I stumbled across an interesting analysis of a new technological process, horizontal drilling and extraction of shale natural gas. Read the whole thing here but here is the key chart comparing horizontal vs vertical wells:

Comparative production from a vertical and horizontal natural gas well (Chris McGill).

Comparative production from a vertical and horizontal natural gas well (Chris McGill).

Production Volume

One thing that did strike me is that the horizontal peak production is well above the vertical well but has a shorter life span. Horizontal wells do have significant technical challenges (as seen in the article), but perhaps we can analyse the above chart to give us an idea of the benefits of horizontal drilling. Now to do this is a little tricky, as I do not have the original chart. However, using Photoshop, I was able to extract the area of the chart and the scale to get us total volume (note these are approximations only, but it gives us a “back of the envelope” view):

  • Vertical Well (Yellow): 3547 MMFC
  • Horizontal Well (Orange): 6097 MMFC
  • Horizontal to Vertical Well total production gain: +72%

Judging from the chart the horizontal well extracts and extra 72% more oil in 10 months versus 100 months for vertical wells.

Production Value

Now to estimate the total value of the well let’s assume the price of natural gas is stable (at Henry Hub) at $8.00 per MCF:

  • Total value of the horizontal well is  6097*1000*$8.00 = $48,776,000
  • Total value of the vertical well is 3547*1000*$8.00 = $28,376,000

Time Value of Money

This is where we get to use some basic financial models to determine the value of horizontal wells compared to vertical wells. The time value of money is the value of money figuring in a given amount of interest earned over a given amount of time. As an example, with an interest rate of 5% per annum, 100 dollars received today is equivalent of receiving 105 dollars in a year’s time.

Note that the horizontal well lifetime is 10 months compared to the vertical well lifetime of 100 months. Thus to be fair we need to compare the value of the horizontal well and the vertical well after 100 months. This is where the Time Value of Money comes in. Let’s pretend we bank the $48,776,000 that the horizontal well extracts, thus after 100 months (assuming 5% interest rates):

  • Total value of horizontal well at 100 months: $70,913,392
  • Total value of vertical well at 100 months: $28,376,000
  • Horizontal to Vertical well gain: +150%

Extraction Costs

I do not know, in detail, the relative difference in extraction costs for these two methods. However, we now have the Horizontal to Vertical Well gain to use in our decision making. If the Horizontal to Vertical well cost is less than Horizontal to Vertical Well gain (+150% in our example), then it becomes economical to use the horizontal well method.

UPDATE: here is some commentary from The Oil Drum on this article regarding the discount rates:

Rockman: I think you’re on a good track grae but a few questions: how are you using that “5% interest”? To do the type of comparison you’re attempting we use a discount rate (usually 10 to 15%) to calculate a net present value…NPV. It is essentially a negative interest rate. A dollar produced next year has a NPV of $0.90 ($1 x 0.9). A dollar produced the second year = $.80 ($1 X 0.8). As you can see by the time you get to year 7 or 8 the future revenue stream has almost no NPV.

Beyond NPV the payout period (time to recover investment from net revenue stream) is a critical component of the decision process. When PO gets much beyond a couple of years a project becomes much less appealing. The longer payout obviously equates to a lower rate of return.

The other big factor in doing NPV is the oil/NG price inflation factor. If it’s high enough in can neutralize the effect of the discount rate. There’s no good answer to what price inflation rate to use. But we tend to stay conservative… usually just a few per cent and often after the first couple of years being flat.

Well costs: can vary a good bit. A horizontal might cost as little as 150% of a vert well but can also run 2 or 3 times more.

Me: Thanks Rockman. I have used 5% because that seems to be the historical interest rate. In my business plans, I normally compare the ROI compared to this rate (eg. compared to sticking it in a bank). I find it interesting that the industry uses 10 – 15%, this is seems unusually high, perhaps the industry likes to compare returns based on long terms stock market returns?

Yes, price inflation can reduce the impact of the discount rate, but pricing oil/natural gas so many years out is pretty difficult.

Re: costs. I did some quick calcs for discount rates:
10%: horizontal needs to be less than 3.62 times the vertical
15%: horizontal needs to be less than 5.25 times the vertical

Rockman: grae — We use the higher discount rate more as a “hair cut” as we call it. It allows us to add another risk factor. Actually more of a fudge factor. We also give the targeted reserves a hair cut also…maybe only use 50% to 80% of the proposed volume. Same thing with keeping the oil/NG inflation factor conservative. We’ll even normally use a contingency factor in the well cost: if the estimated well cost is $2 million we would use $2.2 million as an estimate. Lots of fudge factors. And then when oil sells for $38/bbl instead of the $70/bbl you used in your economic analysis all the fudge factors don’t come close to saving your butt.

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