US production remains high due to high-grading, well design,
cost efficiencies, and lower oil service contracts.
High-grading from marginal to core areas can increase per well
production from 200% to 500% depending on area, which means one
core well can equate to several marginal producers.
Shorter stages, increased proppant and frac fluids increase
production and flatten the depletion curve.
EOG's work in Antelope field provides a framework for other
operators to increase production while completing fewer wells.
Few operators are currently developing Mega-fracs, this
provides significant upside to US shale production as others start
producing more resource per foot.
US Oil production remains at volumes seen when WTI was at
$100/bbl. Many analysts believed operators couldn't survive, but
$60/bbl may be good enough for operators to drill economic wells.
Oil prices have decreased significantly, and the US Oil ETF
(NYSEARCA:
USO) with it. Many were wrong about US
production, and the belief $60/bbl oil would decrease US
production. Although completions have been deferred, high-grading
and mega-fracs have made up for fewer producing wells. When
calculating US production going forward, it is important to account
for the number of new completions. If more wells are completed, the
higher the influx of production should be. We are finding the
quality of geology and well design have a greater effect on total
production than originally thought.
(click to enlarge)
There are several factors influencing US production. Operators
have moved existing rigs to core areas. This decreases its ability
getting acreage held by production. In the Bakken, rigs have moved
near the Nesson Anticline.
In the Eagle Ford, Karnes seems to be the area of interest.
Midland County in the Permian has also been attractive. Operators
have decided to complete wells with better geology. When an
operator completes wells in core acreage versus marginal leasehold,
we see increased production per location. This is just part of the
reason US production remains high.
The average investor does not understand the significance. Most
think wells have like production, but areas are much different.
When oil was at a $100/bbl, it allowed operators to get acreage
held by production, although payback times were not as good.
Marginal acreage was more attractive, even at lower IRRs. Operators
have a significant investment in acreage, and do not want to lose
it. Because of this, many would operate in the red expecting future
rewards. Just because E&Ps lose money, does not mean the
business isn't economic. It is the way business is done in the
short term as oil is an income stream. Wells produce for 35 to 40
years, and once well costs are paid back there are steady revenues.
Changes in oil prices have changed this, as now operators will have
to focus on better acreage.
Re-fracs are starting to influence production. Although most
operators have not begun programs, interest is high. Re-fracs may
not be a game changer, but could be an excellent way to increase
production at a lower cost. This is not as significant with well
designs of today, but older designs left a significant amount of
resource. More importantly, when operators began, it was drilling
the best acreage. Archaic well designs could leave some stages
completely untouched. Current seismic can now identify this, and
provide for a better re-frac. We expect to see some very good
results in 2016. In conjunction with high-grading, well design
continues to be the main reason production has maintained. Changes
to well design have been significant, and the resulting production
increases much better than anticipated.
No operator is better than EOG Resources (NYSE:
EOG) at well design. From the Bakken, to the
Eagle Ford and Permian it continues to outperform the
competition.
The following map courtesy of
ShaleMapsPro.comdoes a good job of illustrating EOG's exposure
in the Eagle Ford.
(Source: Shalemapspro.com)
EOG's focusing of frac jobs closer to the well bore has provided
for much better source rock stimulation (fraccing). Since more
fractures are created, there is a greater void in the shale. This
means more producing rock has contact with the well. EOG continues
to push more sand and fluids in the attempt to recover more
resource per foot. To evaluate production, it must be broken into
days over 6 to 12 months. To evaluate well design, locations must
be close to one another and by the same operator. This consistency
allows us to see advantages to well design changes. Lastly, we
compare marginal acreage it is no longer working to the
high-grading program. This is how operators are spending less and
producing more.
EOG is working in the Antelope field of northeast McKenzie
County. This is Bakken core acreage and considered excellent in
both the middle Bakken and upper Three Forks.
