from undiscovered accumulations by application of future development 

projects. Prospective Resources have both an associated chance of discovery and a chance of 

development. Prospective Resources are further subdivided in accordance with the level of certainty 

associated with recoverable estimates assuming their discovery and development and may be subclassified 

based on project maturity. Refer to COGEH and Figure 5-1. 

Reserves, Contingent Resources, and Prospective Resources should not be combined without 

recognition of the significant differences in criteria associated with their classification. For example, 

the sum of Reserves, Contingent Resources, and Prospective Resources may be referred to as 

Remaining Recoverable Resources. When resources categories are combined, it is important that 

each component of the summation also be provided, and it should be made clear whether and how 

the components in the summation were adjusted for risk. 

Uncertainty ranges 

The range of uncertainty of estimated recoverable volumes may be represented by either deterministic 

scenarios or by a probability distribution. Resources should be provided as low, best, and high estimates as 

follows: 

Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be 

recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If 

probabilistic methods are used, there should be at least a 90 percent probability (P 90 ) that the 

quantities actually recovered will equal or exceed the low estimate. 


7 

Best Estimate: This is considered to be the best estimate of the quantity that will actually be 

recovered. It is equally likely that the actual remaining quantities recovered will be greater or less 

than the best estimate. If probabilistic methods are used, there should be at least a 50 percent 

probability (P 50 ) that the quantities actually recovered will equal or exceed the best estimate. 

High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be 

recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. 

If probabilistic methods are used, there should be at least a 10 percent probability (P 10 ) that the 

quantities actually recovered will equal or exceed the high estimate. 

This approach to describing uncertainty may be applied to reserves, contingent resources, and prospective 

resources. There may be significant risk that sub-commercial and undiscovered accumulations will not 

achieve commercial production. However, it is useful to consider and identify the range of potentially 

recoverable quantities independently of such risk. 

Assessing commerciality 

In order to assign recoverable resources of any category, a development plan consisting of one or more 

projects needs to be defined. In-place quantities for which a feasible project cannot be defined using 

established technology or technology under development are classified as unrecoverable. In this context 

“technology under development” refers to technology that has been developed and verified by testing as 

feasible for future commercial applications to the subject reservoir. In the early stage of exploration or 

development, project definition will not be of the detail expected in later stages of maturity. In most cases 

recovery efficiency will be largely based on analogous projects. 

Estimates of recoverable quantities are stated in terms of the sales products derived from a development 

program, assuming commercial development. It must be recognized that reserves, contingent resources, 

and prospective resources involve different risks associated with achieving commerciality. The likelihood that 

a project will achieve commerciality is referred to as the “chance of commerciality”. The chance of 

commerciality varies in different categories of recoverable resources as follows: 

Reserves: To be classified as reserves, estimated recoverable quantities must be associated with a 

project(s) that has demonstrated commercial viability. Under the fiscal conditions applied in the 

estimation of reserves, the chance of commerciality is effectively 100 percent. 

Contingent Resources: Not all technically feasible development plans will be commercial. The 

commercial viability of a development project is dependent on the forecast of fiscal conditions over 


8 

the life of the project. For contingent resources the risk component relating to the likelihood that an 

accumulation will be commercially developed is referred to as the “chance of development”. For 

contingent resources the chance of commerciality is equal to the chance of development. 

Prospective Resources: Not all exploration projects will result in discoveries. The chance that an 

exploration project will result in the discovery of petroleum is referred to as the “chance of discovery”. 

Thus, for an undiscovered accumulation the chance of commerciality is the product of two risk 

components – the chance of discovery and the chance of development. 

Economic status 

By definition, reserves are commercially (and hence economically) recoverable. A portion of contingent 

resources may also be associated with projects that are economically viable but have not yet satisfied all 

requirements of commerciality. Accordingly, it may be a desirable option to sub-classify contingent resources 

by economic status. 

Economic Contingent Resources are those contingent resources that are currently economically 

recoverable. 

Sub-Economic Contingent Resources are those contingent resources that are not currently 

economically recoverable. 

Where evaluations are incomplete such that it is premature to identify the economic viability of a project, it is 

acceptable to note that project economic status is “undetermined” (i.e., “contingent resources – economic 

status undetermined”). 

In examining economic viability, the same fiscal conditions should be applied as in the estimation of reserves, 

i.e. specified economic conditions, which are generally accepted as being reasonable (refer to COGEH 

Volume 2, Section 5.8). 

Reserve categories 

Reserves are classified by AJM Deloitte in accordance with the following definitions published by COGEH 

and which meet the standards established by National Instrument 51-101, Standards of Disclosure for Oil 

and Gas Activities and found in Appendix 1 to Companion Policy 51-101 CP, Part 2 Definition of Reserves. 


9 

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be 

recoverable from known accumulations, as of a given date, based on: 

 

 

 

analysis of drilling, geological, geophysical, and engineering data; 

the use of established technology; and 

specified economic conditions, which are generally accepted as being reasonable and shall be 

disclosed. 

Reserves are classified according to the degree of certainty associated with the estimates: 

Proved Reserves are those reserves that can be estimated with a high degree of certainty to be 

recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated 

proved reserves. 

Probable Reserves are those additional reserves that are less certain to be recovered than proved 

reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than 

the sum of the estimated proved plus probable reserves. 

Possible Reserves are those additional reserves that are less certain to be recovered than probable 

reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the 

estimated proved plus probable plus possible reserves. 

Development and production status 

Each of the reserves categories (proved, probable and possible) may be divided into developed and 

undeveloped categories: 

Developed Reserves are those reserves that are expected to be recovered from existing wells and 

installed facilities or, if facilities have not been installed, that would involve a low expenditure (for 

example, when compared to the cost of drilling a well) to put the reserves on production. The 

developed category may be subdivided into producing and non-producing. 

Developed Producing Reserves are those reserves that are expected to be recovered from 

completion intervals open at the time of the estimate. These reserves may be currently producing, or 

if shut-in, they must have previously been on production, and the date of resumption of production 

must be known with reasonable certainty. 


10 

Developed Non-Producing Reserves are those reserves that either have not been on production, 

or have previously been on production, but are shut-in, and the date of resumption of production is 

unknown. 

Undeveloped Reserves are those reserves expected to be recovered from known accumulations 

where a significant expenditure (for example, when compared to the cost of drilling a well) is required 

to render them capable of production. They must fully meet the requirements of the reserves 

category (proved, probable, possible) to which they are assigned. 

In multi-well pools it may be appropriate to allocate total pool reserves between the developed and 

undeveloped categories or to subdivide the developed reserves for the pool between developed producing 

and developed non-producing. This allocation should be based on the estimator’s assessment as to the 

reserves that will be recovered from specific wells, facilities, and completion intervals in the pool and their 

respective development and production status. 

Levels of certainty for reported reserves 

The qualitative certainty levels referred to in the definitions above are applicable to individual reserves entities 

(which refers to the lowest level at which reserves calculations are performed) and to reported reserves 

(which refers to the highest – level sum of individual entity estimates for which reserves estimates are 

presented). Reported reserves should target the following levels of certainty under a specific set of economic 

conditions: 

 

 

 

at least a 90 percent probability that the quantities actually recovered will equal or exceed the 

estimated proved reserves; 


sum of the estimated proved plus probable reserves; and 


sum of the estimated proved plus probable plus possible reserves. 

A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves 

categories is desirable to provide a clearer understanding of the associated risks and uncertainties. 

However, the majority of reserves estimates are prepared using deterministic methods that do not provide a 

mathematically derived quantitative measure of probability. In principle, there should be no difference 

between estimates prepared using probabilistic or deterministic methods. 


11 

Resource and reserve estimation 

AJM Deloitte generally assigns reserves to properties via deterministic methods. Probabilistic estimation 

techniques are typically used where there is a low degree of certainty in the information available and is 

generally used in resource evaluations. This will be stated within the detailed property reports. 

Deterministic 

Reserves and resources were estimated either by i) volumetric, ii) decline curve analysis, iii) material balance 

techniques, or iv) performance predictions. 

Volumetric reserves were estimated using the wellbore net pay and an assigned drainage area or, where 

sufficient data was available, the reservoir volumes calculated from isopach maps. Reservoir rock and fluid 

data were obtained from available core analysis, well logs, PVT data, gas analysis, government sources, and 

other published information either on the evaluated pool or from a similar reservoir in the immediate area. In 

mature (producing) reservoirs decline curve analysis and/or material balance was utilized in all applicable 

evaluations. 


12 

Statistical analysis 

Whenever there is the need within an evaluation to assign reserves based on analogy or when volumetric 

reserves are being assigned, AJM Deloitte utilizes a variety of different tools in support of. When 

evaluating Western Canadian prospects, typically AJM Deloitte uses petroCUBE. 

The petroCUBE program is a web-based (www.petroCUBE.com) product co-developed by AJM Deloitte 

and geoLOGIC Systems Inc. petroCUBE provides geostatistical, technical, and financial information for 

conventional hydrocarbon plays throughout the Western Canadian Sedimentary Basin (“WCSB”). 

The information provided by petroCUBE is an unbiased independent perspective into the historical 

performance of the conventional hydrocarbon activity in the WCSB. The statistical information is 

presented by commodity type (gas, oil) with each commodity further analyzed by geographic area and 

play type. 

Analysis output includes cumulative frequency resource distribution curves, chance of success tables, 

production performance profiles for each play type and area, unrisked and risked resources, and initial 

production rates on a per well zone basis, and full cycle economic and play parameters. 

Cumulative frequency curves show how the volumes for a play are distributed. These calculations 

include the average volumes for a play (P 50 ), volumes for the best 10 percent of the wells (P 10 ), the 

minimum volumes developed by 90 percent of the wells (P 90 ). 

Reserves assigned are compared to those volumes noted in the cumulative frequency curves for the 

corresponding area and play type. Typically an expected or proved plus probable reserve is a P 50 

volume. 

Probabilistic 

Because of the uncertainty inherent in reservoir parameters, probabilistic analysis, which is based on 

statistical techniques, provides a formulated approach by which to obtain a reasonable assessment of the 

petroleum initially in place (PIIP) and/or the recoverable resource. Probabilistic analysis involves generating 

a range of possible outcomes for each unknown parameter and their associated probability of occurrence. 

When probabilistic analysis is applied to resource estimation, it provides a range of possible PIIPs or 

recoverable resources. 


13 

In preparing a resource estimate, AJM Deloitte assesses the following volumetric parameters: areal extent, 

net pay thickness, porosity, hydrocarbon saturation, reservoir temperature, reservoir pressure, gas 

compressibility factor, recovery factor, and surface loss. A team of professional engineers and geologists 

experienced in probabilistic resource evaluation considered each of the parameters individually to estimate 

the most reasonable range of values. Working from existing data, the team discusses and agrees on the low 

(P 90 ) and high (P 10 ) values for each parameter. To help test the reasonableness of the proposed range, a 

minimum (P 99 ) and maximum (P 1 ) value are also extrapolated from the low and high values. After ranges 

have been established for each parameter, these independent distributions are used to determine a P 90 , P 50 , 

and P 10 result which comprise AJM Deloitte’s estimated range of PIIP or recoverable resource. 

It is important to note that the process used to determine the final P 10 , P 90 , and P 50 results involves multiplying 

the various volumetric parameters together. This yields results which require adjustments to maintain an 

appropriate probability of occurrence. For example, when calculating total reservoir volume (Area x Pay), the 

chance of getting a volume greater than the P 10 Area x P 10 Pay is less than 10 percent – the chance of 

getting the calculated result is only 3.5 percent (p 3.5 ). As you multiply additional P 10 values, the probability of 

achieving the calculated value becomes less likely. Similarly, multiplying P 90 parameters together will yield a 

result that has a probability greater than P 90 . As such, when multiplying independent distributions together 

the results must be adjusted via interpolation to determine final P 90 and P 10 values. 

The results appearing in this report represent interpolated P 90 and P 10 values. As defined by COGEH (and 

the Petroleum Resource Management System “PRMS”), the P 50 estimate is the “best estimate” for reporting 

purposes. 

Production forecasts 

Production forecasts were based on historical trends or by comparison with other wells in the immediate area 

producing from similar reservoirs. Non-producing gas reserves were forecast to come on-stream within the 

first two years from the effective date under direct sales pricing and deliverability assumptions, if a tie-in point 

to an existing gathering system was in close proximity (approximately two miles). If the tie-in point was of a 

greater distance (and dependent on the reserve volume and risk) the reserves were forecast to come onstream 

in years three or four from the effective date. If the reserves were located in a remote location and/or 

the reserve volume was of higher risk, the reserves were forecast to come on-stream beyond five years from 

the effective date. These on-stream dates were used when the company could not provide specific onstream 

date information. 


14 

Land schedule and maps 

The evaluated Corporation provided schedules of land ownership which included lessor and lessee royalty 

burdens. The land data was accepted as factual and no investigation of title by AJM Deloitte was made to 

verify the records. 

Well maps included within this report represent all of the Corporation’s interests that were evaluated in the 

specified area. 

Geology 

An initial review of each property is undertaken to establish the produced maturity of the reservoir being 

evaluated. Where extensive production history exists a geologic analysis is not conducted since the 

remaining hydrocarbons can be determined by productivity analysis. 

For properties that are not of a mature production nature a geologic review is conducted. This work consists 

of: 

 

 

 

 

developing a regional understanding of the play, 

assessing reservoir parameters from the nearest analogous production, 

analysis of all relevant well data including logs, cores, and tests to measure net formation 

thickness (pay), porosity, and initial water saturation, 

auditing of client mapping or developing maps to meet AJM Deloitte’s need to establish 

volumetric hydrocarbons-in-place. 

Procedures specific to the project are discussed in the body of the report. 


