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Underbalanced Drilling in Canada: Tracking the Long-Term Performance ofUnderbalanced Drilling Projects in CanadaDave Kimery, SPE, Matt McCaffrey, Weatherford International Ltd.

Copyright 2004, SPE/IADC Underbalanced Technology Conference and Exhibition

This paper was prepared for presentation at the 2004 SPE/IADC Underbalanced TechnologyConference and Exhibition held in Houston, Texas, U.S.A., 1112 October 2004.

This paper was selected for presentation by an SPE/IADC Program Committee followingreview of information contained in a proposal submitted by the author(s). Contents of thepaper, as presented, have not been reviewed by the Society of Petroleum Engineers or theInternational Association of Drilling Contractors and are subject to correction by the author(s).The material, as presented, does not necessarily reflect any position of the Society ofPetroleum Engineers, the International Association of Drilling Contractors, their officers, ormembers. Electronic reproduction, distribution, or storage of any part of this paper for

commercial purposes without the written consent of the Society of Petroleum Engineers or theInternational Association of Drilling Contractors is prohibited. Permission to reproduce in printis restricted to a proposal of not more than 300 words; illustrations may not be copied. Theproposal must contain conspicuous acknowledgment of where and by whom the paper waspresented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A.,fax 01-972-952-9435.

Abst ractThe development of underbalanced drilling (UBD) forproduction enhancement has advanced significantly since theadvent of this technology in the early 1990s. The basis for theinitial judgment as to the success of a UBD campaign wasusually limited by the information that was available at thetime of project completion: project execution success andinitial production rates. However, the full scope of the effect

of UBD on the overall economic success of a project remainsunknown for many cases. While several underbalanced fielddevelopments have sufficient production history, drillingrecords, and cost data available for analysis, to date the bodyof published literature lacks thorough, long-term casehistories.

This paper addresses this scarcity by analyzing severalUBD projects in the Western Canadian Sedimentary Basin.The discussion includes a comparison of UBD and completedwells with the offsetting conventional producers in the samereservoir. Comparative analysis using industry-standarddecline analysis and economic techniques yield technical andeconomic insight. To provide a balanced picture of theeconomic benefits that UBD can bring, both successful andunsuccessful projects are examined. The unsuccessful casesare analyzed to determine the reasons for underperformance,whether they fall into the categories of poor candidateselection or sub-optimal execution.

Understanding the magnitude and the driving factorsbehind the success and failure of UBD projects is critical tothe growth and acceptance of the technology. This paperattempts to assist in that understanding and provide abenchmark for thorough comparisons of UBD case historiesfor the future.

IntroductionHorizontal wells can be a very effective field developmentechnique for several reasons. Horizontal techniques excel inreservoirs that are naturally fractured or highly heterogeneousor that exhibit gas or water coning problems. Horizontal wellscan also benefit low-permeability reservoirs by draining alarger area per well and thus reducing the number of wells

needed to drain the reservoir.1

Formation damage in highly damageable reservoirspresents the main obstacles to achieving the benefits ohorizontal wells. Delivering effective stimulation treatmentin horizontal wells can be expensive and difficult, soformation damage can seriously limit the effectiveness ofthese treatments. UBD developed as a technique forminimizing invasive, drilling-induced formation damage toallow the drilling of effective horizontal wells in damageablereservoirs.

The development of horizontal UBD, in its current formbegan in the early 1990s. Significant development has takenplace in the areas of equipment design, operational techniquesand the understanding of what occurs in the reservoir duringunderbalanced operations. One considerable shortcominghowever, is the distinct lack of published literature that clearlydemonstrates that horizontal UBD is an economically effectivefield development method compared to conventional drillingcompletion, and stimulation techniques.

The majority of industry knowledge on horizontal UBD isbased on anecdotal evidence, in-house analyses not availableto the public, and case histories focused on operational aspectsor very early time production results.2-8 Published literaturethat examines the long-term performance of previous UBDprograms is virtually non-existent. This paper represents a firsattempt at addressing this issue.

A number of underbalanced campaigns in the Western

Canadian Sedimentary Basin have several years of productiondata. The following analysis of these case studiesdemonstrates that horizontal UBD is a viable fielddevelopment technique and quantifies the significaneconomic benefit that can be achieved. The analysis alsoincludes programs in which UBD was not successful andinvestigates the reasons for failure.