(click to enlarge)
(Source:
Welldatabase.com)
The center of the above map is the location of both its
Riverview and Hawkeye wells. These six wells are located in two
adjacent sections. The pad is just west of New Town in North
Dakota. Riverview 100-3031H was completed in 6/12. It is an upper
Three Forks well. 39 stages were used on an approximate 9000 foot
lateral. 5.7 million pounds of sand were used with 85000 barrels of
fluids.
(click to enlarge)
(Source: Welldatabase.com)
Date
Oil (BBL)
Gas ((NYSEMKT:
MCF))
BOE
6/1/2012
4,384.00
3,972.00
3972
7/1/2012
27,133.00
15,337.00
15337
8/1/2012
24,465.00
17,223.00
17223
9/1/2012
21,457.00
9,190.00
9190
10/1/2012
18,040.00
12,601.00
12601
11/1/2012
19,924.00
13,366.00
13366
12/1/2012
28,134.00
22,259.00
22259
1/1/2013
15,382.00
12,661.00
12661
2/1/2013
3,429.00
2,451.00
2451
3/1/2013
15,242.00
22,774.00
22774
4/1/2013
15,761.00
8,479.00
8479
5/1/2013
13,786.00
18,372.00
18372
6/1/2013
14,485.00
18,555.00
18555
7/1/2013
15,668.00
27,250.00
27250
8/1/2013
12,084.00
23,876.00
23876
9/1/2013
13,841.00
46,815.00
46815
10/1/2013
11,388.00
45,800.00
45800
11/1/2013
2,711.00
10,533.00
10533
12/1/2013
0
0
0
1/1/2014
5,953.00
35
35
2/1/2014
11,368.00
20,851.00
20851
3/1/2014
8,784.00
11,179.00
11179
4/1/2014
5,607.00
8,479.00
8479
5/1/2014
4,727.00
5,663.00
5663
6/1/2014
8,359.00
12,726.00
12726
7/1/2014
8,799.00
22,957.00
22957
8/1/2014
7,958.00
31,621.00
31621
9/1/2014
7,218.00
44,318.00
44318
10/1/2014
3,778.00
14,058.00
14058
11/1/2014
3,701.00
9,951.00
9951
12/1/2014
6,612.00
18,435.00
18435
1/1/2015
6,181.00
24,142.00
24142
2/1/2015
3,517.00
10,722.00
10722
3/1/2015
5,218.00
24,175.00
24175
4/1/2015
4,275.00
24,233.00
24233
(Source: Welldatabase.com)
Riverview 100-3031H was a progressive well design for 2012. It
produced well. To date it has produced 379 thousand bbls of crude
and 615 thousand Mcf of natural gas. This equates to $24 million in
revenues. Over the first 360 days (using the true number of
production days) it produced 240,036 bbls of crude. The month of
December 2013, this well was shut in for the completion of an
adjacent well. There was a return to production but no significant
jump in production from pressure generated by the new locations.
This well declined 42% over 12 months. This is much lower than
estimates shown through other well models. The next year we see a
35% decline. 10 months later we see an additional decline of
approximately 55%. The decline curve of a well is very specific to
geology and well design. Keep in mind averages are just that, and
do not provide specific data. These averages should not be used to
evaluation acreage and operator as there are wide average swings.
Also, averages are generally over a long time frame. Production in
the Bakken began in 2004 (first horizontal well completed). Wells
in 2004 produce nothing like wells today. Updated averages based on
year (IP 360) are more useful. Riverview 100-3031H was part of a
two well pad. A middle Bakken well was also completed.
Riverview 4-3031H began producing a month after Riverview
100-3031H. It was a 38 stage 9000 foot lateral. 4.3 million lbs of
sand were used and 69000 bbls of fluids.
(click to enlarge)
(Source: Welldatabase.com)
The Riverview and Hawkeye wells analyzed in this article were
drilled in a southern fashion.
