Tech Talk - of longer wells and drawdown pressure

There are, simply, three major parts to the coming global economic mess that will be created as we enter into the period of Peak Oil. The first of these comes from the current rising demand for oil, particularly emphasized by those countries, such as China and India, where demand is rising fastest. The second part is the declining production from existing fields as their reserves are drawn down. (Though it should be remembered that even when “exhausted” the fields will still contain vast quantities of oil, but oil which is at present not economically recoverable). And finally there is the oil in the undeveloped, and undiscovered wells and fields that can be added to the existing reserve to help ameliorate the imbalance between demand and supply from existing wells.

The high decline rates from long horizontal wells drilled into, and along the shale deposits in the United States, most particularly the Bakken and the Eagle Ford, mean that there is a constant need to drill new wells to sustain existing production. The EIA has taken note of this and calculated based on some assumptions, the number of rigs that must be operating in these fields, so that they will drill enough new wells to sustain current production.

Figure 1. The number of rigs required in the Bakken and Eagle Ford formations to sustain production at the level of the previous month (EIA).

Should the need be to increase production (which is the current assumption by most prognosticators of future equilibrium between demand and supply) then these numbers need to be significantly higher, perhaps by as many as 50 additional rigs. At present the Bakken rig count is running at around 176 rigs while there are around 270 rigs drilling in the Eagle Ford.

One of the ways in which production is anticipated to expand above earlier estimates for the wells drilled in both fields comes from the ability to drill longer horizontal wells and to increase the fracture density along these wells.

However, as the Kingdom of Saudi Arabia discovered some years ago, longer wells can only be viably effective out to a certain distance, beyond which there is no gain in productivity. As a result they have changed their drilling patterns so that the wells are shorter, with multiple laterals spreading from the original wells to more thoroughly cover the rock within the formation. Initially wells were drilled out to distances of up to 12 km, but over time the KSA found that this was too long.

Since there is a somewhat similar argument to be made for the wells in the United States, as they move to longer distances, I thought I would go over the explanation as to why this is not a very productive idea a second time.

To begin consider that regardless of whether I put a tiny glass of water or a huge glass of soda in front of you, if I glue it to the table then the amount that you can drink at one time becomes limited by the size of the straw that I give you to drink the liquid, rather than the amount in the container. And to get that liquid into the straw and up into your mouth requires that you suck on the straw.

What you are doing is reducing the pressure at the bottom of the straw, while the pressure from the atmosphere on the top of the liquid remains the same. By creating this differential pressure there is now a force to move the liquid into the straw and thence up into your mouth.

But, as Fishbuch et al showed, as the horizontal well bore gets longer the pressure at the back of the hole declines as then does the difference in pressure between the oil in the rock and the well (the drawdown pressure), and while the longer hole gives an overall increase in production to a certain point this seems to maximize at a length of around 6,000 ft. Beyond that distance the differential pressure between the formation and the well falls to a point where there is less benefit to the additional cost of drilling to that distance.

Figure 2. Drop in well pressure with increased well length, while increasing overall oil flow (Simulation by Fishbuch et al )

The answer which Aramco came up with to get around this problem was to use a main lateral from which a number of shorter laterals could then be drilled out into the formation, providing higher drawdown pressures within the wells and making it also easier to isolate any well section where the underlying water broke through into the well.

Figure 3. Schematic of a Maximum Reservoir Contact well as used in Saudi Arabia (Aramco).

The optimum length at which a well can produce is a function of the rock type and structure as well as the nature of the oil/natural gas that it contains and the water content (to name by a few of the parameters). Thus there are limits to the analogy, nevertheless it does show, even in the much more productive rocks of the fields in KSA that there are limits to how far a well can be productively driven, and these limits will also exist in the shales of the United States, although the oil locations and the optimal ways of extracting it are somewhat different.

The extraction of oil and natural gas in these shales is more sensitive to the levels of drawdown pressure, since much of the oil and gas is found in natural fractures that are not that wide (although they may be spread further apart by the fracking process itself). With exposure to the lower well pressure thus being restricted to a relatively small volume, significant reduction in the pressure because of the location relative to the heel of the well can have significant effects on lowering the overall well production.

Further as a general rule the complex valve systems used in KSA are not installed in the shale wells of the United States, making it less practical to focus the relative pressure differentials at different points along the well bore as a means of increasing production sequentially along the well.