15 

Royalties and taxes 

General 

All royalties and taxes, including the lessor and overriding royalties, are based on government regulations, 

negotiated leases or farmout agreements, that were in effect as of the evaluation effective date. If regulations 

change, the net after royalty recoverable reserve volumes may differ materially. 

AJM Deloitte utilizes a variety of reserves and valuation products in determining the result sets. 


16 

Capital and operating considerations 

Operating and capital costs were based on current costs escalated to the date the cost was incurred, and are 

in current year dollars. The economic runs provide the escalated dollar costs as found in the Pricing Table 1 

in the Price and Market Demand section. 

Reserves estimated to meet the standards of NI 51-101 for constant prices and costs (optimal), are based on 

unescalated operating and capital costs. 

Capital costs were either provided by the Corporation (and reviewed by AJM Deloitte for reasonableness); or 

determined by AJM Deloitte taking into account well capability, facility requirement, and distance to markets. 

Facility expenditures for shut-in gas are forecast to occur prior to the well’s first production. 

Operating costs were determined from historical data on the property as provided by the evaluated 

Corporation. If this data was not available or incomplete, the costs were based on AJM Deloitte experience 

and historical database. Operating costs are defined into three types. 

The first type, variable ($/Unit), covers the costs directly associated with the product production. Costs for 

processing, gathering and compression are based on raw gas volumes. Over the life of the project the costs 

are inflated in escalated runs to reflect the increase in costs over time. In a constant dollar review the costs 

remain flat over the project life. 

The second type, fixed plant or battery ($/year), is again a fixed component over the project life and reflects 

any gas plant or battery operating costs allocated back to the evaluated group. The plant or battery can also 

be run as a separate group and subsequently consolidated at the property level. 

The third type takes the remaining costs that are not associated with the first two and assigns them to the well 

based on a fixed and variable component. A split of 65 percent fixed and 35 percent variable assumes 

efficiencies of operation over time, i.e.: the well operator can reduce the number of monthly visits as the well 

matures, workovers may be delayed, well maintenance can also be reduced. The basic assumption is that 

the field operator will continue to find efficiencies to reduce the costs over time to maintain the overall $/Boe 

cost. Thus as the production drops over time the 35 percent variable cost will account for these efficiencies. 

If production is flat all the costs will also remain flat. Both the fixed and variable costs in this type are inflated 

in the escalated case and held constant in the constant dollar review. These costs also include property 

taxes, lease rentals, government fees, and administrative overhead. 


17 

In reserve evaluations conducted for purposes of NI 51-101, or, if an economic analysis was prepared for a 

resource evaluation, well abandonment and reclamation costs have been included and these costs were 

either provided by the Corporation (and reviewed by AJM Deloitte for reasonableness) or based on area 

averages (only the base abandonment costs were utilized and no consideration for groundwater protection, 

vent flow repair costs, or gas migration costs were considered). If there were multiple events to abandon the 

costs were increased by a 25 percent factor. Site reclamation costs were based on information provided by 

the Corporation or based on area averages. For undeveloped reserve estimates for undrilled locations, both 

abandonment and site reclamation costs are also included for the purpose of determining whether reserves 

should be attributed to that property in the first year in which the reserves are considered for attribution to the 

property. 


18 

Price and market demand forecasts 

Base case forecast effective March 31, 2012 

The attached price and market forecasts have been prepared by AJM Deloitte, based on information 

available from numerous government agencies, industry publications, oil refineries, natural gas marketers, 

and industry trends. 

The prices are AJM Deloitte’s best estimate of how the future will look, based on the many uncertainties that 

exist in both the domestic Canadian and international petroleum industries. Inflation forecasts and exchange 

rates, an integral part of the forecast, have also been considered. 

In preparing the price forecast AJM Deloitte considers the current monthly trends, the actual and trends for 

the year to date, and the prior year actual in determining the forecast. The base forecast for both oil and gas 

is based on NYMEX futures in US dollars. 

The crude oil and natural gas forecasts are based on yearly variable factors weighted to higher percent in 

current data and reflecting a higher percent to the prior year historical. These forecasts are AJM Deloitte’s 

interpretation of current available information and while they are considered reasonable, changing market 

conditions or additional information may require alteration from the indicated effective date. 


AJM Deloitte 

Canadian Domestic Price Forecast 

Base Case Forecast Effective March 31, 2012 

Crude Oil Pricing Natural Gas Liquids Pricing Natural Gas Pricing Sulphur 

Edmonton Par Prices Alberta Alberta Alberta Alberta Alberta B.C. Sask. 

WTI at WTI at Med. Oil Bow River Heavy Oil Reference AECO AECO System Direct Direct Direct 

Cushing Cushing Edmonton Edmonton 29 Deg. API 25 Deg. API 12 Deg. API Pentanes + Average Average Average Plant Gate Plant Gate Stn. 2 Plant Gate Alberta 

Price Cost CAD to USD Oklahoma Oklahoma City Gate City Gate Cromer, Sk. Hardisty Hardisty Ethane Propane Butane Condensate Price Price Price Sales Sales Sales Sales NYMEX NYMEX Plant Gate 

Inflation Inflation Exchange US$/bbl US$/bbl C$/bbl C$/bbl C$/bbl C$/bbl C$/bbl C$/bbl C$/bbl C$/bbl C$/bbl C$/mcf C$/mcf C$/mcf C$/mcf C$/mcf C$/mcf C$/mcf US$/Mcf US$/Mcf C$/lt 

Rate Rate Rate Real Current Real Current Current Current Current Current Current Current Current Current Real Current Current Current Current Current Real Current Current 

H 1997 1.6% 1.6% 0.722 $27.04 $20.60 $36.73 $27.98 $23.71 $21.26 $14.35 n/a $19.41 $19.02 $30.85 $1.87 $2.24 $1.71 $1.78 $1.69 $1.98 $1.74 $3.40 $2.59 $11.50 

i 1998 0.7% 0.7% 0.675 $18.58 $14.38 $25.94 $20.08 $16.94 $14.63 $9.43 n/a $11.97 $12.92 $22.35 $1.94 $2.67 $2.07 $1.90 $1.95 $2.00 $2.13 $2.73 $2.11 ($6.51) 

s 1999 1.8% 1.8% 0.648 $24.75 $19.29 $35.16 $27.41 $21.72 $20.29 $17.62 $8.09 $13.21 $14.39 $20.94 $2.48 $3.53 $2.75 $2.22 $2.50 $2.64 $2.61 $2.69 $2.10 $6.93 

t 2000 2.6% 2.6% 0.674 $38.08 $30.22 $55.88 $44.33 $39.89 $34.46 $28.57 $14.10 $32.59 $36.51 $46.30 $4.51 $7.08 $5.62 $4.84 $5.47 $4.73 $5.05 $5.44 $4.32 $13.59 

o 2001 2.5% 2.5% 0.646 $14.28 $25.87 $21.62 $39.17 $31.54 $25.12 $18.07 $17.20 $30.62 $30.49 $43.03 $5.39 $2.99 $5.42 $5.42 $5.26 $6.34 $6.10 $2.17 $3.93 ($14.50) 

r 2002 2.3% 2.3% 0.637 $31.23 $26.11 $48.24 $40.33 $35.52 $31.89 $27.63 $11.21 $20.92 $27.78 $41.22 $3.88 $5.01 $4.19 $3.85 $4.03 $4.09 $4.08 $4.02 $3.36 $12.74 

i 2003 2.8% 2.8% 0.716 $36.26 $31.01 $50.87 $43.51 $37.47 $32.96 $27.35 $18.43 $32.31 $36.03 $45.18 $6.12 $7.81 $6.68 $6.11 $6.51 $6.42 $6.67 $6.40 $5.48 $40.99 

c 2004 1.8% 1.8% 0.770 $47.11 $41.45 $60.19 $52.96 $45.76 $38.01 $30.44 $19.04 $35.20 $44.07 $55.49 $6.31 $7.45 $6.55 $6.32 $6.38 $6.52 $6.84 $7.10 $6.25 $40.82 

a 2005 2.2% 2.2% 0.826 $63.16 $56.61 $77.35 $69.33 $57.39 $45.68 $33.77 $23.80 $43.23 $51.91 $74.67 $8.31 $9.80 $8.78 $8.56 $8.61 $8.22 $8.51 $9.94 $8.91 $40.99 

l 2006 2.0% 2.0% 0.882 $72.05 $66.06 $79.99 $73.34 $62.42 $52.04 $39.68 $19.81 $44.11 $58.16 $78.19 $6.56 $7.13 $6.54 $6.63 $6.35 $6.57 $7.11 $7.36 $6.75 $19.51 

2007 2.1% 2.1% 0.935 $77.36 $72.38 $82.39 $77.09 $65.18 $53.86 $39.75 $18.41 $49.77 $59.40 $81.67 $6.20 $6.88 $6.44 $6.31 $6.22 $6.40 $6.54 $7.45 $6.97 $38.32 

2008 2.4% 2.4% 0.943 $104.15 $99.58 $107.55 $102.83 $93.26 $83.97 $73.17 $22.61 $56.94 $83.56 $109.80 $7.88 $8.53 $8.15 $8.13 $7.92 $8.21 $8.19 $9.28 $8.88 $304.51 

2009 0.3% 0.3% 0.880 $63.08 $61.78 $67.60 $66.21 $62.77 $59.90 $54.49 $11.60 $34.56 $56.29 $69.59 $3.84 $4.04 $3.96 $3.94 $3.74 $4.16 $4.14 $3.99 $3.90 ($4.97) 

2010 1.8% 1.8% 0.971 $80.84 $79.42 $79.18 $77.79 $73.48 $68.16 $60.59 $11.52 $45.13 $68.78 $84.00 $3.76 $4.07 $4.00 $4.07 $3.76 $4.00 $3.90 $4.46 $4.38 $57.81 

2011 2.9% 2.9% 1.012 $94.91 $94.91 $95.58 $95.58 $88.21 $78.50 $69.56 $10.30 $52.44 $87.06 $105.31 $3.46 $3.63 $3.63 $3.84 $3.42 $3.34 $3.33 $3.99 $3.99 $79.49 

2 3 Mths H 2.4% 2.4% 0.997 $103.00 $103.00 $93.63 $93.63 $88.16 $83.28 $72.33 $7.16 $50.38 $85.91 $106.92 $2.32 $2.16 $2.16 $2.42 $1.97 $2.69 $2.07 $2.47 $2.47 $80.00 

0 9 Mths F 0.0% 0.0% 1.000 $100.00 $100.00 $98.00 $98.00 $91.00 $77.00 $71.00 $10.65 $55.00 $85.00 $105.00 $2.05 $2.30 $2.30 $2.00 $2.10 $2.00 $2.25 $2.80 $2.80 $80.00 

1 

2 Avg. n/a n/a 0.999 $100.75 $100.75 $96.91 $96.91 $90.29 $78.57 $71.33 $9.78 $53.85 $85.23 $105.48 $2.12 $2.26 $2.26 $2.11 $2.07 $2.17 $2.21 $2.72 $2.72 $80.00 

F 2012 0.0% 0.0% 1.000 $100.00 $100.00 $98.00 $98.00 $91.00 $77.00 $71.00 $6.00 $53.90 $83.30 $102.90 $2.05 $2.30 $2.30 $2.00 $2.10 $2.00 $2.25 $2.80 $2.80 $80.00 

o 2013 2.0% 2.0% 1.000 $100.00 $102.00 $98.00 $100.00 $92.30 $79.00 $73.00 $8.85 $55.00 $85.00 $105.00 $3.00 $3.20 $3.25 $2.95 $3.05 $2.95 $3.20 $3.50 $3.55 $81.60 

r 2014 2.0% 2.0% 1.000 $100.00 $104.05 $98.00 $102.00 $93.00 $80.00 $74.00 $10.65 $56.10 $86.70 $107.10 $3.60 $3.70 $3.85 $3.55 $3.65 $3.55 $3.80 $4.00 $4.15 $83.25 

e 2015 2.0% 2.0% 1.000 $100.00 $106.10 $98.00 $104.00 $94.25 $82.00 $76.00 $11.85 $57.20 $88.40 $109.20 $4.00 $4.00 $4.25 $3.95 $4.05 $3.95 $4.20 $4.30 $4.55 $84.90 

c 2016 2.0% 2.0% 1.000 $100.00 $108.25 $98.00 $106.10 $95.60 $84.10 $78.10 $13.05 $58.35 $90.20 $111.40 $4.40 $4.30 $4.65 $4.35 $4.45 $4.35 $4.60 $4.60 $5.00 $86.60 

a 2017 2.0% 2.0% 1.000 $100.00 $110.40 $98.00 $108.20 $96.95 $86.20 $80.20 $14.40 $59.50 $91.95 $113.60 $4.85 $4.60 $5.10 $4.80 $4.90 $4.80 $5.05 $4.90 $5.40 $88.35 

s 2018 2.0% 2.0% 1.000 $100.00 $112.60 $98.00 $110.35 $98.35 $88.35 $82.35 $16.05 $60.70 $93.80 $115.85 $5.40 $5.00 $5.65 $5.35 $5.45 $5.35 $5.60 $5.30 $5.95 $90.10 

t 2019 2.0% 2.0% 1.000 $100.00 $114.85 $98.00 $112.55 $99.05 $90.55 $84.55 $17.40 $61.90 $95.65 $118.20 $5.85 $5.30 $6.10 $5.80 $5.90 $5.80 $6.05 $5.60 $6.45 $91.90 

2020 2.0% 2.0% 1.000 $100.00 $117.15 $98.00 $114.80 $99.80 $92.80 $86.80 $19.20 $63.15 $97.60 $120.55 $6.45 $5.70 $6.70 $6.40 $6.50 $6.40 $6.65 $6.00 $7.05 $93.75 

