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SPE 158207

Eagle Ford Shale - An Early Look at Ultimate RecoveryGary S. Swindell, SPE

Copyright 2012, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, USA, 8-10 October 2012.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not beenreviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, itsofficers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission toreproduce in print is restricted t o an abstract of not mor e than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

AbstractAlthough the Eagle Ford shale is early in its history, the study provides a comprehensive examination of per well recoveryand decline data in the South Texas trend using the latest production information up to early 2012.

Individual forecasts of the estimated ultimate recovery (EUR) were made for more than 1,000 horizontal wells in the SouthTexas Eagle Ford shale trend and statistics were developed for EUR in the 10 primary counties where development isoccurring. The study used rate vs. time plots and included all the producing wells in the trend which have decline databelieved to be sufficient to project EUR. Normalized decline curves were developed for each county and distributions ofEUR were produced. In addition, for a portion of the wells, correlations were made between EUR, frac size, horizontallength and the date of first production.

The results show that for the 10 county trend, the average and median EUR per well were 206,779 barrels of oil equivalent(BOE) and 160,519 BOE, respectively. Of the counties with more than 50 wells, the best are DeWitt (403,715 BOE) andKarnes (210,801 BOE). Live Oak, with only 28 wells averages 248,818 BOE. The normalized rate vs. time plots showminor hyperbolic behavior. In fact, for all the wells in the study, the normalized oil decline was 76% and the gas 60%, withhyperbolic exponents of .25 and .40, respectively. The wells have clearly become better since the start of horizontal drilling,but the average performance has not shown much improvement since mid-2010 even as the frac sizes became larger. Thebest well performance has generally come from wells with horizontal legs in the 4,000 to 5,500 ft. range.

The South Texas Eagle Ford shale trend is one of the most active in the US, adding approximately 100 new producing leaseseach month. Although a great deal is being written about the trend, there is a lack of independent, hard data on per wellreserves. This study provides an early look at individual well ultimate recovery.

IntroductionThe industry literature is full of articles about the Eagle Ford shale in South Texas, and for good reason as it is among themost active plays in the US. Some of these mention estimates of per well ultimate recovery, often in barrels-of-oil-equivalent(rarely stating what was used to convert gas to oil equivalent), but nearly all the quoted figures, which range up to 850,000

BOE or 8.5 billion cubic feet, are from companies active in the trend. That certainly does not disqualify the figures given,and in fact, these companies possess data not publically available. Rarely, however, is the supporting data made available,and the EUR figures are usually limited to the specific areas the companies are working.

For an excellent discussion of the Eagle Ford geology, petrophysics, drilling trends and some early decline curve work, seeSPE 145117, Understanding Production from Eagle Ford-Austin Chalk System (Martin et al. 2011) – information that willnot be repeated here but it is recommended reading. The remainder of the available SPE papers either address the matterfrom a modeling or theoretical standpoint, apply auto-fitting of the decline curves, or use very limited well counts.

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The Scope of the StudyThe Eagle Ford horizontal trend grew from nothing in early 2008 to nearly 1,200 producing leases by the end of February2012 (the latest data used in this study), and new producing leases are being added at a rate of nearly 100 each month. Tencounties lie in the heart of the trend, Atascosa, DeWitt, Dimmit, Gonzales, Karnes, La Salle, Live Oak, Maverick, McMullen,and Webb. Although a number of the wells have not been producing long enough to establish a decline trend, 1,041 wells on843 leases have a decline rate sufficiently established to make an estimate of ultimate recovery using conventional declinecurve methods, manually fitting a decline projection to the individual leases or wells. All of the EUR figures given in this

paper are per well. Figure 1 is a map showing the wells included in the study. A conversion to barrels-of-oil-equivalent(BOE) was made, including an estimate of the natural gas liquids (NGL) that may be extracted from the gas stream.

These individual well ultimate recovery projections and especially the controversial hyperbolic nature of the declines werefurther guided by normalized profiles of large groups of wells – some of these are presented for the larger well-countcounties.