MethodologyDetermination of the overall economic performance of bothconventional and underbalanced techniques requires aproduction forecast to extrapolate existing production data to

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abandonment. All analyses were based on production dataonly because flowing pressures were unavailable; therefore,Arpss decline curve analysis9was chosen as the forecastingmethod.

Arpss decline analysis is only valid during boundary-dominated flow, so a test was required for determiningwhether this is true for all of the wells analyzed. Fetkovich-

type curves10

provide the diagnostic functionality11

forconfirming that boundary-dominated flow exists, confirmingthat Arpss decline analysis is valid, and determining theappropriate curve (b exponent) with which to forecast. Thus,Fetkovich-type curves were used to confirm that all the wellsexamined in this analysis were in boundary-dominated flow.Then the forecast was generated using Arpss methods.

After production forecasts were generated, discountedcash-flow analysis was performed to generate economicindicators for the comparison of conventional andunderbalanced techniques, such as net present value (NPV)and internal rate of return (IRR). For simplicity, allcomparisons were based on cash flows before taxes androyalties.

Case StudiesPosit iveThe following case studies present the results of campaigns inwhich horizontal underbalanced wells outperformed theoffsetting conventional producers.

Elkton FormationHarmattan East Field. The Elktonformation is the productive member of the Rundle group in theHarmattan East field, located in Central Alberta (Twp 33 Rge3 W5M). The formation is an Upper Mississippian agedolomitized carbonate. Key general reservoir properties are asfollows:

Depth ~ 2,450 mPermeability 0.1 to 5.0 mDPorosity 6 to 12%Initial water saturation 11 to 30%Gross pay 8.7 to 32.8 mInitial pressure 12.3 to 21.6 MPa

This field first began producing in 1967, with a number ofpetroleum companies involved in its early development. Initialexploitation of the field entailed the vertical drilling of wellsoverbalanced and subsequent hydraulic fracturing of theElkton to optimize production. In the early 1990s, operatorsbegan to apply a combination of 3-D seismic activity,

complemented by overbalanced horizontal drilling tomaximize production from the Elkton. However, ApacheCanada Ltd. (Apache) found that overbalanced horizontalwell applications indicated moderate if any improvementsover vertical wells and that subsequent stimulation attemptsof damaged horizontal wells have proven to be ineffective.12Therefore, Apache believed that the application of UBD mightbe a better technology choice for this reservoir. Apache drilledits first underbalanced well in this reservoir in 1996 and wassoon followed by other operators in the area.

Fig. 1 and 2show the average production profiles for boththe horizontal, conventionally drilled wells that were acidizedand the horizontal underbalanced wells. As Fig. 1 indicatesthe horizontal underbalanced wells increased initial productionby an average of 24%. As shown in Fig. 2, the underbalancedhorizontals are projected to recover approximately 32% moregas in a 10-yr period.

0

10

20

30

40

50

60

70

80

90

100

0 1 2 3 4 5 6 7 8 9

Time (Years)

q(e3m3/d)

10

UB

OB

Fig. 1. Elkton Formation Production Rates

0

20

40

60

80

100

120

140

160

0 1 2 3 4 5 6 7 8 9

Time (Years)

Gp(e6m

3)

10

UB

OB

Fig. 2. Elkton Formation Cumulati ve Product ion

Economic analyses were performed on the productionforecasts. Table 1 illustrates the average results on theunderbalanced and conventional cases. A full table of resultsappears in Appendix A.

Although the well costs were similar between thestimulated horizontal wells and the underbalanced horizontawells, the underbalanced wells are predicted to recoverapproximately 29% more gas per well and realize a 40%improvement in NPV. The underbalanced wells also areexpected to improve IRR by 62% and reduce the payouperiod by 42%.

