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Alkaline-Surfactant-Polymer (ASP) Flooding in Alberta

QI: The Future of Geophysics

Interval NameStratigraphic NameSta

geE

ra

Belly River

Cretaceous

Upper

Lower

Upper

Middle

LowerJurassic

Triassic

Middle

Upper

Lower

Cardium

Viking

Ellis

Grou

p Swift

Sawtooth

Nordegg

Charlie LakeHalfwayDoig

TurnerValley

Keg River

Beaverhill

Lake

Gp

SwanHills

Slave PointFt. Vermilion

Waterways

Gilwood

Muskeg

Contact Rapids

Rund

leGp Debolt

Elkton

Banff

Pekisko

Shunda

Exshaw

WabamunCrossfield

Blueridge

Nisku

Winter-

burn

Ireton

Leduc

Duvernay

Majeau Lk.Cooking Lk.

Leducreef

WoodbendGp

ElkPointGp

Cold Lake

Lotsberg

Mississipp

ian Upper

Lower

Devon

ian

Upper

Middle

Colorado

Group

Montney

2nd White Specks

Upper Mannville

Lower MannvilleMannvilleGroup

Bluesky / GlauconiticWilrich

Belly River

Cardium

2nd White Specks

Viking

U. MannvilleWilrichBluesky/GlauconiticL. Mannville

Jurassic

Nordegg

Charlie LakeHalfwayDoigMontney

Mississippian

BanffBakken/ExshawWabamunWinterburn

WoodbendDuvernay/Muskwa

Beaverhill Lake

Elk Point

Pre-Devonian

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Deep-Cut YieldA

SP

Flooding in Alberta

QI: The Future of G

eophysics

explora t ion review

AlkAline-SurfActAnt-Polymer (ASP) flooding in AlbertASmall Amounts of the Right Chemicals Can Make a Big Differenceby Marc Charest, M.Sc., P.Geol., Senior Exploration Analyst

Much of the oil and gas industry, particularly in North America, is currently focused on investing money, time and effort in maximizing hydrocarbon extraction from shales and other tight rock resource plays, largely thanks to long-reach horizontal drilling and multi-phase completion technology. There remains, however, incredibly large volumes of known “residual” oil resources in countless “conventional” reservoirs. Secondary recovery methods, like waterflooding, have been proving their worth in extracting incremental oil for decades in fields the world over. Now tertiary methods, or enhanced oil recovery (EOR) schemes, are increasingly making their mark in extracting more resources from conventional reservoirs. Alkali-Sur-factant-Polymer (ASP) chemical flooding, which is one of these methods, has been applied in many parts of the world (e.g. Alberta, Saskatchewan, Wyoming, China and India) for over 20 years. The objective of this Canadian Discovery Digest review is to focus on some recent Alberta ASP schemes and the geological contexts in which they are situated.

20 VOLUME 1 2013 CANADIAN DISCOVERY DIGEST

EXPLORATION REVIEW

Photo overleafLooking from west to east at the Zargon Little Bow gas plant/oil battery . The water injection facility is in the middle and right foreground. The larger blue building on the left, east of the water injection facility is the gas plant. Photo courtesy Zargon oil & gas ltd.

Enhanced Oil Recovery (EOR)

Enhanced oil recovery (EOR) is a self-explanatory term, also known as improved oil recovery or tertiary recovery. In the US, EOR accounts for about 13% of total US annual oil production (Green Car Congress, April 2012). Primary recovery of oil occurs as a result of oil naturally flowing to surface through a wellbore due to pressure. This pressure may be caused by the expansion of solution gas/associated gas cap and/or the upward migration of a water-oil interface as oil is produced. Artificial lift of oil through devices such as pump jacks also falls under primary production, as does cold heavy oil production with sand (CHOPS). Secondary recovery goes a step further, involving the localized injection of water or gas (including CO2, N2, hydrocarbon gases) or the large-scale flooding of the reservoir with water, which physically pushes out residual oil. This operation results in reservoir pressure maintenance that continues to move oil to the surface. A reservoir may be subjected to water or gas injection from the beginning of its productive life, in order to maintain pressure and effectively maximize oil production rates and recovery. Together, however, both primary and secondary recovery phases may only ultimately recover a small fraction of the original oil-in-place (OOIP) or petroleum initially in place (PIIP), a figure that varies depending on a number of reservoir properties. For example, the two production stages “can leave up to 75% of the oil in the [ground]” (http://www.rigzone.com/). Another source (California Energy Commission - http://www.energy.ca.gov/) states that primary and secondary methods can recover 20 to 40% of OOIP. In any case, significant proven oil often remains in the reservoir.

Tertiary recovery, or enhanced oil recovery (EOR), is just that: an attempt to economically squeeze out additional increments of residual oil from the reservoirs. Tertiary methods are divided into thermal and non-thermal. Many tertiary methods will actually change physical/chemical properties of the reservoir and its hydrocarbons, principally through the addition of heat, gas (principally CO2) or chemicals (or even micro-organ-isms). These changes often imply lowering the viscosity of the

residual oil and thereby improving its flow into the borehole. EOR may also be applied at the initial stages of production. Thermal tertiary methods involve the injection of steam (most widely applied) or hot water, mostly in heavier crudes or bitumen in Canada. Fire flooding, or in-situ combustion through the injection of air or oxygen, is another thermal method the object of which is to reduce oil viscosity, but which may also crack some of the higher molecular weight oils into smaller more easily moveable molecules. Tertiary gas injection technology (a non-thermal method) usually involves carbon dioxide (CO2), which is injected under supercritical (pressure + temperature) fluid conditions, and thus acts like a liquid to displace residual light oils by mixing with them (miscible flood). Nitrogen (N2) and hydrocarbon gases have also been used in miscible oil displacement. Finally, chemical injection introduces various compounds, usually as dilute solutions. For example, the addition of long-molecular chained water-soluble polymers can increase the efficiency of a traditional waterflood by increasing the viscosity of the injected water, which in turn leads to a more efficient displacement of the oil. Less than 1% of all EOR methods used in the US are chemical injections (http://www.rigzone.com/), chiefly due to costs. But consistently high oil prices and better technology are changing the equation.

Chemical Injection in EOR

Largely because of high costs, tertiary chemical injection methods are not used as much, or on as large a scale as other EOR methods. A host of chemicals, individually or in various combinations, can be introduced or flooded into the reservoir, in an effort to move and extract more oil. These chemicals include water-soluble polymers, polymer gels, surfactants (natural or artificial), alkalis, and combinations of these, which in turn include alkali-polymer (AP), surfactant-poly-mer and alkali-surfactant-polymer (ASP). The objectives of these chemical additions are to increase volumetric efficiency (area times thickness of pay zone) and displacement efficiency in the reservoir.

WWW.CANADIANDISCOVERY.COM 21

ASP FLOODS IN ALBERTA

Of course, a proposed EOR project may not be viable for economic reasons. A myriad of factors and variables must be taken into account. For example, surfactants and polymers are very expensive. Also, drilling new wells for a chemical injection project instead of using existing wells may not be cost effective.

Oil recovery by injection is a function of: Ea x Ev x Ed

where,

Ea = Areal sweep efficiencyEv = Vertical sweep efficiency Ed = Displacement efficiency

The product of areal and vertical sweep efficiency (Ea x Ev) is referred to as Volumetric Conformance. It is the fraction of the reservoir volume that is contacted by the injected fluid.

Vertical sweep efficiency is generally a function of rock property variations between different reservoir layers (high permeability layers will take more of the injected fluid, generally leading to a lower vertical sweep efficiency). Areal sweep efficiency is influenced by permeability trends, pressure distribution, differences in the viscosity of injected and displace fluids, relative permeability effects etc. (thanks are due to engineering leadership at Zargon Oil & Gas [TSX: ZAR] for additional information on volumetric conformance).

Interactions between the introduced chemicals, and between these chemicals and reservoir components can be very complex and can even, if not done carefully and knowledgeably, result in more harm than good, or less than anticipated oil recovery results. At the very low concentrations used in an ASP flood, the chemicals are not toxic to the environment.

A surfactant (surface active agent) is defined, in brief, as a substance, which when used in very low concentrations, can greatly reduce the surface tension of water. Surfactants have been used for EOR for over 80 years. Foaming agents, emulsifiers and dispersants are surfactants, which suspend, respectively, a gas, an immiscible liquid and a solid in liquid (water or other liquid) - http://www.chemistry.co.nz/surfactants.htm. For example, Softanol 90™ (polyoxyethylene or polyoxy-ethylenealkylether), a common surfactant agent with multiple

applications, in an extremely small concentration (0.005%) can reduce the surface tension of pure water from 73 dyne per centimetre (dyn/cm), or 73 E3N/m in SI units, to just 30 dyn/cm (30 E3N/m). In contrast, ethanol at a concentration of 40% would be required to obtain the same reduction in surface tension (http://www.chemistry.co.nz/surfactants.htm). The chemical formula for Softanol 90™ is :

where,

n + m = 9~11, x = 3-20 (average = 9)

A non-ionic ethoxylate (see below), thus without an electrical charge, Softanol 90™ is liquid at 25°C and its pour point is 8°C. It is soluble in hydrocarbons, but only poorly soluble in water.

In a system with water and oil, a surfactant will reduce the interfacial tension between the two liquid phases, which “liberates” residual oil held by capillary forces, i. e. a reduction of capillary pressure in the reservoir, leaving it water-wet. This “liberated” oil can now be more easily mobilized and produced. (http://www.chemistry.co.nz/surfactants.htm).

Surfactant molecules are composed of a hydrophobic (water insoluble) non-polar component at one end, which will “latch on” to oil hydrocarbons (oleophilic), and a hydrophilic (water soluble), polar component at the opposite end of the molecule ( schematic page 22). Surfactants can be of natural origin (oleochemicals) or synthesized from petroleum (petrochemicals). The nature of the hydrophilic portion of the molecule yields the primary classification of surfactants, which are anionic, cationic or non-ionic. In all cases, the hydrophilic end of each surfactant molecule is strongly attracted to the water molecule (a dipolar molecule) at the water surface or inside the water volume, while the hydrophobic end orients itself or is squeezed away from the water.

“Many light oils do not contain sufficient amounts of the components that react with alkali to reduce the oil-water interfacial tension sufficiently to overcome capillary forces trapping the oil. Blending [a small quantity of – 0.05% to 0.5%] surfactant with the alkali overcomes this barrier.”

EXPLORATION REVIEW

Hydrophobe

A surfactant molecule is made up of a water soluble (hydrophilic)and a water insoluble (hydrophobic) component.

Schematic of surfactant molecules in water

The internal group of surfactant molecules is referred to as a micelle (m).

Hydrophile

SchemAtic of SurfActAnt moleculeS in wAterFrom http://www.chemistry.co.nz/surfactants.htm

(US-based chemical EOR firm Surtek http://www.surtek.com/technologies/alkalisurfactantpolymer.html).

The use of alkali in a chemical flood is beneficial in many ways and has been used for over 80 years. Alkali significantly reduces the absorption of the surfactant on the reservoir rock. It also forms in-situ surfactant by reacting with acidic components of the oil. In addition, alkali makes the reservoir rock more water-wet. Finally, alkali is relatively inexpensive. Common alkaline agents include sodium hydroxide (NaOH, or caustic soda) and sodium carbonate (Na2CO3, or soda ash) at low concentrations, usually < 2% (http://www.surtek.com/technologies/). Softened injection water is required in ASP and AP flooding, i.e. very low concentrations of divalent cations (hardness) such as Ca+2 and Mg+2. Otherwise, these cations react with the alkali agent and form a precipitate (e.g. hydroxides), which could plug the pores of most reservoirs (http://www.surtek.com/technologies/). Higher salinity of the water phase can also be undesirable; it can decrease the solubility of surfactant molecules in the water. In essence, the alkali, usually caustic soda, reacts with components present in some oil to form soap. That process is called saponification, which in the right environment reduces the interfacial tension enough to overcome capillary forces retaining the oil.