2021 2.0% 2.0% 1.000 $100.00 $119.50 $98.00 $117.10 $102.10 $95.10 $89.10 $21.30 $64.40 $99.55 $122.95 $7.15 $6.20 $7.40 $7.10 $7.20 $7.10 $7.35 $6.50 $7.75 $95.65 

2022 2.0% 2.0% 1.000 $100.00 $121.90 $98.00 $119.45 $104.45 $97.45 $91.45 $21.75 $65.70 $101.55 $125.40 $7.30 $6.20 $7.55 $7.25 $7.35 $7.25 $7.50 $6.50 $7.90 $97.55 

2023 2.0% 2.0% 1.000 $100.00 $124.35 $98.00 $121.85 $106.85 $99.85 $93.85 $22.20 $67.00 $103.55 $127.95 $7.45 $6.20 $7.70 $7.40 $7.50 $7.40 $7.65 $6.50 $8.10 $99.50 

2024 2.0% 2.0% 1.000 $100.00 $126.80 $98.00 $124.30 $109.30 $102.30 $96.30 $22.65 $68.35 $105.65 $130.50 $7.60 $6.20 $7.85 $7.55 $7.65 $7.55 $7.80 $6.50 $8.25 $101.50 

2025 2.0% 2.0% 1.000 $100.00 $129.35 $98.00 $126.75 $111.75 $104.75 $98.75 $23.10 $69.70 $107.75 $133.10 $7.75 $6.20 $8.00 $7.70 $7.80 $7.70 $7.95 $6.50 $8.40 $103.55 

2026 2.0% 2.0% 1.000 $100.00 $131.95 $98.00 $129.30 $114.30 $107.30 $101.30 $23.70 $71.10 $109.90 $135.75 $7.95 $6.20 $8.20 $7.90 $8.00 $7.90 $8.15 $6.50 $8.60 $105.60 

2027 2.0% 2.0% 1.000 $100.00 $134.60 $98.00 $131.90 $116.90 $109.90 $103.90 $24.15 $72.55 $112.10 $138.50 $8.10 $6.20 $8.35 $8.05 $8.15 $8.05 $8.30 $6.50 $8.75 $107.70 

2028 2.0% 2.0% 1.000 $100.00 $137.30 $98.00 $134.55 $119.55 $112.55 $106.55 $24.60 $74.00 $114.35 $141.30 $8.25 $6.20 $8.50 $8.20 $8.30 $8.20 $8.45 $6.50 $8.90 $109.85 

2029 2.0% 2.0% 1.000 $100.00 $140.00 $98.00 $137.20 $122.20 $115.20 $109.20 $25.20 $75.45 $116.60 $144.05 $8.45 $6.20 $8.70 $8.40 $8.50 $8.40 $8.65 $6.50 $9.10 $112.05 

2030 2.0% 2.0% 1.000 $100.00 $142.80 $98.00 $139.95 $124.95 $117.95 $111.95 $25.65 $76.95 $118.95 $146.95 $8.60 $6.20 $8.85 $8.55 $8.65 $8.55 $8.80 $6.50 $9.30 $114.30 

2031 2.0% 2.0% 1.000 $100.00 $145.70 $98.00 $142.75 $127.75 $120.75 $114.75 $26.25 $78.50 $121.35 $149.90 $8.80 $6.20 $9.05 $8.75 $8.85 $8.75 $9.00 $6.50 $9.45 $116.60 

2032+ 2.0% 2.0% 1.000 0.0% 2.0% 0.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 0.0% 2.0% 2.0% 2.0% 2.0% 2.0% 0.0% 2.0% 2.0% 

Notes: ‐ All prices are in Canadian dollars except WTI and NYMEX gas which are in U.S. dollars. 

‐ Edmonton city gate prices based on light sweet crude posted at major Canadian refineries. (40 Deg. API < 0.5% Sulphur) 

‐ Natural Gas Liquid prices are forecasted at Edmonton therefore an additional transportation cost must be included to plant gate sales point. 

‐ 1 Mcf is equivalent to 1 mmbtu. 

‐ System gas prices includes TCGSL, Progas, Pan Alberta and Alliance. 

‐ Real dollars listed include future growth in prices with no escalation considered. 

‐ Alberta gas prices, except AECO, include an Average cost of service to the plant gate. 

Disclaimer - No representation or warranty of any kind (whether expressed or implied) is given by Deloitte & Touche LLP as to the accuracy, completeness, currency or fitness for any purpose of this document. As such, this document does 

not constitute the giving of investment advice, nor a part of any advice on investment decisions. Accordingly, regardless of the form of action, whether in contract, tort or otherwise, and to the extent permitted by applicable law, Deloitte & 

Touche LLP accepts no liability of any kind and disclaims all responsibility for the consequences of any person acting or refraining from acting in reliance on this this price forecast in whole or in part. This price forecast is not for 

dissemination in the United States or for distribution to United States wire services. 

© Deloitte & Touche LLP and affiliated entities. 

Price Summary

20 

Glossary of terms 

AJM Deloitte subscribes to the Glossary of Terms as defined by the Canadian Oil and Gas Evaluation 

Handbook, Volume 2. 


Property index 

1. Athabasca, Alberta 





Effective date: March 31, 2012 

Prepared by: 

D. S. Ashton, P. Eng. 

L. J. Machula, P. Geol. 

D. L. Horbachewski, P. Geol. 




Introduction 

Oil Reserve Inc. (“ORI” or “the company”) holds oil sands rights from below the top of the Viking 

Formation to the base of the Woodbend Group in 621 semi-contiguous sections (397,440 acres) in the 

Athabasca area of Alberta. This land was acquired by ORI during March and April 2011 and rights are 

held at a working interest of 100 percent. 

ORI land holdings in the Athabasca area are located in the Nixon area of Athabasca County Number 12, 

at the northern edge of Lac la Biche, two miles north and two miles east of the La Biche River Wildland. 

The location of company land holdings in the Nixon area, relative to Lac La Biche are illustrated on the 

Working Interest Lands maps. 

The sandstone zones identified for review are the Cretaceous Viking and Grand Rapids Formations, 

illustrated on the Stratigraphic Column, where hydrocarbon potential has been identified on well logs and 

drill stem test recovery on ORI lands. Bitumen is expected from both formations and would require 

enhanced recovery techniques to exploit in economically viable volumes and rates. The API gravity is 

unknown at this time but is expected to be between 10 and 13 degrees. 

The carbonate zone identified for review is the Devonian Nisku Formation, illustrated on the Stratigraphic 

Column, where hydrocarbon potential has been identified. Based on drill stem test recovery on ORI 

lands, bitumen of approximately 10 to 11 API gravity is expected and would require enhanced recovery 

techniques to exploit in economically viable volumes and rates. 

Resource categorization 

This report summarizes the unconventional resources in the Nisku, Viking, and Grand Rapids Formations 

at Nixon. Bitumen constitutes the primary product expected from all three formations in the area of 

interest; therefore, calculations were made in barrels of oil. A number of wells demonstrate hydrocarbon 

potential on well logs, potential which has been mapped by AJM Deloitte. 

Viking 

Of the 7,137 wells in the mapped area, 6,818 have penetrated the top of the Viking Formation (Viking 

Structure map). Volumes assigned to the Viking Formation at Nixon are categorized as undiscovered 


petroleum initially‐in‐place (“PIIP”). Viking natural gas has been produced from 188 wells in the mapped 

area however no oil has been produced to date. Prospective resources have not been assigned due to 

lack of oil being tested or produced on ORI leases and lack of an appropriate analogue. Additionally, flow 

rates, drainage area, and possible recovery mechanism are unknown at this time. 

Grand Rapids 

Of the 7,137 wells in the mapped area, 6,307 have penetrated the top of the Grand Rapids Formation 

(see Grand Rapids Structure map). Volumes assigned to the Grand Rapids Formation at Nixon are 

categorized as prospective resources. Grand Rapids natural gas has been produced from eight wells in 

the focus area on company land (Grand Rapids Working Interest map). Upper Grand Rapids bitumen is 

currently being cold produced 50 kilometers northwest of company land, in Township 73, Ranges 19 to 

22W4. Producing wells are variable in quality, some inferior and some superior to the potential Grand 

Rapids on company land (Grand Rapids Structural X-Section). Ability to extract hydrocarbon at sustained 

rates has not been proven at this time therefore contingent resources have not been assigned. This 

analogue is further discussed in the Analogues section of this report. 

Nisku 

Of the 7,137 wells in the mapped area, approximately 1,000 have penetrated down to the top of the Nisku 

Formation in the mapped area (see Nisku Structure and Subcrop map), where many demonstrate 

hydrocarbon potential on well logs. Nisku gas has been produced from 213 wells in the mapped area, 

however, no oil has been produced to date. 

Volumes assigned to the Nisku Formation at Nixon are categorized as undiscovered PIIP with 

prospective resources being assigned to an area at, and surrounding the 102/07-27-072-18W4 well which 

has tested oil on drill stem test. No oil production exists on or offsetting ORI leases however. Ability to 

extract hydrocarbon at sustained rates has not been proven at this time therefore contingent resources 

have not been assigned. Additionally, flow rates, drainage area, and possible recovery mechanism are 

unknown at this time. 

According to the Alberta Securities Commission (“ASC”) 2010 Oil and Gas Review, resource studies of 

bituminous carbonate must “ consider that there is overwhelming evidence that geological units are 

almost invariably heterogeneous and that extrapolation of productive capability beyond the immediate 

vicinity of a control point requires substantial supporting technical evidence.” In this case, the Nisku in the 

Germain pilot area on Laricina Energy (“Laricina”) lands (discussed further in the Analogues section of 

this report) is similar or better in all geological parameters than the Nisku on ORI lands. The Nisku in the 

Germain area is in the early stages of testing and development is highly dependent on technically 


complex and unproven recovery schemes. Based on these observations, “substantial supporting 

technical evidence” is not available to prove productive capability for the Nisku at Nixon. 

Results and recommendations 

ORI land holdings in the Athabasca area have been analyzed stochastically for Nisku, Viking and Grand 

Rapids Formations bitumen potential. Summing multiple estimated volumes arithmetically is a misleading 

practice according to statistical principles. The sum of the best estimates is generally considered to be an 

approximation of overall best estimate. However, the sum of the low estimates is likely to be lower than 

the expected low estimate, and the sum of the high estimates is likely to be higher than the expected high 

estimate. A Monte Carlo analysis was necessary to aggregate multiple results. 

The distributions for PIIP for the Viking and PIIP and prospective resources for the Grand Rapids and 

Nisku Formation in the Nixon area have been calculated. The resource estimation results are included in 

the table below. 

Summary of Athabasca area resources on ORI lands (1) 

Nisku, Viking and Grand Rapids Formations 

Detailed Summary of Resources on Oil Reserve Inc. Lands (1) 

NIXON 

Gross MBbl 

WI MBbl 

Resource Class 

Low Expected High Low Expected High 

Cumulative Production - - - - - - 

Remaining Reserves - - - - - - 

Surface Loss/Shrinkage - - - - - - 

Total Commercial - - - - - - 

Contingent Resources - - - - - - 

Unrecoverable - - - - - - 

Total Sub-Commercial - - - - - - 

Total Discovered PIIP - - - - - - 

Prospective Resources 1,828.0 5,493.0 20,456.0 1,828.0 5,493.0 20,456.0 

Grand Rapids 304.0 655.0 1,412.0 304.0 655.0 1,412.0 

Nisku 1,120.0 4,702.0 19,738.0 1,120.0 4,702.0 19,738.0 

Unrecoverable 2,037,127.0 3,348,787.0 5,554,649.0 2,037,127.0 3,348,787.0 5,554,649.0 

Total Undiscovered PIIP 2,038,955.0 3,354,280.0 5,575,105.0 2,038,955.0 3,354,280.0 5,575,105.0 

Total PIIP 2,038,955.0 3,354,280.0 5,575,105.0 2,038,955.0 3,354,280.0 5,575,105.0 

Viking 1,419,623.0 2,460,916.0 4,265,997.0 1,419,623.0 2,460,916.0 4,265,997.0 

Grand Rapids 4,437.0 8,461.0 16,133.0 4,437.0 8,461.0 16,133.0 

Nisku 233,075.0 671,933.0 1,937,121.0 233,075.0 671,933.0 1,937,121.0 

Notes: (1) Effective March 31, 2012 


Additional details regarding the stochastic analysis are included within the Tables section of the report. 

Additional well logs, core data and seismic data would be useful to further delineate the geology and 

increase certainty for some parameters. Further to that, a pilot program and development of an 

appropriate enhanced recovery scheme is necessary. 

Cautionary statements 

The range of estimated undiscovered PIIP has not been adjusted for risk based on the chance of 

development. There is no certainty that pools will be developed or, if they are developed, there is no 

certainty as to the timing of such development. 

The effect of gas and possible water zones on any particular recovery scheme in will not likely be known 

until pilot testing is underway or completed. Any possible bitumen recovery on ORI leases would not 

necessarily be economically feasible. 

The wide ranges of parameters and volumes in the Nisku evaluation are a direct result of numerous 

uncertainties including the lack of well log control to the base of the target interval and uncertainty due to 

geological heterogeneity observed in this and other bituminous carbonate pools globally. The efficiency 

of any enhanced recovery scheme is unknown in carbonates such as the Nisku. 


Geology 


The Lower Cretaceous Viking Formation in the Athabasca area of Alberta represents a shallow shelf 

environment and is dominated by sand. The grains were derived primarily from the eroding Cordillera to 

the west. During late Viking time, fluvial sands were transported and reworked during a transgression 

into a series of shoreline and tide dominated deposits (Reinson et. al, 1994). The Viking Formation 

overlies the Joli Fou shale and is capped by the Colorado shales. The Viking in the Nixon area is 

composed of fine-grained sandstone, argillaceous sandstone, and shale. 

