I have been pondering the question: “At what point in the exploration/exploitation cycle might it be the best time for a landowner to lease?”.

If I may, I am going to take the opportunity to “think out loud” as I go through a mental exercise.

I have addressed this to the Marcellus Shale in PA (the area that I am most familiar with), but much of the below would be applicable to the Utica.

I would expect that the progression of exploration through exploitation might follow a sequence similar to that which follows:

A company comes into an area and attempts to put together an acreage position.

They might have become interested in this particular area by extrapolating (along trend) from an existing area known to be productive. Or, they might have become interested in this particular area by interpolating between two areas known to be productive. Or, they might have information from access to data from old well penetrations that tested deeper objectives (passing through the Marcellus). Whatever the exact reason for becoming interested in a particular are, they will want to quickly evaluate the area’s economic potential.

Next, they put together a unit, preferably near existing infrastructure (existing pipeline, source of water, near roads, etc.).

Next, they drill a vertical well on this unit, penetrating the Marcellus.

They either core the entire Marcellus Shale (via core barrel), or obtain an extensive suite of sidewall cores. The core data should give them important information about the Marcellus Shale in and around their area of interest – information such as Total Organic Content (T.O.C.) - how much hydrocarbons the shale has been capable of generating, how “rich” the source rocks are, Thermal Maturity (via such measurements as Vitrinite Reflectance) – to what extent has the organic content of the shale been converted to gas and natural gas liquids, (with luck) some idea as to the extent of existing fracturing within the shale, information on the mineral/clay content of the shale (to help determine the best chemistry for drilling fluids in order to limit formation damage while drilling)

They will production test and tie in this well to a pipeline and produce this vertical well. There is information of value obtained from the production of this vertical well. However, it is commonly understood that the producibility of a vertical well is very much less than that of a horizontal well. The vertical well would only have penetrated something of the order of 100’ of the objective Marcellus Shale (and possibly not have crossed any joints/fractures); whereas a horizontal well will have thousands of feet of Marcellus Shale exposed to the bore hole (and will have crossed many joints/fractures).

The vertical well will tie up the entire unit (HBP) until the company wishes to come back. At some point in the future they will likely reenter the well and kick it out as a horizontal; likely adding additional wells to the pad. But further activity in this first unit will likely be put on hold, the unit tied up by very modest royalties from the modest production of the vertical well. As a landowner, there are pitfalls in being in the first unit to be drilled in a “new” area.

Once the company digests the data from the vertical well, they will have the information that they need in order to decide how they next wish to proceed. If they feel that have sufficient encouragement from the vertical well, they will accelerate their leasing efforts.

Next, they will put together a second unit, preferably near existing infrastructure (existing pipeline, source of water, near roads, etc.); permitting for horizontal wells. The azimuth of the horizontal portions of the wells will be planned to be in a direction that is expected to result in the well bore encountering the maximum number of existing joints (fractures) present within the Marcellus Shale. The best jointing within the Marcellus can be expected to parallel/sub-parallel the trend of the mountains to the east. The mountains in PA roughly trend NE-SW, thus that is roughly the orientation of the best jointing. To encounter the maximum number of joints the horizontal well bores will be programmed to roughly trend NW-SE.

The extent, frequency and direction of jointing is of critical importantance. The ability of a rock unit to give up its natural gas/natural gas liquids/oil is a function of a number of rock properties; the most important of these are porosity and permeability. Porosity is a measure of the amount of voids (pore spaces) within the rock unit; these pores/voids are the spaces that can contain the natural gas/natural gas liquids/oil. Permeability is a measure of the communication between the voids (pore spaces) within the rock unit; permeability is a measure of the mobility of the natural gas/natural gas liquids/oil; permeability is a measure of the ability of the natural gas/natural gas liquids/oil to move out of the pore spaces and into the well bore. Traditional sandstone reservoirs have both good porosity and good permeability. The shallow “tight” gas sands of PA have low porosity and poor permeability; but, these shallow sands can be cheaply drilled and fraced such that they can still be economically produced. Shales (such as the Marcellus) have low porosity and very poor permeability; only recently has the technology been developed such that shale oil and shale gas can be economically exploited. Economic exploitation of the Marcellus Shale was only made possible through the use of horizontal drilling and multi-stage hydrofracing (a great number of technological advances cumulatively contributed to make possible the current Marcellus Shale production). In the fracing of the Marcellus Shale, the existing jointing/fractures can (under pressure) be opened up with proppants (such as clean sands suspended within the fracing solution) injected into these joints/fractures. Post fracing, the proppants injected into the joints/fractures keep (prop) open the joints/fractures; maintaining avenues open to the flow of natural gas/natural gas liquids/oil out of the shale and into the bore hole.

Getting back to the second unit, with its horizontal wells. The O&G company is still at the early stages of its learning curve for this new area. They may decide upon a four well pad on this second unit. The horizontal offsets for these wells will likely be short (compared with later efforts); perhaps 2000’ laterals. The O&G company will be searching for the most “bang for their buck”; taking baby steps. With four wells, they can experiment with fracing fluids and with the number of frac stages. They will likely extensively production test these wells. They will tie these wells into an existing pipeline and closely monitor the ongoing draw down.

With more results and yet more data they will revisit how they next wish to proceed. If they still feel that have sufficient encouragement, they will further accelerate their leasing efforts. As a landowner, there are pitfalls in being in the first unit to be drilled in a “new” area – as the O&G company are still looking for the best parameters with which to exploit.

Next they will put together additional units.

For the third unit, they will likely drill on a four well pad, extending the laterals out further (perhaps to 3000’). And, again, they will experiment with the uses of additional frac stages. Maybe they will experiment with ceramic proppants, rather than the (cheaper) traditional sand proppants.

For the fourth unit, they will likely drill on a four well pad, extending the laterals out further yet (perhaps to 5000’). The O&G company are likely getting close to deciding upon he best means of optimizing production in this area.

For the fifth unit, they may (by now) fell sufficiently comfortable to go to a six or eight well pad, with long (perhaps 5000’) laterals. It is like Goldilocks and the five bears (three are not enough).

By my hypothetical exercise, I would want to be in the fifth (or subsequent) units.

I invite comments/criticisms/orrections/additions.

All in my humble opinion.

One size fits most.

Consider the preceding free information to be worth every penny you paid for it.

JS