Finally, adding a polymer to flood water is aimed at improving the volumetric sweep efficiency of the reservoir (i.e. increasing the volume of the reservoir contacted). Water-soluble polymers are also known as viscosifiers as they seek, at relatively low concentrations (measured in parts per million or ppm), to significantly increase the viscosity of the injected water and thus lower the mobility ratio (M) for displacing oil. That mobility ratio is defined as the mobility of the injected fluid over that of the reservoir oil, where, in turn, mobility is the ratio of relative permeability over viscosity. By increasing the viscosity of the injected fluid through the addition of a small volume of polymer, the mobility ratio will be lowered and the sweep efficiencies, both vertical and areal, will be increased. This relationship has been shown experimentally (Habermann [1960], cited in http://www.belgravecorp.com/chemical-in-jection : Calgary-based EOR technology firm Belgrave Oil and Gas), where, in a quarter of a five-point well pattern at higher M values, “viscous fingers” of injected fluid developed leaving large bypassed oil volumes at breakthrough in the producing well ( schematic opposite page). Ideally, a mobility ratio of about one or less “is considered favourable”. To be effective, polymers, which are non-toxic and non-corrosive, must remain stable for a long time at reservoir conditions. The two most frequently used polymers in polymer flooding



P.V. P.V. P.V.

0.7 B.T.

B.T. B.T. B.T.

B.T. B.T.

0.1

M = 0.151

M = 4.58 M = 17.3 M = 71.5

M = 1.0 M = 2.40

0.2

0.3

0.10.2

0.050.15

0.3

0.50.6

0.2

0.3

0.050.1

0.20.3

0.050.1

0.40.5

A B C

D E FX

X X X

X X

X

diSPlAcement frontS for different mobility rAtioS And injected Pore volumeS until breAkthrough

From Habermann (1960) in: http://www.belgravecorp.com/chemical-injection

P.V. = Injected Pore Volume M = Mobility ratio

B.T. = Breakthrough Areas: quarters of five-spot patterns

Producing Well

Injection WellX

are polysaccharide biopolymers and synthetic polyacryl-amides (http://www.belgravecorp.com/chemical-injection).

Alkaline-Surfactant-Polymer (ASP) Flooding

Alkaline-Surfactant-Polymer flooding, or ASP flooding, is a relatively new and still evolving chemical enhanced oil recovery technology. The process was developed in the early 1980s as a lower-cost alternative to micellar/surfactant/polymer flooding (Belgrave website). In essence, a predetermined volume or slug mixture of ASP is injected into the reservoir, often followed by an additional injection or “push” of polymer, which help to reduce the slope of the oil production decline and thus extends the production period (Denver-based EOR products and services firm TIORCO: http://www.tiorco.com/tio/products/asp-sp.htm). Regular waterflooding then

resumes. The three, generally non-toxic (in dilute solution) chemicals act together, or synergistically, to effectively sweep more petroleum than if they were used as lone components. Stated another way, “the ASP chemicals reduce interfacial tension and scrub the reservoir, releasing some of the oil which remains locked in the reservoir after waterflooding.” (Zargon Oil & Gas website; the company’s ASP project at Little Bow is discussed below). As intimated above in the description of individual ASP phase components, only small percentages of each additive are necessary to effectively carry out the sweep; the formulation “typically consists of about 0.5-1% alkali, 0.1% surfactant and 0.1% polymer.” (http://www.tiorco.com/tio/products/asp-sp.htm).


EXPLORATION REVIEW

ASP chemicAl flooding recoverS byPASSed oilFrom Zargon website, December 2012

Polymer “thickens” the injected fluid to increase the volume of reservoir contacted.

Injector Producer

WaterWater

Injector Producer

PolymerSolution

IncreasedContactVolume

PolymerSolution

IncreasedContactVolume

a) Water Injection b) Polymer Injection

RockRock

a) Water Injection:More than half of oil is “trapped”

b) Alkali / SurfactantMobilizes trapped oil

Alkali and Surfactant act together to mobilize oil trapped in the reservoir. The injected fluids must contact the trapped oil to be effective.

Water Injection

TrappedOil

Water

RockRock

Mobilized Oil

Alkali & SurfactantSolution

A schematic diagram from Zargon’s website illustrates the process of ASP chemical flooding ( below). Another generic diagram, from EOR chemical services firm Surtek (http://www.surtek.com/technologies/ ), demonstrates possible effects of waterflood and ASP on residual oil production ( schematic opposite page).

Conceptually, ASP technology is relatively simple, but it can be very complicated in design and application. Field implementation of an ASP flood, as with other EOR projects, requires in-depth research and testing in the laboratory, which of course adds to the bottom line. An “integrated approach” to this application also includes reservoir engineering and geological studies, numerical simulations, facilities design, and ongoing monitoring. “Typical implementation of (A)SP in the field (pilot scale) take about 3-4 years.” (http://www.tiorco.com/tio/products/asp-sp.htm). The currently sustained high commodity price environment likely helps in the go-ahead decision for many EOR projects, but it can

happen that a proper ASP formulation or “recipe” cannot be achieved to procure sufficient oil displacement for a given reservoir to be economically viable (http://www.belgravecorp.com/chemical-injection).

Alkaline-Surfactant-Polymer (ASP) Flood

Technology in Alberta

The Alberta government announced, in June 2004, the Innovative Energy Technologies Program (IETP), to which it is committing $200 million in terms of royalty adjustments (Alberta Energy website, http://www.energy.gov.ab.ca/1797.asp). The principal objective of the IETP is to invest in research, technology and innovation that creates commercial value while achieving high environmental standards. Specifically, innovative pilot or demonstration projects, which are responsibly and efficiently used to achieve increased recoveries of existing petroleum and natural gas reserves (including in-situ bitumen resources), can be assisted by this fund. So far (December 2012), 37 projects (33 projects counted in the list published by Alberta



effectS of wAterflood And ASP flood on oil recoveryFrom Surtek Website

SURTEK

Mechanisms

Ultimate Residual Oil

Oil Bank

Waterflood Residual Oil

ASP

Poly

mer

Wat

er

Wat

er

Injection Production

Energy) have been approved and announced since 2005, in five “rounds” of applications; a sixth round closed at the end of September 2011 (Alberta Energy website). Assuming full subscription to IETP, government and industry may commit over $800 million to new technologies. Industry participants in the program are required to submit an annual progress report on their respective project(s) by the end of June of each year. By the end of December 2012, annual and final reports for 2009 were publicly available, as later reports submitted to Alberta Energy remain confidential for two years. 2010 reports, which were submitted by June 30, 2011, will be released in 2013.

Among approved IETP projects, two are Alkaline-Surfactant-Polymer (ASP) flood schemes. These projects are summarized in a table( top of page 27). The link to Alberta Energy’s compilation of IETP reports and other program information is: http://www.energy.gov.ab.ca/768.asp. There are several

ASP project schemes, which are approved or in progress toward approval in Alberta ( map page 26) Three of these schemes, at Taber South (Warner) and Little Bow in southern Alberta, and at Mooney in Northern Alberta, were selected for examination in this review. In addition, a polymer flood at Seal in northern Alberta was examined.

Husky Energy ASP at Taber South Mannville B Pool

The Taber South Mannville B Pool (T. 7, R. 16W4) was discovered 50 years ago, in 1963, in a vertical well drilled by Canadian Pacific Oil & Gas (now Encana – TSX, NYSE: ECA) at 16-20-7-16W4, which was drilled 1,038m to the Mississippian Madison Group. The well was completed in the Cretaceous Sunburst Member (Mannville Group), as were most later wells in the Mannville B Pool (the other producing zones in the same pool are listed as Mannville and, more rarely, Glauconitic sandstone). Initially, ~ 4m in the upper part of the reservoir were completed (perforation)


EXPLORATION REVIEW

cAnAdiAn ASP ProjectSFrom Zargon, January 2013

Edmonton

Lethbridge

Calgary

Medicine Hat

Grande Prairie Mooney(BlackPearl)

July 2011Bluesky A

Little Bow (Zargon)Mannville I & P

Strathmore(Terrex)

Suffield(Cenovus)Apr. 2007

Taber South (Husky)May 2006

Mannville B

Grand Forks(CNRL)

Instow(Talisman)2007/11

Gull Lake(Husky)

2009

Battrum(Hyak Energy)

Fosterton(Husky)

Bone Creek(Husky)

Coleville(Penn West)Feb. 2011

Taber (Husky)Jan 2008

Glauconitic K

T83, R15W5 Seal (Murphy)Oct 2010BlueskyPolymer floodpilot in progress

*

*

Alberta Saskatchewan

In Progress Scheme Approved

in the well; then, an additional ~ 6m, located below, were completed (perforation + acid squeeze) about 3.5 years later; finally, more acidizing + fracturing of the whole ~10m interval was performed in 1970. In all, ~10m of the total 15m gross thickness of the clean, blocky (cored; no analysis) reservoir interval, which lies unconformably on the Jurassic Rierdon shale, were completed. Since going on stream in January 1967, and to August 2012, the 16-20 discovery well has produced 208.0 E3M3 (1.31 million barrels) of oil and only 3,633 E3M3 (129 mmcf) of gas. Also, 2,251.0 E3M3 (14.2 million barrels) of water were produced. Water influx in the well, which started in July 1970, was high almost from the onset. No apparent bottom-water leg was seen in logs; the

two nearest water injectors did not begin injecting until much later, in 1997 and 2006, respectively.

From April 1963 to August 2012, the Mannville B Pool (78 oil wells/32 injection wells) accumulated 3,171 E3M3 (20.0 million barrels) of medium to heavy 19.4°API crude, 28,117 E3M3 (177.0 million barrels) of water and 57.8 E6M3 (2.0 bcf) of sweet solution gas. The Mannville B Pool has been under water injection since the beginning of production, and has responded well to that secondary scheme.

International integrated major Husky Energy (TSX: HSE), which operates (100%) the Mannville B Pool, is about 70% oil-weighted in terms of production. At its foundation, the



AlbertA ietP AlkAline-SurfActAnt-Polymer flood (ASP) ProjectSFrom Alberta Energy website, January 2013

Project nameProject #

(Alberta energy)operator

year Approved

last year report Avail.

year completed

comments

Taber S Mannville B Warner ASP Flood

01-023Husky Oil Operations

2005 2009 -Implemented May 2006

Taber Glauconitic K Advanced ASP Process Process (Crowsnest)

03-055Husky Oil Operations

2008? 2009 -Implemented January 2008

bASic reServoir ProPertieS, tAber South, mAnnville b PoolFrom Husky Oil, IETP Annual Report 2005 (June 2006)

Formation Glauconite Initial Pressure 9,950 kPa

Lithology Sandstone Current Pressure (2006) 9.000 kPa

Mean Depth 985m TVD Bubble Point 4,606 kPa

Porosity 24% Reservoir Temperature 35°C

Permeability >1,000 mD API Gravity 19.1°

Swi 18% Oil Viscosity 40 cp (at res. temp.)

Avg. Net Pay 7.1m Rsi 16.7 M3/M3

Primary Drive Fluid Expansion PVF 1.05 RM3/SM3

Secondary Drive (current) Waterflooding

company has a vast historic asset base in western Canada, consisting especially of significant heavy oil production and facilities. “Growth Pillars” for Husky are in oil sands, the Canadian Atlantic region and the Asia-Pacific region.

In western Canada, in addition to heavy oil (Cretaceous clastics and Upper Devonian carbonates), oil sands and resource plays, the company has important conventional oil and gas properties, from which it seeks to maximize hydrocarbon extraction and recovery, especially oil, by “evaluating enhanced recovery options”. Toward that goal, Husky is applying “enhanced recovery techniques such as alkaline surfactant polymer (ASP) floods” (Husky website).