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Table 1. Elkton Formation Analysis Average Results

Conventional Underbalanced

Well Cost $2,500,000 $2,500,000

EUR (106m3) 176.2 226.7

NPV $12,870,982 $18,033,106

IRR 127% 206%

Payout Period 16.1 months 9.4 months

Glauconitic FormationGarden Plains Field. The GardenPlains field is situated in southeastern Alberta (Twps 33-34Rges 11-12 W4M). The Glauconitic formation in this field is alower-Cretaceous sandstone consisting of incised valleys filledwith lithic, fluvial deposits.Typically, the Glauconitic was vertically drilled andhydraulically fractured. In 1999 and 2000, a juniorindependent Canadian oil and gas operator conducted a five-well UBD program in this field, over a 5- 16-km area. Keygeneral reservoir properties are as follows:

Depth 1,280 mPermeability 0.1 to 1.2 mDPorosity 12 to 27%Initial water saturation 32 to 64%Net thickness 1.7 to 23.5mInitial pressure 5.4 to 8.7 MPa

Fig. 3 and 4show the average production profiles for boththe vertical, conventionally drilled and hydraulically fracturedwells and the horizontal underbalanced wells. The horizontalunderbalanced wells increased initial production by an averageof 118%. As shown in Fig. 4, the underbalanced horizontalsare projected to recover approximately 43% more gas in a 10-

yr period.

0

5

10

15

20

25

30

35

40

45

50

0 1 2 3 4 5 6 7 8 9

Time (Years)

q(e3m3/d)

10

UB

OB

Fig. 3. Glauconitic Formation Producti on Rates

0

5

10

15

20

25

0 1 2 3 4 5 6 7 8 9

Time (Years)

Gp

(e6m3)

10

UB

OB

Fig.4. Glauconitic Formation Cumulative Production

Economic analyses were performed on the productionforecasts. Table 2 presents the average results on theunderbalanced and conventional cases. A full table of result

appears in Appendix A.The underbalanced wells are predicted to improve

recovery per well by 11%. Although the underbalanced wellsincreased the average well cost by 26%, the NPV and IRRwere increased by 52% and 113%, respectively, and thepayout period was reduced by 21%.

Table 2. Glauconitic Formation Analysis Average Results


Well Cost $755,000 $950,000

EUR (106m3) 22.5 25.0

NPV $1,862,763 $2,821,906

IRR 117% 250%


Pekisko FormationThree Hills Creek Field. The Pekiskois an early Carboniferous, clean limestone formationprevalent throughout much of Alberta. In the Three HillsCreek field, it is coarsely crinoidal and fragmental to finegrained, sparsely crinoidal.13 Typical Pekisko developmenwas through vertically drilled wells, which were stimulated byacidizing, hydraulic fracturing or acid fracturing. A seven-welhorizontal underbalanced program was undertaken in 1997Key general reservoir properties are as follows:

Depth 1,740 mPermeability 0.25 to 5 mDPorosity 4.5 to 11%Initial water saturation 20 to 30%Net thickness 1.7 to 10.3mInitial pressure 3 to 12 MPa

Fig. 5 and 6show the average production profiles for boththe vertical, conventionally drilled and stimulated wells andthe horizontal underbalanced wells. The horizontaunderbalanced wells increased initial production by an averageof 238%. As shown in Fig. 6, the underbalanced horizontals

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are projected to recover approximately 138% more gas in a10-yr period.

0

10

20

30

40

50

60

70

80

90

0 1 2 3 4 5 6 7 8 9

Time (Years)

q(e3m3/d)

10

UB

OB

Fig. 5. Pekisko Formation Producti on Rates

0

10

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30

40

50

60

70

80

0 1 2 3 4 5 6 7 8 9

Time (Years)

Gp(e6m3)

10

UB

OB

Fig. 6. Pekisko Formation Cumulative Producti on

Economic analyses were performed on the productionforecasts. Table 3 presents the average results on theunderbalanced and conventional cases. A full table of resultsappears in Appendix A.

Table 3. Pekisko Formation Analysis Average Results


Well Cost $950,000 $1,500,000

EUR (106m3) 43.5 112.9

NPV $3,769,884 $10,056,993

IRR 121% 313%


Gething X PoolKaybob Field. The Gething in the Kaybobarea is a highly heterogeneous, fluvial-incised valley filldeposit. The lithology consists of conglomeratic, coarse tofine-grained facies. A UBD program was undertaken aroundthe Kaybob field in 1998 and 1999, in two separate, nearbypools, and the results of this program varied dramaticallybetween the two. In the Gething X pool, the program wassuccessful, but in the Chickadee Gething D pool, it was not.This case study examines the successful case; the unsuccessful

case is discussed later in this paper. Key general reservoiproperties are as follows:

Depth ~1,845 mPermeability 0.07 to 4.2 mDPorosity 10.5 to 19.7%Initial water saturation 23 to 47%

Net thickness 1.9 to 11.5 mInitial pressure 11.9 to 15.0 MPa

Fig. 7 and 8show the average production profiles for boththe vertical, conventionally drilled and hydraulically fracturedwells and the horizontal underbalanced wells. The horizontaunderbalanced wells increased initial production by an averageof 254%. As shown in Fig. 8, the underbalanced horizontalsare projected to recover approximately 121% more gas in a10-yr period.