In addition, for a portion of the 1,000 wells analyzed for EUR, information was obtained for oil and gas gravity, frac sandvolume, frac stages, horizontal perforated length, peak monthly gas and oil production, and initial potential. This informationdid not cover all the wells but should be fairly representative with data points ranging from 165 wells (frac stages) to 438wells (peak monthly gas production). Some correlations of this data to EUR are presented.

Fig. 1 – Map showing wells included in the study.

Problems with the Production dataYes, there are some problems. First, nearly 80 of the leases have multiple wells with the production combined; the rest aresingle well leases. Addressing this, the lease EUR is simply divided by the well count. Most multiple well leases wereexcluded from the normalizing work. Second, in Texas wells not yet assigned a RRC number are considered preliminary or“P” wells, so any duplicates had to be excluded, corrected or merged with later production data. Third, some leases havebeen reclassified from gas to oil generating a new RRC record, or in a few cases are later merged with other RRC records.These were carefully combined, producing a single complete decline curve. Finally, some leases have production that startsslow and increases or is initially erratic as early production problems are solved. Since inclusion of these leases would distortthe results, all these were excluded from the normalizing work.

The study’s whole database of Eagle Ford production included nearly 1,200 leases, but only 843 leases (1,041 wells) wereconsidered established enough to make a EUR projection. The rest were considered too early to make a reasonable declineforecast.

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Economic LimitThe following parameters were used to establish the economic limit of the decline forecasts:

Interests 100% working, 75% net revenue (25% burdens)Oil price $100/barrel held constantGas price $4.00/MCF held constantOperating costs $3,000 per month per wellTaxes 4.6% oil and 7.5% gas Texas severance, 2.5% ad valorem

Gas-to-oil conversionMost papers, articles, and company reports fail to explain or define how natural gas is converted to barrels-of-oil-equivalent.The traditional 6 MCF/BBL conversion on the basis of BTU might have been used, but the divergence in oil and gas pricesno longer make this a meaningful approach. For this work, a rough price ratio of 20 MCF per barrel was used to convertnatural gas into equivalent barrels. Yes, as this is being written the price ratio is more like 40:1 but the assumption is that thisrecent jump will not be a long term trend.

What about the NGL?It is a difficult problem because there is almost no public data available. Even if you had NGL plant output information, itwould be a blend of many wells from a wide geographical area and individual well gas analyses would be necessary, data thatresides with the operators. Using a few public reports of NGL yield, an estimate of NGL barrels per MMCF was developedfor each county and used in the conversion of gas-EUR to barrels-of-oil-equivalent (BOE). That estimate included an

adjustment for gas shrinkage and the price received for NGL. The county figures that were used vary from 40 to 130 barrelsof NGL per million cubic feet of natural gas. This conversion and BOE adjustment would admittedly not stand muchscrutiny because of the lack of hard data. (On the other hand, in a career spent on evaluating oil & gas properties I havefound only a handful of cases where an interest owner made money through an NGL plant. By the time deductions are madefor shrinkage, line losses, compression, fuel and the plant fractions, there is usually little income benefit to the workinginterest owner. It might be different if you owned the plant, and certainly in the current $2.00/MCF price environment itmakes some sense to sell your product as NGL.)

EUR Overview and Summary TableFor the 1,041 well study group covering the heart of the trend, the mean EUR per well is 206,800 BOE and the median is160,500 BOE. The overall distribution is log-normal (De Witt is not – see Fig. 7 ) with a best well of 1,002,000 BOE. Sixpercent of the wells are forecast to recover in excess of 500,000 BOE. Unless you are drilling the whole trend, the overallaverages do not mean much and the county details given later in the paper are more useful. Table 1 summarizes the results

by county.

TABLE 1 - SUMMARY OF ULTIMATE RECOVERY STUDY BY COUNTY

County

Number ofwells instudy

Avg. Fracsand - Th.