Husky implemented the first “field-wide ASP flood” in Canada in May 2006. Information about this EOR scheme was obtained largely through the company’s participation in Alberta Energy’s IEPT (see above and http://www.energy.gov.ab.ca/768.asp). The report for calendar year 2009 is the latest information available as of mid-September 2012. In its first annual report to Alberta Energy about its Taber South ASP scheme, which was submitted in June 2006, the company said that it expected to recover 1,003 E3M3 (6.31 million barrels) of incremental oil from the Taber South Mannville B Pool (a.k.a Warner ASP Project – the actual Warner Field is

centred on T. 4-5, R. 18-19W4), an incremental volume which is equivalent to 14.5% of the original oil-in-place (OOIP). Husky anticipated using, in its Warner project, existing well bores (as much as possible) in areas of higher residual oil volumes, at the same time optimizing the placement of ASP flooding. Much work had to be coordinated and performed by the operator on existing wells (including clean-outs, reactivations and conversions to obtain the desired injector/producer pattern) and facilities (including pipeline clean-out/replacement) in this old oil pool, to ready it for ASP flooding. A few new injectors/producers were also drilled (seven in all, initially, focused on sections 16 and 21-7-16W4, which have highest reservoir quality/OOIP). The spacing and pattern is a combination of peripheral injection and a modified line drive. This injector strategy is preferred in this reservoir, which has a high vertical to horizontal permeability ratio (Kv/Kh) ratio. In addition, previous injectors situated in structurally high positions were converted to producers, to take advantage of gravity effects (Alberta Energy, 2005-2012: Husky 2005 report). A map ( page 28) shows the distribution of ASP injectors and producers. Initially, injector wells were divided into four groups (A to D) to better meet injection targets in the four regions of the project reservoir area, which are defined as each having about equal pore volume. In the 2009 report (submitted June 25, 2010), the Mannville B Pool is divided


EXPLORATION REVIEW

tAber South (wArner) mAnnville b Activity From Husky IETP Application 01-023 Annual Report 2005,

Attachment 6: Injectors and Producers, 2005-2006 ASP Flood

Base map generated with AccuMap ™

Injector drilled to counter “most severe reduction in injectivity” in Area 2, in 10m pay (2009 Report). In contrast, Areas 3, 4 and 5 had the best injectivity, recovery rates (>10%) and voidage replacement ratios (VRR) (2009 Report).

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Section 4:Poor

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Injector Group A

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Injector Group B0/2-163/7-160/14-16

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re-drill(2009)

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into seven groups or areas (1 through 7), from south to north, to allow for easier monitoring of chemical response as well as to help balance voidage replacement and pore volume injected (Alberta Energy, 2005-2012: Husky 2009 report).

In its 2005 annual IETP report (June 30, 2006), Husky mentions that the 45 wells, which are producing and 18 injector wells (all vertical or directional completions), are contained within an area spanning about four sections ( map opposite page) of the Mannville B Pool.

A table ( bottom page 27) summarizes the pool’s principal reservoir properties, as compiled in Husky’s first annual IETP project report (2005 - submitted June 2006).

Also listed in the 2005 report are the components of the ASP solution for the Mannville B Pool (note the very small quantities required). These proportions, or ASP system, were obtained through lab testing conducted by Colorado-based Surtek (http://www.surtek.com/home.html ) in May 2005:

• Alkali: 0.75 weight % sodium hydroxide (NaOH),

• Surfactant: 0.15 weight % ORS-97HF (a petroleum-based ASP surfactant - di or mono alkyl aryl sulfonate structure, manufactured by Oil Chem Technologies, http://www.oil-chem.com/msds.htm),

• Polymer: 1,200 ppm Flopaam 3630 (“conventional” polymer, produced by private giant SNF Floeger - http://www.snf-oil.com/SNF-s-presentation.html ), which is blended in softened formation water produced from 0/4-20-7-16W4 - no water analysis (see below).

Project costs had increased significantly between when the EUB (now the ERCB) injection applications were approved in September 2005, and May 2006, when injection began.

Produced water from the oil battery at 4-20-7-16W4, which is used as a water source, is transported by pipeline to the Etzikom Creek 6-13-6-17W4 Alkali-Surfactant-Polymer (ASP) blending plant, where it is first filtered and softened before the ASP chemicals are added. However, the May 2005 Surtek lab report states that the total dissolved solids for samples of both produced and injected water were similar

and rather low, each bordering on soft water, at 5,070 mg/L and 4,405 mg/L, respectively. Furthermore, “hardness is low for both waters with a total divalent cation [Ca + Mg] content of [30 mg/L and 70 mg/L, respectively]”, which means that “softening requirements for the injection water should be minimal” (Surtek, 2005). Softening the formation water created a buffer between the hard water and the NaOH (alkali) in the ASP solution, with the goal of preventing obstructing precipitate from forming at perforation sites. In addition, as mentioned by Surtek in its report, the presence of Ca and Mg ions “is intolerable for many surfactants, greatly reduces the polymer solution viscosity, and accelerates the rate of polymer degradation.”. No CaCO3 precipitate or sulphate scaling was expected to form out of either produced or injected water compositions, according to Surtek (see Husky’s 2009 Report discussion, below).

The ASP solution is sent by pipeline to the 11-16-7-16W4 injection satellite in the ASP Flood area, from where it is distributed to the project injector wells (18, as counted in September 2012), which were initially (2005-2006) distributed among four project regions of approximately equal pore volume, each having a pump with 900 M3/d injection capacity. The ASP injection began on May 17, 2006. In that month, total Mannville B Pool oil production was 60 M3/d of oil (376 bopd) and water production was 3,525 M3/d (22,183 bpd) (IHS data). The ASP injection target at the time was 3,600 M3/d (22,643 barrels/d) of solution. ASP injection was planned for two years, from May 2006 to June 2008 (end of ASP injection later extended to October 2008 – see below). After that, and until September 2010, the injection of polymer alone was anticipated (Husky IETP 2005 Annual report); polymer injection was later extended to the end of 2012 (Husky IETP 2009 Annual report).

A Summer 2010 investor presentation by junior Pacific Paradym (TSX-V: PPE) mentions that a small Taber Glauconite “consistently clean and highly porous and permeable” mature reservoir (2m-5m pay) centred around sec. 24-10-16W4 (Taber Glauconite D), which is under primary production with an oil gravity of 27°API, is being explored for “tertiary recovery opportunities with ASP” (March 2012) with partner Strategic Oil & Gas (TSX-V: SOG). Pacific Paradigm goes on to mention that a similar reservoir at Little Bow “has been contemplated” by Zargon Oil & Gas (TSX: ZAR) as


EXPLORATION REVIEW

ActuAl Production And reviSed forecASt vS. dAte, tAber South, mAnnville b PoolFrom Husky Warner ASP Flood, 2009 Annual Report, p. 6

Innovative Energy Technologies ProgramTaber S Mannville B Alkaline-Surfactant-Polymer Flood

(Warner ASP Flood)

Husky Oil Operations Limited Page 6 of 16 2009 Annual Report

Based on the simulation, it is expected that the decline will jump to 50% once polymer injection is stopped. Originally, it was planned to only inject 30% pore volume of polymer only.However, with higher oil prices, it has become economic to inject at least 40% pore volume of polymer. This is reflected in the current forecast and adds an additional 800 mbbls of incremental reserves. The write off in reserves from the production adjustment was 1,400 mbbls.This left a net write off of 600 mbbls of reserves. Incremental reserves decreased from 14.1% to12.7% OOIP for the unrisked production, and a drop from 11.4% to 11.3% for the risked production. Figure 2 shows the production to the end of March 2010 with the new production forecasts (risked and unrisked). Table 5 outlines the current reserves information.

Figure 2: Actual production and revised forecast vs date

0

50

100

150

200

250

300

350

400

May-06 May-07 May-08 May-09 May-10 May-11 May-12 May-13 May-14 May-15

Dai

ly R

ate

(m3/

day

)

Actuals Base PDP PROB

Table 5: Reserve Summary for the Taber S Mannville B pool

Production Values as of March 2010 Oil Volume103m3 (MMBO)

Percent of OOIP(%)

Original Oil in Place (OOIP) 6,992 (44.0) -Cumulative Production to date (CTD) 2,928 (18.4) 41.9%Waterflood Ultimate Oil Production 2,756 (17.3) 39.4%ASP Forecast Ultimate Oil Production 3,648 (22.9) 52.1%ASP Risked Forecast (Proven Reserves) 3,548 (22.3) 50.7%Incremental Production (CTD) 222 (1.4) 3.2%Remaining Incremental Production (unrisked) 670 (4.2) 9.6%Total Incremental Oil Production from ASP 892 (5.6) 12.7%

Probable Production Rates(PROB) - unrisked

Proved -Developed -

Producing (PDP) - risked

Base Case

Actual ProductionRates

March2010

an ASP scheme candidate (see below for Zargon Little Bow discussion).

In its 2009 Annual Report (submitted June 25, 2010), Husky reviewed the project and its many challenges to date. ASP injection occurred from project commissioning in May 2006 to October 2008 when the project switched to polymer-only injection. Earlier challenges included surfactant and alkali (caustic) “force majeure” in 2006-2007 and 2007, respectively. Two producers and three injectors were drilled (infill) during the first half of 2008. The first half of 2008 was also marked by carbonate (calcite) scale in some wells, a problem apparently addressed by the injection of a scale inhibitor. From the time of the switch to polymer-only injection to the date of the 2009 report (i.e. into 2010), “silicate” (silica) scale has plagued the project, with “very frequent” well servicing required and chemical companies working toward a solution to this problem (more recent advances have improved run times). In January 2009, water softening was stopped after a soft water buffer was injected following the switch to polymer-only. Finally, Q4 2009 saw the re-drilling of wells (two, see below) plugged up with scale. In 2009, production rates continued “to be substantially lower than original estimates”, with silicate

scale and reduced injectivity being the largest contributing factors. Scaling and its remediation have of course increased costs. Also during that year, polymer injection, which was expected to continue to the end of 2012, was increased to 40% pore volume from 30%. This increase is economically supported by current high oil prices. Incremental reserves estimates have varied “significantly” over the years, not only because of operational issues, but also due to lack of analogous projects. In brief, at the onset of ASP injection, these reserves estimates were 1,002 E3M3 (6.3 million barrels) or 14.5 % of OOIP (unrisked). By calendar year-end 2009, the estimates had decreased to 890 E3M3 (5.6 million barrels), or 12.7% of OOIP (unrisked), principally because of aforementioned scale and injectivity issues (costly and difficult remediation) ( table bottom opposite page). To December 31, 2009, Husky’s total net capital spending on the Taber South ASP Project was $88.4 million.

Areas of higher reservoir pressures compounded the difficulty and added to the danger of well servicing. The dozen wells identified as “problems” are also the best producers (with large areas swept, large volumes of silica are dissolved), which has dramatically affected production.



current reServe SummAry for the tAber S mAnnville b Pool**As 2009 Annual Report to Alberta Energy

From Husky Warner ASP Flood, 2009 Annual Report, p. 6

Production values as of march 2010oil volume

e3m3 (million barrels)ooPi (%)

Original Oil-in-Place (OOIP) 6,992 (44.0) -

Cumulative Production to Date (CTD) 2,992 (44.0) 41.9

Waterflood Ultimate Oil Production 2,756 (17.3) 39.4

ASP Forecast Ultimate Oil Production 3,648 (22.9) 52.1

ASP Risked Forecast (Proven Reserves) 3,548 (22.3) 50.7

Incremental Production (CTD) 222 (1.4) 3.2

Remaining Incremental Production (unrisked) 670 (4.2) 9.6

Total Incremental Oil Production from ASP 892 (5.6) 12.7

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One of the two late 2009 re-drills (twins) of plugged wells (03/4-21-7-16W4) was cored as was the original 00/4-21 well, allowing interesting comparisons. The bottom 3m of the new core (12.5m total pay) showed “possible signs” of clay and chert dissolution (as well as “possible signs” of “amorphous” silica precipitation and some “dolomite cement”), which “seemed to diminish” with increased oil saturation.

Production, from the beginning of the project to the end of March 2010, has been 261.5 E3M3 (1.6 million barrels) of oil and 3,750 E3M3 (23.6 million barrels) of water, with a

cumulative voidage replacement ratio (VRR) of 0.95 (target is 1.0). The production rate, which was 50 M3/d – 315 bopd (1.5% oil cut – OC) at project start, peaked at 290 M3/d – 1,824 bopd (8.4% OC) in October 2008 when polymer-only injection began. Since late 2008, however, the overall rate has declined. At the end of March 2010, production was 230 M3/d – 1,447 bopd – but with a higher OC of 10.5%, which is closer to prediction despite recent operational obstacles. This higher OC is an encouraging indication to Husky that the flood is working, but that it will take longer to recover the predicted reserves, at least in some of the seven areas of


EXPLORATION REVIEW

the flood (e.g. Areas 2 and 6). By contrast, the recovery in the central part of the pool, Areas 3, 4 and 5, remains near original expectations. An oil rate (Actual to March 2010/revised [risked and unrisked] forecast) versus time is shown ( graph top page 30). A table ( page 31) shows the most recent reserve numbers published by Husky Oil for the Taber South (Warner) Mannville B under waterflood and ASP.

