Light volatile liquid and gas shale potential Canada.pdf

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Light volatile liquid andgas shale reservoir potentialof the Cretaceous Shaftesbury

Formation in northeasternBritish Columbia, CanadaGareth R. L. Chalmers and R. Marc Bustin

A B S T R A C T

The geologic controls on reservoir properties and potential hy-

drocarbon (volatile, low-molecular-weight liquid and gas) re-sources of the Cretaceous Shaftesbury Formation in north-eastern British Columbia have been investigated. Maturityvaries from the oil todry gas window (Tmax= 429486C), withincreasing maturity and depth of burial toward the south. TheTmax, in degrees Celsius, is the oven temperature at the peakgeneration of S2 during pyrolysis. Total organic carbon (TOC)content ranges between 0.64 and 8.0 wt. %, with an averageof 2.2 wt. %. The TOC content distribution mirrors the trendsin maturity, with lower TOC content in areas of high matu-rity. Kerogen is characterized as either type II-III or type III.The quartz content ranges between 33 and 66%, with higherquartz content in areas with lower TOC content and greatermaturities. Porosity ranges between 4.5 and 14.6%, with higherporosities observed within shallower wells, low quartz con-tent, or maturities, or a combination of all three. The porosityis reduced in high-maturity samples by mechanical compac-tion and silica cementation. Total gas capacities range between4.5 and 24.8 cm3/g, and gas-in-place (GIP) estimates are be-tween 0.98 and 3.39 bcf/(section meter). The calculatedhydrocarbon generation is less than 3.6 bcf/(section meter),

with light liquid generation between 3.7 and 516.2 MMBO.Present-day depths and organic maturity have strong

influences on the hydrocarbon capacity more so than TOC

A U T H O R S

Gareth R. L. Chalmers Department ofEarth and Ocean Sciences, University of BritishColumbia, 6339 Stores Road, Vancouver, BritishColumbia, Canada; [email protected]

Gareth R. L. Chalmers is a postdoctoral researchfellow at the University of British Columbiafocusing on the geologic controls on liquid andgas shale reservoirs. He is the global directorof Chalmcoal Consulting, and he received hisPh.D. from the University of British Columbia.

R. Marc Bustin Department of Earth andOcean Sciences, University of British Columbia,6339 Stores Road, Vancouver, British Columbia,Canada; [email protected]

R. Marc Bustin is a professor of petroleum andcoal geology in the Department of Earth andOcean Sciences at the University of British Co-lumbia and the president of R. Marc BustinEarth Science Consultants. Bustin is an electedfellow of the Royal Society of Canada.

A CKNOWLE DGE M E NTS

We thank the EnCana Corporation for providingfinancial assistance and drill cuttings. We ac-knowledge funding from Geoscience BC andthe Natural Sciences and Engineering Research

Council and technical assistance from CBMSolutions. We thank the AAPG Editors StephenLaubach and Frances Whitehurst and thereviewers Dale Leckie, Julia Gale, and ThomasWhitfield for their helpful comments andsuggestions.The AAPG Editor thanks the following reviewersfor their work on this paper: Julia F. Gale, DaleA. Leckie, and Thomas G. Whitfield.

Copyright 2012. The American Association of Petroleum Geologists. All rights reserved.

Manuscript received March 24, 2011; provisional acceptance June 16, 2011; revised manuscript received

September 14, 2011; final acceptance October 4, 2011.

DOI:10.1306/10041111041

AAPG Bulletin, v. 96, no. 7 (July 2012), pp. 13331367 1333


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content. Deeper, higher maturity samples in thesouth have the largest total gas capacity and GIPestimates (0.983.39 bcf/[section meter]). Ma-turity is within the dry gas window in the south-ern one-third of the study area. Highest volumesof light liquid hydrocarbons are found within the

less mature northern part of the study area.

INTRODUCTION

Gas shale exploitation to date in northeastern Brit-ish Columbia has focused on the Devonian shalewithin the Horn River Basin and Cordova em-bayment and on the shale and tight sand hybridwithin the Triassic Doig and Montney formations.

These strata are exploited where the maturity ex-ceeds the oil window, with the general assumptionthat the absence of liquid phase is required forcommercial production. With the recent success-ful exploitation and economic importance of vol-atile liquids (light oil and condensate) from stratawith maturities that correspond to the oil windowsuch as the Eagle Ford (Texas), Marcellus (Appala-chia), and Barnett (Texas), a renewed interest inevaluating and reevaluating organic shales that liein the oil window is observed. One of the thickest

and most laterally extensive fine-grained intervalsin western Canada is the Cretaceous ShaftesburyFormation. This formation is thick, organic rich,and ranges in organic maturity from the oil to gaswindow, with the potential of containing both vol-atile liquids and gas resources. Mud logs confirmthat free gas is present throughout the ShaftesburyFormation albeit at varying levels.

This article evaluates the shale gas and hydro-carbon liquid potential of the Cretaceous Shaftes-

bury Formation within the Deep Basin (Masters,1984) trough area south of Fort St. John in BritishColumbia (Figure 1). The objectives of this re-search are to (1) identify the geologic controls onthe distribution of the hydrocarbon capacity ofthe Shaftesbury Formation, (2) identify zones ofgreater gas and volatile liquid potential within thethick sequences, and (3) estimate and identify con-trols on the distribution of the maximum gas-in-place (GIP) capacity.

GEOLOGIC BACKGROUND

The Cretaceous Shaftesbury Formation is definedfor the strata bound by the underlying Peace Riverand the overlying Dunvegan formations alongthe Peace River in northeastern British Columbia

(McLearn and Henderson, 1944) (Figure 2). Previ-ous studies of the Shaftesbury Formation and equiv-alent lower Colorado Group are mainly within Al-berta (Bhattacharya and Walker, 1991; Leckie et al.,1992, 1994; Bloch et al., 1993, 1999; Bhattacharya,1994; Plint, 2000), with limited published data onthe Shaftesbury Formation within British Columbia(i.e., McLearn and Henderson, 1944; Stott, 1982).

The Shaftesbury Formation was deposited ina foreland basin resulting from the downflexing

of the western margin of the North Americancraton (Leckie and Smith, 1992) during the Cre-taceous. The study area has experienced maxi-mum subsidence and sedimentation rates becauseof its proximity to the Cordilleran fold and thrustbelt during the Laramide orogeny (mid-JurassicTertiary; Leckie and Smith, 1992). Basin modelsfor the Alberta Basin suggest that as much as 3 km(2 mi) of sediment was eroded during the sub-sequent uplift that followed the burial of sedi-ments during the Laramide orogeny (Ness, 2001).

Kalkreuth and McMechan (1988) calculated thatLower Cretaceous sediments within the foothillsof east-central British Columbia experienced asmuchas 6 km (4 mi) ofuplift and erosion fromthemaximum depth of burial.