Date
Oil
Gas
BOE
7/1/2012
20,529.00
12,537.00
12537
8/1/2012
16,553.00
16,903.00
16903
9/1/2012
17,096.00
10,148.00
10148
10/1/2012
23,197.00
17,914.00
17914
11/1/2012
20,122.00
14,402.00
14402
12/1/2012
27,340.00
33,217.00
33217
1/1/2013
16,044.00
24,394.00
24394
2/1/2013
4,267.00
4,946.00
4946
3/1/2013
27,516.00
26,219.00
26219
4/1/2013
20,792.00
7,940.00
7940
5/1/2013
17,516.00
35,948.00
35948
6/1/2013
15,457.00
50,500.00
50500
7/1/2013
13,480.00
50,807.00
50807
8/1/2013
11,254.00
42,300.00
42300
9/1/2013
9,319.00
40,341.00
40341
10/1/2013
8,559.00
33,116.00
33116
11/1/2013
2,190.00
40
40
12/1/2013
0
0
0
1/1/2014
1,124.00
11
11
2/1/2014
5,271.00
81
81
3/1/2014
8,931.00
9,827.00
9827
4/1/2014
5,469.00
7,940.00
7940
5/1/2014
4,807.00
5,748.00
5748
6/1/2014
8,522.00
13,819.00
13819
7/1/2014
7,982.00
17,983.00
17983
8/1/2014
7,169.00
26,755.00
26755
9/1/2014
5,750.00
22,586.00
22586
10/1/2014
1,349.00
3,194.00
3194
11/1/2014
6,495.00
15,947.00
15947
12/1/2014
6,442.00
18,806.00
18806
1/1/2015
5,840.00
22,126.00
22126
2/1/2015
4,171.00
18,682.00
18682
3/1/2015
4,221.00
18,539.00
18539
4/1/2015
3,878.00
19,725.00
19725
(Source: Welldatabase.com)
Riverview 4-3031H has produced 361 thousand bbls of crude and
657 thousand Mcf of natural gas. It under produced Riverview
100-3031H, but this is consistent with well design. 360 day
production totaled 237,735 bbls of oil. We do not know if the Three
Forks is a better pay zone than the middle Bakken as the well
design was not consistent. Most operators have reported better
results from the middle Bakken. The Three Forks well used one more
stage (less feet per stage should mean better fracturing). It also
used significantly more sand and fluids. Either way both wells were
good results. Riverview 4-3031H only declined approximately 36% in
a comparison of the first month to month 12. This was 7% better
than 100-3031H. It declined another 41% in year two on a month to
month comparison. This was 6% greater. 56% was seen when compared
to adjusted production for 5/15. The Three Forks well declines
slower in later production than 4-3031H. This may be due to well
design. The well with more stages, proppant and fluids continues to
out produce the Bakken well. It is possible the source rock is
better. There are many other variables to look at, but this data
provides why EOG continues to push ahead with more complex
locations.
In September of 2012, EOG drilled its next well in this area.
Hawkeye 100-2501H is a 13700 foot lateral targeting the upper Three
Forks. It is a 47 stage frac. 14 million pounds of sand were used
with 158000 bbls of fluids.
(click to enlarge)
(Source: Welldatabase.com)
Of the three pads, this well is located in the center. It was an
interesting design, given the length of the lateral.
Date
Oil
Gas
BOE
9/1/2012
21,959.00
444
444
10/1/2012
54,927.00
155
155
11/1/2012
47,557.00
57,300.00
57300
12/1/2012
55,367.00
92,144.00
92144
1/1/2013
33,396.00
55,877.00
55877
2/1/2013
22,100.00
32,810.00
32810
3/1/2013
36,631.00
57,544.00
57544
4/1/2013
29,075.00
32,696.00
32696
5/1/2013
22,210.00
33,351.00
33351
6/1/2013
17,544.00
25,794.00
25794
7/1/2013
15,872.00
23,600.00
23600
8/1/2013
19,647.00
28,746.00
28746
9/1/2013
15,486.00
22,352.00
22352
10/1/2013
21,325.00
31,678.00
31678
11/1/2013
6,418.00
9,214.00
9214
12/1/2013
0
0
0
1/1/2014
0
0
0
2/1/2014
0
0
0
3/1/2014
29,699.00
23,822.00
23822
4/1/2014
39,782.00
32,696.00
32696
5/1/2014
35,267.00
61,543.00
61543
6/1/2014
27,554.00
49,551.00
49551
7/1/2014
7,229.00
12,565.00
12565
8/1/2014
31,155.00
98,086.00
98086
9/1/2014
12,617.00
32,742.00
32742
10/1/2014
2
4
4
11/1/2014
7,769.00
15,996.00
15996
12/1/2014
15,487.00
49,147.00
49147
1/1/2015
4,427.00
9,918.00
9918
2/1/2015
9,344.00
20,654.00
20654
3/1/2015
8,459.00
25,171.00
25171
4/1/2015
7,235.00
24,752.00
24752
(Source: Welldatabase.com)
Hawkeye 100-2501H had some excellent early production numbers.