Both injector and producing wells are monitored regularly or as needed for a host of variables, to ultimately determine response or breakthrough in producing wells. For example, “polymer concentration in the produced water is one of the easiest and most reliable components [Husky] monitor[s] for assessing flood response in production wells. Polymer concentrations will tend to jump to approximately 100 ppm just prior to a jump in production and oil cut.” (Husky 2009 Annual Report, p. 9). Another example is the recent use of the pH of the produced fluid to predict scaling tendencies in a well. In general, pH values between 9 and 11 denote a possible tendency toward silicate scale issues. With a pH over 11, silicate tends to be kept in solution, while a value below 9 means not enough silicate was dissolved in the reservoir to be a problem, or solution occurred, but silicate precipitation took place in the formation and not in the well.

Significant decreases in the injection rates since going to polymer-only in late 2008 have resulted from the increased viscosity of the injected fluid and the aforementioned silicate scaling issue. As a consequence of loss of injectivity, a pool-wide cumulative (from project start) voidage replacement ratio (VRR) of 0.95 has been maintained since the previous year (2008), which is somewhat less than the ideal target VRR of 1.0. “Injection support is key to the success of these floods” (Husky 2009 Annual Report, p. 12).

Finally in Husky’s 2009 report, it is stated that facilities for the current flood “will be in operation until at least 2013.” A Phase 2 flood could be developed, and could target another pool in the area. Optimally-placed high quality injection wells is one of the most important lessons learned so far (2009/2010) through the ASP flood of the Mannville B Pool in the Taber South (Warner) Field.

Geology of Taber South Mannville B Pool

The regional paleogeographic context in which the Taber South Mannville B Pool (widely recognized as Glauconite-age) clastics were deposited was a series of generally northwest-trending fluvial channels transporting sediment across a north-westerly-prograding (pulse regression toward central Alberta) coastal plain (Jackson, 1984: Fig. 22) ( map page 34). This progradation culminated in the formation of the SW-NE trending Hoadley Barrier Island Trend (regressive sequence - stillstand) in central Alberta ( map opposite page). In southern Alberta, the Glauconite (Glauconitic) Sandstone Member is stratigraph-ically at the base of the Upper Mannville Group, which marks the regressive part of the major Mannville cycle (Jackson, 1984) ( stratigraphic chart page 31). Underlying much of the Glauconitic of southern Alberta is the Ostracod marine shale/silt member of the uppermost Lower Mannville, which represents the maximum southward extent or transgression (flooding) of the Boreal Sea (Jackson, 1984). It is locally known, in southern Alberta, as the Bantry Shale Member. Over wide areas of central and southern Alberta, a thin “Calcareous Member” occurs at the top of the Ostracod Member.

Resumption of major regressive conditions marks the base of the Upper Mannville with deposition of the Glauconitic Sandstone. The term “Glauconitic” is generally restricted to central and southern Alberta (Glass, 1990). The stratigraphic unit is called Glauconitic “Formation” by some (e.g. Rosenthal, 1988; Sherwin, 2001). The Glauconitic is a major producer of hydrocarbons in central and southern Alberta. Conventional oil reserves have been exploited for many years from a series of channels or incised valley systems (sea level drop) and related shoreface complexes (Sherwin, 2001). Hayes et al. (2008) describe “Glauconitic Member” sandstones at Taber South as “clean, fine- to medium-grained sublitharenites, exhibiting excellent reservoir quality”, with “substantial lateral continuity” (estuarine channel).

Sherwin (1996) proposed a stratigraphic nomenclature for the Glauconitic-Ostracod interval that is compared with that of other selected authors and contains most of the names used in the geological discussion of this part of the present review ( stratigraphic chart page 31). Note the various interpreta-tions. The term Glauconite “Formation”, was proposed by Rosenthal (1988) and includes the Ostracod Member.



PAleogeogrAPhy, glAuconitic timeSFrom Sherwin (2011)

HACKETTHIGH

KINDERSLEYHIGH

WAINWRIGHTRIDGE

EDMONTON

CALGARY

JENNERHIGHSTANDSHORELINE

HODLEYBARRIERCOMPLEX

T1

T10

T20

T30

T40

T50

T60

R1W402R 01RR1W5R10

WABASCACOMPLEX

MEDICINEHATHIGH

TORRENSMEMBERCOMPLEX

HK

PROVOST

BH

LB

C

GF

ALD

T

HS

SH

ALBERTA

U.S.A.

HD

SHALLOW

COASTAL

PLAIN

CO N T I N E N TA L

M A R I N E

MannvilleDeformation

Front

Regression

TaberSouth

HOADLEY

(Montana)

T60

T50

T40

T30

T20

T10

T1

R1W4R10R20R1W5R10

Glauconitic channels in green, Lithic channels in orange; major fields: T-Taber,GF-Grand Forks, LB-Little Bow. ALD-Alderson, C-Countess, SH-Shouldice, HS-Hussar, HK-Halkirk, BH-Bellshill Lake, HD-Hoadley.

The Glauconitic channel facies and valley trends have been extensively identified and mapped by Petrel Robertson Consulting from Township 14 south to the Montana border, and by Mike Sherwin (http://www.geoedges.com/, Sherwin, 1996) from Township 14 north to the Hoadley and Pembina barriers (~ T. 50). The paleotopography of the underlying pre-Cretaceous erosion surface, of course, has had a major controlling influence on the facies distribution. Sherwin subdivides the Glauconitic channel facies into Glauconitic “quartzose” and post-Glauconit-

ic “Lithic” or feldspathic channels [e.g. Little Bow-Turin area – Sherwin, 1996] ( stratigraphic chart page 31) Quartzose channels, where quartz grains dominate, suggest a possible crystalline Canadian Shield origin (from east and south) for the sediment, while lithic content (chert + feldspar + volcanic fragments) may indicate a western cordillera source. The Lithic channels fed the Torrens Member (Upper Mannville basal Gates Formation/lowermost Falher member, a. k. a. Bigoray barrier beach) shoreface complex ( map above).


EXPLORATION REVIEW

Southern AlbertA regionAl SunburSt/ glAuconitic/ lithic chAnnelS

T1

T3

T5

T7

T9

T11

T13

T15

T1

T3

T5

T7

T9

T11

T13

T15

R10W4R12R14R16R18R20


Little BowMannville

I & PASPFloodArea

Taber SouthMannville BASP Flood Area


T15

T13

T11

T9

T7

T5

T3

T1

R10W4R12R14R16R18R20

Lithic Channel Trends

Glauconitic Channel Trends

Sunburst Sandstone

Glancing at the regional Glauconitic paleogeographic map, it would appear that the dominant channel type at Taber South might be the Lithic variety.

Furthermore, Sherwin distinguishes the Quartzose and Lithic sandstones on the basis of reservoir quality. The Quartzose or “true” Glauconitic sandstone channel facies form excellent reservoirs. Clean, porous and permeable, they often and typically

include a shale fill (“plug”) component. In contrast, Lithic channel sandstones have poor reservoir quality because of the abundant feldspars and lithic grains, which, when compacted and altered to clays, reduce porosity and permeability. Both channel types followed similar trends toward their ultimate destinations of the shoreface complexes, with the Lithics often crosscutting, or even totally eroding, the older Quartzose



Log Analysis generated with HDS Petrophysical Software

950

975

1000

Core1

10%

GR0 150( GAPI )

HCAL125 325( mm )

Vsh0 100( % )

RT_In.2 2000( OHMM )

RXO8.2 2000( OHMM )

PhiDc30 0( % )

PhiNc30 0( % )

Bvw30 0( % )

Bvxo30 0( % )

PhiE30 0( % )

Core_Porosity30 0

Custom Lith Sw100 0( % )

Core_SW100 0( % )

Ki.01 10000( MD )

KMax.01 10000( MD )

Lithology ComponentsVsh Sand PhiE

Res Pay

MD1:500Meters

HUSKY 5A TABERS 3/5-21-7-16W4

SunburSt SAndStone

mAnnville

rierdon

3/5-21-7-16w4 SunburSt PetroPhySicAl AnAlySiS

Parameters: Sunburst (Glauconitic) Sandstone Rw at 25°C: 0.577 Averages: • Effective Φ: 25.1% • Water Sat: 17%

Net pay: 12.9m Porosity Source: Neutron/Density Crossplot Water Sat. Source: Modified Simandoux A: 1.0 M: 2.0 N: 2.0

channels. Lower porosity Lithic channels can form traps when they cut older, porous Quartzose channels.

The stratigraphic complexity in the “undifferentiated” Upper Mannville mentioned above also extends to the Lower Mannville below the Ostracod. The generically-named Taber South Mannville B Pool, which is the object of the ASP flood, is described by Husky as “Glauconitic channel” in its 2005 Annual Report to Alberta Energy (see above). Furthermore, the reservoir is of high quality ( table page 31), which would be a prerequisite for an experimental ASP flood. From that brief reservoir description, it is deduced that the targeted Mannville B Pool is largely composed, at least in the ASP flood area, of Quartzose or “true” Glauconitic sandstone channel facies as defined by Sherwin. A regional map showing selected Mannville channels facies distribution ( opposite page), which reproduces the two Glauconitic-age channel facies mapped by Sherwin ( map page 33) plus the underlying

Lower Mannville Sunburst sandstone fluvial channel facies (also mapped by Sherwin), graphically illustrates how complex (and open to interpretation) the continental stratigraphic picture can be with just three channel facies. Also, interpre-tations will vary depending on available data (well control, seismic), and interpreter’s bias and stratigraphic model.

Adding to the already complex picture, the producing strata in the Mannville B Pool, which was discovered in 1963, is identified as the “Sunburst Sandstone”. The discovery well at 16-20-7-16W4 shows a 15m-thick (gross), typically blocky fine to medium clean sand as sitting unconformably on the Jurassic Rierdon, in the heart of the Mannville B ASP project. This contrasts with Husky’s description, almost 40 years later in its ASP flood submission, which interprets the same sand as a “Glauconite Channel”, also lying directly on the Rierdon. In other places in the Mannville B project area, there appears to be at least a thin Lower Mannville section

EXPLORATION REVIEW

StrAtigrAPhic croSS-Section, mAnnville b glAuconitic chAnnel, tAber South field

AccuLogs Cross-section, IHS

3370.00

SUNBSTSS3213.9 (-168.0) [TVD] <S>

RIERDON3262.1 (-216.2) [TVD] <S>

SAWTH3315.9 (-270.0) [TVD] <S>

MADSN3357.0 (-311.0) [TVD] <S>

SUNBSTSS(Glauconite)

RIERDON

SAWTOOTH

MADISON

930.00

1030.00

SUNBSTSS979.0 (-50.7) [TVD] <S>

RIERDON984.0 (-55.7) [TVD] <S>

SAWTH1010.0 (-81.7) [TVD] <S>

MADSN1022.0 (-93.7) [TVD] <S>

SUNBSTSS(Glauconite)RIERDON

SAWTOOTH

MADISON

3020.00

3380.00

SUNBSTSS3211.0 (-166.0) [TVD] <S>

RIERDON3269.0 (-224.1) [TVD] <S>

SAWTH3330.1 (-285.1) [TVD] <S>

MADSN3365.2 (-320.2) [TVD] <S>

SUNBSTSS(Glaconite)