PoundsAvg. oilgravity

Avg. peak oilproduction -BBL/month

Avg. peak gasproduction -MCF/month

Avg. EURoil - BBL per

well

Avg. EURgas - MMCF

per well

Avg. EUR -BOE per

well

ATASCOSA 23 3,509 36.3 8,390 9,689 80,117 67 86,864

DEWITT 89 4,576 55.5 21,551 123,873 261,326 1,338 403,715

DIMMIT 182 3,450 49.3 7,430 37,772 114,644 638 180,870

GONZALES 83 3,280 41.3 13,457 10,635 121,795 135 135,102

KARNES 194 4,156 48.3 14,329 66,037 156,782 508 210,801

LA SALLE 173 4,649 50.9 5,195 128,891 64,157 1,331 194,991

LIVE OAK 28 3,538 51.7 17,184 107,657 136,136 963 248,818 MAVERICK 21 2,839 42.7 2,567 9,192 17,380 159 31,356

MCMULLEN 65 3,194 50.1 9,363 86,218 90,503 832 172,237

WEBB 178 3,646 59.3 5,721 119,458 70,104 1,925 192,697

Total 1,041 115,282 1,044 206,779

Normalized decline curvesLeaving out the wells with early erratic production, the decline curves of the wells in each of the 10 counties in the studywere normalized, bringing all the starting dates back to the same time-zero and dividing the production totals by the wellcount. This approach gives a plot of how the average well in those counties declines. The end portion of the decline curveswere trimmed off when the well count approached 10 wells. Normalizing is not without its problems, including partial first-

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month of production, wells that are later worked over (see Karnes County Fig. 16 ), and survivor bias – the best, most longlived wells influence the later points of the curve. But it does, however, give a decline profile across a large sample of wellswhich is free of any interpretation, and I believe that the normalized profile should serve as a guide to individual declinecurve decisions. Table 2 below summarizes the normalized decline profiles. Note that the decline rates and hyperbolicexponents are from manual curve fitting of about 2 years of normalized production data. The flow regimes are probablychanging and may change further in the life of the wells.

TABLE 2 - SUMMARY OF NORM ALIZED DECLINE BY COUNTY G ROUPS

County

Number ofwells

normalizedQi Oil -

BBL/month

Initial Oildecline

rate

Early OilHyperbolic

exponent - bQi Gas -

MCF/month

Initial Gasdecline

rate

Early GasHyperbolic

exponent - bATASCOSA 21 6,408 89% 0.35 3,750 77% 0.30 DEWITT 86 20,079 72% 0.20 95,885 66% 0.10 DIMMIT 128 5,356 49% - 26,468 54% - GONZALES 49 13,769 71% 0.25 13,268 78% 0.40

KARNES 121 12,714 88% 0.85 35,224 80% 0.50

LA SALLE 131 4,115 79% - 91,678 69% 0.70 LIVE OAK 127 12,967 84% 0.25 46,235 85% 0.70

MAVERICK 17 1,782 92% 0.35 8,257 82% -

MCMULLEN 52 7,887 79% - 76,955 76% 0.30 WEBB 167 3,655 63% 0.30 92,269 51% 0.10

Everyone Talks About Initial PotentialInitial potential (IP) is a widely quoted figure that certainly gives an indication of instantaneous well productivity. Testingprocedures vary between companies and the IP may not be a reliable indicator of EUR, however. In a sample of more than200 gas wells, the first month’s gas production was 76% of the state recorded IP. For a group of 150 oil wells, the actual firstmonth’s production was 88% of the IP test rate. Peak actual monthly oil production ( Fig. 2 ) had a fairly good correlationwith EUR in a group of 400 wells but the relationship of EUR to peak gas production ( Fig. 3 ) was not as defined.

EUR vs. Peak Month Oil

(Is peak production correlated to EUR?)

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

-

5 , 0

0 0

1 0

, 0 0 0

1 5

, 0 0 0

2 0

, 0 0 0

2 5

, 0 0 0

3 0

, 0 0 0

3 5

, 0 0 0

4 0

, 0 0 0

Peak Oil - BBL/month

E U R

, B B L e q u

i v a

l e n

t 2 0 : 1 Atascosa

De WittDimmitGonzalesKarnesLaSalleLive OakMcMullenMaverickWebb

Fig 2. EUR vs. peak actual oil production, all counties.

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EUR vs. Peak Month Gas(Is peak production correlated to EUR?)