The thickness of the Shaftesbury Formationranges between 259 and 823 m (850 and 2700 ft)within the Peace River area of northeastern BritishColumbia (Stott, 1982). On a regional scale, thethickness of the Shaftesbury Formation decreases

from the Cordilleran fold and thrust (deformation)belt toward the east and southeast into east-centralAlberta (Bhattacharya, 1994). The study area isproximal to the deformation belt. The ShaftesburyFormation is composed of dark-gray noncalcareousshale and mudstone, with the upper parts becom-ing sandier in a transitional zone with the overlyingDunvegan Formation. The Shaftesbury Formationhas a sharp basal contact with the Paddy Memberof the Peace River Formation (Figure 2). Based on

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the stratigraphic names proposed by Bloch et al.(1993, 1999), the lower section of the ShaftesburyFormation is equivalent to the Westgate Member;the middle section, to the Fish Scales Sandstone;and the upper section, to the Belle Fourche Sand-

stone Member (Figure 2). For light volatiles andgas shale evaluation, we have separated the Shaftes-bury Formation into four units: basal organic-richunit (BOU), lower Shaftesbury unit (LSU), basalFish Scale unit (BFSU), and upper Shaftesbury unit(USU;Figure 2).

The Shaftesbury Formation is the result of amajor transgression that connected both the Borealand Gulfian seas within the Western Interior sea-way (Williams and Stelck, 1975). During this ma-

jor transgression, periods of sea level fall caused bytectonic activity were also observed (Bloch et al.,1999). The basal section of the Shaftesbury For-mation (equivalent to our BOU), within the town-ship of Peace River, Alberta, is an organic-rich,

radioactive, shallow-water condensed section thatwas deposited in restricted marginal-marine con-ditions that progressively deepened into a nearshoreopen marine setting (Leckie et al., 1990). The min-eralogy of the Westgate Member (equivalent toLSU) consists of quartz, potassium feldspar, mus-covite, kaolinite, mixed layer illite, and smectite,with minor amounts of chlorite, pyrite, glauconite,and siderite (Bloch et al., 1993). The Fish ScaleSandstone (equivalent to the BFSU) has a similar

Figure 1.Location ofstudy area in northeasternBritish Columbia, Canada,and the wells examined inthis study. Adsorption iso-therms were measured onwells that have either astar or a diamond symbol.All ranges are west of thesixth meridian. RE = sam-ples analyzed by Rock-Evalpyrolysis; sorption =methane sorption analysis;XRD = mineralogical anal-ysis by x-ray diffraction.

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mineralogy to the Westgate Member but containsmore pyrite and may contain dolomite and apatitein the form of phosphatic beds. The Fish Scale

Sandstone was deposited in anoxic stratified-bottomwaters, with fish scales concentrated within coarsersediments (Leckie et al., 1992). The unique com-bination of coarser sediments and high total organiccarbon (TOC) content within the Fish Scale Sand-stone has created a gas shale and tight sand hybrid,with wells being completed in southern and centralAlberta (Benteau and Faraj, 2008). Flow rates aregenerally low with rates between approximately2 and 250 mcf/day (Benteau and Faraj, 2008), with

average wells producing less than 150 mcf/day(Dawson, 2008).Kalkreuth and McMechan (1988) examined the

regional maturation distribution of Cretaceous coal-bearing strata in northeastern British Columbiathat include this study area. The overall maturitydistribution reflects the depth of burial of the Cre-taceous strata, with maturity decreasing from thedeformation front toward the northeast. The isore-flectance lines are parallel with the deformation

front with the exception at Dawson Creek and thePeace River arch where the isoreflectance lines de-viate toward the northeast. The maturity deviation

is the result of the localized thickening of stratacaused by the downwarping of the Peace Riverarch (Kalkreuth and McMechan, 1988).

APPROACH AND METHODS

A total of 448 samples from 27 wells have beenanalyzed for Rock-Eval organic geochemistry, quan-

titative mineralogy, porosity, surface area analyses,and sorbed gas and total gas capacities. A suite ofgeophysical logs in conjunction with the drillcuttings was used to define the stratigraphy andstructure of the Shaftesbury Formation within thestudy area. Samples were collected as fresh drillcuttings and in-situ reservoir properties were notpreserved. Because samples were not preserved atreservoir conditions, the water and gas saturationsare not known.

Figure 2.Stratigraphic table of the Cre-taceous stratigraphy of northeastern BritishColumbia and northwestern Alberta (modi-fied from Jowett and Schroder-Adams, 2005,used with permission from the Bulletin ofCanadian Petroleum Geology). The unitsused within this study are shown. The north-ern British Columbia equivalent of the Shaftes-bury Formation includes the shales of theHasler and Cruiser formations and thesandstone-dominated Goodrich Formation.The equivalent Colorado Group withinAlberta can be separated into the Westgate,Fish Scale, and Belle Fourche units (Blochet al., 1993). The light-gray shading rep-resents sandstone-dominated formations,and the dark-gray shading represents shale-dominated formations. FSMB = Fish Scalesmarker bed.



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Figure 3. Structural cross section DDshowing the stratal geometries, maturity (Tmax), total organic carbon (TOC) content, quartz content,Shaftsbury Formation and the Dunvegan and Paddy units. Gas contents from mud logs are also shown for B-37-A-93-P-10, C-43-B-93-P-8, anoriented along the depositional strike, with the exception of well C-43-B that is positioned farther downdip than the other wells (refer ttemperatures (C) on the right side of the cross section are calculated using hydrostatic and geothermal gradients. GR = gamma ray; ga

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Isopach and Structural Maps andCross Sections

Isopach maps were constructed for the Shaftes-bury Formation and the four unitsUSU, BFSU,LSU, and BOU. The Shaftesbury Formation and

informal unit tops were defined from gamma-rayand resistivity logs for all wells in the study area(Figure 1). Two structural cross sections illustratereservoir properties parallel with depositional strike(DD) and dip (AA) (Figures 3,4). Downhole dis-tributions for gamma ray, maturity (Tmax), TOCcontent, and mineralogy were determined for allwells. A selection of wells also illustrates distribu-tion for porosity, methane sorption capacity at res-ervoir pressure and at an arbitrary pressure of 6 MPa

(870 psi; for comparison between locations with-out variation in reservoir pressure), and GIP esti-mates on a bcf/(section meter) basis, using amoving average of 50-m (160-ft) intervals.

Rock-Eval and Organic Geochemistry

Organic geochemistry was determined by Rock-Eval pyrolysis and TOC content analysis. From theRock-Eval analysis, maturity, TOC content, hydro-

gen index, and S1 and S2 values were used forthis study. Thermal maturity was determined fromTmax in degrees Celsius, which is the oven tem-perature at the generation peak of S2, and S1 is theamount of free liquid hydrocarbons that is presentwithin the sample. The S1 data are used to cal-culate the volume of liquid hydrocarbons withinthe Shaftesbury Formation. The S2 peak resultsfrom the cracking of kerogen and represents thetotal residual hydrocarbons that can be produced

from the source rock. The difference in S2 betweenimmature and mature rocks is used to calculate themaximum volume of hydrocarbons generated.