0

20

40

60

80

100

120

140

0 1 2 3 4 5 6 7 8 9

Time (Years)

q(e3m3/d)

10

UB

OB

Fig. 7. Gething Formation Producti on Rates

0

10

20

30

40

50

60

0 1 2 3 4 5 6 7 8 9

Time (Years)

Gp(e6m3)

10

UB

OB

Fig. 8. Gething Formation Cumulative Product ion


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Table 4. Gething Formation Analysis Average Results


Well Cost $1,371,000 $1,930,000

EUR (106m3) 31.6 60.2

NPV $2,407,730 $6,558,720

IRR 129% 170%


Case StudiesNegativeFor UBD to be successful, appropriate operational techniquesmust be applied in suitable candidate reservoirs. The followingcase studies illustrate programs in which either (a) thereservoir was not an appropriate candidate for horizontalunderbalanced wells or (b) the operational techniquesemployed led to formation damage, thus sacrificing theeconomic viability of the technique.

Cardium FormationAnsell Field. The Ansell field islocated in the Foothills region of Central Alberta (Twps 5053, Rges 19-20 W5M). Primarily during the winters of 2000

and 2001, a major underbalanced horizontal drilling campaignwas implemented.

The target formation was the Cardium zone, a Cretaceous-age, fine-grained marine sandstone. Key reservoir propertiesare as follows:

Depth ~2,250 mPermeability 0.05 to 1.7 mDPorosity 9.5 to 13%Initial water saturation 17 to 37%Net thickness 5 to 19 mInitial pressure 15.4 to 21.9 MPa

Horizontal lengths ranged from 20 to 985 m, averagingapproximately 500 m. The shorter horizontal lengths were theresult of either hole problems (i.e., stuck drillstring) orequipment problems (both downhole and at surface). Some ofthese problems necessitated sidetracking of some of the wells.Liquid injection rates were low on some of the wells; and it issurmised that hole cleaning may have been less than efficient,thereby resulting in stuck pipe situations. Wiper trips wereoften conducted to condition the hole.

Fig. 9 and 10 show the average production profiles forboth the vertical, conventionally drilled and hydraulicallyfractured wells and the horizontal underbalanced wells. Initialproduction from the vertical wells was 27% higher than for theunderbalanced horizontals. As shown in Fig. 10, the verticalwells are projected to recover approximately 37% more gas ina 10-yr period.

0

20

40

60

80

100

120

0 1 2 3 4 5 6 7 8 9

Time (Years)

q(e

3m3/d)

10

UB

OB

Fig. 9. Cardium Formation Producti on Rates

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10

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30

40

50

60

0 1 2 3 4 5 6 7 8 9

Time (Years)

Gp(e6m3)

10

UB

OB

Fig. 10. Cardium Formation Cumulative Producti on

Economic analyses were performed on the production

forecasts. Table 5 presents the average results on theunderbalanced and conventional cases. A full table of resultsappears in Appendix A.

Table 5. Cardium Formation Analysis Average Results


Well Cost $1,900,000 $2,675,000

EUR (106m3) 66.3 46.8

NPV $6,170,600 $3,474,400

IRR 173% 71%


As the results of the analysis indicate, the conventiona

wells are better performers than the horizontal underbalancedwells. The apparent reasons are that (a) the Cardium in theAnsell region is not an appropriate candidate for horizontaUBD and (b) the as-drilled horizontal well design was notcompetitive with hydraulic fracturing in the first place. Thereis also evidence that the UBD operations were not optimallydesigned to minimize formation damage.

In terms of candidacy, the Cardium appears, based on itsproperties, to be a better candidate for hydraulic fracturingthan for horizontal underbalanced wells. The in-situpermeability is very lowlow enough, in most cases, to makehorizontal wells not very economically viable. Although

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natural fracturing does occur, it is not prevalent enough toincrease the effective permeability to a level at whichhorizontal wells would be effective.

