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Linn Energy, LLC (LINE) Message Board

  • rlp2451 rlp2451 Apr 29, 2012 4:23 PM Flag

    Differences in Decline Rates of Vertical vs. Horizontal Wells and Other Stuff;

    Since there has been much discussion about decline rates, I thought I'd do a little investigation as to the topic. Here are some tidbits I found.

    June, 2011:
    http://www.oilandgasinquirer.com/article.asp?article=profiler%5C110620%5Cpro2011_uk0001.html

    "Earlier this year, Peters & Co. Limited reported that five multi-frac horizontal plays showed average first-year decline rates of 72 per cent, with the median first-year decline rate on 10 oil resource plays at 60 per cent. The median first-year decline rate on horizontal wells in nine gas resource plays was 75 per cent-15 percentage points higher than the oil plays.

    The decline rates are important, Peters & Co. noted, because companies with higher proportional exposure to such plays tend to have high corporate decline rates, which Peters warned will often lead to increasing maintenance capital requirements to maintain production.

    An example of this is the Bakken tight oil play in southeastern Saskatchewan. According to Saskatchewan government figures, horizontal Bakken wells have an average 74 per cent decline rate during their first year of production. On average, they decline by 24 per cent in the second year and 22 per cent in the third year.

    Peters & Co. says what these decline rates mean is companies active in the play need to be continually drilling and completing wells just to stay in place production-wise. It points to one major producer, which it estimates will have to spend $785 million in 2011 just to keep production flat in the region.

    May, 2012:
    http://priceofoil.org/2012/03/09/north-dakotas-oil-boom-from-space/
    (Pretty cool picture on that website)
    "First, the decline rate on tight oil wells is very high. This means that the flow of oil from the well declines to a relative trickle typically after about a year. The result of this is that the drillers move on quickly in search of new pastures. So the infrastructure to pipe the gas away will often be struggling to catch up, arriving too late for the bulk of the gas and in some cases may not be worth putting in at all."

    February 2010 (getting old, I know, but a valid point):
    http://www.oilandgasevaluationreport.com/tags/ip-rate/
    When I read a press release which includes IPs it's usually with a great deal of skepticism. The only thing you can tell for sure from an IP test is that the well isn't dry. Only after several wells have been on production in a given area and a "type curve" established, can the IP rate be used to approximate reserves.

    And finally, from a blog on "the Oil Drum" website (debates go on on other websites as well):

    Decline rates are THE problem. If you have a well with an initial production rate of 1,000 bpd and a decline rate of 80% per year, after 1 year it will be producing 200 bpd, after 2 years it will be producing 40 bpd, after 3 years it will be producing 8 bpd, after 4 years it will be producing 1.6 bpd, and after 5 years it will be producing 1/3 bpd. (Assuming an exponential decline curve, which is typical).

    It will not produce 46 bpd for 30 years.

    At this point the well has recovered nowhere near its hypothetical 500,000 barrels of oil, so you have to drill an infill well near the first, frac it, and start over - but then you are back on the decline curve again.

    So, imagine you have thousands of these wells, all of them in steep decline. You have to drill thousands more to increase production. Soon, you have tens of thousands of wells in steep decline, so you have to drill tens of thousands more to increase production. At some point in time you just can't find enough money to drill enough wells to increase production, and then you find yourself on downslope of the classic Hubbert bell-shaped production curve, which, unbeknownst to you, you have been following up until that point.

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