HighPressure Methane Sorption Isotherms

The methane capacity of samples was determinedby a high-pressure (020 MPa [02900 psi]) volu-metric sorption apparatus. All samples were ground

to pass a 60-mesh (250-mm) sieve. Ground sampleswere placed in an atmosphere of saturated solu-tion of KCl at 30C to obtain equilibrium mois-ture (ASTM D 1412-04, 2004). Moisture contentwas measured by oven-drying, weight-loss calcu-lations. All analyses reported here were performed

under their respective reservoir temperatures,and isothermal conditions were maintained (lessthan 0.1C). Gas volumes are reported at stan-dard temperature and pressure in cubic centime-ters per gram of rock both at reservoir (hydrostatic)pressure and at the arbitrary pressure of 6 MPa(870 psi). The repeatability of analysis is less than4% difference in the gas volumes calculated.

X-Ray Diffraction and Rietveld Analysis

Crushed samples (


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Figure 4.Structural cross section AA shows stratal geometries, maturity (Tmax), total organic carbon (TOC) content, quartz content, aShaftesbury Formation and the Dunvegan and Paddy units. The gas content from mud logs is also shown in the B-86-H-93-P-7 well. The croReservoir pressure (MPa) and temperatures (C) on the right side of the cross section are calculated using hydrostatic and geothermal gradgas content from mud logs.

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porosimetry do not consider water saturation orthe microporosity of the sample but still providevaluable information of the pore-size distributionwithin the mesopore- and macropore-size ranges.

The total gas capacity is the measurement ofthe maximum volume of sorbed, free, and solu-tion gas within the shale. To calculate the total gascapacity, the volume occupied by sorbed gas issubtracted from the total porosity to yield the po-rosity available to free gas. The volume occupiedby moisture is not considered in these free gas cal-culations. Moisture within the pore system wouldreduce the total gas capacity of the reservoir.

The mesoporous surface area of each samplewas determined by a Quantachrome Autosorb-1using N2 gas adsorption at low temperature andpressure (196C and


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Reservoir Depths, Structure, Thickness, andGas Contents of the Shaftesbury Formation

Within the study area, the depths range between500 and 2100 m (1640 and 6890 ft), with reser-

voir pressures between 5 and 21.6 MPa (725 and3132.8 psi) and reservoir temperatures between 16and 72C (cross sections DD and AA; Figures 3, 4,respectively). The depth to the base of the Shaftes-bury Formation increases to the south from 21 to

Figure 6.Isopach maps for (A) the Shaftesbury Formation, and the four units: (B) upper Shaftesbury unit (USU), (C) basal Fish Scaleunit (BFSU), (D) lower Shaftesbury unit (LSU), and (E) basal organic-rich unit (BOU). The thicknesses generally increase to the west.



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Figure 7. Maturity distribution using maturity (Tmax) averages for (A) the Shaftesbury Formation, and the four units: (B) upperShaftesbury unit (USU), (C) basal Fish Scale unit (BFSU), (D) lower Shaftesbury unit (LSU), and (E) basal organic-rich unit (BOU). Theblack solid line demarks the 445C isotherm that is the average for all samples in the Shaftesbury Formation. The black dashed linerepresents the 455C isotherm that represents the initiation of thermal gas generation (Tissot and Welte, 1984; Leckie et al., 1988;Schimmelmann et al., 2006).



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Figure 8.Average total organic carbon (TOC) content distribution across the study area for (A) the Shaftesbury Formation, and the fourunits: (B) upper Shaftesbury unit (USU), (C) basal Fish Scale unit (BFSU), (D) lower Shaftesbury unit (LSU), and (E) basal organic-rich unit(BOU). The lowest TOC contents are found in areas that have experienced the highest maturity levels.



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1422 m (694665 ft) below sea level (Figure 5).All units increase in thickness toward the west,with the greatest cumulative thickness (>416 m[>1365 ft]) in the western one third of the studyarea (Figure 6). The average thickness of the BOUis 29 m (95 ft), 179 m (587 ft) for the LSU, and181 m (594 ft) for the USU (Figure 6). The BFSU(with an average thickness of 27 m [89 ft]) alsoshows a thickness increase toward the west, withthe exception of the A-29-B-93-P-7 well in thesouthwestern part of the study area (Figure 6).

Where available, downhole gas profiles frommud logs have been included within both cross sec-tions (Figures 3,4). Gas volumes increase withinthe lower parts of the USU and into the BFSU aswell as within the lower parts of the LSU and intothe BOU. The Tmax, TOC content, quartz con-tent, and porosity profiles are also shown in crosssections DDand AA. The downhole profiles are

illustrated within the following sections on the dis-tribution of reservoir properties within the studyarea.

Maturity and Organic Geochemistry

The average Tmax for the Shaftesbury Formationwithin the study area is 445C and ranges between429 and 486C (Figure 7). Maturity consistently

increases from the top to the bottom of the Shaftes-bury Formation (Figures 3,4), with an overall in-crease in maturity from north to south, consistentwith the current stratal depths. An anomalous lowis centered near the A-29-B-93-P-7 well because ofthe lower Tmax values in the USU (Figure 4). Whenconsidering all of the Shaftesbury Formation, al-most one-third of the study area is within or greaterthan the initial generation of thermogenic gas (Tmax,455C), with the rest of the study area within theoil generation window (Tmax, >435C; Tissot and

Welte, 1984; Leckie et al., 1988; Schimmelmannet al., 2006).

The average TOC content for the ShaftesburyFormation is 2.2 wt. % and ranges between 0.64and 8.0 wt. %. The TOC content mapped for theShaftesbury Formation and each unit (Figure 8) areaveraged over the respective interval in each well.The averaged TOC content between units ranges

between 1.25 and 4.3 wt. %. The BSFU has thehighest average TOC content of 2.9 wt. %, with theBOU having the second highest average of 2.5%.Gamma-ray profiles peak within these two units,for instance, hottest shale (Figures 3,4). The USUand LSU have TOC content averages of approxi-mately 2 wt. %. The TOC content decreases to-ward the southwestern corner of the study area forall units. A northeastern-southwestern trough oflow values that extends through the center of the

Figure 9.The relationship between S2and total organic carbon (TOC) content(Langford and Blanc-Valleron, 1990) pro-vides information on the kerogen typeswithin the Shaftesbury Formation. The black-filled circles are mature samples (Tmax,>430C), whereas the open triangles areconsidered immature samples (


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study area is also observed (Figure 8). Downholeprofiles for the TOC contents are similar betweenwells, with higher TOC contents within the BOU

and a low TOC content within LSU that increasestoward and peaks within the BFSU and then de-clines toward the top of USU. These profiles are

Figure 10.The hydrogen index (HI; well averages) trend across the study area for (A) the Shaftesbury Formation, and the four units:(B) upper Shaftesbury unit (USU), (C) basal Fish Scale unit (BFSU), (D) lower Shaftesbury unit (LSU), and (E) basal organic-rich unit(BOU). Lower HI is found within the more mature parts of the study area (southwestern corner) as more hydrocarbons are generated.The highest HI is associated with the immature kerogen in the northwestern part of the study area and more closely resembles theoriginal organic geochemistry of the kerogen compared with the mature kerogen. The thicker black line represents the overall average HIvalue for the Shaftesbury Formation, which is 130 mg HC/g rock.



