Shale Economics: Watch the Curve

Posted on March 17, 2010 by Greg McFarland

The economics of a shale play are sensitive to certain criteria that may not be critical to a conventional type oil or gas play.  One important criterion is the Initial Potential (IP) and the shape of the hyperbolic decline production curve.  A hyperbolic decline curve is composed of an IP followed by an initial steep decline rate, transitioning into a later long term, shallow, stabilized decline rate (see the graph below from Range Resources).  Shale production is characterizes by a steep decline curve early in its productive life.  The more oil and/or gas that you can make up front the better the economics.  

We've heard about the impressive IP's coming out of the Haynesville Shale and Marcellus Shale plays.  Currently, there is a lot of discussion about the initial decline rate of the Haynesville.  Analysis of current producing wells indicates that the wells are stabilizing in about one year.  This rapid decline calls into question some of the large reserves and the economics being proclaimed by the operators in the play.  Allen Brooks discusses this in his article:  New Research Questions Haynesville Shale Economics.

Obviously, costs and prices are also important criteria affecting the economics.  However, these two factors are known early on in a shale plays life.  Costs are determined by:

  • Depth of target shale and length of lateral
  • Number and size of stimulations
  • Lease prices
  • Existing infrastructure

Finally, price (especially for gas) can make or break a play.  Gas price depends on proximity to demand.  A big play driver for the Marcellus Shale is the price that producers get for their product.  The northeastern U.S. has the highest gas prices in the nation.  With the current price disparity between oil and gas, an oil shale play such as the Bakken has better economics than the Barnett Shale.  Due to the amount of reserves produced early in the wells life, the price on day one may determine if you drill or not.  Testament to this fact is the decline in activity in the Barnett over the last year.

Time will sort out the economics of all shale plays.  Watch the decline curves and hope for higher gas prices.

 

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Does "I.P." Mean "Investor Problems?"

Posted on February 25, 2010 by Mike Markes

In a recent article, Keith Schaefer asks the question whether there should be standardized rules for reporting IP (Initial Production) rates for newly drilled wells.  As Keith points out, currently there is no standardized methodology for these reported tests and some operators choose to report instantaneous rates while others report average rates over some period of time; however, even these average rates are not consistently reported (24 hrs, a week, a month, etc.).

This is even more critical when looking at horizontal wells drilled in tight formations, which are typically frac'd on completion-- shale plays.  These characteristics typically create linear flow near the well and expose a large amount of "virgin" reservoir, both of which give rise to high initial rates which rapidly drop-off before stabilizing at a lower rate.

The IP rate of a new well can impact the economics of the well because the greater the initial rate the more revenue the operator can use to repay the development costs, which directly impacts the ROR (rate of return).  The IP alone, however, has little impact on the well's ultimate reserves which is the key to the project's economics.

When determining the well's ultimate recovery, what happens after the IP is more important than the IP itself.  The initial decline rate of the well and the hyperbolic exponent (the rate at which the decline rate lessens) give character to the production curve and ultimately determine the well's reserves.

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.

There are several stories in the oil patch about the company who drills a well and based on it's IP, constructs a flowline, production facilities, and stakes several more offset wells (no doubt booking them as PUDs) only to have the well fizzle when put on production.  As bad as it would be to be the engineer on a project like this, it would be worse for the investor.

So, as Keith says, when it comes to reported IPs Caveat Emptor.

 

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