From that perspective, it is one of the best wells to date in the
Bakken. It has already produced 655,000 bbls of crude and 960,000
Mcf of natural gas. It has revenues in excess of $42 million to
date. This includes roughly four non-producing or unproductive
months. Crude production over the first 360 days was 389,835 bbls.
Over the first 12 months, this well produced crude revenues in
excess of $23 million. Decline rates were higher, as the first full
month of production declined 65% over the first year. This isn't
important as early production rates were some of the highest seen
in North Dakota. It is important to note, decline rates are
emphasized but higher pressured wells may deplete faster depending
on choke and how quickly production is propelled up and out of the
wellbore. Any well that produces very well initially will have
higher decline rates, but this does not lessen the value of the
well. This specific well is depleting faster, but no one is
complaining about payback times well under a year. Decline rates
decrease significantly in year two at 11%. This well saw a marked
increase in production when adjacent wells were turned to sales.
The additional pressure associated with well communication
increased production from 20,000 bbls/month to 35,000 bbls/month on
average. This occurred over a 6 month period.
(click to enlarge)
(Source: Welldatabase.com)
Hawkeye 102-2501H was the fourth completion. This 14,000 foot 62
stage lateral targeted the upper Three Forks. It used 14.5 million
pounds of sand and 164,000 bbls of fluids.
Date
Oil
Gas
BOE
1/1/2013
18,486.00
41
41
2/1/2013
27,120.00
8,705.00
8705
3/1/2013
39,702.00
15,748.00
15748
4/1/2013
17,714.00
30,501.00
30501
5/1/2013
41,368.00
57,489.00
57489
6/1/2013
26,602.00
34,399.00
34399
7/1/2013
0
0
0
8/1/2013
133
0
0
9/1/2013
0
0
0
10/1/2013
0
0
0
11/1/2013
0
0
0
12/1/2013
0
0
0
1/1/2014
5,163.00
6,403.00
6403
2/1/2014
41,917.00
74,353.00
74353
3/1/2014
36,439.00
18,111.00
18111
4/1/2014
19,477.00
30,501.00
30501
5/1/2014
26,388.00
43,071.00
43071
6/1/2014
27,480.00
49,456.00
49456
7/1/2014
14,529.00
33,072.00
33072
8/1/2014
24,542.00
62,753.00
62753
9/1/2014
17,613.00
53,460.00
53460
10/1/2014
17,451.00
66,544.00
66544
11/1/2014
9,634.00
33,366.00
33366
12/1/2014
16,338.00
76,547.00
76547
1/1/2015
11,450.00
65,277.00
65277
2/1/2015
8,971.00
50,919.00
50919
3/1/2015
3,177.00
14,820.00
14820
4/1/2015
6,495.00
13,616.00
13616
(Source: Welldatabase.com)
It has produced 458,000 bbls of crude and 839,000 Mcf to date.