The Viking Formation extends regionally in this area; in the Nixon area this is a play on the thick channel 

sand focused on a four township area of ORI land (Viking Focus Area; Viking Formation map). The best 

quality reservoir is composed of thick, clean, contiguous sandstone and grades towards the south and 

east to shale interbedded sandstone down to a thin sandstone over thick shale. Potential reservoir zones 

on ORI land average 34 meters of gross thickness, 32 percent porosity, and 43 percent water saturation. 

No Viking core recoveries are available to determine permeability; however off ORI leases, in the thin, 

regional Viking, core permeability ranges from 20 to 3,000 millidarcies. Intervals within the Viking appear 

to be hydrocarbon charged in many locations based on volumetric calculation, and drill stem test 

recovery. 

Bitumen viscosity is unknown. One meter of ‘heavy oil’ has been tested from the 100/03-09-075-23W4 

well from a thin, one meter sand, however, there is no available oil analysis. No oil has been produced 

from the Viking Formation in the mapped area and oil recovery from the drill stem test is rare. 100/16-19- 

072-18W4, located on ORI land, has recovered oil cut mud in the drill stem test. 

Over company land, the top of the Viking Formation ranges in depth in the Viking Focus Area from 

approximately 219 to 310 meters true vertical depth and in elevation from approximately +315 to +370 

meters subsea, as illustrated by the Viking Structure map. This map, picked on the top of the Viking, is 

computer contoured on a ten meter interval, using formation tops created by ORI, and audited by AJM 

Deloitte. Viking gas has been produced from 188 wells in the mapped area. The majority of wells on 

company land, in the target area have been drilled from 1990 to 2012. Nineteen Viking gas wells are 

located on company land however none are located in the Viking focus area. A majority of the ten drill 

stem tested wells on ORI land have tested water; the effect of water production on bitumen recovery 

cannot be verified until a pilot test is completed. 



The Lower Cretaceous Grand Rapids Formation in the Athabasca area of Alberta represents a regional 

marine shoreface environment (Connelly, 2012). This sand-dominated system composed of very finegrained, 

unconsolidated sand, argillaceous sand, and shale consists of a series of coarsening-upward, 

unconsolidated sand cycles. It is divided into two main intervals the Upper and Lower Grand Rapids. 

The Grand Rapids Formation overlies the Clearwater shale and is capped by the Joli Fou shale. 

Hydrocarbons are trapped in the porous sands as the pinch-out or grade laterally into the surrounding 

marine shales and silts. 

The Grand Rapids Formation extends regionally in this area; in the Nixon area this is a play on the Upper 

Grand Rapids with gas over bitumen, as indicated by well logs. It is focused on a nine section area of 

ORI land (Grand Rapids focus area; Grand Rapids Formation map) where three wells show oil potential 

on logs (100/14-13, 100/09-22 and 100/11-23-069-15W4). Potential reservoir zones on ORI land average 

56 meters of gross thickness, 34 percent porosity, and 43 percent water saturation. Grand Rapids core 

recoveries in Nixon are rare, however, core data over the target interval is available in the 100/08-28-068- 

17W4 well. With the exception of a one meter thick, high porosity interval, core and well log porosity are 

very similar. Core permeability averages between 100 to 800 millidarcies and oil saturation is recorded at 

20 to 40 percent over an interval calculating 30 to 50 percent. The upper zone of the Upper Grand 

Rapids appears to be hydrocarbon charged (gas over oil) in three wells in the Grand Rapids focus area, 

based on volumetric calculation, drill stem test, and core recovery. 

Fifty six wells have produced oil/bitumen from the Upper Grand Rapids in the mapped area, none in the 

focus area. The Athabasca - Grand Rapids pool has produced 78 thousand barrels of bitumen from 48 

wells since 1974. Production comes from the same Upper Grand Rapids interval targeted by ORI. 

Additionally, 18 oil tests in the Grand Rapids exist in the mapped area suggesting an expected, average 

bitumen API gravity of approximately 12.0 degrees. Within ten miles of the focus area, two wells have 

produced Upper Grand Rapids oil; 100/07-07-069-13W4/02 and 100/10-31-068-13W4/02 (analogue 

wells) have produced one and two barrels of oil respectively. Further southwest, with similar 

characteristics to the two analogue wells, 100/10-26-065-17W4/00 has produced six barrels of oil. 

The entire hydrocarbon column in the 100/14-13-069-15W4 well on company land shows cross-over of 

the density and neutron porosity curves, indicating gas. It is possible that 100/14-13-069-15W4 also 

contains bitumen for a number of reasons. Firstly, the degree of separation of the porosity curves is 

instantly and drastically reduced at the gas over bitumen contact, approximately +280 meters subsea, a 

value based on the contacts in the 100/09-22 and 100/11-23-069-15W4 wells. Secondly, the gas 

production rates of the analogue wells reflect the respective net pay. 100/14-13-069-15W4 production 


eflects the net pay assuming gas over bitumen, however, if the entire hydrocarbon column is gas 

saturated this correlation does not hold true. 

In the Grand Rapids focus area, the top of the Grand Rapids Formation ranges in depth from 

approximately 267.3 to 281.0 meters true vertical depth and in elevation from approximately +281.5 to 

+286.6 meters subsea, illustrated by the Grand Rapids Structure map. This map, picked on the top of the 

Grand Rapids, is computer contoured on a ten meter interval, using formation tops created by ORI, and 

audited by AJM Deloitte. Grand Rapids natural gas has been produced from over 1,400 wells in the 

mapped area. Seven wells in the nine section focus area have produced Grand Rapids gas and water. 

In both the Upper and Lower Grand Rapids, a water zone exists below the hydrocarbon zone, the two 

separated by a low permeability zone. The seven wells completed in the Upper Grand Rapids, on ORI 

land, have produced water. The effect of water production on bitumen recovery cannot be verified until a 

pilot test is completed however oil has successfully been produced in the Athabasca Grand Rapids pool. 


The Upper Devonian Nisku Formation in the Athabasca area of Alberta represents an extensive 

carbonate shelf complex deposited during a transgressive phase of a dominantly regressive period 

(WCSB Atlas, 1994). In the Athabasca area, this large buildup overlies the irregular Woodbend Group 

paleotopography where local differential basin subsidence and compaction affected deposition 

(Stratigraphic Column). Regionally, the Nisku is divided into a limestone area and a dolomite area; the 

northern arm of the shelf complex where ORI lands are located is predominantly dolomitized. The shelf 

extends almost 100 townships north to south through central Alberta and the source rock is believed to be 

the Exshaw Formation (Fowler et al., 2001). 

The Nisku Formation subcrops in the area of interest; this is a play on the western subcrop edge where 

much of the Nisku has been diagenetically altered. The various carbonate lithofacies exhibit extensive 

dolomitization, vugs, and solution-enhanced fracturing; core demonstrates heterogeneity in porosity, 

permeability, and oil saturation among other characteristics. Porosity is strongly controlled and enhanced 

by the diagenetic processes, namely regional dolomitization of limestone, dissolution, fracturing and 

karsting in some areas (Peachey et al. 2007). Due to the high degree of heterogeneity of the Nisku, 

current well log and core control may not be sampling the range of actual values adequately; this has 

been represented in the ranges of volumetric parameters. 

The Nisku in the Nixon area is characterized by intercrystalline dolomite with pinpoint to large vugs, 

fractures, pyrite, and thin un-dolomitized limestone intervals. Potential reservoir zones average 22 

meters of gross thickness, 17 percent porosity, 45 percent water saturation, and permeability of 50 to 


1,000 millidarcies. Intervals within the Nisku appear to be hydrocarbon charged in many locations based 

on volumetric calculation, drill stem test recovery and oil pore volumes from core of 20 to 60 percent. 

Bitumen viscosity is estimated to be 10 to 11 API gravity based on the drill stem test of the Nisku Type 

Log well (102/07-27-072-18W4), on ORI leases, which recovered seven meters of “heavy oil (tar)” (10.6 

API gravity). Bitumen staining is not common however several wells have oil residue in drill stem test. 

No oil has been produced from the Nisku Formation in the mapped area however several wells, including 

100/10-31-071-17W4 and 100/16-19-072-18W4, recovered oil cut mud in drill stem tests. Several core 

reports indicate the core of many high porosity intervals was not recovered. 

Over company land, the top of the Nisku Formation ranges in depth from approximately 440 to 500 

meters true vertical depth and in elevation from approximately +80 to +140 meters subsea, as illustrated 

by the Nisku Structure and Subcrop Map. This map, picked on the top of the Nisku, is computer 

contoured on a ten meter interval, using formation tops created by ORI, and audited by AJM Deloitte. 

The Nisku Subcrops across ORI lands. 

Nisku gas has been produced from 213 wells in the mapped area, the majority drilled and produced from 

the late 1970’s to the late 1990’s. One of the earliest wells, 100/07-23-071-18W4/00, was drilled in 1964 

and produced over 25 billion cubic feet of Nisku gas over a 27 year period. In a review of the 41 gas 

producers located on company leases, the vast majority were found to be completed in the uppermost 

gas interval and have produced a combined total of 71.5 billion cubic feet of gas to the effective date. 

There is uncertainty as to the specific volume of the gas cap on company lands due to the inconsistent 

representation of gas on well logs. Some producers show little to no density-neutron log cross-over while 

some wells show crossover but recovered no gas from the zone of interest (see Nisku Type Log). 

Total PIIP volume calculations indicated in this report have only included bitumen net pay thickness. 

None of the net pay attributed to gas has been included in the calculation. This is further discussed in the 

Technical Assessment section of the report. 

The vast majority of gas wells have produced water; cumulative water volumes in gas producers is 

relatively consistent on and offsetting ORI land. Significant water production is not expected to be 

problematic however cannot be verified until a pilot test is completed. 

Analogous plays 

Many oil sands projects exist in the Athabasca area however according to the Alberta Securities 

Commission (“ASC”), use of analogy in unconventional resource studies, ‘should consider not only the 


eservoir properties (reservoir analog), but the validity of the proposed recovery process (process analog)’ 

(ASC, 2011). 


No producing Viking heavy oil pools exist in the greater Athabasca area. Many companies, such as 

Laricina Energy Ltd. (“Laricina”), Athabasca Oil Sands Corp. (“Athabasca Oil”) and Sunshine Oilsands 

Ltd. (“Sunshine”), are targeting Lower Cretaceous oil sands and Devonian bituminous carbonates at 

project sites located approximately 100 to 250 kilometers northwest of ORI lands (Laricina, 2012, 

Athabasca Oil, 2012, Sunshine, 2012). Some operators, such as Sunshine, have indicated the Viking as 

an uphole bitumen target (Sunshine, 2012) on these properties. Approximately four Sunshine wells in the 

Harper area of Alberta have Viking core recoveries which show equivalent core to well log porosity and 

20 to 50 percent oil saturation. While porosity averages three percent higher than on ORI lands, the net 

pay in Harper is only one third to one half that in Nixon. No further indications of testing in the Viking 

have been made publically available nor have there been discussions on reservoir parameters, oil 

characteristics, or recovery methods. 


The Athabasca Grand Rapids pool located at approximately Township 73, Ranges 19 and 20W4, 

produces from the Upper Grand Rapids Formation in the same upper interval targeted by ORI. This 

cannot be considered a true analogue because the net pay is significantly thicker, the water saturation is 

lower, the area is larger and a negligible amount of gas exists as compared to the potential pool on ORI 

land. The Athabasca Grand Rapids pool is currently producing at a relatively flat rate, at a combined 

production rate of approximately 500 barrels per day from vertical wells. Only primary recovery methods 

have been employed in this pool. 

Laricina is targeting Grand Rapids bitumen on their Germain Lease in Athabasca at Township 84, Range 

22W4. Laricina has performed drill stem tests on three wells which have all recovered water. They have 

also performed a comprehensive Grand Rapids coring program over their leases which show bitumen 

saturated Upper Grand Rapids sand of 32 to 34 percent average porosity. Well logs and core show a net 

reservoir almost four times as thick as on ORI lands with an average oil saturation higher by 10 percent 

(Connelly, 2011). This cannot be considered an analogy due to the higher quality reservoir as compared 

to the Grand Rapids on ORI leases. 

Two Grand Rapids gas wells, located 6.5 miles (11.5 kilometers) west-southwest of the ORI Grand 

Rapids focus area and 0.75 miles from ORI land, have also produced small amounts of oil from the Grand 

Rapids. 100/10-31-068-13W4/02 and 100/07-07-069-13W4/02 have produced 2.89 and 4.47 billion cubic 


feet of gas and two and one barrels of oil respectively. The first event in both wells is commingled 

production from the Grand Rapids and the McMurray Formations; however this first event did not produce 

any oil in either well. Oil production is most likely from the Grand Rapids as it was only produced in each 

well’s second event, Grand Rapids-only events. Neither analogue well has Upper Grand Rapids oil tests 

therefore the specific viscosity is unknown. 

These wells can be considered analogues due to the proximity to the ORI Grand Rapids focus area and 

the inferior well log characteristics as compared to those of the Grand Rapids in the focus area. The 

exact reservoir parameters are difficult to determine in the analogue wells due to 100/10-31-068-13W4 

having only resistivity well logs, 100/07-07-069-13W4 showing cross-over throughout the entire pay 

interval and both wells being of an older vintage (pre 1978). The bitumen net pay averages 1.5 meters 

(half of Grand Rapids net pay on the ORI focus area) and similar porosity and hydrocarbon saturation as 

on the ORI focus area. This analogue allows these resources to be classified as prospective. 