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pronounced within wells B-51-F-93-P-9 and A-29-B-93-P-7 in cross section AA(Figure 4).

Kerogen types have been interpreted from thecrossplot of S2 and the TOC content (Langford andBlanc-Valleron, 1990) and most plot within thefields of type II-III and type III, with the remainderin types II and IV (Figure 9). The hydrogen index(HI) ranges between 13 and 399 mg HC/g TOC,with an average of 123 mg HC/g TOC (Figure 10).Most of the samples have an HI less than 200 mgHC/g TOC (90%). The HI decreases from thenortheastern toward the southwestern part of thestudy area. The oxygen index ranges between 0 and78 mg CO2/g TOC, with a mean value of 17 mgCO2/g TOC.

Mineralogical Composition of theShaftesbury Formation

Mineralogy is similar between wells and plots withina relatively small field, with carbonate content av-eraging less than 13% (most of the samples have


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Figure 12.The distribution of the average quartz content for (A) the Shaftesbury Formation, and the four units: (B) upper Shaftesburyunit (USU), (C) basal Fish Scale unit (BFSU), (D) lower Shaftesbury unit (LSU), and (E) basal organic-rich unit (BOU). Higher quartzcontents overlay the higher maturity areas of the study area and suggest that silicification of clays occurred during diagenetic processes(see text for details). The thicker line represents an average quartz content of 37%.



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Figure 13.Average porosity (%) distribution for (A) the Shaftesbury Formation, and the four units: (B) upper Shaftesbury unit (USU),(C) basal Fish Scale unit (BFSU), (D) lower Shaftesbury unit (LSU), and (E) basal organic-rich unit (BOU). Porosity is lowest in areas ofhigher maturity and higher quartz contents, indicating that porosity is possibly lost because of both compaction and cementation byquartz. The black solid line represents an average porosity of 8%.



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porosity is found in the shallower wells and withinthe BSFU. The BOU contains the lowest porosity,with the exception of D-17-C-93-P-10 and 4-19-78-10. The D-17-C-93-P-10 well has consistentlyhigh porosity in all units. A positive trend existsbetween TOC content and porosity (Figure 14A),with a negative trend between porosity and ma-

turity (Figure 14B) caused by the negative re-lationship between maturity and TOC content(Figure 14C).

To compare the pore-size distribution betweensamples and with the TOC content, quartz con-tent, and maturity, five BFSU samples from fivewells were selected for detailed analyses (Table 1;Figure 15). Greater porosity is found within sam-ples that contain many more macropores thanmesopores (i.e., D-10-C-1330; Figure 15). The

lower porosity samples have approximately anequal proportion of mesoporosity and macropo-rosity (Table 1), with most of the pores rangingfrom 40 to 100 mm and 6 to 20 nm.

Using the samples from the C-4-J-93-P-1 well,the relationship between the pore-size distributionand depth is illustrated in Table 2 andFigure 16.

Porosity decreases with depth from 11.6 to 4.1%,with the samples showing a reduction in the macro-pore range and a relative increase in the mesopores,particularly, in the 3- to 10-nm range (Figure 16).The contribution of macroporosity and mesoporos-ity to the total porosity is shown inTable 2. Meso-pores increase from 5 to 26% of the total porosity,with increasing depth from 1905 to 2115 m (62506939 ft). A general trend of increasing micropo-rosity (microporous surface area) and mesoporosity

Figure 14. The interrelationship between porosity, total organic carbon (TOC) content, and maturity. (A) A positive trend existsbetween the TOC content and porosity. (B) This relationship exists because the porosity is destroyed with increasing burial and maturity,and (C) simultaneously, the TOC content decreases because of hydrocarbon generation. Samples that are more mature have low

porosity and TOC content compared with immature samples. The porosity that is created during hydrocarbon generation caused by TOCshrinkage is not as significant as the porosity that is destroyed by diagenesis.



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with increasing maturity and depth is observed for

the samples in both Tables 1 and 2.

Sorption and Total Gas Capacity

Methane sorption capacity was determined forrepresentative samples across both the study areaand the stratigraphy. For comparative purposes,all sorption capacities are compared at a pres-sure of 6 MPa (870 psi; Figure 17). The averagemethane sorption capacity at 6 MPa (870 psi) is

0.9 cm3/g (29 SCF/ton) and ranges between 0.13

and 2.28 cm3

/g (2.9

73 SCF/ton). Wells that havea below-average capacity occur in the northwest-ern corner of the study area (Figure 17), with above-average capacities (>1.1 cm3/g) in the southernpart of the study area.

No trend exists between methane capacity at6 MPa (870 psi) and TOC content (Figure 18; dia-monds). Shaftesbury samples have a higher sorp-tion capacity compared with Cretaceous Bucking-horse shale samples (open squares; Chalmers and

Table 1.Five Basal Fish Scale Unit Samples Chosen to Compare Total Porosity to Pore-Size Distribution, Surface Area, Maturity, andwith Total Organic Carbon Content and Quartz Content*

Sample ID

Macropore

(% of Hg Porosity)

Mesopore

(% of Hg Porosity)

DR**

Micropore

Surface Area

BJH**

Surface

Area

Total

Porosity

(Hg)

TOC**

Content

(wt. %)

Quartz

Content

(%)

Tmax(C)

Calculated

Ro(%)

B-37-A-1390 45 55 7.14 4.36 4.0 1.7 40.2 451 0.98

D-A90-B-1550 58 42 62.5 5.04 5.4 1.7 42.4 451 0.98C-43-B-1625 72 28 17.56 12.31 8.5 5.2 34.4 437 0.71

D-17-C-1330 92 8 8.23 11.81 11.9 4.2 31.6 432 0.61

4-19-78-755 78 22 12.63 8.36 14.6 5.1 41.0 428 0.54

*Vitrinite reflectance (Ro) is calculated from the relationship between maturity (Tmax) and Roin Teichmuller and Durand (1983). The Hg porosity data are from the mercuryporosimeter.