RIERDON

SAWTOOTH

MADISON

940.00

1030.00

SUNBSTSS989.5 (-61.8) [TVD] <S>

RIERDON995.0 (-67.3) [TVD] <S>

SAWTH1015.0 (-87.3) [TVD] <S>

MADSN1024.0 (-96.3) [TVD] <S>


SAWTOOTH

MADISON

3020.00

3410.00

SUNBSTSS3209.0 (-168.0) [TVD] <S>

RIERDON3241.1 (-200.1) [TVD] <S>

SAWTH3303.1 (-262.1) [TVD] <S>

MADSN3350.1 (-309.1) [TVD] <S>


RIERDON

SAWTOOTH

MADISON

JET PERFORATIONJET PERFORATION JET PERFORATION

ACID SQUEEZECHEMICAL SQUEEZE

CEMENT SQUEEZEJET PERFORATIONACID SQUEEZE

JET PERFORATION

JET PERFORATION

FRACTUREDJET PERFORATIONFRACTUREDJET PERFORATION

DATUMDATUM

11

3025(20.9)

3050(-4.1)

3075(-29.1)

3100(-54.1)

3125(-79.1)

3150(-104.1)

3175(-129.1)

3200(-154.1)

3225(-179.1)

3250(-204.1)

3275(-229.1)

3300(-254.1)

3325(-279.1)

3350(-304.1)

925(3.3)

950(-21.7)

975(-46.7)

1000(-71.7)

1025(-96.7)

3025(19.9)

3050(-5.1)

3075(-30.1)

3100(-55.1)

3125(-80.1)

3150(-105.1)

3175(-130.1)

3200(-155.1)

3225(-180.1)

3250(-205.1)

3275(-230.1)

3300(-255.1)

3325(-280.1)

3350(-305.1)

3375(-330.1)

BRIDGE PLUG CAPPED W/CEMENT

PACKER-BRIDGE PLUG

950(-22.3)

975(-47.3)

1000(-72.3)

1025(-97.3)

1

PACKER-BRIDGE PLUG

3025(16.0)

3050(-9.0)

3075(-34.0)

3100(-59.0)

3125(-84.0)

3150(-109.0)

3175(-134.0)

3200(-159.0)

3225(-184.0)

3250(-209.0)

3275(-234.0)

3300(-259.0)

3325(-284.0)

3350(-309.0)

3375(-334.0)

3400(-359.0)

West

Regional Facies

Glauc. Channel

East

Regional Facies

RR: 1965-02-01FormTD: MADSN

Fluid: N/A

CPOG TABER S

Mode: AbndTD: 3370.1 ft [TVD]

KB: 3045.9 ft

< 128.8 m >

00/08-20-007-16W4/0RR: 1996-09-07FormTD: MADSN

Fluid: Oil

RENAISSANCE 8D TABER S

Mode: PumpTD: 1038.0 [TVD]

KB: 928.3 m

< 241.6 m >

03/08-20-007-16W4/0RR: 1996-09-07

FormTD: MADSNFluid: Water Injection

RENAISSANCE TABER S


KB: 3044.9 ft

< 263.4 m >

00/05-21-007-16W4/0RR: 1994-01-21



Mode: Inj.TD: 1035.0 m [TVD]

KB: 927.7 m

< 1041.5 m >

02/05-21-007-16W4/0RR: 1965-05-07

FormTD: MADSNFluid: Gas

CPOG TABER S

Mode: AbndTD: 3444.9 [TVD]

KB: 3041.0 ft 00/08-21-007-16W4/0

No prod. Sept. 96 - Jul. 201210,629 M3 oil

191,320 M3 water

Jan. 65 - Aug. 7463,825 M3 oil

92,871 M3 water

Jan. 94 - Jan. 200626,050 M3 oil

761, 670 M3 water

No prod.(Bow Island target)

Feb. 2006: water injector

UpperMannville

25 m

See map page 28

(undifferentiated) underlying the Glauconite, as interpreted in well log analyses submitted by Husky (Husky 2005 IETP annual report – June 2006). A short stratigraphic cross-section across the channel trend and including Glauconite “regional” prograding sand-shale coastal plain (non-channel) facies serves to illustrate the typical aspect of the project target ( cross-section below). One vertical well at 3/5-21-7-16W4, which is situated only about 250m south of the short west-east stratigraphic section ( map page 28 ), was selected for log analysis ( page 35) as representative of the Mannville B reservoir. The development well was drilled by Husky to the Rierdon at the end of 2005 and went on production in

December (Sunburst [Glauconite] completion), recording an initial production (IP) rate of 7.8 M3/d (49 bopd). In October 2012, the producer was still putting out about 0.7 M3/d of oil (~ 4.5 bopd), but with 82.7 M3/d of water (520.4 bwpd). The 14m gross reservoir interval was cored almost entirely, retrieving mostly fine to very fine sandstone, in places medium grained, with very high porosities (geometric average: 26%) and permeabilities (geometric average, Kmax: 2,946 mD). Husky had chosen to display an analysis of 3/5-21 in its first IETP report (June 2006) to Alberta Energy (and http://www.energy.gov.ab.ca/768.asp ). The company has reported a “positive surprise” when analysing that well. It found that the

3370.00

SUNBSTSS3213.9 (-168.0) [TVD] <S>

RIERDON3262.1 (-216.2) [TVD] <S>

SAWTH3315.9 (-270.0) [TVD] <S>

MADSN3357.0 (-311.0) [TVD] <S>


RIERDON

SAWTOOTH

MADISON

930.00

1030.00

SUNBSTSS979.0 (-50.7) [TVD] <S>

RIERDON984.0 (-55.7) [TVD] <S>

SAWTH1010.0 (-81.7) [TVD] <S>

MADSN1022.0 (-93.7) [TVD] <S>


SAWTOOTH

MADISON

3020.00

3380.00

SUNBSTSS3211.0 (-166.0) [TVD] <S>

RIERDON3269.0 (-224.1) [TVD] <S>

SAWTH3330.1 (-285.1) [TVD] <S>

MADSN3365.2 (-320.2) [TVD] <S>

SUNBSTSS(Glaconite)

RIERDON

SAWTOOTH

MADISON

940.00

1030.00

SUNBSTSS989.5 (-61.8) [TVD] <S>

RIERDON995.0 (-67.3) [TVD] <S>

SAWTH1015.0 (-87.3) [TVD] <S>

MADSN1024.0 (-96.3) [TVD] <S>


SAWTOOTH

MADISON

3020.00

3410.00

SUNBSTSS3209.0 (-168.0) [TVD] <S>

RIERDON3241.1 (-200.1) [TVD] <S>

SAWTH3303.1 (-262.1) [TVD] <S>

MADSN3350.1 (-309.1) [TVD] <S>


RIERDON

SAWTOOTH

MADISON

JET PERFORATIONJET PERFORATION JET PERFORATION

ACID SQUEEZECHEMICAL SQUEEZE

CEMENT SQUEEZEJET PERFORATIONACID SQUEEZE

JET PERFORATION

JET PERFORATION

FRACTUREDJET PERFORATIONFRACTUREDJET PERFORATION

DATUMDATUM

11

3025(20.9)

3050(-4.1)

3075(-29.1)

3100(-54.1)

3125(-79.1)

3150(-104.1)

3175(-129.1)

3200(-154.1)

3225(-179.1)

3250(-204.1)

3275(-229.1)

3300(-254.1)

3325(-279.1)

3350(-304.1)

925(3.3)

950(-21.7)

975(-46.7)

1000(-71.7)

1025(-96.7)

3025(19.9)

3050(-5.1)

3075(-30.1)

3100(-55.1)

3125(-80.1)

3150(-105.1)

3175(-130.1)

3200(-155.1)

3225(-180.1)

3250(-205.1)

3275(-230.1)

3300(-255.1)

3325(-280.1)

3350(-305.1)

3375(-330.1)

BRIDGE PLUG CAPPED W/CEMENT

PACKER-BRIDGE PLUG

950(-22.3)

975(-47.3)

1000(-72.3)

1025(-97.3)

1

PACKER-BRIDGE PLUG

3025(16.0)

3050(-9.0)

3075(-34.0)

3100(-59.0)

3125(-84.0)

3150(-109.0)

3175(-134.0)

3200(-159.0)

3225(-184.0)

3250(-209.0)

3275(-234.0)

3300(-259.0)

3325(-284.0)

3350(-309.0)

3375(-334.0)

3400(-359.0)

West

Regional Facies

Glauc. Channel

East

Regional Facies

RR: 1965-02-01FormTD: MADSN

Fluid: N/A

CPOG TABER S


KB: 3045.9 ft

< 128.8 m >

00/08-20-007-16W4/0RR: 1996-09-07FormTD: MADSN

Fluid: Oil


Mode: PumpTD: 1038.0 [TVD]

KB: 928.3 m

< 241.6 m >

03/08-20-007-16W4/0RR: 1996-09-07


RENAISSANCE TABER S


KB: 3044.9 ft

< 263.4 m >

00/05-21-007-16W4/0RR: 1994-01-21



Mode: Inj.TD: 1035.0 m [TVD]

KB: 927.7 m

< 1041.5 m >

02/05-21-007-16W4/0RR: 1965-05-07

FormTD: MADSNFluid: Gas

CPOG TABER S


KB: 3041.0 ft 00/08-21-007-16W4/0

No prod. Sept. 96 - Jul. 201210,629 M3 oil

191,320 M3 water

Jan. 65 - Aug. 7463,825 M3 oil

92,871 M3 water

Jan. 94 - Jan. 200626,050 M3 oil

761, 670 M3 water

No prod.(Bow Island target)

Feb. 2006: water injector

UpperMannville

25 m

reservoir in this well had not been swept by the waterflood as expected, but that instead “there was a large un-swept portion at the top of the sand”.

A regional stratigraphic section from Sherwin (1996) shows several channels relative to one another (both fine to medium-grained) and the strata they transect ( page 38), in the Queenstown-Jumpbush-Lathom region (T. 19-20W4). While Glauconite sand channel facies typically show a blocky gamma ray signature, with or without shale fill (younger, Lithic channel fills look less “clean” due to relatively high radioactive mineral contents), the regional Glauconitic, which

overlies the Ostracod, is typically characterized by one or more coarsening-upward successions, from mudstone to fine-grained sandstone, often capped by a thin carbonaceous zone (Sherwin, 1996). The Glauconite and non-Glauconite channels are incised into this regional facies and often into the underlying Lower Mannville.

Zargon Oil & Gas ASP at Little Bow

Calgary-based Zargon Oil & Gas (TSX: ZAR) has stated that its “core business is oil exploitation - targeting increased oil recovery from existing oil production” (company website). Its foray into tertiary recovery is a relatively recent endeavour


EXPLORATION REVIEW

StrAtigrAPhic croSS-Section, queenStown-jumPbuSh-lAthom regionFrom Sherwin (1996), p. 534

Shale Fill

EW

Shale Fill

Ost. LimeDatum(Ostracod)

20 m.

Glauconite Channels Lithic Channels

(see below), however. “In a typical Alberta Plains South Mannville oil reservoir, primary production brings only about 15 percent of the original oil-in-place to the surface. The implementation of a waterflood improves recoveries, but still only captures approximately 40 percent of the original oil-in-place. Tertiary floods, based on chemicals, can increase the recovery of oil by at least another 10 percent” (Zargon website).

In addition to six “conventional” oil exploitation properties (December 2012), the company has one ASP tertiary recovery project in preparation. It is situated in the Alberta Plains South core region, which also includes Taber South assets (Lower Cretaceous Sunburst Member sandstone). Currently under an expanding waterflood using horizontal wells, Zargon’s Little Bow (Glauconitic Member) ASP enhanced recovery scheme is of major importance to the company. In its Q3 2012 report, Zargon stated that this developing EOR project was expected to contribute an incremental average of 223 M3/d of oil (1,400 bopd) between 2017 and 2019 (Q3 2012 press release), significantly more than if polymer alone was injected. An incremental figure of over 239 M3/d of oil (1,500 bopd) in 2017 is estimated, as posted in a December 2012 company presentation. In a February 20, 2013 communiqué, the company says that the capital budget for 2013 was set at $78 million, of which an estimated $38 million was earmarked for the ASP project. The capital for the ASP project at the

Little Bow I Pool will be spent over two phases: Phase 1 (2013-2017) for a total of $72.1million for facilities and chemicals, and Phase 2 (2016-2019) for an additional $37.9 million ( map opposite page).