Laricina’s Germain project site is located approximately 108 kilometers northwest of ORI lands. There 

are three target pools at Germain, the bitumen carbonates of the Grosmont and Nisku Formations as well 

as the oil sands of the Grand Rapids Formation (CERI, 2009). The Grosmont Formation is the primary 

target, being developed using enhanced recovery methods. These include an optimized combination of 

Steam Assisted Gravity Drainage (“SAGD”), solvent-cyclic SAGD (“SC-SAGD”) and Non-Thermal Solvent 

Recovery. Laricina has indicated preliminary success in early testing of the Nisku at the Germain Field 

(Laricina, 2011) however the specific data is not yet publically available. 

Nisku well log control is scarcer in Germain than in Nixon. The limited number of well logs and core 

recoveries from this field indicate cavernous porosity (35 to 40 percent), high permeability (500 to 1,000 

millidarcies), higher oil pore volumes (60 to 80 percent) and a thicker average gross interval (45 meters); 

seemingly higher quality than the Nisku on ORI land. Due to the high degree of heterogeneity of the 

Nisku in Germain, as in Nixon, current well log and core control may not be sampling the range of actual 

values adequately however. 

The ASC considers that there is currently “ no commercially viable production from bituminous 

carbonate reservoirs and there have been only one or two significant pilot tests.” This is the case for the 

Nisku pilot in the Germain area. It has not produced bitumen from the Nisku, only a reported test and 

considering the differences in apparent reservoir quality, limited data set and lack of production, the Nisku 

at Germain cannot be considered an analogue. Substantial supporting technical evidence does not exist 

to prove recoverability in Nixon. Recovery factors have therefore not been applied to the undiscovered 

petroleum initially-in-place volumes. 


Geological risk factors 

A total of six criteria are considered in determining the overall geological risk. 

 

 

 

 

 

 

source rock – is there thermally mature hydrocarbon source rock present in adequate thickness, 

extent, and organic richness, 

charge – is the source rock capable of generating hydrocarbon, 

migration – are there sufficient migration pathways such as faults, fractures, and carrier beds to 

the reservoir, 

reservoir rock – does the reservoir have favorable parameters such as thickness, pore space, 

and the ability to allow fluid flow, 

trap / closure – does closure of the reservoir exist in terms of adequate areal extent and vertical 

relief, 

seal / containment – are there effective sealing rocks present to ensure that containment has 

occurred. 

Source rock, charge, migration, trap and seal are of low risk due to the indication of hydrocarbon on well 

logs, and bitumen recovered on drill stem tests. 

For the Viking and Grand Rapids Formations, the reservoir rock is also relatively low risk due to the good 

well control demonstrating a relatively homogeneous reservoirs, availability of core, indication of oil in drill 

stem test and oil saturations in core. The largest risk is related to the oil saturation and the degree of 

biodegradation of the oil. There is a large degree of uncertainty as to whether this resource could be 

successfully produced in if so, whether the rates would be sustainable given the viscosity and apparent 

water saturation and whether production would be economically feasible. 

For the Nisku Formation, the main geological risk revolves around the reservoir rock. Many areas have 

sparse well control and even among control wells, potential is not seen in every one. Within the reservoir, 

facies and lithological changes can be abrupt. As is the case with the majority of carbonate oil reservoirs 

in the Western Canadian Sedimentary Basin, the Nisku Formation at Athabasca is heterogeneous. 

Porosity, contiguous net pay thicknesses and hydrocarbon saturation are variable and permeability is 

irregular. 

The ASC 2010 Oil and Gas Review states that due to the degree of heterogeneity typically found in 

carbonate heavy oil reservoirs, estimating recoverable resources beyond control wells requires 

“substantial supporting technical evidence”. In this case, we do not have production on or offsetting 

company land or an appropriate analogue; Therefore recoverability cannot be proven or estimated at this 

time. 


Technical assessment 

Probabilistic analysis 

AJM Deloitte has used data provided by ORI and from the public domain to assess the Nisku, Viking and 

Grand Rapids potential on and around company land holdings. AJM Deloitte considered wells on and 

adjacent to these lands, and additional wells required in the assessment of geological elements on 

company lands. 635 wells were reviewed for the Viking and Grand Rapids assessments, and 202 wells 

were reviewed for the Nisku assessment. This is in addition to the wells reviewed in the potential 

analogue areas. 

The well log review consisted of an analysis of the porosity (density and neutron porosity or sonic) and 

resistivity (induction or electric well logs) for all wells with log control of each respective zone. Cutoffs 

have been applied to the gamma ray, porosity, and hydrocarbon saturation calculation from log 

parameters and averages for each parameter was recorded. Low and high case mapping has been 

created based on wells penetrating a sufficient thickness of each formation. Seismic data was not 

available for this assessment. 

The Viking and Grand Rapids Structural X-Sections characterize the respective intervals in the Nixon 

area. Cutoffs have been applied to the gamma ray, porosity, and hydrocarbon saturation calculation from 

log parameters and averages for each parameter was recorded. Seismic data was not available for this 

assessment. Ninety five percent of wells in the mapped area penetrate the Viking and 88 percent 

penetrate the Grand Rapids. 

The Nisku Type Log and corresponding Nisku Core Plot for 102/07-27-072-18W4 characterize the Nisku 

interval in the Nixon area. This well has comparatively higher resistivity, thicker net pay and 

comparatively lower porosity than the average for each parameter on company lands. 

Area 


ORI owns a 100 percent working interest in 397,440 acres of land in the Athabasca area, according to the 

company. For the Viking Formation, most of this area exists beyond the thick channel; the company 

owns approximately 66,700 acres of land over the Viking channel, based on high case mapping. The 

ranges of area have been derived from the low and high case mapping of geological parameters for each 

interval. PIIP area distributions for the Viking include a reasonable range of area considering the lower 


density well spacing from Section 01- and 02-072-19W4 up to Section 31-072-18W4 and the lack of 

producing analogues. 


The company owns approximately 274 acres of land with Grand Rapids potential, best case estimate. 

The 100/14-13-069-15W4 well with the uncertain bitumen pay interval has been assumed to contain gas 

over bitumen in the high case and is considered to be gas charged throughout in the low case. The lack 

of well control creates uncertainty in reservoir extent and is also reflected in the area distribution. 


The Nisku subcrop edge can be traced across company land where 118,400 acres extending over the 

Nisku (Nisku Structure and Subcrop map). The ranges of area have been derived from the low and high 

case mapping of geological parameters for each interval. PIIP area distributions include a reasonable 

range of area considering the high degree of heterogeneity, a lack of well control and lack of producing 

analogues. The contouring of data honors all data points and reflects the heterogeneity of the reservoir. 

The area included in the prospective resource assessment is based on data from the 102/07-27-072- 

18W4 well. A drill stem test in the Nisku of this well recovered seven meters of “heavy oil (tar)” which 

constitutes proof of in-place hydrocarbons for this well and a small area surrounding it. Where geological 

continuity of this reservoir exists adjacent to this well, proof of in-place hydrocarbon has been extended 

where adjacent wells show similar or better reservoir parameters and are of a reasonable distance away. 

For each of the low, best and high cases, a slightly different value for step-out distance was used. The 

resulting area distribution has been used to calculate prospective resources for the Nisku on ORI lands. 

Wells producing from the Nisku do not exist in the low or best case area; production volumes have been 

subtracted from the high case estimate because the area estimated in the high case includes wells that 

have produced Nisku gas (Prospective Area Assessment map). 

Thickness (net to gross) 

Reservoir zones separated by low porosity intervals of one meter thickness or less have been considered 

contiguous; tight intervals of this thickness are not continuous over long distances and are not expected 

to inhibit the effectiveness of enhanced recovery. 


Viking and Grand Rapids 

Gross thickness has been measured from top to base of the Viking and Grand Rapids Formations. In 

some cases, the public data tops were used but in many cases, ORI has edited these tops based on what 

was seen in stratigraphic correlation. Seventy five percent of these tops have been audited and accepted 

by AJM Deloitte. Net pay measurements have been calculated on intervals which met or exceeded the 

cutoffs applied and where a minimum of four meters of contiguous pay was available. Thickness (net and 

gross) were mapped for the low, best, and high cases from which the average gross thickness and 

average net pay ranges have been estimated. The net to gross ratio was subsequently calculated for 

each well. 


Gross thickness has been measured from top to base of the Nisku Formation. In some cases, the public 

data tops were used but in many cases, ORI has edited these tops based on what was seen in 

stratigraphic correlation. Seventy five percent of these tops have been audited and accepted by AJM 

Deloitte. Net pay measurements have been calculated on carbonate intervals which met or exceeded the 

cutoffs applied. Thickness (net and gross) were mapped for the low, best and high cases, from which, 

the average gross thickness and average net pay ranges have been estimated. The net to gross ratio 

was subsequently calculated for each well. 

Well log analysis included a review of potential gas-bitumen contacts. A clear, consistent contact is not 

well defined in the Nixon area. Density and neutron porosity logs as well as sonic and resistivity logs 

were evaluated for gas signatures. From the available data, a contact has been assumed to be 

approximately 110 to 112 meters subsea. This range is reflected in the net pay distribution. The net pay 

attributed to gas has been deducted in each well therefore the range of pay thickness used in the 

assessment is bitumen net pay only. Based on the Nisku Structure and Subcrop map, the 110 meter 

contour suggests that there should be more gas towards the east. 

The 100/07-25-071-18W4 and 100/02-01-073-19W4 are examples of wells that have produced about 3.6 

billion cubic feet of gas from the Nisku, both showing most or all the Nisku hydrocarbon interval above the 

110 meter subsea level. Like most wells in this property, there does not appear to be a definitive gaswater 

contact. It is possible the entire interval was gas charged, however it is difficult to ascertain the 

exact thickness of the gas column in this well and the surrounding sections due to uncertainties in the well 

log analysis. Higher gas-oil contacts have been used for wells in Ranges 18 and 17W4 due to the Type 

Log well having all pay above the 121 meters subsea. In this well, which tested oil, the lowest known oil 

is at 134.8 meters subsea, the base of the testing interval. In the east half of ORI lands, contacts range 


from 122 to 140 meters subsea. The uncertainty related to gas-oil contacts is reflected in the range of 

thickness values. 

Porosity 


A porosity cutoff of 27 percent on the sandstone density scale has been used for both formations. The 

average porosity of the resultant pay interval has been recorded for each well. Core and log porosity are 

relatively consistent therefore no adjustments to log porosity have been made in non-cored wells. The 

cutoff of 27 percent has been used as the very low case end member in both cases to reflect the cutoff. 


A porosity cutoff of six percent on the limestone density scale has been used. According to a core to well 

log porosity comparison of five wells cored in the Nisku on company land, this is approximately equivalent 

to 10 to 12 percent on the dolomite density scale. The comparison suggests that on limestone scale, 

dolomite intervals read approximately 4.5 percent lower than core and on sandstone scale, read 

approximately seven percent lower than core. Porosity readings have been adjusted to reflect the 

appropriate lithology (based on the photoelectric curve) and the cutoff has been applied to each. The 

average porosity of the resultant pay interval has been recorded for each well. 

The Nisku Type Log and Nisku Core Plot illustrate the difference between core porosity and log porosity. 

The limestone scale density porosity curve is on average five percent lower than the core porosity, for this 

particular well. Conversely, the dolomite scale density porosity curve for this same well was one to two 

percent higher than in core and therefore shows false cross over a large part of this interval. This 

difference is relatively consistent for other cored wells included in the review. 

In many cored wells, the lower porosity Nisku intervals have a higher degree of core recovery than high 

porosity intervals. This was also the case for the Grosmont core recoveries in the Athabasca area; many 

show lost core over high porosity intervals. 


Hydrocarbon saturation 


The Viking and Grand Rapids hydrocarbon saturation for each evaluated well has been calculated from 

the respective well log parameters using the ‘Simandoux’ calculation method. A cutoff of 35 percent has 

been applied (water saturation of 65 percent). 


The Nisku hydrocarbon saturation for each evaluated well has been calculated from the respective well 

log parameters using the ‘Archie’ calculation method. It should be noted that the ‘Archie’ equation has 

been developed to assess conventional hydrocarbon, not necessarily unconventional hydrocarbon; this 

adds uncertainty to the hydrocarbon saturation determination. The pyrite evident in the core throughout a 

number of pay intervals suggest that the low resistivity zones could be influenced by pyrite and not water 

saturation. The best case hydrocarbon saturation has been increased two percent to reflect this data. 

Formation water resistivity (at 25 degrees Celsius) ranges in the greater Nixon area from 0.53 to 0.21 

ohm*meters, however many indicate contaminated water. Two wells, 100/10-10 and 102/16-34-069- 

18W4, have Nisku water tests of 0.21 ohm*meters, both suggest uncontaminated formation water. AJM 

Deloitte has used this value in the calculation of hydrocarbon saturation. 

Water has not produced from the Nisku Type Log well where the entire interval measured over 20 ohm 

meters. 

Oil shrinkage 


No recovery factor has been estimated for the Viking Formation in the Nixon area because only PIIP 

resource volumes have been estimated. 


The oil shrinkage is assumed to be 1.00 to 1.02 based on oil analyses in the Athabasca Grand Rapids 

pool. Oil of this low API gravity is expected to have negligible solution gas. 



The oil shrinkage is assumed to be 1.000 due to the expectation that oil of this low API gravity would have 

negligible solution gas. 

Recovery factor 


No recovery factor has been estimated for the Viking Formation in the Nixon area because only PIIP 

resource volumes have been estimated. 


A range of recovery factors has been applied to the Grand Rapids. Existing thermal recovery projects in 

oil sands are generally applied to much thicker sand reservoirs than on ORI lands, generally seven 

meters of contiguous pay or thicker (Jiang, Q., 2009 and ERCB, 2011). This consideration drastically 

reduced the expected recovery factor, assuming thermal recovery a possibility in the high case. 