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

-

3 0 , 0 0 0

6 0 , 0 0 0

9 0 , 0 0 0

1 2 0 , 0 0 0

1 5 0 , 0 0 0

1 8 0 , 0 0 0

2 1 0 , 0 0 0

2 4 0 , 0 0 0

2 7 0 , 0 0 0

3 0 0 , 0 0 0

Peak Gas - MCF/month

E U R

, B B L e q u

i v a

l e n

t 2 0 : 1 Atascosa


Fig. 3 – EUR vs. peak actual gas production, all counties.

Correlation of EUR to Time, Frac Size, Horizontal Length

Are The Wells Getting Better?Figure 4 below is a plot of the EUR for all the wells in the study vs. the month of first production, color coded by county.There may be too much information here and the individual county plots are better at showing trends, but it clear that the perwell EUR increased from the early days but after early 2010 it is difficult to see an overall pattern.

EUR-BOE vs. Time(Are the wells getting better?)

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

J a n -

0 8

J a n -

0 9

J a n -

1 0

J a n -

1 1

First Production

E U R

, B

B L e q u

i v a

l e n

t 2 0 : 1

AtascosaDe WittDimmitGonzalesKarnesLaSalleLive OakMcMullenMaverickWebb

Fig. 4 – EUR vs. month of first production, all counties.

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Do Larger Fracs Give Higher EUR?Figure 5 is a plot of the frac sand vs. the forecast of EUR for 319 wells in which the frac sand data was tabulated. The datais scattered but a clear trend can be seen for better results with larger frac jobs, up to 4,000,000 lb., then the trend seems todisappear, at least in some of the counties, and may even show decreasing EUR results with larger jobs. Note that the KarnesCounty data set does indicate continued improvement in EUR with larger jobs.

EUR vs. Frac Size(Are bigger fracs yielding more?)

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

1 0 0 0

2 0 0 0

3 0 0 0

4 0 0 0

5 0 0 0

6 0 0 0

7 0 0 0

8 0 0 0

9 0 0 0

1 0 0 0 0

1 1 0 0 0

Thous Pounds of Frac Sand

E

U R

, B B L e q u

i v a

l e n

t 2 0 : 1 Atascosa

De WittDimmitGonzalesKarnesLaSalleLive OakMcMullen

MaverickWebb

Fig. 5 – EUR vs. frac size in thousands of pounds of sand, all counties.

Are Longer Horizontals Better?Information on horizontal length is available but tedious to assemble for such a large group of wells. As a proxy forhorizontal length, I substituted the length of perforated interval from the public records for 257 of the wells in the study groupand correlated it to the EUR forecast. Figure 6 summaries the data, again color coded by county. There appears to be atrend of increasing EUR with perforated length up to approximately 5,000 ft., then the data suggests decreasing EUR vs.

length.

EUR vs. Perforated Length(Are longer horizontals yielding more?)

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

0

1 0 0 0

2 0 0 0

3 0 0 0

4 0 0 0

5 0 0 0

6 0 0 0

7 0 0 0

8 0 0 0

9 0 0 0

1 0 0 0 0

Perforated Length, Ft.

E U R

, B B L e q u

i v a

l e n

t 2 0 : 1 Atascosa


Fig. 6 – EUR vs. perforated length, all counties.

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Individual County Summaries

DE WITT COUNTY

Eagle Ford EUR Distribution - DeWitt County

0

2

46

8

10

12

1416

18

20

5 0 0 0 0

1 0 0 0 0 0

1 5 0 0 0 0

2 0 0 0 0 0

2 5 0 0 0 0

3 0 0 0 0 0

3 5 0 0 0 0

4 0 0 0 0 0

4 5 0 0 0 0

5 0 0 0 0 0

5 5 0 0 0 0

M o r e

EUR - BOE

F r e q u e n c y

0%

10%

20%30%

40%

50%

60%

70%80%

90%

100%

89 wells Mean 403,715 BOE

Median 391,212 BOE

Fig. 7 – EUR distribution, De Witt County. The distribution is unusual in that there are few small wells

and it is not log-normal.

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 203010

100

1,000

10,000

100,000

Time

M o n

t h l y R a

t e

DeWitt normalized (86 w ells)( )CO,

Fig. 8 – Normalized decline of 86 wells in De Witt County. (Gas in dashed red, oil in solid green, well count in black).

