Decline rates of wells with enhanced completion

October 2016

This article has been updated with more data about the decline rates of EOG wells, adding time series for wells with peak production (IP30) in 2014 and 2015.

Other names (non exclusive) for enhanced completion are  “high intensity” or “high density” completions.

Part of the concept has been used by EOG since 2012, when EOG doubled the amount of fracking sand for some of its wells. Other  companies have started to apply that concept  in 2014, with a significant amount of those wells entering service in 2014-Q4.

The current methods vary from company to company and are geology dependent. Most common is the doubling or trebling of proppants , more fracking stages, the quantity and quality of fracking fluids (slick water…). Oasis  has described a variant with 100% ceramics proppant in one of its presentations.

In 2014, Continental resources saw costs increasing by more than 2M$/well for enhanced completion wells. After 2014, with average well cost down and making compromises on the completion enhancements, the cost difference to traditional  completion seems to have come down to between $1 M and $1.5M/well in the Bakken play.

The companies claim that initial production increases by 25% to more than 50%, compared to standard completions.

EOG has presented a chart showing a cumulated production difference of 33% between enhanced and normal completions after 6 months.

Oasis Petroleum presented some comparison data in a summer 2015 presentation for two Bakken areas. The highest difference existed for 9 “high intensity” completed Alger wells vs 27 standard completed Alger wells, claiming 54% higher IP production for the enhanced wells (the length of the comparison period is not specified). Oasis also gave the numbers for cumulative first 9 month production of those wells. After 9 months, the cumulative difference is down to 30%. That is still impressive, but with half of the first 9 months production typically happening in the first 3 months (for a standard completed well), the numbers suggest that the strength of the enhancing effect is fading during the year.

Blue analytics, quoting a Continental Resources source, said the “high graded” wells show a first year decline rate of “nearly 80%”.

EOG data 

EOG has the longest experience with enhanced completion wells. These completions are based on high volumes of sand from own sources. According to an IHS chart published here, most its 2013 wells got at least 1000 pound of proppant per lateral ft, more than twice the amount used by competitors. In the second half of 2013, for several wells, that amount was increased to 1500 pound/ft, in some cases even more.

EOG’s Bakken wells are mostly located in the Parshall field, which has been one of the most productive sweet spots. Even without enhanced completion, they would have shown excellent results. EOG is also said to have used pressure management to maintain high output over a longer period.

To see how EOG’s enhanced completion might have impacted production decline curves, the production history of EOG-Bakken wells completed after the first quarter of 2013 was initially considered. Because the initial analysis was done in 2015 and a minimum of post IP30 number of months was required, the total sample has been limited to 35 wells. The production data for confidential months was derived from a commercial database.

To these initial data, EOG wells that had their peak production months in 2014 and 2015 have been added later 2016. Ten of the original wells completed at the end of 2013 hat their IP30 month in early 2014 and are also included in the 2014 wells (representing 12% of these wells). Because most of EOG’s wells after 2013 had confidential status, the “Runs” have been used as a proxy for production numbers (regarding Runs, see here under confidential wells)

The  cumulative amount of pre IP30 production  (around 100% of IP30) is s higher than the amount observed for the average Bakken  well (around 70% of IP30).

 Results

The results are presented in the table below.

EOG
Total Bakken
2013
2014
2015
Pre 2014
Completions
IP30 Wells
IP30 Wells
IP30 (b/d)
1077
949
817
Nb wells start
35
87
49
Month↓
1
100.0%
100.0%
100.0%
100.0%
2
71.3%
71.8%
72.8%
76.4%
3
67.5%
55.1%
55.0%
61.8%
4
55.4%
46.9%
42.1%
54.5%
5
48.0%
42.6%
38.5%
49.1%
6
41.0%
37.9%
33.5%
44.5%
7
46.1%
36.0%
29.4%
40.9%
8
37.4%
34.4%
27.2%
38.2%
9
32.5%
28.8%
25.6%
35.5%
10
31.2%
26.8%
21.2%
32.7%
11
29.4%
24.4%
18.9%
30.9%
12
29.8%
23.1%
16.3%
29.1%
13
25.5%
21.6%
 14.3%
27.7%
14
24.2%
19.2%
26.4%
15
23.3%
17.6%
25.0%
16
19.0%
19.8%
23.6%
17
17.8%
15.8%
23.0%
18
19.0%
15.3%
22.3%
19
18.8%
13.7%
21.6%
20
16.7%
13.1%
21.0%
21
13.6%
12.2%
20.4%
22
14.0%
12.4%
19.9%
23
14.3%
11.1%
19.5%
24
13.9%
12.1%
19.1%