**TOC = total organic carbon; DR = Dubinin-Radushkevich equation; BJH = Barrett, Johner and Halenda equation.Data collected from gas adsorption analysis (units in square meters per gram).

Figure 15.Pore-size distribu-tion by percent cumulative intru-sion volume for the five selectedsamples in Table 1. The cumu-lative percentage of pore vol-umes illustrates that the higherporosity samples contain greaterthan 80% macropores, and lowerporosity samples contain agreater proportion of mesopores.

indicates porosity. The samplename is a combination of thewell name and depth, for in-stance, 4-19-78-755 is from the4-19-78-10W6 well at a depthof 755 m (2477 ft).



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Bustin, 2008) at the same TOC content (Figure 18).Methane sorption capacity increases with maturity

for samples with capacities below 0.6 cm3

/g/TOC(diamond symbol; Figure 19A) Samples with ca-pacities greater than 0.6 cm3/g/TOC have a high S1(circle symbols; Figure 19B). High S1 is commonlyfound in lower maturity samples (420440C),with the S1 decreasing with increasing maturity(Figure 19C). The downhole profiles for the meth-ane sorption capacity at 6 MPa (870 psi) for a se-

lection of wells are shown in cross sections DD(Figure 20) and AA (Figure 21). No significant

trends between the units are observed because thedownhole variation is too low in comparison withthe methane sorption capacity at reservoir pressure.

The average methane sorption capacity at res-ervoir pressure is 1.8 cm3/g (58 SCF/ton), and thecapacities range between 0.14 and 6.15 cm3/g (4.5and 197 SCF/ton) across the study area (Figure 22).The methane capacity at reservoir pressure shows

Table 2.Pore-Size Distribution, Surface Area Maturity, Total Organic Carbon Content, and Mineralogical Properties of Four Samples inthe C-4-J-93-P-1 Well*

Sample ID

Macropore

(% of Hg Porosity)

Mesopore

(% of Hg Porosity)

DR**

Micropore

Surface Area

BJH**

Surface

Area

Total

Porosity

(Hg)

TOC**

Content

(wt. %)

Quartz

Content

(%)

Tmax(C)

Calculated

Ro(%)

C-4-J-1905 95 5 7.12 7.2 11.6 2.27 41.0 442 0.81

C-4-J-1995 80 20 6.71 4.15 7.6 1.67 42.9 463 1.22C-4-J-2030 80 20 8.55 5.77 6.0 1.96 38.7 440 0.77

C-4-J-2115 74 26 12.24 4.85 4.1 2.56 44.1 460 1.16

*Vitrinite reflectance (Ro) is calculated from the relationship between Tmaxand Ro in Teichmuller and Durand (1983). The Hg porosity data are from the mercury

porosimeter.

**TOC = total organic carbon; DR = Dubinin-Radushkevich equation; BJH = Barrett, Johner and Halenda equation.Data collected from gas adsorption analysis (units in square meters per gram).

Figure 16.Comparison be-tween pore-size distribution byincremental pore volume anddepth (from surface). Pore-sizedistribution is shown by the in-cremental pore volume thatintruded at a given pressure(converted to pore size). Macro-porosity destruction occurs withincreasing depth and relativeincrease in mesoporosity, par-ticularly toward the mesopore-

micropore boundary. No rela-tionship exists between the quartzcontent and pore-size distributionbecause of the small variation inquartz content between selectedsamples (Tables 1,2). The samplename is a combination of thewell name and depth, for instance,C-4-J-2115 is from the C-4-J-93-P-1 well at a depth of 2115 m(6939 ft).



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Figure 17.The distribution of average methane sorption capacities at 6 MPa (870 psi) for (A) the Shaftesbury Formation, and the fourunits: (B) upper Shaftesbury unit (USU), (C) basal Fish Scale unit (BFSU), (D) lower Shaftesbury unit (LSU), and (E) basal organic-rich unit(BOU). The arbitrary pressure of 6 MPa (870 psi) was selected to allow comparison between locations without the variation in reservoirpressure. The black line represents an average methane sorption capacity (at 6 MPa [870 psi]) of 0.9 cm 3/g. See Figure 22for averagemethane capacities at reservoir pressure.



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a similar distribution as the methane capacity at6 MPa (870 psi) with, in most cases, a shift to-ward higher values (Figures 17,22). Wells withinthe southern half of the study area have above-average methane capacities in all units. Downhole

profiles for methane sorption capacity at reservoirpressure in cross sections DD (Figure 20)andAA(Figure 21) show higher capacities within the BOUand BFSU (the 4-19-78-10 well is an exception).Methane sorption capacity increases from the BOUand LSU into the USU in the 4-19-78-10 well.

The average total gas capacity (free + sorbedgas) for the Shaftesbury Formation is 11 cm3/g(352 SCF/ton), with a minimum capacity of4.5 cm3/g (144 SCF/ton) and a maximum ca-

pacity of 24.8 cm3

/g (794 SCF/ton). The southerntwo-thirds of the study area have above-averagetotal gas capacity (Figure 23).

Gas-in-Place Estimates

Gas-in-place estimates are shown based on eitherthe unit thickness (bcf/section) or a 1-m (3-ft)thickness (bcf/[section meter]). The average

GIP estimates based on stratal thickness for theShaftesbury Formation are 317 bcf/section and rangebetween 115 and 726 bcf/section (Figure 24).Higher than average GIP occurs in the south andsouthwest. Two wells with the highest GIP esti-

mates (>600 bcf/section) are B-86-H-93-P-7 andC-4-J-93-P-1.

The GIP has been estimated for each unit ofthe Shaftesbury Formation. Similar GIP distribu-tions occur between the units with the exceptionof the BFSU. The average GIP value for the BOU is18 bcf/section and ranges between 9 and 49 bcf/section (Figure 24). The LSU has the highest GIPaverage compared with the other units (143 bcf/section), with estimates ranging between 50 and

265 bcf/section. The average GIP for the BFSU is20 bcf/section and ranges between 7 and 40 bcf/section. The general trend has changed within theBFSU from a north-south to an east-west direc-tion, with above-average GIP in the west and es-timates decreasing toward the east. The averageGIP for USU is 121 bcf/section within a range of79 to 217 bcf/section. The USU has limited databut still shows an above-average GIP in the south-western and western parts of the study area.

Figure 18.The relationshipbetween total organic carbon(TOC) content and methanesorption capacity for the Shaftes-bury and Buckinghorse forma-tions. No correlation between themethane sorption capacity (at 6MPa [870 psi]) and the TOC con-tent for the Shaftesbury Forma-tion (solid diamonds) is observedcompared with the positive trendfound in the Cretaceous Bucking-horse shale (open squares)(Chalmers and Bustin, 2008, usedwith permission from the Cana-dian Petroleum Geology). Lowervariation in the TOC contentcompared with the BuckinghorseFormation may be a factor inthe poor correlation. The highermethane capacities in the Shaftes-bury Formation are caused bynatural bitumen (i.e., high S1).See text for details.