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DE WITT COUNTY – CONTINUED

EUR-BOE vs. Time - DEWITT COUNTY(Are the wells getting better?)

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

J a n - 0

8

J a n - 0

9

J a n - 1

0

J a n - 1

1

First Production

E U R

, B B L e q u

i v a

l e n

t 2 0 : 1

Fig. 9 – EUR vs. date of first production, De Witt County.

Frac Sand vs. Time - DEWITT COUNTY(Are the fracs getting bigger?)

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

J a n - 0

8

J a n - 0

9

J a n - 1

0

J a n - 1

1

First Production

T h o u s .

P o u n

d s o

f F r a c

S a n

d

De Witt

Fig. 10 – Frac size over time, De Witt County.

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DIMMIT COUNTY

Eagle Ford EUR Distribution - Dimmit County

0

5

10

15

20

25

30

35

5 0 0 0 0

1 0 0 0 0 0

1 5 0 0 0 0

2 0 0 0 0 0

2 5 0 0 0 0

3 0 0 0 0 0

3 5 0 0 0 0

4 0 0 0 0 0

4 5 0 0 0 0

5 0 0 0 0 0

5 5 0 0 0 0

M o r e

EUR - BOE

F r e q u e n c y

0%

10%

20%

30%

40%

50%

60%

70%

80%90%

100%

182 wells Mean 180,870 BOE Median 129,129 BOE

Fig. 11 – EUR distribution, Dimmit County.

2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029

10

100

1,000

10,000

100,000

Time

M o n

t h l y R a

t e

Dimmitt normalized (128 we lls)( )CO,

Fig. 12– Normalized decline of 128 wells in Dimmit County. (Gas in dashed red, oil in solid green, well count in black).

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DIMMIT COUNTY - CONTINUED

EUR-BOE vs. Time DIMMIT COUNTY(Are the wells getting better?)

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

J a n - 0

8

J a n - 0

9

J a n - 1

0

J a n - 1

1

First Production

E U R

, B B L e q u

i v a

l e n

t 2 0 : 1

Dimmit

Fig 13 – EUR vs. date of first production, Dimmit County.

EUR vs. Perforated Length - DIMMIT COUNTY(Are longer horizontals yielding more?)

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

0

1 0 0 0

2 0 0 0

3 0 0 0

4 0 0 0

5 0 0 0

6 0 0 0

7 0 0 0

8 0 0 0

9 0 0 0

1 0 0 0 0


E U R

, B B L e q u

i v a

l e n

t 2 0 : 1

Dimmit

Fig. 14 – EUR vs. perforated length, Dimmit County.

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KARNES COUNTY

Eagle Ford EUR Distribution - Karnes County

0

5

10

15

20

25

5 0 0 0 0

1 0 0 0 0 0

1 5 0 0 0 0

2 0 0 0 0 0

2 5 0 0 0 0

3 0 0 0 0 0

3 5 0 0 0 0

4 0 0 0 0 0

4 5 0 0 0 0

5 0 0 0 0 0

5 5 0 0 0 0

M o r e

EUR - BOE

F r e q u e n c y

0%10%20%30%

40%50%60%70%

80%90%

100%


Median 192,925 BOE

Fig. 15 – EUR distribution, Karnes County.

2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 202910

100

1,000

10,000

100,000

Time

M o n

t h l y R a

t e

Karnes normalized (121 wells on 113 lses)( )CO,

Fig. 16 – Normalized decline of 121 wells in Karnes County. (Gas in dashed red, oil in solid green, well count in black).

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LA SALLE COUNTY

Eagle Ford EUR Distribution - La Salle County

0

5

10

15

20

25

30

35

5 0 0 0 0

1 0 0 0 0 0

1 5 0 0 0 0

2 0 0 0 0 0

2 5 0 0 0 0

3 0 0 0 0 0

3 5 0 0 0 0

4 0 0 0 0 0

4 5 0 0 0 0

5 0 0 0 0 0

5 5 0 0 0 0

M o r e

EUR - BOE

F r e q u e n c y

0%

10%

20%

30%

40%

50%

60%

70%

80%90%

100%


Median 178,466 BOE

Fig. 19 – EUR distribution, La Salle County.