In addition, the well design did not help the economicperformance of the wells. Using the concept of effectivewellbore radius14, the as-drilled net effective horizontal lengthwas not sufficient to create an effective wellbore radius greater

than the average radius created by hydraulic fracturing. Thus,from the outset, the wells were not designed to be moreproductive than the vertical wells; and, thus, the extra expenseto drill the horizontal wells was not offset by the difference inproduction.

Fig. 11 and 12 compare the production of theunderbalanced horizontals to a program of conventional,overbalanced drilled horizontals in the Cardium in the Ansellfield. The underbalanced wells do outperform theconventionally drilled wells, giving good evidence that theunderbalanced wells were effective in reducing formationdamage to some extent. Based on the factors stated above,however, the underbalanced wells are not economicallyeffective in comparison to the offsetting vertical, hydraulicallyfractured wells.

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0 1 2 3 4 5 6 7 8 9

Time (Years)

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Fig. 11. Cardium Formation Production Rates - Underbalancedversus Overbalanced Horizontals

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35

40

0 1 2 3 4 5 6 7 8 9

Time (Years)

Gp(e6m3)

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Fig. 12. Cardium Formation Cumulative Production -Underbalanced versus Overbalanced Horizontals

Gethind D PoolChickadee Field. Unlike the wells in theKaybob Gething X pool, the wells drilled in the ChickadeeGething D pool were not successful in comparison to the

conventionally drilled and stimulated wells. Two wells weredrilled in this pool, but only one was produced. Key generareservoir properties are as follows:

Depth ~1,845 mPermeability 0.09 to 1.9 mDPorosity 12 to 16.7%

Initial water saturation 29 to 50%Net thickness 3.1 to 14.2 mInitial pressure 9.8 to 14.9 MPa

Fig. 13 and 14 show the average production profiles forboth the vertical, conventionally drilled and hydraulicallyfractured wells and the horizontal underbalanced wells. Initiaproduction from the vertical wells was 44% higher than for theunderbalanced horizontals. As shown in Fig. 14, the verticawells are projected to recover approximately 22% more gas ina 10-yr period. This projection is based on the one producingwell. The fact that the other horizontal underbalanced wellwas abandoned should also be considered when comparing theperformance of the two techniques.

0

10

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30

40

50

60

70

80

0 1 2 3 4 5 6 7 8 9

Time (Years)

q(e3m3/d)

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UB

OB

Fig. 13. Gething Formation Production Rates

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5

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30

35

40

0 1 2 3 4 5 6 7 8 9

Time (Years)

Gp(e6m3)

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UB

OB

Fig. 14. Gething Formation Cumulative Producti on


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Table 6. Gething Formation Analysis Average Results


Well Cost $1,371,000 $1,940,000

EUR (106m3) 59.7 45.7

NPV $4,464,040 $2,937,340

IRR 85% 48%

Payout Period 16.1 months 24 months

Based on the reservoir properties, it would be expectedthat the wells drilled in the two different Gething pools wouldbe similar in performance. Analyzing the UBD operationaldata, however, reveals that the operational techniques used inthe program had a negative effect on ultimate productivity.Poor bottomhole pressure transient management andinefficient hole cleaning yielded several instances of thebottomhole pressure exceeding the pore pressure adjacent tothe well bore. From this data, it can be assumed that thereservoir had been damaged during the drilling operation.

Conclusions

Horizontal UBD is a proven technology that can yieldsignificantly greater economic value than conventionaldrilling operations in selected mature field-developmentscenarios.

UBD, however, is not applicable to all reservoirs.Conventional (overbalanced) techniques can outperformUBD in some reservoirs. Therefore, proper candidateselection is of paramount importance when consideringapplication of UBD for field development.

Even if a given reservoir has been selected as a suitablehorizontal UBD candidate, appropriate techniques mustbe used both during drilling and completion operations toachieve the goal of minimal formation damage. If not,

sub-optimal production performance and resulting pooreconomics can occur.

References1. Joshi, S. D.:Horizontal Well Technology, PennWell

Books, Tulsa, Oklahoma (1991) 7.2. McGregor, B., Cox, R., and Best, J.: Application of

Coiled Tubing Drilling Technology on a DeepUnderpressured Gas Reservoir, paper SPE 38397presented at the Second North American CoiledTubing Roundtable, Montgomery, Texas, 1-3 April,1997.