By the end of Q3 2012, front-end engineering and design studies (FEED) had been completed, and key alkaline and polymer components had been selected. The ERCB has approved the scheme, and final sanctioning of construction (Phases 1 and 2) by Zargon was announced on February 20, 2013, the ninth ASP project in Canada, which could lead to chemical injection starting in January 2014 (ASP injection is expected to last two years). Incremental production, in turn, would start appearing during 2014. Early in 2013, Zargon will carry out well workovers and pipeline upgrades, which should also benefit existing waterflood operations in the near term. At year-end 2012, McDaniel and Associates Consultants had assigned 698 E3M3 (4.39 million barrels) of “probable undeveloped oil equivalent reserves”, under phases 1 and 2 of the Little Bow ASP project (100% Zargon WI). McDaniel estimated a 10% incremental ASP recovery factor. Zargon, in its February 20, 2013 news release, posted a 12% recovery factor over the “base waterflood” from phases 1 and 2, based in part on the Husky Taber South analog (see above), which translates into an internal reserve evaluation of 774 E3M3 (4.87 million barrels) of oil. Zargon also has plans for Phase 3 and 4 ASP projects to the south of the I pool, which may



little bow ActivityFrom IHS AccuMap/ Zargon Website: Mannville I & P pools and land

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IV

IV

IV

I

VIISC

GJCD

J

U

IS

J

IC

EC

J

S

G

I

E

E

G

G

JFU

M

S

I

V

E

I

S

I

G

F

J

U

GG

K

K

G

G

G

G

G

G

K

G

G

G

BSU

BSU

BS

BS

BS BS

BS

BSBSBS

BSBS

BSBS

BSBS

BS

BSU

BSU

BSJ

M

EE

E

E

U

I

U

IS

EE U

S

E

SU

L

EU

E

V

E

E

C

EU

IU

I

VJDJULUGUK

S

D

JV

CV

K

U

G

DK

S

I

U

IUGU

E

L

U

G

U

G

U

G

JGIID

V

I

GUCUICI

V

EUL

UL

U

G

I

VI

VI

GJCD

IS

IC

EC

S

I

E

E

FK

IUJSUG

EV

E

U

J

JUMU

E

U

IV

JJ

U

KISC

IV

IV

MS

E

J

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V

II

E S

EI

V

EE

C

S

I IU

I

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I

S

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SJ

V

I I

V

IS

US

U

JLG

D

UF

IU

I U

E

E

U

I

UD

U

G

U

JG

T14

T15

T14

T15

R18W4R19

R18W4R19


L I T T L E B O W F I E L D

ASP Phase 2

ASP Phase 2

ASP Phase 1

(Zargon interest)

Upper Mannville Soil

(Crescent PointEnergy)

RETLAWMannville

PaleovalleyTrend

Wood andHopkins

(1989)

Mannville

Upper

P

H9H

U p p e r M a n n v i l l e I

A

A


T15

T14

R18W4R19

Note: For the regional cross-section (W-E) reproduced from Sherwin (1996), which runs just south of the map area, see page 38. For the local cross-section (A-A') reproduced from Wood and Hopkins (1989), see page 42.

Freehold Upper Mannville I Pool,Little Bow Field

Ashton Oil & Gas Crown Land

Zargon Crown Land Upper Mannville P Pool,Little Bow Field

Injection Wells

Zargon Licences

Ashton Oil & Gas Licences

N

N

N

add an incremental 11% recovery. In brief, the injection schedule will be as follows: an ASP blend followed by a polymer “push” capped by a terminal waterflood.

In February 2013, Zargon reported that it had updated its reservoir simulation model of Little Bow to optimize the ASP flood design. That study was nearing completion, with runs predicting the recovery of up to 1.1 E6M3 (7.0 million barrels) of incremental oil.

The Little Bow Upper Mannville I (T. 14-15, R. 18W4) and P (T. 15, R. 19W4) pool properties were aquired by Zargon through the acquisition of public Masters Energy in April 2009 and through a significant property acquisition in May 2010. As an analog to its Little Bow ASP, Zargon is using Husky Energy’s Taber South Mannville B project (Glauconite Formation), which began ASP injection in May 2006 (see discussion, above) and is located about 70 km south of Little Bow. A table ( page 40) posted on the Zargon website (December 2012) shows how analogous the Taber South and Little Bow Mannville pools are, and how both meet or exceed

EXPLORATION REVIEW

Selected reServoir And fluid ProPertieS comPAriSon, tAber South mAnn. b And little bow u. mAnn. i & P PoolS

From Zargon website, December 2012. *Discovered Petroleum Initially In Place. **ERCB

Propertytaber South mannville b

little bow u. mann. i & P

ASP Screening

Lithology Sandstone Sandstone Sandstone

Oil gravity (°API) 19 21 >15

Mean depth (m) 983 1,085 <1,829

Average Permeability (mD) 1,000 900 >100

Reservoir temperature (°C) 31 33 < 82

Viscosity (cp) 40 21 < 200

Successful waterflood Yes Yes Yes

DPIIP* (E3M3) 6,836** 6,200** Large

Average porosity (%) 25 23 >15

Original porosity (kPa) 164.3 234.0 -

Net pay (m) 7.0 11.3 -

Initial water saturation 22 21 -

key ASP screening criteria. Furthermore, the Mannville pools have “analogous” production histories and have been under waterflood for a considerable time (mature production), with Husky’s Taber South Mannville B under ASP flood since 2006 ( graph opposite page). Finally, the Mannville pools selected for ASP flooding have other desirable features such as a water-wet reservoir, and minimal gas caps or water legs. Also, they are shallow enough that temperature-sensitive chemicals will be minimally or not affected.

Zargon’s ASP follow-up development after the Little Bow I and P pools project would include Mannville pools in the north of the large Retlaw Field ( map page 39) – see also review of Little Bow-Retlaw Geology, below.

Geology of Little Bow Upper Mannville Pools

In broad terms, the geology of the Cretaceous reservoirs, which are scheduled for ASP flooding in the Little Bow Field, is similar to that of the reservoirs at Taber South (see above). Basically, acceptable candidates for ASP flooding are porous and permeable sandstone bodies containing medium gravity crude. Also, their size, extent and properties are as well defined as possible thanks to previous drilling and careful modeling of spatial properties obtained through seismic. Also, these reservoirs have been waterflooded for some time. The channel facies identified in the Upper Mannville I and P pools at Little Bow fit the bill according to Zargon ( table above). The Upper Mannville I pool, which was

discovered in 1974 (on stream in October), currently has 18 producing wells and eight active water injectors (Zargon, January 2013). The pool has been on injection since November 1983 and is at the heart of Phase 1 of the upcoming ASP flood. To October 2012, the pool has produced 1,912 E3M3 (over 12 million barrels) of 21°API oil and 244 E6M3 (over 8.6 bcf) of gas, as well as 13,432 E3M3 (85 million barrels) of water. The smaller Upper Mannville P Pool, which has two active producers and two operating injectors (Zargon, January 2013), was found in 1979 and put on stream in July of that year. It had only one producing well until March of 1996. Water injection did not start until December 2003. To October 2012, the pool has produced 183 E3M3 (1.2 million barrels) of 21° API (ERCB incorrectly reports 32.3° API) oil, 19 E6M3 (690 mmcf) of gas and 853 E3M3 (5.4 million barrels) of water. According to Wood and Hopkins (1989), high water cuts as well as “viscous interfingering” are common in lower gravity pools that, consequently, could benefit from ASP flooding (see above).

Wood and Hopkins (1989), in a detailed “Glauconitic Member” pool study centred on T. 14, R. 19W4 in the Little Bow Field (actually, at the junction of the Little Bow and Retlaw fields), focused on three Upper Mannville pools, which they describe as “three parallel, elongate sandstone bodies within an estuarine valley fill”. The authors, who were aiming at better modeling these Glauconitic sandstone bodies, went on to describe a paleovalley that is 2.0 to 2.5 km wide and 4



100

1,000

10,000

100,000

Oil

Pro

du

ctio

n &

Wat

er In

ject

ion

(bp

d)

0%

1%

10%

100%

Oil C

ut (%

)

Data to July 2012

Injection

Oil Cut

Oil Rate

Zargon Little Bow Production History

Husky Taber Production History

100

1,000

10,000

100,000

1972 1976 1980 1984 1988 1992 1996 2000 2004 2008 2012

Oil

Pro

du

ctio

n &

Wat

er In

ject

ion

(bp

d)

0%

1%

10%

100%

Oil C

ut (%

)

Data to July 2012

Injection

Oil Cut

Oil Rate

1964 1968 1972 1976 1980 1984 1988 1992 1996 2012200820042000

Husky ASP FloodInitiated

mAnnville PoolS AnAlogouS Production hiStoryFrom Zargon website, December 2012


EXPLORATION REVIEW

OstracodBedsUnits

Glauc.Shale LithofaciesOnly

A Aꞌ

Sandstone/ ShaleSandstone ShaleLimestone

StrAtigrAPhic croSS-Section, little bow/ retlAw - counteSS - enchAnt regionFrom Wood and Hopkins (1989), p. 1366

See map page 39

to 30m thick, which has been mapped over a 55 km length. The three hydrodynamically-separate reservoir bodies it contains, where logs, pressure histories, original oil-water contacts and seismic interpretations indicate are separated by 100 to 200m wide shales, are 3 to 4 km long, 300 to 500m wide and up to 22m thick. These shales “are interpreted as the fills of mud-prone estuarine channels”. In turn, the reservoir sandstone bodies are interpreted as longitudinal sand bars. Shale and shaly units provide the reservoir seals.

A modern analog believed by the authors to match the Glauconitic facies at Little Bow is the broad (~ 4-6 km wide) middle zone of the mud-dominated Gironde estuary on the Atlantic coast of France, downstream from Bordeaux. There, sand is deposited in the form of longitudinal bars (15 km long by 0.5 to 1.0 km wide by over 5m thick) and outer marine bodies near the mouth of the estuary. The bars, which quickly aggrade/degrade vertically, do not migrate much laterally, being limited horizontally by active mud-filling channels. The authors believe that similar “penecontemporaneous muddy channels” in the Little Bow estuarine system “played a major role in limiting the lateral migration of adjacent longitudinal sand bars.” (Wood and Hopkins [1989], p. 1,379). Various shale units, as well as the tight Ostracod facies, stratigraph-ically trap the hydrocarbons in the Glauconitic reservoirs ( cross-section above). A structural element to trapping was created by differential compaction.

Wood and Hopkins (1989) produced three short stratigraphic cross-sections that are mostly confined to the northeastern quarter of T. 14, R. 19W4 ( map page 39) and cut across the three subject pools. One of these sections (A – A’) is reproduced in this review ( cross-section above) as representative of the authors’ interpretation of the pools’ appearance in logs and their separate nature. Compare this section with the more regional view of the same stratigraphic interval where the focus is on channel facies ( cross-section top opposite page).

BlackPearl Resources at Mooney

Calgary-based BlackPearl Resources (TSX: PXX, OMX [Stockholm]: PXXS) is heavily focused on three Cretaceous heavy oil projects, two in Alberta and one in Saskatchewan near the Alberta border. Onion Lake, in Saskatchewan near Lloydminster, which produced most of the company’s heavy oil (conventional) in 2011, has a major future SAGD project planned. Blackrod, which is located in the Athabasca region of Alberta, is BlackPearl’s largest project and has the potential for a large SAGD development.

The company’s third and final core area (operated 100%) is a compact conventional heavy oil property centred on the small, but expanding, Cretaceous Bluesky-dominated Mooney Field. As of December 1, 2012, the Bluesky A Pool had 53 producing wells and 26 injectors. Discovered in 1986, the 17°API Bluesky A Pool was developed initially using “primary



StrAtigrAPhic croSS-Section, little bow/ retlAw - counteSS - enchAnt regionFrom Sherwin (1996), p. 534

Shale Fill

EastWest

20 m.

Shale Fill

Ost. LimeDatum(Ostracod)

Glauconite Channels Lithic Channels

79 BLUSKY; GETH; BANFF 1986-05 to 2012-10MOONEY (902) 3718956.3 bbl

Oil; Waste; Water Injection 304001 5232109.4 mcfAbandoned; Disposal; Injection; Pumping; 4691567.8 bblAbandoned Zone...