2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 202910

100

1,000

10,000

100,000

Time

M o n

t h l y R a

t e

LaSalle normalized (131 w ells on 126 lses)( )CO,

Fig. 20 – Normalized decline of 131 wells in La Salle County. (Gas in dashed red, oil in solid green, well count in black).

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LA SALLE COUNTY – CONTINUED

EUR-BOE vs. Time - LA SALLE COUNTY(Are the wells getting better?)

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

J a n - 0

8

J a n - 0

9

J a n - 1

0

J a n - 1

1

First Production

E U R

, B B L e q u

i v a

l e n

t 2 0 : 1

LaSalle

Fig. 21 – EUR vs. date of first production, La Salle County.

EUR vs. Frac Size - LA SALLE COUNTY

(Are bigger fracs yielding more?)

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

1 0 0 0

2 0 0 0

3 0 0 0

4 0 0 0

5 0 0 0

6 0 0 0

7 0 0 0

8 0 0 0

9 0 0 0

1 0 0 0 0

1 1 0 0 0


E U R

, B B L e q u

i v a

l e n

t 2 0 : 1

LaSalle

Fig. 22 – EUR vs. frac sand, La Salle County.

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MCMULLEN COUNTY

Eagle Ford EUR Distribution - McMullen County

0

2

4

6

8

10

12

14

16

18

20

5 0 0 0 0

1 0 0 0 0 0

1 5 0 0 0 0

2 0 0 0 0 0

2 5 0 0 0 0

3 0 0 0 0 0

3 5 0 0 0 0

4 0 0 0 0 0

4 5 0 0 0 0

5 0 0 0 0 0

5 5 0 0 0 0

M o r e

EUR - BOE

F r e q u e n c y

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%


Median 126,427 BOE

Fig. 23– EUR distribution, McMullen County.

2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 202910

100

1,000

10,000

100,000

Time

M o n

t h l y R a

t e

McMullen normalized (52 w ells)( )CO,

Fig. 24 – Normalized decline of 52 wells in McMullen County. (Gas in dashed red, oil in solid green, well count in black).

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MCMULLEN COUNTY – CONTINUED

EUR-BOE vs. Time - MCMULLEN COUNTY(Are the wells getting better?)

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

J a n - 0

8

J a n - 0

9

J a n - 1

0

J a n - 1

1

First Production

E U R

, B B L e q u

i v a

l e n

t 2 0 : 1

McMullen

Fig. 25 – EUR vs. date of first production, McMullen County.

EUR vs. Perforated Length - MCMULLEN COUNTY

(Are longer horizontals yielding more?)

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

0

1 0 0 0

2 0 0 0

3 0 0 0

4 0 0 0

5 0 0 0

6 0 0 0

7 0 0 0

8 0 0 0

9 0 0 0

1 0 0 0 0


E U R

, B B

L e q u

i v a

l e n

t 2 0 : 1

McMullen

Fig. 26 – EUR vs. perforated length, McMullen County.

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WEBB COUNTY

Eagle Ford EUR Distribution - Webb County

0

5

10

15

20

25

30

35

40

45

5 0 0 0 0

1 0 0 0 0 0

1 5 0 0 0 0

2 0 0 0 0 0

2 5 0 0 0 0

3 0 0 0 0 0

3 5 0 0 0 0

4 0 0 0 0 0

4 5 0 0 0 0

5 0 0 0 0 0

5 5 0 0 0 0

M o r e

EUR - BOE

F r e q u e n c y

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%


Median 155,190 BOE

Fig. 27 – EUR distribution, Webb County.

2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 202910

100

1,000

10,000

100,000

Time

M o n

t h l y R a

t e

Webb normalized (167 w ells)( )CO,

Fig. 28 – Normalized decline of 167 wells in Webb County. (Gas in dashed red, oil in solid green, well count in black).

8/9/2019 Sp 158207

18/19

18 SPE 158207

WEBB COUNTY - CONTINUED

EUR-BOE vs. Time - WEBB COUNTY(Are the wells getting better?)

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

J a n - 0

8

J a n - 0

9

J a n - 1

0

J a n - 1

1

First Production

E U R

, B B L e q u

i v a

l e n

t 2 0 : 1

Webb

Fig. 29 – EUR vs. date of first production, Webb County.

