US Shale Oil: drilling productivity and decline rates

Euan Mearns

Summary

• The EIA drilling productivity report has been used to estimate decline rates in the Bakken, Eagle Ford and Permian light tight oil (LTO or shale) plays (Figure 1). The objective is to estimate how far production will fall in these plays in light of the sharp decline in US rig count. The rationale is to calculate the production level at which new oil production capacity added will cancel the declines and equilibrium is reached.
• The shale drilling industry is highly dynamic. While rig count has fallen by about 60% in the 3 plays since end 2014 this is in part offset by rig productivity that has more than doubled in recent years. The rig count decline has more recently stabilised. Improved productivity should help profitability, but this is cancelled by the collapse in oil price.
• The estimated recent annual decline rates are 47% for the Bakken, 55% for the Eagle Ford and 22% for the Permian. These declines are not constant. Since year one declines are often of the order 70% and the smaller number of wells now being drilled means that the number of fast declining year one wells in the production pool is falling. Play decline rates are therefore also falling with time.
• With these declines and current rig count and productivity levels, production in the Bakken will stabilise at around 870,000 bpd, down 330,000 bpd on current levels. Production in the Eagle Ford will stabilise at around 1,140,000 bpd, down 560,000 on current levels. The lower decline in the Permian means that production there will continue to rise. It is estimated that the net effect will be an LTO production decline of the order 830,000 bpd spread over several months.
• It is questionable whether a decline in LTO production on this scale will be sufficient to bolster the flagging oil price and may, for example, be offset by production gains in Iran and elsewhere. Since much of the global oil industry cannot survive at current price levels a second and more brutal round of cuts to OECD companies is to be expected. This may in part take the form of company insolvencies that are just getting underway in the US shale industry. Ultimately, a balance between global oil supply and demand must be restored and, without a production cut by OPEC, this must then occur within the non-OPEC companies and countries.

Figure 1 The main shale oil and gas plays of the USA [1]

Introduction
The Energy Information Agency (EIA) of the USA publishes a monthly Drilling Productivity Report detailing the production and drilling statistics for the 7 shale oil and gas regions of the USA (Figure 1). This post presents an analysis of this data for the Bakken, Permian and Eagle Ford, that combined, account for 89% of US shale oil production. Much of this production does not actually come from shale but from 'tight' formations that need to be fracked to allow the oil and gas to flow. Shale oil has therefore been re-christened as light tight oil (LTO). In this post I use both terms - they both mean the same thing.
At this point I need to add a disclaimer. There are reasons to doubt the reliability of all the data in the EIA drilling productivity report. For example some have questioned whether all the Permian wells counted are in fact LTO wells. Some may be in more conventional oil pools. The interpretations of the data presented here can only be as good as the input data upon which they are based.

For each region, for oil and gas, the EIA publishes 3 key statistics: 1) monthly production, 2) number of operational rigs 3) production added per operational rig. This data allows for an analysis of the decline rates to be made. Declines in shale are known to be extremely high, often 70% in the first year, and many estimates of play declines have already been made. Because of the collapse in US oil directed drilling, shale oil production was also supposed to collapse sending the oil price back up. Since this has NOT YET happened, I decided to take a look at the numbers myself.

If no new wells are drilled in a shale region with 50% decline rate then at the end of a year production will halve. Declines are not constant over time and tend to reduce in maturing wells. Hence production will fall by less than 50% in the second year.
In the past, new and 'frenzied' drilling in the US shale patch has done three things: 1) it has compensated for declines, 2) it has added to production and 3) a certain number of wells have been drilled and not completed. Hence there is / was a stock of drilled and uncompleted wells and this makes the analysis presented here more complex and less certain. Generally there is a problem matching drilling one month directly to a production change that month. This has been partially overcome by smoothing the data.

The logic applied is that the difference between production added and production change each month equals the production decline. For both production change and production added I have used a 7 month centred moving average to calculate declines (see charts below). Information on drilled but not completed wells is not readily available and has been ignored. There is probably a better way of doing this but the results I get are similar to those produced by others. For example, Ron Paterson estimated 54% annual decline for Bakken and 62% for Eagle Ford in May of this year.

For each of the Bakken, Permian and Eagle Ford areas 5 standard charts have been produced. These charts are presented below with key observations and the discussion follows.

The Bakken


Figure 2 Raw data for the Bakken showing monthly production and rig count. Note how rig count peaked in June 2012 but that production has continued to rise steeply. The recent peak in September 2014 followed by a sharp decline in rig count has resulted in a production plateau. There are four reasons for this: 1) time lags between drilling, completion and first production, 2) a substantial improvement in rig productivity (Figure 3), 3) there are still 75 rigs drilling that helps compensate for declines and 4) old drilled but uncompleted wells are perhaps now coming on line (an accentuated version of reason '1').


Figure 3 Drilling productivity as reported by the EIA based on their analysis of available data. Note how back in January 2011 a single rig added on average 200 bpd new production capacity. By mid-2015 that number has risen to over 600 bpd, a three fold improvement in efficiency in less than 5 years. Note there are 3 variables that can combine to improve efficiency: 1) drilling faster (more wells / rig), 2) drilling and fracking better - improved completion technology and 3) targeting more productive zones.


Figure 4 By combining the rig and productivity data shown in Figure 4 we can produce this chart that shows production capacity added each month by multiplying number of rigs by the production added per rig. Not surprisingly, production added has collapsed along with the rig count. But almost 50,000 bpd per month is still being added in the Bakken. Is that enough to cancel declines?


Figure 5 The monthly production increase comes from Figure 2 and the monthly production added from Figure 4. Note that both curves have a 7 month centred moving average applied. The difference between production added and production increase is accounted for by decline (Figure 6).


Figure 6 The difference between production added and production increase is accounted for by decline (Figure 5) converted to a monthly % of the production in the prior month. The 7 month smoothed data (dark blue line) conveys decline rates that vary from 3 to 8% and a tendency for annual cycles. This variability in calculated declines almost certainly reflects in part operational dynamics. The 13 month smoothed line provides a better picture of the underlying trend. Decline rate increased when the 2009 drilling frenzy got under way - larger numbers of fast declining year one wells and has stabilised at around 5.2% per month. Note that annual decline is not 12*5.2% but is rather 47% (calculated from spreadsheet).

The Eagle Ford


Figure 7 The Eagle Ford rig count and production profiles are very similar to The Bakken (Figure 2). The Eagle Ford rig count peaked in May 2012 and has since more or less moved sideways until the late 2014 crash. Eagle Ford production began to decline in April 2015. Note that at 1.7 Mbpd, Eagle Ford production is substantially higher than Bakken.

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