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Gas-in-place estimates have also been calcu-lated as downhole profiles for selected wells inDD (Figure 20) and AA (Figure 21), with estimatesranging between 0.98 and 3.39 bcf/(section me-ter). In these calculations, the GIP is estimated on arockvolume of1 m (3 ft) 1 section using a moving

average of 50 m (160 ft). No similar downholeprofiles exist between wells in cross sections AAand DD. The GIP peaks vary stratigraphically be-tween wells and can be located in the basal part ofthe USU, in the middle to upper intervals of theLSU, or within the BOU. The average GIP per sec-tion meter for each analyzed well increases towardthe southern part of the study area (Figure 25). Alow GIP trough extends to the south, in the westernpart of the study area.

Calculations of Volume ofHydrocarbon Generated

Gas capacity calculations are based on the maxi-mum sorbed and free gas capacities and do not givean indication on the current amount of GIP, which

requires a sample suite with preserved reservoirconditions. Mass balance calculations from the dif-ference in organic geochemistry of immature andmature organic matter provide an estimation of thevolume of hydrocarbons generated within themost mature areas of the study area. For this study,the amount of hydrocarbons generated from thekerogen is estimated using the crossplot of S2 andmaturity (Jarvie et al., 2007). A crossplot of ma-turity and S2 shows the most immature samples

Figure 19. The interrelationship between methane sorption capacity, S1, and maturity. (A) A positive relationship exists betweenmaturity and methane sorption capacity at 6 MPa (870 psi) on a per-unit total organic carbon (TOC) content basis, with the exclusion ofsamples with a high S1 (circles). (B) Increasing organic maturation increases the ability for kerogen to sorb methane. Higher sorption

capacity (>0.8 cm3/g TOC) in the maturity (Tmax) of 435 to 450 is caused by the presence of bitumen-high S1. (C) S1 decreases withmaturity, indicating that S1 is from natural bitumen and not an invert drilling mud contaminant.



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Figure 20. Downhole profiles of methane sorption capacity at both 6 MPa (870 psi) and reservoir pressure, gas-in-place (GIP) estimates (section DD. The GIP is calculated as a moving average over 50-m (160-ft) intervals. Gas = methane gas content from mud logs; sorption gamma ray.

Chalmersand

Bustin

1355


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Figure 21. Downhole profiles of methane sorption capacity at both 6 MPa (870 psi) and reservoir pressure, gas-in-place (GIP) estimates (section AA. The GIP is calculated as a moving average over 50-m (160-ft) intervals. Gas = methane gas content from mud logs; sorption gamma ray.

1356

LiquidandGa

sShalePotentialoftheShaftesburyForm

ation,Canada


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Figure 22.The distribution of methane sorption (average) capacities at reservoir pressure for (A) the Shaftesbury Formation, and thefour units: (B) upper Shaftesbury unit (USU), (C) basal Fish Scale unit (BFSU), (D) lower Shaftesbury unit (LSU), and (E) basal organic-rich unit (BOU). The similar distribution between the methane sorption capacity at reservoir pressure and at 6 MPa (870 psi) indicatesthat the reservoir pressure does not affect the distribution pattern; only the absolute numbers. The thick black line represents an averagemethane sorption capacity of 1.8 cm3/g for all analyzed samples.



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Figure 23.The distribution of total gas (average) capacities for (A) the Shaftesbury Formation, and the four units: (B) upper Shaf-tesbury unit (USU), (C) basal Fish Scale unit (BFSU), (D) lower Shaftesbury unit (LSU), and (E) basal organic-rich unit (BOU). The total gascapacity is the sorbed gas with the calculated free gas component, assuming all pores are accessible to methane and no water saturation(Sw= 0). The porosity distribution shows that porosity is not the major control on the total gas capacity because capacity is high in low-porosity samples (i.e., C-4-J-93-P-1 well). Reservoir pressure is a major factor in the distribution of total gas capacity.



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to have an S2 of 13.35 mg HC/g rock whereas themost mature samples have an average S2 value of0.31 mg HC/g rock (Figure 26). Assuming that themature samples had a similar S2 when they were

at the similar maturity level as the immature sam-ples, these samples have generated 13.04 mg HC/grock. Using the calculations from Jarvie et al.(2007), 13.04 mg HC/g of rock is equivalent to

Figure 24.Gas-in-place (GIP) estimates using stratal thicknesses for (A) the Shaftesbury Formation, and the four units: (B) upperShaftesbury unit (USU), (C) basal Fish Scale unit (BFSU), (D) lower Shaftesbury unit (LSU), and (E) basal organic-rich unit (BOU). The GIPestimates increase toward the southern part of the study area, particularly toward the southwestern corner. Gas-in-place estimates are alsohigher in the western part of the study area because of the increase in the thickness of the Shaftesbury Formation. The black line representsthe average GIP value for each informal unit and the Shaftesbury Formation. See text for the average value for each unit.



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1.7 mmcf/ac-ft or 3.6 bcf/(section meter). To con-vert S2 (mg HC/g rock) to the volume of methane

(mcf/ac-ft), multiply S2 by 131.34 (Btu basis).Based on this calculation, the gas generation ex-

ceeded the gas capacity of the shale in most of thestudy area (C-4-J-93-P-1 is an exception; Figure 25).

The calculations to determine the volume ofliquid hydrocarbons present within the Shaftsbury

Figure 25. The average gas-in-place (GIP)estimates for each well calculated on a per-section meter basis using a 50-m (160-ft)moving average. The bulk density and totalgas measurements are used in the calcu-lations. The average GIP is 2.44 bcf/(section meter) and is highlighted by a thickerblack line.

Figure 26.Crossplot of S2 andmaturity (Tmax[C]) showing theamount of hydrocarbons thatcould have been generated bycomparing the S2 value of im-mature and mature samples.From this crossplot, 13.04 mg

HC/g rock was estimated fromsamples with maturity greaterthan aTmaxof 475C, which isequivalent to 3.6 bcf/(section meter) of hydrocarbons gener-ated using an average bulkdensity of 2.39 g/cm3. This is themaximum amount of hydro-carbons generated at the highestmaturity levels measured withinthe study area. TOC = total or-ganic carbon.



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Formation are based on the S1 from the Rock-Eval

analysis. The S1 value ranges between 0.01 and66.12 mg HC/g rock for the Shaftesbury Formation.The average S1 for each well is used to calculate thevolume of liquid hydrocarbons on a section pertotal thickness of the Shaftesbury Formation. Thevolumes range between 3.7 and 516.2 MMBO(Figure 27). The highest volume of liquids is foundwithin the lower maturity parts of the study areain the northeastern and northwestern flanks of thestudy area (i.e., the C-48-C-93-P-10 and 4-19-78-

10W6 wells), and the volumes decrease to thecenter and the southern part of the study area asmaturity increases.