© IHS, 1991 - 2013 Created in AccuMap Datum: NAD27TM Printed on 16/01/2013 9:57:12 AMPage 1/1

9 wells

2 wells1 well

4 wells

48 wells

July2011:Largewater

injectionvolumes

begin(ASPflood)

65 wells

rAte vS. time, mooney blueSky AFrom IHS AccuMap™

Avg Dly Oil (bbl/d) Avg Dly Gas (mcf/d) Avg Dly Wtr (bbl/d) Nbr of Wells


EXPLORATION REVIEW

mooney Activity

AA'

M

G

G

G

G

GG

GG

FC

C

E

G

G

G

G

G

G

G

G

G

G

G

EVE

V CVC

VC

V CV CV AV

E

V

ID

EV

E

G

G

EG

E

G

ECUEU

JG

EV SV

EV

EV

SVE

V

SV

EVE

V SVS

VE

V

SV

SV SV EV

EV

EIGU

G

GF

G

G

G

GV

G

EV SVE

V SV

EV GSV

EV

EV DV

SV EV SV

AV

SV

EVS

V

EV

J

G

G

SV

GU

G

DV

KK

GDG

DV

GG

I

JD

JK

JKD

C

J

GV

D

I

J

JM

J

G

JS V

KC

G

EVE V

S V

S V

S V

S V

SV

I V

S V

S VE V

EVE V

EV

I V

EVE V

G

G

U

EV EV

EV

A

V CV CV

EV

G

G

G

FF

EVE

V

AV

G

GE V

I

VE V

C

VC

VC V

G

G

G

G

U

G

G

G

G

G

G

G

J

J

E

G

GGU

G

G

G

E V

E

VE V

E VE

V

AV AV

AV

G

G

G

G

G

KK

G

GG

CF

CFC U

FF

KC

G

G

G

G

G

IG

G

G

G

G

G

G

G

G

G

G

J

G

G

A

CV

G

G

JGM

M

GU

G

C

GG

G

G

C

SE

SEV SEV SCVSC

VSC

V SCV SCV SAV

SEV

SEV

SG

SESGSGSEV SSV

SEV

SEVSSVSE

V

SSV

SEVSE

V SSVSS

V

SEV

SSV

SSV SSV SEVSE

VSG

SG

SGV

SEV SSVSE

V SSV

SEV SGSSV

SEV

SEV SDV

SSV SEV SSV

SAV

SSV

SEVSSV

SEV SSV

SDV

SGSDSG

SDV

SISJSDSJSKSDSGVSD

SI

SS V

SE VSE VSS VSS V

SS V

SS V

SS V

SI V

SS V

SS VSE V

SE VSE VSE

V

SI V

SEVSE V

SGSGU

SEV SEVSEVSA

V SCV SCV

SEV

SG

SEV SEVSA

V

SGSE VSI

VSE V

SCV

SCVSC V

SG

SGSG

SGU

SGSE V

SEVSE V

SE VSE V

SAV SAV

SAV

SG

SG

SGSISG

SG

SG

SG

SJ

EVE

V

E

VE

V

EV SV

EV

EV

SVE

V

SV

EVE

V SVS

VE

V

SV

SV SV EV

EV

EVE

V

EV SV

EV

EV

EV SV

SV

EVS

V

EV

J

SV

J

J

D

I

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J

JS V

EVE V

S V

S V

I V

E V

EVE V

EV

EVE V

EV EV

EVE

VEVE

V

E V

I

VE V

E V

E

VE V

E VE

V

T70

T71

T72

T73

T70

T71

T72

T73

R6W5R7R8R9R10

R6W5R7R8R9R10


Bluesky A Pool(BlackPearl)

BlackPearl6-18 Oil Battery/Gas Plant/ ASP/ InjectionFacility/ Disposal Facility

BlackPearl6-8 Gas Plant

BlackPearl9-24 Oil Battery/Oil Loading Facility (rail)

1/2

S L A V E

L A K E

L E S S E R

(Phase 3)

Phase 2B

Phase 2A

Dev 14-18

ANALYSISLOG

2

33Phase 1 Active

ASP Flood

Base map generated with AccuMap ™ Area Phases 1& 2 Outlines: BlackPearl website Jan/2013

T73

T72

T71

T70

R6W5R9 R8 R7R10

SN BlackPearl LandBlackPearl Licences

cross-section A-A' see pages 48-49

Roads Bluesky ProductionN

production techniques”. Limited water injection, which started in April 1989, began in earnest in August 2006. In 2011, an ASP flood was initiated. In July of that year, very large water volumes began to be injected (up to 4,071 M3/d of water – 25,621 bwpd [September 2011]) ( graph bottom page 43).

Initiated in Q3 2011, the 8.5-section Phase 1 of the ASP flood ( map above) involved the conversion of 25 existing wells to ASP injectors. Initial response from repressurization was seen in Q2 2012. Significant response from Phase 1 of the flood was expected by late 2012. Prior to the implementation of the full Phase 1 ASP flood, a polymer flood pilot was run for about 18 months resulting in about 18% recovery of the

oil-in-place. “Conventional primary recovery rates without ASP flooding would typically be 3% to 5%”. Recovery factor for the ASP project is expected to be an incremental 25% - perhaps even as high as 30% (BlackPearl website).

As additional ASP flood phases (2 and 3, so far) are developed on the property, the company estimates that over 1,113 to 1,590 M3/d of oil equivalent (7,000 to 10,000 boe/d) could be produced (BlackPearl website). As at December 31, 2011, Sproule estimates 2P reserves of 2,544 E3M3 of oil equivalent (16 million boe) and a contingent resource (2C) of 5,882 E3M3 of oil equivalent (37 million barrels)



ResourcesReserves

2012

2015

2018

2021

2024

2027

2030

2033

2036

2039

2042

2045

2048

2051

2054

10,000

8,000

6,000

4,000

2,000

Year

(bop

d)

mooney Production ProfileAS PER THE SPROULE RESERvES And “BEST ESTIMATE” cOnTInGEnT RESOURcE REPORTS dATEd dEcEMBER 31, 2011

From BlackPearl website, November 2012

- best estimate recoverable resource, through BlackPearl’s horizontal ASP flood.

In 2012, the company planned on spending about $146 million in total (November 7, 2012 news release). At Mooney, Phase 2 of the ASP will continue in 2013 with the drilling of 20 to 25 horizontal wells (15-20 wells Q4 2012/Q1 2013). Conversion to ASP injection flooding will commence in late 2013/early 2014 ( map opposite page). Already, the company’s total year-over-year production increase in Q3 2012 has been attributed mainly to the “initially successful” ASP flood response (Phase 1) and last fall’s Phase 2 drilling at Mooney (November 7, 2012 news release). Also in Q3 2012, output from the ASP flood area has increased over 200% to 134 M3/d of oil (843 bopd) since the flood was initiated in 2011 (over 191 M3/d of oil [1,200 bopd] on average in November 2012). Peak production of 477 to 636 M3/d of oil (3,000 to 4,000 bopd) in Phase 1 is expected in 2013 (company website). Once phases 2 and 3 are converted

to ASP, an additional 636 to 954 M3/d of oil (4,000 to 6,000 bopd) is expected.

Mooney is a 40+ years project. BlackPearl stated that the closest analog to Mooney, in terms of depositional setting and development method (e.g. 200m inter-well spacing), is Cenovus’ (TSX, NYSE: CVE) Lower Cretaceous Wabiskaw reservoir (Bluesky equivalent in northeastern Plains of Alberta) at Pelican Lake. At Pelican Lake (~T. 82-83, R. 17-22W4), which is near the southeastern edge of the Wabiskaw/McMurray oil deposits area, Cenovus has applied waterflooding and polymer injection with horizontals, and is expanding polymer injection. In addition, the company is “evaluating the use of surfactants … to supplement the polymer technology”. Cenovus estimates a 32% recovery factor at Pelican Lake (BlackPearl website), likely using polymers alone. Mooney is also “similar to other EOR projects with significant long-life oil pools ([Upper Paleozoic] Swan Hills, Midale)” (BlackPearl website). A cumulative oil production versus time profile


EXPLORATION REVIEW

Non-marine Silts, Shales

Shoreface Sands Continental Conglomerate Marine Shales

Incised Valley Fill/ Fluvial

PlAy SchemAtic: blueSky-gething-cAdomin - SAndSFrom Modified from Warters et al., Fig. 15, 1997

NW SE

PembinaHighlands

Devonian

Spirit River FormationBluesky Formation

Mississippian

ContinentalGething Formation

Cadomin (Alluvial, Fluvial)Jurassic

Deltaic

Boyer Field (Bluesky) Rigel Field (Gething) Wapiti Field (Cadomin) Peco Field (Gething)

Modified from Warters et al, Fig 15, 1997 Marine Shales Continental Conglomerate

Non marine Silts, Shales Incised Valley Fill/ Fluvial

Shoreface Sands

shows the expected relative contributions of conventional “reserves” and the “resource” in the Bluesky at Mooney ( graph page 45).

Bluesky Geology at Mooney

In brief, the Bluesky Formation at Mooney and area is formed of shallow marine, relatively clean and continuous shoreface sands. A schematic section ( below) places the Bluesky in its stratigraphic context. A short, five-well cross-section ( pages 48-49), which cuts across the Phase 1 ASP flood area, clearly demonstrates the continuous nature of the thin (~5-7m gross), shallow (average 908m), relatively clean and generally shoaling-upward nature of the Bluesky reservoir. These reservoir properties make the uppermost Bluesky interval at Mooney a good candidate for systematic exploitation by horizontal ASP flood. One of the wells on the cross-section was analysed ( opposite page): Development 14-18-72-7W5, which was drilled at the end of 1987, produced oil sporadically from January 1988 to March 2001, recording a low initial production (IP) rate of about 5.0 M3/d (~ 31 bopd) and producing a total of 8,426 M3 (53,000 barrels) of oil before being abandoned. A core describes in brief the gross reservoir interval as porous (avg. geometric porosity: 21%) and permeable (avg. geometric permeability: 246 mD) fine to medium-grained sandstone. By any definition, this reservoir is conventional. The well was converted to water

disposal in March 2006, and it retains that status to this day (November 2012). The water is injected into a 7m thick clean and very porous, but wet, Gething Formation sand about 1,000m deep.

Murphy Oil Polymer Flood at Seal

Another tertiary recovery project involving a chemical flood in the Bluesky is in progress at Seal (T. 83, R. 15W5). This scheme, which is operated by Murphy Oil (wholly-owned by Murphy Oil Corporation – NYSE: MUR – and headquartered in Eldorado, AK), involves the injection of polymer alone. The company has provided some details about its first polymer flood pilot project at Seal.

Murphy Oil’s integrated international parent is focused, in its North American onshore portfolio (60% oil-weighted), on light oil production in the Eagle Ford Shale (EFS) of Texas and at Seal in northern Alberta (November 14, 2012 presentation), a focus that reflects the current interest in oil prospects. In 2013, Seal is scheduled to consume 7% of the company’s US$3.5 billion worldwide development budget (development of Murphy’s Canadian Syncrude holdings will consume 5%). At year-end 2011, Seal accounted for 10% of the total resource base (~ three-quarters oil and other liquids) of Murphy Oil Corporation. Like EFS, Seal production is expected to increase (~ double) through 2015.



Log Analysis generated with HDS Petrophysical Software

Field Name: MOONEY State / Province: ALBERTAGL: 841.7 metersCALX125 375( mm )

CALY125 375( mm )

GR0 150( GAPI )

Vsh0 100( % )

ILD.2 2000( OHMM )

RFOC.2 2000( OHMM )

PhiDc30 0( % )

PhiNc30 0( % )

Bvw35 0( % )

Bvxo35 0( % )

PhiE35 0( % )

Core_Porosity35 0( % )

Sw100 0( % )

Core_Sw100 0( % )

Lithology ComponentsVsh Sand PhiE Coal

Res Pay

MD1:500Meters

900

925

950

975

Core1

BLUSKY

GETH

1000

1025

925

950

975

Core1

*

10%

GULF ET AL MOOnEY14-18-72-7W5

blueSky

mAnnville

14-18-72-7w5 blueSky PetroPhySicAl AnAlySiS

Parameters: Bluesky Rw at 25°C: 0.198 Averages: • Effective Φ: 27.8% • Water Sat: 30.2%

Net pay: 3.5m Porosity Source: Neutron/Density Crossplot Water Sat. Source: Modified Simandoux A: 1.0 M: 2.0 N: 2.0

gething

water in gething formation: Records from various operators’ licensed in the area indicated that it could be very economical to take water from the Gething Formation and use it for the Bluesky water injection system. Because both formations in the area have approximately the same TDS (Total Dissolved Solids) quantity and composition, the Gething water could be suitable for Bluesky injection.