3. Mullane, T.J., et al: Benefits of Underbalanced

Drilling: Examples from the Weyburn and WesteroseFields, paper presented at the First InternationalUBD Conference, The Hague, The Netherlands, 2-4October, 1995.

4. Cox, R.: Horizontal Underbalanced Drilling in aSour Gas Carbonate Using Coiled Tubing: A CaseStudy, paper SPE 37075 presented at the 1996 SPEInternational Conference on Horizontal WellTechnology, Calgary, Canada, 18-20 November.

5. Cox, R., Li, J., and Lupick, G: HorizontalUnderbalanced Drilling of Gas Wells With Coiled

TubingChallenges and Experiences, paper SPE37676 presented at the 1997 SPE/IADC DrillingConference, Amsterdam, The Netherlands, 4-6March.

6. Bennion, D.B., Bietz, R.F., Thomas, F.B., andCimolai, M.P.: Reductions in the Productivity of Oiland Low Permeability Gas Reservoirs Due toAqueous Phase Trapping, The Journal of CanadianPetroleum Technology(November 1994) Volume 33,No. 9.

7. Deis, P.V., Yurkiw, F.J., and Barrenchea, P.J.: TheDevelopment of an Underbalanced Drilling Process:An Operators Experience in Westerose Canada,paper presented at the First International UBDConference, The Hague, The Netherlands, 2-4October, 1995.

8. Smith, S., Steiner, A., and Sephton, S.: UBD FlowModellingSelected Case Studies, paper presentedat the IADC Underbalanced Technology Conference,Aberdeen, Scotland, 27-28 November, 2001.

9. Arps, J. J.: Analysis of Decline Curves,AIMETransactions (1945) Volume 160, 228-247.

10. Fetkovich, M. J.: Decline Curve Analysis UsingType Curves,JPT(June 1980), 1065.

11. Mattar, L., Anderson, D. M.: A Systematic andComprehensive Methodology for Advanced Analysisof Production Data, paper SPE 84472 presented at

the 2003 SPE Annual Technical Conference andExhibition, Denver, 5-8 October.

12. McGregor, B., Adamache, I.: ProductivityImprovements in a Deep Underpressured Tight GasReservoir Through the Application of HorizontalUnderbalanced Drilling, paper presented at theThird International Underbalanced DrillingConference and Exhibition, The Hague, TheNetherlands, 8-9 October, 1997.

13. Glass, D.:Lexicon of Canadian Stratigraphy Volume4 Western Canada, Including Eastern British

Columbia, Alberta, Saskatchewan and Southern

Manitoba,Canadian Society of Petroleum

Geologists, Calgary, Alberta (1997) 917.14. Joshi, S. D.:Horizontal Well Technology, PennWell

Books, Tulsa, Oklahoma (1991) 43.

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Appendix ADetailed Resul t Tables

Table A-1. Detailed Results Table: Elkton Formation Harmattan East Field

Location Well Type NPV IRREUR

106m

3Payout

Months

10-12-033-04W5 Horizontal Underbalanced $ 4,882,000.09 49% 90.748 22

102/06-15-033-03W5 Horizontal Underbalanced $14,623,564.29 134% 223.082 9

10-24-033-04W5 Horizontal Underbalanced $20,541,115.54 203% 269.369 711-21-033-04W5 Horizontal Underbalanced $17,223,354.64 146% 213.259 10

12-16-033-03W5 Horizontal Underbalanced $33,213,681.89 491% 310.17 4



01-17-033-03W5 Acidized Horizontal $13,324,872.32 162% 151.998 8

04-20-033-03W5 Acidized Horizontal $ 8,084,284.45 61% 144.794 21









Table A-2. Detailed Results Table: Glaucon itic FormationGarden Plains Field


106m

3Payout

Months

09-18-033-11W4 Horizontal Underbalanced $ (182,179.60) -6% 4.47 n/a


13-01-034-12W4 Horizontal Underbalanced $ 655,411.35 38% 10.816 26



01-25-033-12W4 Vertical with Frac $1,395,144.27 184% 12.582 6

03-19-033-11W4 Vertical with Frac $ 329,785.29 43% 6.397 21



10-06-034-11W4 Vertical with Frac $ (109,476.29) 3% 4.19 n/a

102/10-32-034-11W4 Vertical with Frac $5,681,319.43 227% 63.467 6



Table A-3. Detailed Results Table: Pekisko FormationThree Hills Creek Field


106m

3Payout

Months

05-09-035-25W4 Underbalanced Horizontal $ 5,565,855.20 161% 58.048 805-10-035-25W4 Underbalanced Horizontal $32,853,109.10 1071% 330.112 2