DISCUSSION

Strata in the study area vary markedly in thicknessand depth of burial, resulting in a large variation inreservoir pressure and temperature. Pressures and

temperatures increase toward the southwest as the

depth to the base of the Shaftsbury Formation in-creases toward the southern and southwestern partsof the study area to a maximum depth of 2300 m(7500 ft) below the surface (


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outer foothills where strata have greater maturitiesthan the inner foothills to the west (Kalkreuth andMcMechan, 1988). The Cretaceous ShaftesburyFormation is at sufficient maturities within thestudy area to have generated hydrocarbons (lightvolatile oil and gas). Thermogenic gas (>455C;

Tissot and Welte, 1984) would have been gen-erated in the southern one-third of the study area.S1 indicates the presence of free hydrocarbons inlower maturity samples (420440C) and thepossibility for light volatile oil resources in thenorthern part of the study area (Figure 27). Invertdrilling mud contamination is not the cause ofhigh S1 values because the S1 decreases with ma-turity. Liquid hydrocarbons have the additionalbenefit of increasing the methane sorption capac-

ity of the shale. Chalmers and Bustin (2007) showthat bitumen has a high methane sorption capacityand that the presence of free hydrocarbons (bitu-men) increases the methane sorption capacity ofthe Shaftesbury Formation (Figure 19), althoughthe presence of free liquid hydrocarbons has anegative impact on the shale pore system by reduc-ing the volume of porosity available for free gas.

The TOC content distribution by well averageis affected by the degree of organic maturationand the depth of burial, with clastic sedimentation

rates having a minimal effect on the TOC contentdistribution (contrasting distribution between theTOC content and stratal thickness; Figures 6,8).The TOC content is, in part, controlled by organicmaturation because TOC is reduced by the trans-formation to hydrocarbons (i.e., areas with higherthan averageTmaxcoincide with the areas of lowTOC content; Figures 7, 8). The more maturesouth contains higher quartz contents, which maybe caused by diagenetic processes, and results in

the negative relationship between quartz contentand TOC content (Figures 12,8; discussed in de-tail below). The high TOC content in the westernpart of the study area where clastic sedimentationrates were high indicates that organic sedimenta-tion was at high enough rates to overcome anydilution effects. Preservation of organic matter isalso enhanced by the higher sedimentation ratescaused by the abrupt burial and reduced exposureto degradation (see review by Hedges and Keil,

1995). The variation in the TOC content betweenunits observed in both cross sections and mapsmay reflect the changes in the rate of sea level rise,bioproductivity, preservation, or sediment supply,or a combination of all four to the study area.

We assume that maturity has not significantly

altered the geochemistry of the kerogen becauseof the similar plots for mature samples (Tmax,>430C) and immature samples (Tmax,


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quartz rich, with most of the clay minerals beingillite. Above-average quartz content occurs in thesouthern part of thestudy area and extends into themiddle part of the study area. Similar distributionexists for the TOC content and maturity. The in-crease in quartz content withinthe center of the study

area could be caused by free silica gel being re-leased from the silicates during diagenesis (Foscolos,1990), which is either expelled or becomes quartzcement in pores or quartz overgrowths within theshale. Another possibility for the variation in thequartz content could be related to sedimentologicdifferences across the study area. The increase insilica content in these areas could enhance thebrittleness and the ability to increase reservoir ac-cess through hydraulic fracturing. General down-

hole distribution shows a higher quartz content inthe BOU and BFSU and a lower quartz contentwithin the LSU and USU. Differences in the quartzcontent between units and the downhole distribu-tions are not consistent between wells, which mayreflect the large sampling intervals (510 m [2030 ft]) or the change in the sedimentology anddepositional environment across the study area orthe combination of both. Observations made atthe outcrop exposures of the BFSU found that theunit is both sand and silt rich (Bloch et al., 1993),

which would increase the quartz content. Thegreater range in mineralogy for the BOU may becaused by sediment reworking during the trans-gression, which incorporates some of the sedimentfrom the underlying sands of the Paddy Member.

Similar distributions between porosity, matu-rity, TOC content, and quartz content indicate thatboth organic and inorganic diageneses are the mostimportant controls on the porosity within the studyarea. Porosity distributions are expected to be similar

to the structure of the study area, decreasing to-ward the south and southwest with increasing ef-fective stress. A positive trend exists between po-rosity and TOC content (Figure 14A), with thelowest TOC content occurring in the same areasas the lowest porosity (Figures 8, 13). Negativerelationships exist between maturity and TOCcontent (Figure 14C) and porosity (Figure 14B),with high Tmax (Figure 7) located in the sameareas of the study area as the lowest porosity and

TOC content. The positive trend between TOCcontent and porosity is, in part, an artifact of thenegative relationship that exists between maturityand porosity (Figure 14B) because mature sampleshave lower TOC content and porosity. Porosityincreases within kerogen with increasing maturity

as the volume of kerogen reduces because of ther-mal decomposition, but intergranular porosity de-struction is greater than the creation of kerogenporosity because of kerogen shrinkage. Destructionof porosity with increasing depth of burial is pri-marily caused by the loss of macropores, as shownby the four samples in the C-4-J well. Destructionof porosity is caused by silica cementation andmechanical compaction of pores during diageneticprocesses. Porosity in immature samples is more

variable because of the differences in the primarytexture of the shale, and the variation in porosityreduces with increasing maturity (Figure 14B) asthe texture evolves because of compaction. As theshale loses macropores because of compaction, aconcomitant increase in the microporous surfacearea is observed. The increase in micropores is as-sociated with increasing maturity and shrinkageof the kerogen and the increase in illite crystal-linity (Chalmers and Bustin, 2008). Although anoverall loss in the volume of porosity (i.e., macro-

pores) is observed, the increase in the surface areaassociated with mesopores and micropores resultsin an increase in the sorbed gas component (asso-ciated with mesopores and micropores) but a re-duction in the free gas component (associated withmacropores).

The above-average methane capacity withinthe southern half of the study area is caused by thematurity and the current depth of the reservoir.