Recovery factors have been applied to the assigned prospective resource volumes for an area 

immediately offsetting the Nisku Type Log which recovered bitumen. According to the ASC, heavy oil 

resource studies in carbonate reservoirs must have “substantial supporting technical evidence” to assign 

recoverable resource volumes beyond well control points. The report states that the ASC has “…noticed 

increasing disclosure on resources, frequently classified as contingent resources, in bituminous 

carbonates. Alberta Reporting Issuers should consider that there is no commercially viable production 

from bituminous carbonate reservoirs and there have been only one or two significant pilot tests. The 

properties of carbonate rocks, especially the pore structure, are highly varied and the use of these tests 

as analogs in other reservoirs requires substantial supporting analysis and meaningful discussion in order 

to avoid misleading disclosure.” (ASC, 2010). Due to the uncertainty from a lack of reasonable 

analogues, the range of recovery factors has been kept very low in comparison to recoveries expected for 

oil sands pools. 


Development plans 

To date, ORI has not identified Nisku, Viking and Grand Rapids well locations to be drilled in the 

Athabasca area. Drilling, testing, and production could further increase the estimated volumes and 

concurrently broaden the area where PIIP and prospective resources could be assigned with confidence 

and/or move some volumes to higher categories. A full development scheme will not likely be outlined 

until after the results of the test wells have been analyzed. 


A number of recovery processes have been successful for oil sands recovery. None have been proven 

on the Viking oil sands. Further testing or a successful pilot project in the Viking on company land could 

move some PIIP resource volumes to prospective or contingent resources by providing the appropriate, 

zone specific data to estimate flow rates, recoverability, and prove ORI’s ability to extract Viking bitumen. 


A thermal recovery scheme would be required to produce economic volumes of bitumen from the Grand 

Rapids Formation on ORI leases (Jiang et al. 2009). Steam assisted gravity drainage (“SAGD”) is 

commonly used in the Grand Rapids in other areas of Alberta however requires 10 meters of contiguous 

pay; wells in the Nixon focus area do not reach this minimum. Other methods, such as cyclic steam 

stimulation (“CSS”) could be effective in thinner reservoirs however tend not to perform well with gas 

caps. 


A number of recovery processes have been suggested for bituminous carbonates beyond SAGD normally 

used in oil sands: solvent-cyclic SAGD (“SC-SAGD”) and Thermal Assisted Gravity Drainage (“TAGD”). 

Laricina intends to produce Nisku bitumen from the SC-SAGD facilities in the Germain property, currently 

targeting the Grosmont while Athabasca Oil Sands Corp. (“Athabasca Oil”) tested the Leduc Formation 

carbonate in their Dover West property with a successful Steam Injection Test and subsequent testing of 

TAGD, an innovated technology using heat conduction from electrical heaters. Both companies have 

stated that SC-SAGD and TAGD have shown evidence that recoveries can be increased (Laricina, 2011, 

Athabasca Oil, 2011). 


Development risk factors 

The geological risk factors are discussed within the Geology section of the original report. The chances 

of development for the estimated undiscovered PIIP and prospective resources are subject to a number 

of factors, including: the overall project economics, the employed enhanced recovery technology, and 

regulatory and environmental approval. Prior to committing to any defined development, drilling and 

testing will be required to further quantify the hydrocarbon potential. With the large number of unknowns, 

seismic data, test wells, core and a pilot project could decrease much of the uncertainty and assist in 

moving this resource into a prospective category. 


Viking and Grand Rapids natural gas production in the area has not been considered. Production of gas 

in oil sands reservoirs can have negative effects on production however no Viking gas has been 

produced on company lands or within two miles of the channel area. 


Production of gas from the Nisku in this area totaling 71.5 billion cubic feet (11.9 million barrels of oil 

equivalent) has not been included in this assessment. Production of gas in oil sands reservoirs may have 

negative effects on subsequent oil production, however, the extent of the effect of Nisku gas production 

on the productive capability in Nixon is unknown at this time. Following the progress of pilot projects by 

others (including Laricina and Athabasca Oil) would aid in anticipating the specific development scheme 

requirements to optimize recovery in this type of development. 


References 

Alberta Securities Commission, 2011. 2010 Oil and Gas Review Report. 

Athabasca Oil Sands Ltd. (Athabasca Oil), 2011. Annual Report, 2011. Website accessed May 3 to 18, 

2012. http://www.aosc.com/upload/media_element/124/01/2011-annual-report.pdf. 

Canadian Energy Research Institue (CERI), 2009 CERI Commodity Report, Oil Sands Technology Part 

2. April 2009 Website accessed May 3, 2012 

http://www.laricinaenergy.com/uploads/press/ceri_04_09.pdf. 

Connelly, M. 2010 West Athabasca Grand Rapids Formation – A New SAGD Play (in a simple reservoir) 

Laricina Energy. Website accessed May 22, 2012. 

http://www.laricinaenergy.com/uploads/tech/geocan_2010_pres.pdf. 

Energy Resources Conservation Board, 2011. Alberta’s Energy Reserves 2010 and Supply/Demand 

Outlook 2011-2020. 

Fowler, M. G., Stasiuk, L. D., Hearn, M. and Obermajer, M., 2001 Devonian Hydrocarbon Source Rocks 

and their Derived Oils in the Western Canada Sedimentary Basin. Bulletin of Canadian 

Petroleum Geology, March 2001, v. 49, p. 117-148. 

Jiang, Q., Thronton, B., Russel-Houston, J. and Spence, S., 2009. Review of Thermal Recovery 

Technologies for the Clearwater and Lower Grand Rapids Formations in the Cold Lake Area in 

Alberta. Osum Oil Sands Corp. Canadian International Petroleum Conference Paper 2009-068. 

Laricina Energy Ltd. (Laricina), 2011. Annual Report, 2011. Website accessed May 3 and 18, 2012. 

http://www.laricinaenergy.com/uploads/investors/ar_2011.pdf. 

Peachey, Bruce et al., 2007 Low Carbon Futures; Carbonate Triangle and Conventional Heavy Oil – 

Lowest GHG Production Scenarios. Petroleum Technology Alliance Canada – An Exploration 

Study March 31, 2007. Website accessed May 3, 2012 

http://www.ptac.org/attachments/0000/0113/Low_Carbon_Futures.pdf. 

Reinson, G.E., Warters, W.J., Cox, J., and Price, P.R. 1994. Geological Atlas of the Western Canada 

Sedimentary Basin. Canadian Society of Petroleum Geologists and Alberta Research Council, 

Chapter. 21. 

Sunshine Oilsands Ltd. (Sunshine), 2012. Company website accessed May 18, 2012. 

http://www.sunshineoilsands.com/operations/harper.html. 

Switzer, S.B. et al., 1994. Devonian Woodbend-Winterburn Strata of the Western Canada Sedimentary 

Basin. In: Geological Atlas of the Western Canada Sedimentary Basin. Canadian Society of 

Petroleum Geologists and Alberta Research Council, Chapter. 12. 


Company Evaluated: 

Appraisal For: 

Permit / Block: 



Nixon 

Low Best High 

Viking MMBbls 1,419,623 2,460,916 4,265,997 

Grand Rapids MMBbls 4,437 8,461 16,133 

Nisku MMBbls 233,075 671,933 1,937,121 

Undiscovered PIIP MMBbls 2,038,955 3,354,280 5,575,105 

Undiscovered PIIP 

Cumulative Probability 

0.01 

0.05 

0.10 

0.20 

0.30 

0.40 

0.50 

0.60 

0.70 

0.80 

0.90 

0.95 

0.99 

1,000 10,000 100,000 1,000,000 10,000,000 

Viking Grand Rapids Nisku Aggregate 

insert results for simulation here 


Company Evaluated: 





Nixon 

Low Best High 

Grand Rapids MMBbls 304 655 1,412 

Nisku MMBbls 1,120 4,702 19,738 

Prospective Resources MMBbls 1,828 5,493 20,456 

Prospective Resources 


0.01 

0.05 

0.10 

0.20 

0.30 

0.40 

0.50 

0.60 

0.70 

0.80 

0.90 

0.95 

0.99 

100 1,000 10,000 100,000 1,000,000 10,000,000 

Nisku Grand Rapids Aggregate 

insert results for simulation here 


Company Evaluated: Oil Reserve Inc. 




Nixon 

Entity Name: 1 

Formation: 


Low Best High 

Area acres 50,000 57,749 66,700 

Gross Thickness feet 80.0 93.8 110.0 

metres 24.4 28.6 33.5 

Net to Gross Ratio fraction 0.26 0.39 0.58 

Porosity fraction 0.29 0.32 0.35 

Hydrocarbon Saturation fraction 0.35 0.47 0.64 

Oil Shrinkage STB/rbbl 1.000 1.000 1.000 

Oil Formation Volume Factor rbbl/STB 1.000 1.000 1.000 

Undiscovered PIIP Mstb 1,419,623 2,460,916 4,265,997 

Reservoir Parameter Inputs 


0.01 

0.05 

0.10 

0.20 

0.30 

0.40 

0.50 

0.60 

0.70 

0.80 

0.90 

0.95 

0.99 

0.01 0.1 1 10 100 1000 10000 100000 1000000 

Area (acres) Gross Thickness (feet) Net to Gross Ratio (fraction) 

Porosity (fraction) Oil Saturation (fraction) Oil Shrinkage (STB/rbbl) 

Original Oil in Place / Recoverable Oil 


0.01 

0.05 

0.10 

0.20 

0.30 

0.40 

0.50 

0.60 

0.70 

0.80 

0.90 

0.95 

0.99 

100,000 1,000,000 10,000,000 100,000,000 

Oil Volume (Mstb) 







Nixon 


Formation: 


Low Best High 

Area acres 100 274 750 


metres 54.4 56.1 57.9 






Undiscovered PIIP Mstb 4,437 8,461 16,133 

Oil Recovery Factor fraction 0.05 0.08 0.12 

Prospective Resource Mstb 304 655 1,412 



0.01 

0.05 

0.10 

0.20 

0.30 

0.40 

0.50 

0.60 

0.70 

0.80 

0.90 

0.95 

0.99 

0.01 0.1 1 10 100 1000 10000 100000 



Oil Recovery Factor (fraction) 



0.01 

0.05 

0.10 

0.20 

0.30 

0.40 

0.50 

0.60 

0.70 

0.80 

0.90 

0.95 

0.99 

100 1,000 10,000 100,000 


Undiscovered PIIP Prospective Resource Total Prospective Resource - Mboe 


Company Evaluated: Oil Reserve Inc 


Oil Reserve Inc 


Athabasca 


Formation: 


Low Best High 

Area acres 25,500 41,855 68,700 


metres 11.0 22.0 44.2 






Undiscovered PIIP Mstb 233,075 671,933 1,937,121 



0.01 

0.05 

0.10 

0.20 

0.30 

0.40 

0.50 

0.60 

0.70 

0.80 

0.90 

0.95 

0.99 

0.01 0.1 1 10 100 1000 10000 100000 1000000 





0.01 

0.05 

0.10 

0.20 

0.30 

0.40 

0.50 

0.60 

0.70 

0.80 

0.90 

0.95 

0.99 

10,000 100,000 1,000,000 10,000,000 100,000,000 








Nixon 


Formation: 

Nisku Formation 

Low Best High 

Area acres 2,000 4,690 11,000 


metres 11.0 22.0 44.2 






Undiscovered PIIP Mstb 21,851 75,299 259,481 

Oil Recovery Factor fraction 0.03 0.06 0.13 

Prospective Resource Mstb 1,120 4,702 19,738 



0.01 

0.05 

0.10 

0.20 

0.30 

0.40 

0.50 

0.60 

0.70 

0.80 

0.90 

0.95 

0.99 

0.01 0.1 1 10 100 1000 10000 100000 



Oil Recovery Factor (fraction) 