This equates to roughly $30 million over well life. 360 day
production was 394,673 bbls of crude. Production was interesting as
initial production was outstanding. The big production numbers were
hindered as many of the early months had missed production days. We
don't know if there were production problems, but do know the well
was shut when adjacent wells were turned to sales. Production was
over 1000 bbls/d over the first six months. It was shut in for
another six months. After this production jumped, but this is
misleading. Given the fewer days of production per month, there
wasn't much of an increase when the new wells were turned to sales.
The decline over the first year on a monthly basis is 20%. The
second year is much greater at 80%. We have seen recent production
decrease significantly, and is something to watch. Lower decline
rates initially are more important. This is because production
rates are higher. It equates to greater total production.
Hawkeye 01-2501H was completed in January of 2013.
(click to enlarge)
(Source: Welldatabase.com)
It is a 64 stage, 15000 foot lateral targeting the middle
Bakken. This well used 172,000 bbls of fluids and 15 million pounds
of sand.
Date
Oil
Gas
BOE
1/1/2013
18,792.00
43
43
2/1/2013
30,211.00
13,879.00
13879
3/1/2013
42,037.00
17,648.00
17648
4/1/2013
17,433.00
36,881.00
36881
5/1/2013
38,754.00
63,501.00
63501
6/1/2013
28,602.00
48,817.00
48817
7/1/2013
0
0
0
8/1/2013
134
1
1
9/1/2013
0
0
0
10/1/2013
0
0
0
11/1/2013
0
0
0
12/1/2013
0
0
0
1/1/2014
6,311.00
7,186.00
7186
2/1/2014
43,713.00
74,099.00
74099
3/1/2014
39,156.00
18,492.00
18492
4/1/2014
23,408.00
36,881.00
36881
5/1/2014
21,681.00
33,498.00
33498
6/1/2014
28,502.00
51,543.00
51543
7/1/2014
18,795.00
45,017.00
45017
8/1/2014
25,512.00
58,837.00
58837
9/1/2014
20,522.00
60,662.00
60662
10/1/2014
19,137.00
68,576.00
68576
11/1/2014
12,093.00
37,043.00
37043
12/1/2014
16,587.00
45,980.00
45980
1/1/2015
14,246.00
62,819.00
62819
2/1/2015
9,220.00
35,931.00
35931
3/1/2015
3,617.00
6,634.00
6634
4/1/2015
13,702.00
42,551.00
42551
(Source: Welldatabase.com)
It has produced 492,170 bbls of crude and 866,520 Mcf of natural
gas. 360 day production was 412,072 bbls of oil.
(click to enlarge)
(Source: Welldatabase.com)
This is an excellent well, but the location of focus is Hawkeye
02-2501H. It was completed last in this group. This well provides
the link between changes in well design to production
improvements.
Date
Oil
Gas
BOE
12/1/2013
3,022.00
6,533.00
6533
1/1/2014
37,385.00
75,940.00
75940
2/1/2014
30,066.00
58,949.00
58949
3/1/2014
22,876.00
50,690.00
50690
4/1/2014
26,703.00
43,926.00
43926
5/1/2014
31,987.00
55,124.00
55124
6/1/2014
27,777.00
47,166.00
47166
7/1/2014
31,500.00
50,279.00
50279
8/1/2014
51,709.00
99,583.00
99583
9/1/2014
43,292.00
98,069.00
98069
10/1/2014
40,143.00
98,927.00
98927
11/1/2014
24,064.00
50,495.00
50495
12/1/2014
31,488.00
99,684.00
99684
1/1/2015
27,087.00
94,621.00
94621
2/1/2015
22,207.00
94,490.00
94490
3/1/2015
22,590.00
125,634.00
125634
4/1/2015
17,707.00
94,910.00
94910
(Source: Welldatabase.com)
The production numbers are significant. In less than a year and
a half, it has produced 490,000 bbls of crude and 1.25 Bcf of
natural gas. Revenues to date are $33.2 million. Its 360 day crude
production was 427,663 bbls. The production is impressive but the
decline curve is more important. This Hawkeye well has a steady
production rate with only a slight decline. This is where the
analysts may be getting it wrong, as decline curves change
significantly by area and well design. What EOG has done is not
only increased production significantly, but also flattened the
curve. Initial production is interesting as we don't see peak
production until nine months. This means our best month is August
of 2014, and not the first full month. When we analyze the
production after one full year of production, there is no drop
off.