102/15-32-033-25W4 Underbalanced Horizontal $ 3,982,365.70 84% 48.404 14

10-21-033-24W4 Underbalanced Horizontal $10,129,096.74 298% 99.829 5

11-16-035-25W4 Underbalanced Horizontal $ 4,764,135.93 70% 88.854 16



01-20-035-25W4 Vertical Stimulated $ 1,142,142.14 42% 16.869 27


03-33-033-25W4 Vertical Stimulated $ (522,708.66) -51% 2.407 n/a


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10-03-033-24W4 Vertical Stimulated $ (279,968.84) -4% 4.356 n/a



16-07-034-25W4 Vertical Stimulated $ 718,441.16 29% 13.093 36

Table A-4. Detailed Results Table: Gething X PoolKaybob Field


106 m3

Payout

Months

03-35-063-20W5 Horizontal Underbalanced $ (1,610,039.75) -145% 1.698 n/a



01-07-064-19W5 Vertical with Frac $ 2,992,816.87 200% 26.175 6


03-25-063-20W5 Vertical with Frac $ (34,815.43) 8% 7.847 42



09-11-063-20W5 Vertical with Frac $ (112,132.40) 6% 7.936 58102/01-24-063-20W5 Vertical with Frac $ 313,599.14 19% 11.46 43

102/13-08-063-20W5 Vertical with Frac $ (302,883.23) -9% 6.129 n/a




Table A-5. Detailed Results Table: Cardium FormationAnsell Field


106m

3Payout

Months

01-29-051-19W5 Horizontal Underbalanced $ (1,250,442.09) -15% 9.011 n/a


05-11-053-20W5 Horizontal Underbalanced $ 5,582,511.38 95% 72.231 1105-20-051-19W5 Horizontal Underbalanced $ 8,721,682.35 172% 86.632 7




102/03-09-051-19W5 Horizontal Underbalanced $ (1,965,986.52) -57% 4.116 n/a

102/04-17-052-19W5 Horizontal Underbalanced $ 2,618,311.73 44% 40.641 23






14-04-052-19W5 Horizontal Underbalanced $ 8,843,644.11 164% 90.134 714-08-052-19W5 Horizontal Underbalanced $ 3,209,411.24 108% 36.221 9


1S0/04-29-051-19W5 Horizontal Underbalanced $18,329,741.00 412% 158.416 4


01-36-052-20-W5 Vertical with Frac $13,083,403.59 228% 149.93 6






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05-21-052-19W5 Vertical with Frac $20,992,668.07 418% 178.36 405-33-053-20W5 Vertical with Frac $ 9,071,514.62 120% 89.385 8










09-14-053-21W5 Vertical with Frac $ (681,375.77) -25% 6.92 n/a

09-16-052-19W5 Vertical with Frac $12,762,522.70 697% 93.892 309-28-053-20W5 Vertical with Frac $ 4,120,069.22 159% 39.594 7

103/04-17-052-19W5 Vertical with Frac $ 3,362,946.74 96% 35.623 11

103/11-21-050-20W5 Vertical with Frac $ (906,074.20) -108% 5.242 n/a


11-18-053-21-W5 Vertical with Frac $ 5,800,757.33 184% 61.859 6


















16-01-052-20W5 Vertical with Frac $ 2,267,454.12 65% 28.777 1616-30-052-19W5 Vertical with Frac $ 8,543,593.55 185% 95.516 7

7/22/2019 00091593

11/11

SPE/IADC 91593 11

Table A-6. Detailed Results Table: Gething D PoolChickadee Field


106m

3Payout

Months







01-20-060-17W5 Vertical with Frac $ (1,078,996.50) -133% 1.574 n/a


102/10-22-060-17W5 Vertical with Frac $13,339,474.33 133% 166.669 11






06-36-060-17W5 Vertical with Frac $ 9,477,585.77 163% 135.091 805-04-061-16W5 Vertical with Frac $ 5,145,154.57 112% 70.464 11











Documents

00091593