Wells that are at greater depths have higher meth-

ane sorption capacities normalized to 6 MPa(870 psi) and at their respective reservoir pres-sures. Having similar distributions between a con-stant arbitrary pressure (6 MPa [870 psi]; Figure 17)and changing pressure (reservoir; Figure 22) indi-cates that samples that have experienced greaterdiagenesis (maturity and depth of burial) have theability to store more methane than immature sam-ples although immature samples have a greater vol-ume of kerogen. This is confirmed by the positive



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relationship between maturity and methane sorp-tion capacity calculated on a per-TOC basis (dia-mond symbols in Figure 19A), indicating that highermaturity samples have a higher methane sorptioncapacity on a per-TOC basis compared with lowermaturity samples. The increase in capacity with in-

creasing reservoir pressure according to their cur-rent depths makes the shale at greater depths a morefavorable target, although permeability is antici-pated to be reduced. This relationship is oppositeto the observations made in the Buckinghorse For-mation, where shallower samples had a greatersorption capacity because of a higher TOC content(Chalmers and Bustin, 2008). In the ShaftesburyFormation, samples that are at shallower depthshave a higher TOC content but not higher meth-

ane sorption capacities. Maturity has a strongercontrol on the capacities of these shales than thevariation in TOC content. The reason for such apoor trend between TOC content and methanesorption capacity could be related to the narrowerrange of TOC content compared with the Bucking-horse shale (Figure 18). The difference could alsobe caused by the presence of bitumen (high S1;circle symbols inFigure 19A, B) in the ShaftesburyFormation samples, which would increase the sorp-tion capacity because gas would move into solution

(Chalmers and Bustin, 2007). The bitumen is nat-ural and not an invert drilling mud contaminantbecause the S1 (bitumen) decreases with maturity(Figure 19C).

Total gas capacity at reservoir pressure consid-ers the increase in sorption capacity with pressureand the increase in free gas density within the poresof the sample. Wells with higher-than-average totalgas content have higher sorption capacity, higher-than-average porosity or reservoir pressure, or a

combination of all three. High porosity volumesgenerally increase the total gas capacity of the res-ervoir, assuming that all pores are accessible tomethane. High pressure is more important thanhigh porosity as illustrated by the deepest well C-4-J-93-P-1, which has low to moderate porositybut the highest total gas capacity caused by thehighest reservoir pressures.

The GIP distribution based on stratal thick-nesses (bcf/section) is influenced by the sorption

capacity of the shale, maturity, depth (reservoirpressure), and thickness of the unit. Higher GIPestimates are along the western border and withinthe southern part of the study area. High GIPalong the western border is caused by the increasein the thickness of the Shaftesbury Formation

(Figure 6), whereas high GIP in the southern partof the study area is caused by the greater depthsand maturity. The distribution of GIP averages ona per-meter basis (i.e., gas density; bcf/[section meter]) is similar to the GIP distribution calcu-lated using the stratal thickness (Figure 24) out-lined above, with an increase in GIP toward thesouth (Figure 25). The similarity between theGIP distributions indicates that the stratal thick-ness changes the absolute number but not the dis-

tribution pattern across the study area. The low GIPtrough in Figure 25and within the LSU in B-86-H-93-P-7 (Figure 21) is caused by below-average po-rosity (Figure 13) and total gas content (Figure 23).The GIP downhole distributions from cross sec-tions DD(Figure 20) and AA (Figure 21) showthat the zone of highest gas density shifts betweenunits and is influenced by porosity and total gascapacity. The variation in the stratigraphic locationof the high gas density zone needs to be consideredduring exploration of the Shaftesbury Formation.

The amount of hydrocarbons generated fromthe Shaftesbury Formation is assessed from thecrossplot between S2 and Tmax for both matureand immature samples (Figure 26). Because thekerogen is dominated by gas-prone type III, thehydrocarbons generated would be dominated bymethane (Tissot and Welte, 1984). The value of3.6 bcf/(section meter) was calculated as the max-imum amount of methane generated within themature parts (i.e., Tmax, >475C; Figure 26) of the

study area assuming that the amount of hydro-carbons available for conversion is represented bythe immature samples (i.e., their present day S2)and that the TOC content and S2 are constantacross a section. The maximum GIP capacity rangesbetween 0.98 and 3.39 bcf/(section meter), whichindicates that the Shaftesbury Formation shale res-ervoir has the capacity to store at least one-thirdof the generated hydrocarbons. Gas content mea-surements are needed to ascertain how much gas



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has been retained within the self-sourcing reser-voir. For this study, water saturation is assumed aszero for all gas capacity calculations and capacitywould reduce if recalculated using thein-situ watersaturations (i.e.,Sw= 3050%). Direct gas mea-surements in the field would determine the gas

saturation.

CONCLUSIONS

The conclusions from the evaluation of the Cre-taceous Shaftesbury Formation in northeasternBritish Columbia are as follows:

1. No clear correlation exists between the TOC

content and the methane sorption capacity, andno significant relationships are observed be-tween the distributions of the TOC content andthe methane sorption capacity. The lack of anyrelationships is caused by the narrow range withinthe averaged TOC contents, the presence of bi-tumen within some samples, and the changes ingas capacity and maturity overshadowing thelow variation in TOC abundance.

2. Maturity has a strong influence on the sorbedgas capacity as highlighted by the similar dis-

tributions ofTmaxand sorbed gas capacities at6 MPa (870 psi) and reservoir pressure. If pres-sure had a stronger influence than maturity, alittle difference in the sorption capacity at 6 MPa(870 psi) across the study area would be ob-served and capacities would only increase withdepth when measured at the reservoir pressure.

3. Greater depth of burial of the sediments (highermaturity and diagenesis) has reduced porosityby mechanical compaction and chemical pre-

cipitation of free silica caused by clay diagenesis,which results in a higher quartz content in moremature, lower porosity samples.

4. Total gas capacity is controlled by the reservoirpressure and the present-day depths and less soby the volume of porosity.

5. The GIP estimates on a per-section basis aregreatly influenced by the stratal thicknesses andthe total gas capacity. The GIP on a per-meterbasis shows similar distribution to GIP on a per-

section basis, indicating that the stratal thick-ness changes the GIP estimation but not thedistribution across the study area.

6. Downhole GIP distributions on a 50-m (164-ft)moving average illustrate that the GIP peaks shiftstratigraphically across the study area. Having

GIP calculated on a constant volume of rock (i.e.,1 m 1 section) allows simple calculations of theGIP on a variety of stratal thickness, dependingon the volume of rock that is proposed to bestimulated during well completions.

7. The comparison between the S2 of immatureand mature samples illustrates that a significantamount of hydrocarbon was generated sincethe Cretaceous and that the Shaftesbury For-mation has the necessary surface area within

the pore structure to retain a part of the hydro-carbon generated. How much of these hydro-carbons are retained can only be determined bydirect gas measurement in the field.

8. From the data presented, the greatest gas shalepotential is within the southwestern part of thestudy area because of high maturities, moder-ate porosities, and higher reservoir pressures. Theaccess to the reservoir still needs to be assessedparticularly at greater depths because perme-ability could be reduced and fracture stimulation

is necessary. The higher quartz content and pos-sible silica cementation could enhance the abilityto fracture the reservoir in the southwestern partof the study area.

9. Lower maturity (oil window) areas have lowergas capacities but the potential for volatile lightliquid plays a development with S1-based cal-culations indicating resources between 3.7 and516.2 MMBO.

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