0.01 

0.05 

0.10 

0.20 

0.30 

0.40 

0.50 

0.60 

0.70 

0.80 

0.90 

0.95 

0.99 

100 1,000 10,000 100,000 1,000,000 10,000,000 



Prospective Resource 


T77 

T76 

T75 

T74 

T73 

T72 

T71 

Legend 

T70 

Oil Reserve Inc. Land 

WELL SYMBOLS 

T69 

D&A FG SG D&C AGZ 

AG AZN TH PG LCT 

PTG CMM WD PBO ARE 

SBO PO AK ARG SWD 

1 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 31 36 

31 36 

6 

1 6 

1 

31 36 31 36 

6 

1 6 

1 

31 36 

31 36 

6 

1 6 

1 

31 36 

31 36 

6 

1 

6 

1 

31 36 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 6 

1 6 

1 6 

1 6 

1 

6 

1 6 

1 

6 

1 

6 

1 

6 

1 

6 

1 

6 

1 

31 36 

31 36 31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

6 

1 6 

1 6 

31 36 31 36 

1 6 

1 6 

31 36 

31 36 

1 

6 

1 6 

31 36 

31 36 

1 

6 

1 6 

31 36 

31 36 

1 6 

1 6 

31 36 

31 36 

1 6 

31 36 

31 36 

1 

1 

6 

1 6 

1 6 

31 36 31 36 

31 36 

6 

1 6 

1 

31 36 

31 36 

6 

1 6 

1 

31 36 

31 36 

6 

1 

6 

1 

31 36 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

1 

6 

1 6 

1 6 

31 36 31 36 

31 36 

6 

1 6 

1 

31 36 

31 36 

6 

1 6 

1 

31 36 

31 36 

6 

1 

6 

1 

31 36 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

1 6 

1 

6 

1 6 

1 6 

31 36 

31 36 31 36 

31 36 

6 

1 6 

1 

31 36 

31 36 

6 

1 6 

1 

31 36 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 6 

31 36 

1 6 

1 6 

1 6 

31 36 

31 36 31 36 

1 6 

1 6 

1 6 

1 6 

1 6 

1 6 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

1 

6 

1 

31 36 

31 

36 

1 

1 6 

1 6 

6 

1 6 

1 6 

31 36 

31 36 

31 36 31 36 

31 36 

6 

1 6 

1 

31 36 

31 36 

6 

1 

6 

1 

31 36 

31 36 

1 

6 

1 6 

31 36 

31 36 

6 

1 

31 36 

1 6 

1 

6 

1 6 

1 6 

31 36 

31 36 31 36 

31 36 

6 

1 6 

1 

31 36 

31 36 

6 

1 6 

1 

31 36 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 6 

1 

31 36 31 36 

6 

1 6 

1 6 

31 36 

31 36 

1 6 

1 

31 36 

31 36 

6 

1 

6 

1 

31 36 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 6 

1 6 

31 36 31 36 

1 6 

1 6 

31 36 

31 36 

1 6 

1 6 

31 36 

31 36 

1 

6 

1 6 

31 36 

31 36 

1 6 

1 6 

31 36 

31 36 

1 6 

31 36 

31 36 

1 

1 6 

1 

6 

1 6 

1 6 

31 36 

31 36 31 36 

31 36 

6 

1 6 

1 

31 36 

31 36 

6 

1 6 

1 

31 36 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

1 6 

1 

1 6 

1 6 

6 

1 6 

1 6 

6 

1 6 

1 6 

1 

1 6 

1 6 

6 

R22 R21 R20 R19 R18 R17 R16 R15 R14 R13 R12 R11W4 

J&A UV DRN WI SWI 

T68 

WSC CLG CBM FSW AOZ 

AO AWD STI AWI SL 

Kilometres 

0 10 20 30 

T67 

0 10 20 

Miles 

T66 



WI Land 

T65 

By : laj Date : 2012/06/27 

Scale = 1:545000 Project : athbscwiland

Upper 

Cretaceous 

Eastern Alberta 

Battle 

Whitemud 

Horseshoe Canyon 

Bearpaw 

Belly River 

Edmonton 

Lea Park 

First White Speckled Shale 

Upper Colorado 

La Biche Group 

Cardium 

Colorado Shale 

Second White Speckled Shale 

Fish Scale Zone 

Colorado Shale 

Second White 

Speckled Sandstone 

Colorado 

Upper 

Mannville 

Middle 

Mannville 

Lower 

Mannville 


Joli Fou 

Mannville Group 

Upper 

Lower 

Blairmore 


Clearwater 

Glauconitic 

Basal Colorado 

Colony 

McLaren 

Waseca 

Sparky 

Lloydminster 

Cummings Wabiskaw 

Ostracod 

Basal Mannville 

McMurray Dina 

Ellerslie (Basal Quartz) 

