Tuesday, May 25, 2010

Petrohawk Analyst Day: Part Two

Petrohawk management spent some time going through the company's "recipe" for drilling and completion.  The goal (obviously) is to increase production and decrease costs. The company provided a sample of an authority for expenditure (AFE) worksheet that lays out the costs to ivrill a Haynesville well.  For us mere mortals on the outside looking in, it is interesting to see where the $8-$10 million well costs come from.  Note, it does not include leasing costs, which might be significant for some wells (as Arthur Berman would remind us). 



Note that $2.8 million of the costs listed above are for the completion process (stimulation/sand control).  Petrohawk signed a forward contract with two of its three suppliers to fix costs around $2.5 million for 2010.  The market price would be about $3-$3.5 million right now, according to management.

Pressure pumping in the Haynesville Shale is a major concern, both in cost and timing.  Given the unique requirements of the play, only four companies that can provide required pressure pumping services for Haynesville completions.  As a result, it is harder to get jobs done and the costs are high because the service provider has pricing power.  Not only are there fewer of the pieces of equipment in the market, the pumps themselves take a beating.

Petrohawk's solution is to redesign the wells to be narrower, as shown below.  The belief is the narrower pipe will require lower horsepower pumps.  Right now, the equipment is required to pump at 15,000 HP, where only 10,000 HP might be required in the Eagle Ford or Marcellus Shales.   If Petrohawk can lower the horsepower requirement significantly, perhaps Cotton Valley-grade pumping equipment can be used.  This would expand the universe of service providers, which would speed completions and reduce costs.



In terms of the recipe for the best completions, Petrohawk has found by comparing data from all of its wells that tighter perf clusters with longer stages and higher levels of proppant make the best wells.  The company believes that longer stages also require fewer stages, which reduces costs.  But using more proppant increases cost.  Management also noted that the completions recipe changes by location within the play because of differing geology, so it's not a one size fits all approach.

Along with redesigned wells, Petrohoawk has been on the leading edge of using restricted choke rates to make decline curves less steep and improve EURs.  Data is still somewhat limited, but as we reported last month, all new wells will be produced on some form of restricted choke.  Management provided more detail in the presentation yesterday.  What they have found out is that the higher the EUR for a well, the less effective the restricted choke approach.  This might be because the sheer size and power of the well might already be restricted by the wider choke.  Below are comparative results (restricted chokes in blue and red lines) for four categories of wells broken down by EUR: 4-6 Bcf, 6-8 Bcf, 8-10 Bcf and 10+ Bcf.  Note that the two charts on each page are 1) daily production vs. cumulative gas produced and 2) flowing wellhead pressure vs. cumulative gas.  Neither chart is time-based, which might be confusing.









The data is young, but it shows some promise if the pattern continues.  Petrohawk is also experimenting with restricting chokes on older Haynesville wells.  A few wells have been tried.  In the example used below, pressure got down to around 900 psi, which is line pressure, so the well was choked back.  Production declined as expected, but the company found that it recovered after a few months.  Based on the new curve resulting from higher pressures, the well will hit a breakeven point ("production neutral point" below) to recapture the lost production and cruise ahead with a more favorable decline curve.  (The revised curve is the red line.)  When asked in the Q&A how wells will behave after pressures drop again, management seemed less certain. 

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