*

EXPLORATION REVIEW

StrAtigrAPhic croSS-Section, mooney bASAl cretAceouSAccuLogs Cross-section, IHS

850.00

900.00

BLUSKY870.0 (-107.3) [TVD] <S> BLUESKY

860.00

970.00

BLUSKY885.1 (-92.3) [TVD] <S>

GETH911.9 (-119.1) [TVD] 

BANFF958.0 (-165.2) [TVD] <S>

BANFF

920.00

1050.00

BLUSKY940.2 (-95.0) [TVD] <S>

GETH967.0 (-121.8) [TVD] <S>

BANFF1033.6 (-188.4) [TVD] <S>

BLUESKY

GETHING

840.00

940.00

BLUSKY888.7 (-88.7) [TVD] 

GETH915.9 (-115.9) [TVD] 

BLUESKY

GETHING

840.00

930.00

GETH902.7 (-109.6) [TVD] 

BLUSKY875.1 (-82.0) [TVD] 

GETHING

BLUESKYDATUM: TOP OF BLUESKYJET PERFORATIONCONDENSATE SQUEEZE

JET PERFORATIONJET PERFORATIONJET PERFORATION

JET PERFORATIONCEMENT SQUEEZE

PACKER-BRIDGE PLUG

JET PERFORATION

RR: 2005-03-06FormTD: GETH

Fluid: N/A

ATLAS ET AL RWE MOONEY


KB: 762.7 m 00/08-14-072-08W5/0

RR: 1988-10-02FormTD: BANFF

Fluid: Oil

RWE MOONEY

Mode: SuspTD: 975.0 m [TVD]

KB: 792.8 m 00/08-24-072-08W5/0


Fluid: Oil

GULF ET AL MOONEY

Mode: Abd ZoneTD: 1045.0 m [TVD]

KB: 845.2 m 00/14-18-072-07W5/0

< 2312.1 m> < 1246.1 m> < 2012.0 m>


Fluid: N/A

ATLAS RWE MOONEY

Mode: Abnd TD: 935.0 m [TVD]

KB: 800.0 m 00/13-08-072-07W5/0


Fluid: N/A

ATLAS RWE MOONEY


KB: 793.1 m 00/12-16-072-07W5/0

< 1799.8 m>

A A'

Mannville

1

850(-87.3)

875(-112.3)

2

850(-57.2)

875(-82.2)

900(-107.2)

925(-132.2)

950(-157.2)

975(-182.2)

925(-79.8)

950(-104.8)

975(-129.8)

1000(-154.8)

1025(-179.8)

1050(-204.8)

850(-50.0)

875(-75.0)

900(-100.0)

925(-125.0)

850(-56.9)

875

900(-106.9)

925(-131.9)

(-81.9)Not specified

Diamond, conventional1

Diamond, conventional


1

2

Bluesky5m gross

Bluesky6m gross

Bluesky7m gross

Bluesky5m gross

Bluesky7m gross

25 m

see map page 44

Murphy’s considerable land base at Seal ( map page 51), which includes holdings from the recent Shell Canada Energy (subsidiary of Royal Dutch Shell) agreement which the company considers a long-term oil project, contains 930 E6M3 (5.85 billion barrels) of oil-in-place in the Cretaceous Bluesky-Gething interval (May 2012, November 14, 2012 presentations). Less than 5% of that total (4.3 E6M3 - 27 million barrels) is currently classed as proven reserves, while a further 2.4 E6M3 (15 million barrels) are categorized as probable (November 14, 2012 company presentation). Expected

ultimate recovery (EUR) for the present and proposed polymer projects alone is 7.2 to 11.9 E6M3 (45-75 million barrels) of oil. The current polymer scheme, a seven-well (3 injectors/4 producers, all horizontal) pilot scheme implemented in the southern half of T. 83, R. 15W5, started injection in July 2010. First response was obtained in July 2011. The polymer pilot project has “exceeded expectations” ( graph page 50); in May 2012, Murphy reported that it had 60.4 M3/d (380 bpd) of incremental oil production from four wells, which is in the upper portion of the “targeted range of response” for the

850.00

900.00

BLUSKY870.0 (-107.3) [TVD] <S> BLUESKY

860.00

970.00

BLUSKY885.1 (-92.3) [TVD] <S>

GETH911.9 (-119.1) [TVD] 

BANFF958.0 (-165.2) [TVD] <S>

BANFF

920.00

1050.00

BLUSKY940.2 (-95.0) [TVD] <S>

GETH967.0 (-121.8) [TVD] <S>

BANFF1033.6 (-188.4) [TVD] <S>

BLUESKY

GETHING

840.00

940.00

BLUSKY888.7 (-88.7) [TVD] 

GETH915.9 (-115.9) [TVD] 

BLUESKY

GETHING

840.00

930.00

GETH902.7 (-109.6) [TVD] 

BLUSKY875.1 (-82.0) [TVD] 

GETHING

BLUESKYDATUM: TOP OF BLUESKYJET PERFORATIONCONDENSATE SQUEEZE

JET PERFORATIONJET PERFORATIONJET PERFORATION

JET PERFORATIONCEMENT SQUEEZE

PACKER-BRIDGE PLUG

JET PERFORATION


Fluid: N/A

ATLAS ET AL RWE MOONEY


KB: 762.7 m 00/08-14-072-08W5/0


Fluid: Oil

RWE MOONEY

Mode: SuspTD: 975.0 m [TVD]

KB: 792.8 m 00/08-24-072-08W5/0


Fluid: Oil

GULF ET AL MOONEY

Mode: Abd ZoneTD: 1045.0 m [TVD]

KB: 845.2 m 00/14-18-072-07W5/0

< 2312.1 m> < 1246.1 m> < 2012.0 m>


Fluid: N/A

ATLAS RWE MOONEY


KB: 800.0 m 00/13-08-072-07W5/0


Fluid: N/A

ATLAS RWE MOONEY


KB: 793.1 m 00/12-16-072-07W5/0

< 1799.8 m>

A A'

Mannville

1

850(-87.3)

875(-112.3)

2

850(-57.2)

875(-82.2)

900(-107.2)

925(-132.2)

950(-157.2)

975(-182.2)

925(-79.8)

950(-104.8)

975(-129.8)

1000(-154.8)

1025(-179.8)

1050(-204.8)

850(-50.0)

875(-75.0)

900(-100.0)

925(-125.0)

850(-56.9)

875

900(-106.9)

925(-131.9)

(-81.9)Not specified

Diamond, conventional1



1

2

Bluesky5m gross

Bluesky6m gross

Bluesky7m gross

Bluesky5m gross

Bluesky7m gross

25 m

project. The incremental oil recovery from polymer injection is estimated to be 5-10%. Positive results from this polymer pilot project has resulted in government approval of Phase 1 of a commercial polymer flood in Q2 2012 (approval of Phase 2 is expected in Q4 2012). Phase 1 polymer injection began in August 2012.

Murphy’s current EOR focus at Seal also includes thermal projects. Present schemes include a vertical steam pilot and a one-well cyclic steam pilot, both in T. 85, R. 17W5. Another

contemplated EOR scheme is polymer-thermal. The company’s total production at Seal is expected to be over 1,430 M3/d of oil equivalent (9,000 boe/d), once the Shell transaction (see below) is completed, most of it conventional primary heavy oil production (November 13, 2012 Murphy news release).

On November 13, 2012, Murphy announced an agreement, which was expected to take effect in Q4 2012, to purchase major assets at Seal from Shell Canada Energy. This arrangement includes operatorship, production, plant and equipment,


EXPLORATION REVIEW

Start of PolymerInjection(October 2010)

Targeted range of response

Start of Area 1Injection

(August 2012)

700

600

500

400

300

200

100

0

Oct-10

Dec-10Feb-11

Apr-11

Jun -11Aug-11

Oct-11

Dec-11

Feb-12Apr-1

2Jun-12

Aug-12Oct-1

2

BO

PD

Production rAte vS. time, SeAl Polymer PilotFrom Murphy wesite, November 2012

and about 60,108 net hectares, which raises the company’s total land holding in the Seal core area to over 133,951 net hectares. Some of the agreement land was previously held 50:50 by Shell and Murphy.

Incidentally, Shell’s holdings at Seal, among other assets, had been purchased from private BlackRock Ventures in 2006. Former BlackRock senior management eventually went on to lead BlackPearl Resources (see discussion on Mooney, above).

Murphy expects to drill and complete 78 horizontal wells at Seal in 2012 (BMO Energy Daily, 15 November, 2012).

Beyond Conventional Resources Extraction

As titled in a recent issue of the Oil & Gas Inquirer (January/February 2013), which is published by JuneWarren-Nick-le’s Energy Group, secondary methods of recovery such as waterflooding are now aiming to make horizontally-ex-ploited unconventional tight oil reservoirs, “good to the last drop”, notably in the Beaverhill Lake, Bakken, Shaunavon, Viking and Cardium in the western Canadian provinces. The future could eventually see production-enhancing tertiary recovery schemes for tight reservoirs, as the world’s economy inexorably continues to grow and petroleum self-sufficiency remains the mantra in the US, and even Canada.



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T86

R12W5R13R14R15R16R17R18R19

R11W5R12R13R14R15R16R17R18R19


DAWSON

WALRUS

SEAL

SLAVE

CLIFFDALECADOTTE

Polymer Pilot+ Commercial PolymerProject, Phase 1


T86

T85

T84

T83

T82

T81

T80

R11W5R18 R17 R16 R15 R14 R13 R12R19

Murphy LandFreehold First Nations Shell Land (now Murphy)

Shell Canada LicencesBluesky Production

Murphy Oil LicencesNN N


EXPLORATION REVIEW

Alberta Energy, 2005-2012. Innovative Energy Technologies Programs (IETP). Annual and final reports prepared and submitted by approved projects. http://www.energy.gov.ab.ca/oil/768.asp

Glass, D.J., ed., 1990. Lexicon of Canadian stratigraphy, Volume 4 Western Canada. Canadian Society of Petroleum Geologists.

Hayes, B., Griffith, L. and carey, J., 2008. “Glauconitic” oil reservoirs in southern Alberta – creating the correct geological model to guide development drilling. Extended abstract, 2008 CSPG, CSEG and CWLS Convention Core Conference, 5 p.

Jackson, P.C., 1984. Paleogeography of the Lower Cretaceous Mannville Group of western Canada. In: J.A. Masters, ed. Elmworth – case Study of a deep Basin Gas Field. American Association of Petroleum Geologists Memoir 38, pages 49-78.

Rosenthal, L.R.P., 1988. Wave dominated shorelines and incised channel trends: Lower Cretaceous Glauconitic Formation, west-central Alberta. In: Sequences, stratigraphy, sedimentology; surface and subsurface, James, D.P. and Leckie, D.A. (eds.). Canadian Society of Petroleum Geologists, Memoir 15, pages 207-220.

Sherwin, M.D., 2001. Mannville paleotopography and depositional trends in the Glauconitic Formation, southern and central Alberta. Extended abstract, Canadian Society of Petroleum Geologists convention, Calgary, June 18-22, 2001. 4 p.

Sherwin, M.D., 1996. Channel trends in the Glauconitic Member, southern Alberta. Bulletin of Canadian Petroleum Geology, vol. 44, no. 3, pages 530-540.

Warters, W. J., Cant, D. J., Tzeng, H. P. and Lee, P. J., 1997. Mannville gas resources of the Western Canada Sedimentary Basin: Geological Survey of Canada Bulletin 517, 101 p.

Wood, J. M. and Hopkins, J. c., 1989. Reservoir sandstone bodies in estuarine valley fill: Lower cretaceous Glauconitic Member, Little Bow Field, Alberta, Canada. American Association of Petroleum Geologists Bulletin, vol. 73, no. 11, pages 1361-1382.

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