Detrital 

Mississippian 

Upper Devonian 

Banff 

Exshaw 

Wabamun 

Winterburn 


Woodbend 

Group 

Ireton 

Bakken 

Grosmont 

Leduc 


Eastern Alberta 

Stratigraphic Column 

By : kma 

Project : athabasca 

Legend 

Sandstone 

Shale 

Limestone 

Dolomite 

Date : 2012/06/27

T77 

T76 

T75 

T74 

T73 

T72 

T71 

Legend 

T70 

Viking Penetration Well 


WELL SYMBOLS 

T69 




340 

1 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 31 36 

31 36 

380 

1 6 

1 

31 36 

31 36 

6 

1 

31 36 

6 

1 

1 6 

1 

6 

1 6 

31 36 

31 36 

31 36 

31 36 

410 

1 

6 

1 6 

31 36 

31 36 

6 

1 

31 36 

6 

390 

6 

1 6 

1 

31 36 31 36 

370 

420 

400 

360 

350 

6 

1 6 

1 6 

1 6 

1 6 

1 

6 

1 6 

1 6 

1 6 

1 6 

1 6 

1 6 

1 

31 36 

31 36 31 36 

31 36 31 36 

31 36 

31 36 

31 36 31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

410 

400 

31 36 

6 

390 

430 

6 

1 6 

1 6 

1 6 

1 6 

31 36 

31 36 

1 

380 

1 6 

1 6 

1 6 

1 

1 

1 6 

340 

1 

6 

330 

6 

6 

1 

31 36 

6 

1 

6 

1 6 

1 

31 36 31 36 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 6 

1 

31 36 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

370 

330 

380 

370 

320 

6 

1 6 

1 

31 36 31 36 

1 

6 

1 6 

31 36 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 6 

31 36 

31 36 

1 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

360 

380 

6 

1 

31 36 

6 

31 36 

1 6 

6 

1 6 

1 6 

31 36 31 36 

31 36 

31 36 

1 

6 

31 36 

1 6 

1 

6 

31 36 

31 36 

1 6 

1 6 

31 36 

31 36 

1 6 

1 

6 

31 36 

31 36 

1 6 

1 

31 36 

31 36 

1 6 

1 

6 

1 6 

31 36 

6 

1 

31 36 

6 

1 

31 36 

1 6 

1 6 

31 36 

31 36 

6 

1 6 

31 36 

1 

31 36 

6 

1 

31 36 

31 36 

1 

350 

310 

360 

300 

350 

330 

340 

310 

290 

1 6 

1 

6 

1 6 

1 6 

31 36 

31 36 31 36 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 6 

1 

31 36 

31 36 

1 6 

1 

6 

1 6 

31 36 

31 36 

31 36 

6 

1 

31 36 

360 

300 

290 

260 

250 

6 

1 6 

1 

31 36 31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 6 

1 

31 36 

31 36 

6 

1 6 

31 36 

31 36 

1 6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

330 

310 

270 

240 

300 

260 

6 

1 6 

1 

31 36 31 36 

1 

6 

1 6 

31 36 

31 36 

6 

1 6 

1 

31 36 

31 36 

6 

1 

6 

1 

31 36 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

230 

330 

320 

270 

250 

310 

6 

1 6 

31 36 

6 

1 6 

1 6 

31 36 31 36 

6 

1 6 

1 6 

31 36 31 36 

1 6 

1 6 

1 6 

31 36 

1 6 

1 

31 36 

31 36 

1 6 

31 36 

6 

1 

31 36 

6 

1 

31 36 

31 36 

1 6 

1 6 

1 6 

1 6 

1 6 

1 6 

31 36 

6 

1 

31 36 

31 36 

1 

31 36 

31 36 

6 

1 

6 

1 

6 

31 36 

6 

1 

31 36 

6 

1 

31 36 

31 36 

31 36 

1 

6 

1 6 

31 36 

31 36 

6 

1 6 

1 6 

1 

1 6 

1 6 

1 6 

1 6 

1 

190 

240 

200 

290 

310 

280 

300 

180 

290 

160 

170 

190 

140 




T68 



Kilometres 

0 10 20 30 

T67 

0 10 20 

Miles 

T66 



Viking Structure 

T65 

By : laj Date : 2012/06/27 

Scale = 1:535000 Project : athbscstrct

T75 

T74 

T73 

T72 

T71 

Legend 

T70 

Viking Core 

Viking Producers 

Viking Focus Area 


WELL SYMBOLS 

D&A FG SG AGZ AG 

T69 

D&C AZN TH PBO PG 

PTG WD CMM ARE SBO 

36 

6 

6 

1 

1 6 

1 

1 6 

1 6 

31 

36 

1 6 

1 6 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

6 

1 

1 

31 

36 

31 

36 

6 

1 6 

1 

1 6 

31 36 

31 36 

31 36 

6 

1 

6 

1 

6 

1 

1 6 

1 

31 

36 

6 

1 6 

31 

36 

31 

36 

31 36 

31 36 

31 36 

6 

1 6 

1 

1 6 

31 36 

31 36 

31 36 

6 

1 

6 

1 

6 

1 

1 6 

1 

31 

36 

6 

1 6 

31 

36 

31 

36 

31 36 

31 36 

31 36 

1 

1 6 

1 6 

6 

1 6 

1 6 

1 

31 

36 

31 

36 

1 6 

1 6 

31 

36 

6 

1 6 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

1 6 

1 6 

6 

1 6 

1 

1 6 

1 6 

6 

1 6 

6 

1 

1 

31 36 

31 36 

31 36 

31 36 

31 36 

31 

36 

31 

36 

31 

36 

31 

36 

6 

1 6 

31 36 

31 36 

31 36 

1 6 

6 

1 6 

31 36 31 

31 36 

1 6 

1 6 

1 6 

1 

31 

31 

36 

36 

1 

1 6 

31 

36 

36 

1 

1 6 

1 6 

6 

1 6 

1 6 

1 

31 

36 

31 

36 

1 6 

1 6 

31 

36 

6 

1 6 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

6 

1 6 

1 6 

31 36 

31 36 

31 36 

6 

1 

6 

1 

6 

1 

1 6 

1 

31 

36 

1 6 

1 6 

31 

36 

31 

36 

31 36 

31 36 

31 36 

6 

1 6 

1 

31 36 

31 36 

31 36 

6 

1 6 

1 6 

1 

31 36 

31 36 

31 36 

6 

1 

6 

1 

1 

31 

31 

36 

6 

1 6 

31 

36 

R21 R20 R19 R18 R17 R16 R15 R14 R13W4 

LCT PO ARG AK SWD 

AO DRN SWI AWD FSW 

J&A WI SL 

Kilometres 

0 5 10 15 

T68 

0 5 10 

Miles 

T67 



Viking Formation 

T66 

By : kma Date : 2012/06/27 

Scale = 1:367000 Project : athbscfrmts 

6

360.0 

370.0 

Legend 

Grand Rapids Penetration Well 


270.0 

WELL SYMBOLS 







250.0 

1 

6 

1 6 

1 

31 36 31 36 

6 

1 

6 

1 6 

1 6 

1 6 

1 6 

1 6 

1 

6 

1 6 

1 

31 36 

6 

1 

31 36 

31 36 

400.0 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 31 36 

31 36 

390.0 

350.0 

380.0 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

1 

6 

1 6 

31 36 

31 36 

6 

1 

31 36 

6 

1 

31 36 

1 6 

1 

1 6 

31 36 

330.0 

6 

31 36 

6 

330.0 

320.0 

1 

310.0 

31 36 

6 

1 6 

31 36 

6 

31 36 

6 

31 36 

6 

1 6 

1 

31 36 31 36 

6 

1 6 

31 36 

6 

1 

31 36 

6 

1 6 

1 

31 36 31 36 

6 

31 36 

6 

31 36 31 36 

6 

31 36 31 36 

1 

1 

1 6 

31 36 

6 

1 

31 36 

6 

31 36 

1 

31 36 

31 36 31 36 

6 

1 6 

1 

31 36 31 36 

6 

1 6 

1 

31 36 31 36 

1 6 

1 6 

1 6 

1 6 

31 36 31 36 

6 

1 6 

1 6 

1 

1 6 

31 36 

1 

6 

1 6 

31 36 

31 36 

6 

1 6 

1 

31 36 

31 36 

1 6 

1 

6 

31 36 

31 36 

1 

6 

1 6 

31 36 

31 36 

1 

31 36 

6 

31 36 

1 6 

31 36 

1 6 

1 6 

1 

31 36 

6 

1 

31 36 

1 

6 

1 6 

31 36 

31 36 

6 

1 6 

1 

31 36 

31 36 

31 36 

6 

31 36 

31 36 

6 

31 36 

6 

1 

31 36 

6 

31 36 

31 36 

1 6 

1 

31 36 

31 36 

6 

1 

31 36 

1 

6 

1 6 

31 36 

31 36 

1 6 

1 6 

1 

1 

31 36 

6 

1 

6 

1 

31 36 

6 

1 

1 6 

31 36 

6 

1 6 

31 36 

31 36 

6 

1 

31 36 

6 

31 36 

31 36 

6 

1 

31 36 

31 36 

31 36 

1 6 

31 36 

1 6 

31 36 

1 6 

1 

1 

6 

1 6 

31 36 

31 36 

1 6 

1 

31 36 

6 

31 36 

1 6 

1 

1 

6 

1 

31 36 

6 

31 36 

1 6 

31 36 

1 6 

31 36 

31 36 

6 

1 6 

6 

1 

31 36 

1 

6 

1 6 

31 36 

31 36 

1 

6 

1 6 

31 36 

31 36 

1 

1 6 

1 6 

31 36 

31 36 

6 

31 36 

31 36 

1 

6 

1 6 

31 36 

31 36 

6 

31 36 

31 36 

6 

1 

31 36 

6 

1 

1 

1 

31 36 

31 36 

6 

31 36 

6 

1 

6 

6 

1 

31 36 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

31 36 

6 

1 

31 36 

31 36 

6 

1 

31 36 

31 36 

6 

1 

31 36 

31 36 

6 

1 6 

31 36 

1 6 

1 

1 6 

1 6 

1 6 

1 6 

1 

6 

1 

31 36 

1 

6 

1 6 

31 36 

31 36 

6 

1 

31 36 

1 6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

1 6 

1 

6 

1 6 

31 36 

31 36 

1 6 

31 

36 

6 

1 

31 36 

1 6 

31 36 

6 

1 

31 36 

330.0 

290.0 

320.0 

310.0 

300.0 

340.0 

400.0 

370.0 

390.0 

340.0 

380.0 

350.0 

390.0 

350.0 

370.0 

340.0 

340.0 

380.0 

370.0 

360.0 

350.0 

360.0 

340.0 

350.0 

6 

1 

31 36 

340.0 

330.0 

340.0 

300.0 

280.0 

350.0 

290.0 

6 

1 

31 36 

330.0 

280.0 

270.0 

340.0 

340.0 

320.0 

310.0 

300.0 

340.0 

320.0 

310.0 

270.0 

310.0 

300.0 

280.0 

290.0 

260.0 

250.0 

1 

31 36 

6 

1 

31 36 

310.0 

290.0 

300.0 

280.0 

270.0 

260.0 

290.0 

250.0 

240.0 

260.0 

230.0 

320.0 

240.0 

1 

6 

1 6 

31 36 

31 36 

1 

6 

1 

31 36 

240.0 

250.0 

310.0 

260.0 

240.0 

230.0 

220.0 

280.0 

220.0 

200.0 

260.0 

270.0 

270.0 

250.0 

220.0 

210.0 

190.0 

300.0 

250.0 

290.0 

290.0 

280.0 

240.0 

190.0 

180.0 

280.0 

270.0 

6 

1 

31 36 

230.0 

180.0 

160.0 

260.0 

270.0 

240.0 

190.0 

200.0 

270.0 

250.0 

240.0 

230.0 

140.0 

1 

220.0 

160.0 

31 36 

6 

200.0 

180.0 

170.0 

130.0 

120.0 

150.0 

140.0 

180.0 

160.0 


T77 

T76 

T75 

T74 

T73 

T72 

T71 

T70 

T69 

T68 

T67 

T66 

T65 


Kilometres 

0 10 20 30 

0 10 20 

Miles 



Grand Rapids Structure 

By : laj Date : 2012/06/27 

Scale = 1:545000 Project : athbscstrct 

C.I.: 10m

T75 

T74 

T73 

T72 

T71 

Legend 

Grand Rapids Core 

Grand Rapids Production 

Grand Rapids Oil Production 

Bypassed Grand Rapids: Net Pay >4.0m 

T70 

Grand Rapids Focus Area 


WELL SYMBOLS 

D&A FG SG AGZ AG 

T69 

D&C AZN TH PBO PG 

PTG WD CMM ARE SBO 

LCT PO ARG AK SWD 

36 

6 

6 

1 

1 6 

1 

1 6 

1 6 

31 

36 

1 6 

1 6 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

6 

1 

1 

31 

36 

31 

36 

6 

1 6 

1 

1 6 

31 36 

31 36 

31 36 

6 

1 6 

1 

1 6 

31 36 

31 36 

31 36 

1 

1 6 

6 

1 6 

31 

36 

31 

36 

31 

36 

6 

1 6 

1 

1 6 

31 36 

31 36 

31 36 

6 

1 6 

1 

1 6 

31 36 

31 36 

31 36 

6 

1 

6 

1 

6 

1 

31 

36 

31 

36 

31 

36 

6 

1 6 

1 6 

31 36 

31 36 

31 36 

6 

1 

6 

1 

6 

1 

1 6 

1 

31 

36 

1 6 

1 6 

31 

36 

31 

36 

31 36 

31 36 

31 36 

1 6 

1 6 

6 

1 6 

1 

1 6 

1 6 

6 

1 6 

6 

1 

1 

31 36 

31 36 

31 36 

31 36 

31 36 

31 

36 

31 36 

31 

36 

31 

36 

6 

1 6 

31 36 

31 36 

31 36 

1 6 

6 

1 6 

31 36 31 

31 36 

1 6 

1 6 

1 6 

1 

31 

36 31 

36 

1 

1 6 

31 

36 

36 

1 

1 6 

1 6 

6 

1 6 

1 6 

1 

31 

36 

31 

36 

1 6 

1 6 

31 

36 

6 

1 6 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

1 6 

1 

6 

1 6 

31 36 

31 36 

31 36 

6 

1 6 

1 

1 6 

31 36 

31 36 

31 36 

6 

1 

6 

1 

6 

1 

31 

36 

31 

36 

31 

36 

6 

1 6 

1 

31 36 

31 36 

31 36 

6 

1 6 

1 6 

1 

31 36 

31 36 

31 36 

6 

1 

6 

1 

1 

31 

31 

36 

6 

1 6 

31 

36 

R21 R20 R19 R18 R17 R16 R15 R14 R13W4 

AO DRN SWI AWD FSW 

J&A WI SL 

Kilometres 

0 5 10 15 

T68 

0 5 10 

Miles 

T67 



Grand Rapids Formation 

T66 

By : laj Date : 2012/06/27 

Scale = 1:375000 Project : athbscfrmts 

6

T77 

T76 

T75 

T74 

T73 

T72 

T71 

Legend 

T70 

Nisku Tops 

All Nisku Producers 

Current Nisku Producers 

Approximate Nisku Subcrop Edge 


T69 

WELL SYMBOLS 






T68 



Kilometres 

0 10 20 30 

T67 

0 10 20 

Miles 

T66 



Nisku Structure & Subcrop 

T65 

1 

By : laj Date : 2012/06/27 

Scale = 1:535000 Project : athbsc 

C.I.: 10m 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 31 36 

31 36 

1 6 

1 

1 6 

1 6 

6 

1 6 

31 36 

31 36 

31 36 

31 36 

31 36 

180 

80 

1 6 

1 

6 

1 6 

1 

6 

31 36 

31 36 

31 36 

31 36 

6 

1 6 

1 

31 36 31 36 

1 

6 

31 36 

160 

1 

140 

120 

1 6 

1 6 

1 6 

1 6 

1 6 

6 

1 6 

1 

6 

1 6 

1 

6 

1 

6 

1 6 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

100 

60 

40 

1 

1 6 

1 6 

1 6 

1 6 

1 6 

6 

1 6 

1 

100 

6 

1 

6 

120 

1 

1 6 

1 6 

6 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 31 36 

100 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

1 6 

1 

6 

31 36 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

1 

6 

31 36 

6 

1 6 

1 

31 36 31 36 

80 

140 

100 

120 

120 

6 

1 

6 

1 

6 

1 

1 6 

1 

31 36 

6 

1 

31 36 

31 36 

6 

1 

31 36 

31 36 

6 

1 

31 36 

31 36 

6 

1 

31 36 

6 

31 36 

1 6 

1 

1 6 

1 

6 

1 6 

1 

31 36 

31 36 

31 36 

31 36 

6 

1 6 

31 36 

1 

60 

6 

31 36 

6 

1 

31 36 

80 

40 

20 

0 

6 

1 6 

1 

6 

1 6 

1 

6 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

6 

1 6 

1 

31 36 31 36 

80 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

1 

31 36 

31 36 

6 

1 

6 

1 

31 36 

31 36 

1 6 

31 36 

6 

1 

31 36 

1 6 

31 36 

6 

1 

6 

1 

31 36 

31 36 

1 6 

1 6 

31 36 31 36 

6 

1 

31 36 

6 

1 

1 6 

31 36 

1 6 

6 

1 6 

31 36 

100 

60 

-40 

1 

6 

31 36 

31 36 

31 36 

31 36 

1 

6 

1 6 

31 36 

31 36 

40 

-20 

6 

1 6 

1 

31 36 31 36 

0 

6 

1 

-60 

20 

80 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

1 6 

1 

6 

1 6 

1 

6 

31 36 

31 36 

31 36 

31 36 

1 6 

1 

6 

1 6 

1 6 

31 36 

31 36 31 36 

31 36 

40 

6 

1 

31 36 

60 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

1 6 

1 

1 6 

6 

1 

1 6 

1 

1 6 

1 6 

1 6 

1 6 

31 36 

6 

31 36 

31 36 

31 36 

31 36 

6 

1 6 

31 36 

6 

1 

31 36 

6 

1 

31 36 

0 

-20 

-40 

20 

-60 

1 

1 6 

1 6 

1 6 

1 6 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

31 36 

1 6 

31 36 

1 6 

31 36 

-80 

6 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

31 36 

6 

1 

1 

6 

60 

31 36 

31 36 

1 6 

1 

31 36 

1 6 

1 6 

1 6 

1 6 

6 

31 36 

31 36 

31 36 31 36 

31 36 

40 

20 

-100 

0 

6 

1 6 

1 6 

1 

1 6 

1 6 

1 6 

1 6 

1 6 

1 6 

6 

1 6 

6 

1 

R22 R21 R20 R19 R18 R17 R16 R15 R14 R13 R12 R11W4

102/07-27-072-18W4/00 

Talisman Enrg Inc 

+593.8 

Direton D&A 

1989/02/15 

BVI CALLING LAKE 7-27-72-18 

425 

Kwabiskaw 

Kmcmurray 

Dnisku 

6% Porsity Cutoff LS 

450 

Direton 

475 

TD 493.0m 

1:480 



Nisku Type Log - 

102/07-27-072-18W4/00 

By : laj Date : 2012/06/27 

Scale = 1:480 Datum : Sea Level 

Interval : Screen Display

Depth 

Depth 

Porosity 

Porosity 

0.4 0.0 

Permeability 

K-Vert 

0.01 3000 

K-90 

0.01 3000 

K-Max 

0.01 3000 

0.01 0.1 1.0 10 100 1000 

Density 

Grn Den 

2200 3000 

Blk Den 

2200 3000 

Bulk Mass 

Blk Mass Snd 

0.0 1.0 

Blk Mass Wtr 

1.0 0.0 

Blk Mass Oil 

0.0 1.0 

Grain Mass 

Grn Mass Wtr 

1.0 0.0 

Grn Mass Oil 

0.0 1.0 

Pore Volume 

Por Vol Wtr 

1.0 0.0 

Por Vol Oil 

0.0 1.0 

Blk Volume 

Blk Vol Wtr 

1.0 0.0 

Blk Vol Oil 

0.0 1.0 

Lithology 

Lithology 

450 

452 

454 

456 

458 

460 

462 

464 

466 



Nisku Core Chart 

102/07-27-072-18W4/00 

By : Oil Reserve Inc. 

Project : ath cre 

Date : 2012/06/27

T74 

6 

1 

6 

1 

6 

1 

6 

1 

6 

1 

31 

36 

31 

36 

31 

36 

31 

36 

31 

36 

T73 

6 

1 

6 

1 

6 

1 

6 

1 

6 

1 

31 

36 

31 

36 

31 

36 

31 

36 

31 

36 

T72 

6 

1 

6 

1 

6 

1 

6 

1 

6 

1 

31 

36 

31 

36 

31 

36 

31 

36 

31 

36 

Legend 

T71 

Nisku Tops 

Wells included in Prospective 

Area Assessment 

Type Log Well 

Approximate Nisku Subcrop Edge 


6 

31 

1 

6 

36 

31 

1 

6 

36 

31 

1 

6 

36 

31 

1 

6 

36 

31 

1 

36 

WELL SYMBOLS 

D&A FG SG D&C AG 

AZN AGZ PBO TH PTG 

PG LCT SBO WD CMM 

ARE J&A SWD CLG ARG 

SL 

T70 

Kilometres 

0 5 10 15 

6 

1 

6 

1 

6 

1 

6 

1 

6 

1 

0 5 10 

Miles 

31 

36 31 

36 31 

36 31 

36 31 

R20 R19 R18 R17 R16W4 

36 

T69 



Prospective Area Assessment 

By : laj Date : 2012/06/27 

Scale = 1:210000 Project : athbsc2

A 

100/07-23-072-20W4/00 

Husky Oil Oprtns Ltd +619.3 

Dwintrbrn D&A 

1991/01/09 

RENAISSANCE CALLW 7-23-72-20 

 

100/09-09-072-19W4/00 


Kmcmurray D&A 

2002/12/13 

HUSKY CALLING LAKE WEST 9-9-72-19 

 

100/09-09-072-18W4/00 


Kmcmurray AG 

1995/11/28 Kmcmurray 

RENAISSANCE CALLING LAKE 9-9-72-18 

 

100/08-27-071-18W4/00 


Kwabiskaw D&A 

1996/01/09 


 

100/07-07-071-17W4/00 


Dnisku D&A 

1996/01/09 


A' 

250 

Kbfs 

225 

Kbfs 

225 

Kbfs 

225 

Kviking 

Kbfs 

250 

Kvik_ss 

250 

Kviking 

275 

Kviking 

250 

Kvik_ss 

Kvik_ss 

Kviking 

250 

Kvik_ss 

275 

275 

Kvik_ss 

300 

Kjoli_fou 

275 

Kjoli_fou 

275 

Kjoli_fou 

300 

Kjoli_fou 

Kjoli_fou 

325 

Kgrand_rp 

300 

300 

Kgrand_rp 

Kgrand_rp 

300 

Kgrand_rp 

Kgrand_rp 

325 

325 

350 

325 



Viking Structural X-Section A-A’ 

1:480 

By : laj Date : 2012/06/27 

Datum : Sea Level Scale = 1:480 


A 

100/15-19-073-19W4/00 


Kgrand_rp PBO 

2008/01/09 Kgrand_rp 

HUSKY CHERPETA 15-19-73-19 

 

100/12-20-073-19W4/00 


Kgrand_rp PBO 

2011/05/25 

Kgrand_rp 

HUSKY CHERPETA 12-20-73-19 

 

100/11-23-069-15W4/00 

Chinook Enrg Inc +562.9 

Kmcmurray SG 

1996/10/02 Kgrand_rp 

TALISMAN CHARRON 11-23-69-15 

A' 

375 

375 

Kjoli_fou 

250 

Kgrand_rp 

Kgrand_rp 

A 

400 

400 

Kgrand_rp 

275 

A’ 

TD 419.0m 

425 

300 

TVD 446.6m 

325 

Kgrd_rp_L 

1:480 



Grand Rapids Structural 

X-Section A-A’ 

By : laj Date : 2012/06/27 

Scale = 1:480

Athabasca Viking/Grand Rapids/Nisku Technical ... - Oil Reserve Inc.

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