EUR vs. Frac Size - WEBB COUNTY(Are bigger fracs yielding more?)

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

1 0 0 0

2 0 0 0

3 0 0 0

4 0 0 0

5 0 0 0

6 0 0 0

7 0 0 0

8 0 0 0

9 0 0 0

1 0 0 0 0

1 1 0 0 0


E U R

, B B L e q u

i v a

l e n

t 2 0 : 1

Webb

Fig. 30 – EUR vs. frac sand, Webb County.

8/9/2019 Sp 158207

19/19

SPE 158207 19

Conclusions:

• Estimated ultimate recovery from decline curves of horizontal wells indicates an average EUR for the Eagle Fordshale of 206,800 BOE/well including an estimate of NGL.

• The best counties appear to be De Witt (403,715 BOE), Live Oak (248,818 BOE – limited well count) and Karnes(210,801 BOE).

• The normalized decline profiles of all established wells in 10 counties, suggests high initial decline rates and littlehyperbolic nature.

• The per well EUR has not shown any general increase after mid-2010.• There are only rough correlations of EUR to frac size and perforated length.• Any reference to barrels-of-oil-equivalent (BOE) should include an explanation of the gas-to-oil conversion and

how NGL is handled.

References

Martin, R., Baihly, J., Malpani, R., et al. 2011. Understanding Production from Eagle Ford-Austin Chalk Systems. Paper SPE 145117presented at the SPE Annual Technical Conference, Denver, 30 October – 2 November.

O’Connor, L., Seidle, J., 2011. Well Performance and Economics of Selected U.S. Shales. Society of Petroleum Evaluation Engineers(SPEE) Journal, volume VI issue 1, pg. 7, Spring 2012.

Seager, R. 2011. Shale Engineering. Society of Petroleum Evaluation Engineers (SPEE) Journal, volume VI issue 1, pg. 15, Spring 2012.Baihly, J., Altman, R., Malpani, R., et al. 2010. Shale Gas Production Decline Trend Comparison Over Time and Basins. Paper SPE

135555 presented a the SPE Annual Technical Conference, Florence, Italy, 19-22 September.Mullen, J. 2010. Petrophysical Characterization of the Eagle Ford Shale in South Texas. Paper CSUG/SPE 138145 presented at the

Canadian Unconventional Resources & International Petroleum Conference, Calgary, 19-21 October.Mullen, J., Lowry, J.C., Nwabouku, K.C., 2010. Lessons Learned Developing the Eagle Ford Shale. Paper SPE 138446 presented at the

SPE Tight Gas Completions, San Antonio, Texas, 2-3 November 2010.Fan, L., Martin, R., Thompson, J., et al. 2011. An Integrated Approach for Understanding Oil and Gas Reserves Potential in Eagle Ford

Shale Formation. Paper CSUG/SPE 148751 presented at the Canadian Unconventional Resources Conference, Calgary, 15-17November.

Centurion, S., 2011. Eagle Ford Shale: A Multi-Stage Hydraulic Fracturing, Completion Trends and Production Outcome Study UsingPractical Data Mining Techniques. Paper SPE 149258 presented at the SPE Eastern Regional Meeting, Columbus, Ohio, 17-19August.

Bingziang, X., Haghighi, M., Cooke, D., et al. 2012. Production Data Analysis in Eagle Ford Shale Gas Reservoir. Paper SPE 153072

presented at the SPE/EAGE European Unconventional Resources Conference, Vienna, Austria, 20-22 March.Maksoud, J. ed., Haines, L. ed., Beauboef, B. ed., et al. 2010. Eagle Ford: The Playbook , Houston: Hart Energy Publishing.Eagle Ford output continues to soar. 2011. EP Magazine pg. 72 (October 2011).Pioneer Natural Resources, 2011. Presentation at Barclays CEO Energy Conference, 7 September.BHP Billiton Petroleum Investor Briefing. 14 November 2010.

http://www.bhpbilliton.com/home/investors/reports/Documents/2011/111114_BHPBillitonPetroleumInvestorBriefing_Presentation.pdf .

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