This 12800 foot 69 stage lateral is a very good middle Bakken
design. EOG decided to pull back some of the lateral length. There
are several possible reasons for this. We think it is possible EOG
has discovered it was having difficulty in getting proppant to the
toe of the well. But this is why operators test the length. More
importantly, the increase in stages in conjunction with a shorter
lateral provides for shorter stages. This means the operator will
probably do a better job of stimulating the source rock. This well
also used massive volumes of fluids and sand. 460,000 bbls of
fluids were used with over 27 million lbs of proppant. I don't
normally break down the types of sand, as it can be trivial to some
but in this case I have as the design seems somewhat unique. This
well used approximately 16 million lbs of 100 mesh sand, 7 million
lbs of 30/70 and 4 million 40/70. The large volumes of mesh sand
are interesting. It would seem EOG is trying to push the finest
sand deep into the fractures to maintain deeper shale
production.
Well
Date
Lateral Ft.
Stages
Proppant Lbs.
Fluids Bbls.
12 mo. Oil Production Bbls.
Production/Ft.
Riverview 100-3031H
6/12
9,000
39
5.7M
85,000
240,036
26.67
Riverview 4-3031H
7/12
9,000
38
4.3M
69,000
237,735
26.42
Hawkeye 100-2501H
9/12
13,700
47
14M
158,000
389,835
28.46
Hawkeye 102-2501H
1/13
14,000
62
14.5M
164,000
394,673
28.19
Hawkeye 01-2501H
1/13
15,000
64
15M
172,000
412,072
27.47
Hawkeye 02-2501H
12/13
12,800
69
27M
460,000
427,663
33.41
I completed the above table for several reasons. The first was
to show well design's effect on one year total production. We used
360 days as a base. We didn't use 12 months as that will skew data,
as some wells don't produce every day of every month. Wells are
shut in for service or more importantly when new production from
adjacent locations are turned to sales. So these are a specific
number of days and not estimates. We also broke down production per
foot of lateral. This may be more important than any other factor.
Production per well is important, but lateral length is a key as it
shows how well the source rock was stimulated. In reality,
production per foot matters more at longer lateral lengths. Many
operators don't like to do laterals longer than 10,000 feet, as
production per foot decreases sharply. When looking at well
production data, it is obvious that production per foot suffers as
the toe of the lateral gets farther from the vertical.
There are several other ETFs that focus on U.S. and world crude
prices:
iPath S&P Crude Oil Total Return Index ETN (NYSEARCA:
OIL)
All six wells had fantastic results. The first two Riverview
wells are still considered sand heavy fracs and produced almost a
quarter of a million barrels of oil. This does not include natural
gas in the estimates, but EURs for these wells are approximately
1200 MBo. We don't put much emphasis on EURs other than an
indicator of how good production is in comparison. Since locations
will produce from 35 to 40 years, we are more inclined to emphasize
one year production. Although the Hawkeye wells drilled on 9/12 and
1/13 didn't show a large uptick in production per foot, it is still
quite impressive considering the lateral length. Overall production
uplift was exceptional, and these wells produce decent payback
times at current oil price realizations.
There is no doubt this area has superior geology. It is
definitely a core area, but may not be as good as Parshall field.
Because of this, we know other areas would not produce as well, but
still it provides a decent comparison for the upside to well
design. Geology is still key and this is probably why EOG recently
drilled a 15 well pad in the same general area. These wells are
still in confidential status, so we do not know the outcome. Given
the results in this area, these wells could be very interesting.
The most important reason to focus on these Mega-Fracs is
repeatability. If EOG can do this, so can other operators. Our
expectations are many operators will be able to complete wells this
good within the next 12 to 24 months. If this occurs we could see
production maintained at much lower prices and fewer
completions.
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