 

The right column shows, for comparative reasons, Bakken well decline rates for pre 2014  wells, derived from an empirical curve presented in Drilling Deeper. The data for 24th month  are thus derived from wells having started production in the first half of 2012 at latest. Those wells were barely influenced by tight spacing or by enhanced completions.

For EOG,  the data for the wells with IP30 in 2015 are based on 49 wells at the beginning and 40  wells in  month 12. The data for wells with IP30 in 2014 are based on 67 wells in month 24.

What is striking is the reduction in average well performance between 2013 and 2015. The average IP30 of the 35 wells completed and considered here for 2013 was 1077 b/d, that number fell to 949 b/d for wells having their peak month in 2014 and to 817 b/d in 2015. The 2014 average  was boosted by 10 excellent wells completed in 2013 and having their IP30 month in early 2014. For 2013, average IP30 oil, according to EOG, was close to the number of the 35 wells considered here.

The IP30 numbers of the 2015 wells are still significantly above average,  but that is probably largely the effect of enhance completions. If that boosts IP30 by 35% to 50%, the average peak productivity of the same underlying wells without enhanced completion would have been just  slightly above the average productivity of 2014 first half non confidential wells, which most likely did no benefit from enhanced completion.

Also noticeable is the deterioration of the decline rates between 2013 and 2015..

2013 completed wells: The first year production decline of the 2013 wells was roughly in line with pre 2014 wells shown in the right column and better then the average 2014 Bakken well. It has been said that EOG in 2013 and 2014 took more care to avoid interference, compared to other operators. Pressure management, to flatten the decline in the first year, was most likely also applied. In the second  year, production fell much faster, compared to the pre 2014 wells, especially in the second half of the year.

2014 IP30 wells: The average decline rates of EOG’s 2014 wells (middle column) are similar to slightly worse than the rates of average 2014 Bakken well over the first 2 years following the IP30 month. The decline rates of the 2014 Bakken wells are supposed to have been negatively impacted by interference as a result of tighter well spacing compared to the pre 2014 wells. If EOG’s 2014 wells were less impacted by interference than the average Bakken well, enhanced completion must have had a negative impact.

2015 IP30 wells. The decline rates of EOG’s 2015 wells are significantly worse than  the rates of the average Bakken well. In the 13th month (not shown in the table), based on 27 wells, production is down to 14% of IP30, a ratio that the average 2014 Bakken well reaches in month 24 and that the pre 2014 wells reach only in the 4th production year.

The productivity trends from 2013 to 2015 indicate that EOG’s glory days in the Bakken might be ending and that its high quality acreage is getting exhausted.

Regarding the impact of enhanced completion on the decline rate of a well, the results of the different years leaves room for interpretations. It’s difficult to single out that possible  negative impact from other negative influences.

Outlook

Bakken’s sweetest spots are saturated with wells. To be able to drill more wells there, EOG has started to apply high density fracking limited to a relatively short distance around the wellbore in 2015, to avoid interference with existing nearby wells.

High density fracking coupled with enhanced completion reduces flow resistance and  produces impressive IP30 numbers. But by reducing the frack distance around the wellbore, the reservoir volume is also reduced. The question is: how fast will the flow decline and how long will it last?

In its presentation of results for the 2nd quarter of 2015, EOG stated that had made it’s first high density completion in the Antelope field – well Riverview 102-32h – and mentioned it’s industry record IP30 production in July 2015 with close to 2800 b/d (4 times higher than the average of EOG’s  7 other wells with IP30 in July and August of 2015). But the decline was steep. In  the 6th month, down to one quarter of IP30 and in the 12th month just 14% of IP30.

Interference can nevertheless not be fully avoided if the new high density wells with limited frack distance are placed between older wells with longer frack distances around their well bore. The performance of the older wells will get negatively impacted.

 

 

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