The Tale of Half-Cycle Fields
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The Tale of Half-Cycle Fields

by | published April 23rd, 2019

Today, I will address a forward field development problem emerging in the U.S. It will hardly lead to a shortage of either crude oil or natural gas, but it may well increase the price.

As usual, first we need to consider some background.

As the price of crude oil trends up and the price of natural gas moves down, a major difficulty emerges, becoming a more serious concern in high-production basins like the Permian of West Texas and Eastern New Mexico.

The uninitiated reader might regard this as obliging an obvious choice – produce the oil not the gas. Unfortunately, that misses the realities in the field.

Much of the natural gas present exists as associated gas. That is, it is there along with the oil a company is targeting. Unless the producer deals with the gas, the overall pressure declines in a reservoir. That can significantly lessen the oil produced.

So, the associated gas must be dealt with in some way.

In the old days, unwanted gas would simply be flared, that is, burned off. When I was growing up in Oklahoma, I would be fascinated by the fiery image at night. It looked like the entrance to Hades.

Less scrupulous operators would go one step further and vent the “waste gas” directly into the environment. I last witnessed this unsavory practice during a visit several years ago to production facilities far up river on Ecuadorian tributaries of what would later become the main branches of the Amazon.

I had never before witnessed what would confront me as we turned a bend in the river one morning…

The Problem with Associated Gas Disposal…

Bubbles rising to the water surface. These bubbles contained associated gas, openly vented directly into the water. Occasionally, explosions would result as the gas would be ignited by any of a number of causes.

The charred areas of jungle on the shore line, combined with indigenous tribe members coming out of the bush with extensive body burns, and he smell of rotting dead fish were testimonies to the devastation. Collateral damage, apparently, in the calculations of somebody interested only in the oil obtained.

These extreme approaches are rarely practiced, and the more acceptable examples of flaring are strictly regulated. Since field pressure is essential to oil production, some flaring is inevitable.

But the extent of flaring necessary to deal with the associated gas in a basin like the Permian is well beyond environmental and operational restraints. After all, the levels of associated gas are often commercially viable and few companies would eagerly forego a bottom-line improvement, even in a market environment of low natural gas prices.

Now the gas can be used for secondary and/or enhanced oil recovery (SOR and EOR). Carbon dioxide (CO2), certain gels, heat, water flooding, and chemical treatments are other main techniques. Both recovery approaches target well stimulation, slowing down the inevitable decline in crude oil production rates, but in different ways.

SOR essentially does this by displacing oil from locations in the reservoir, moving it to more centrally-located production wells. On the other hand, EOR enhances lifting volume by making the composition of the oil itself more conducive to being drawn up (usually by making it more viscous).

Yet, injecting associated gas back into a reservoir to improve the volume of oil coming out of the ground hardly uses all that is available and, somewhat more pressing, does not reduce the presence of the gas itself. That means using gas as either SOR or EOR does not resolve the problem of what to do with it.

This problem of associated gas is getting worse, especially in the Permian. Here, two issues are colliding. First, bigger deposits of oil require that operators deal with a larger amount of associated gas. Second, there is the ongoing pipeline deficiency.

I have considered this latter matter in previous editions of Oil & Energy Investor. Lack of adequate pipeline capacity has limited what should have been a further rapid expansion in Permian oil production volume. New trunk and feeder pipeline projects are underway to address the straining operational limitations on companies being able to move oil. However, they are not yet operating.

The same problem is hitting natural gas. And while there are free-standing Permian gas fields (those, in other words, where natural gas is the primary product), the presence of rising amounts of associated gas are creating both gas pipeline concerns and worries over the amount of oil that can be extracted (for reasons already discussed).

The associated gas situation is the primary gas problem in most high-production basins like the Permian.

There is another situation surrounding gas pipelines. While it is also a wrinkle when it comes to oil, much of gas pipeline capacity is used for storage, not transit. That is why one sees more “loops” as part of new gas pipeline construction plans. Such devices are intended to increase the overall storage capacity in the pipes, not to facilitate delivery to end users (i.e., treatment and processing plants).

Finally, we arrive at the topic for today’s Oil & Energy Investor.

The Give and Take of Half-Cycle Wells…

All of this is pressing upon the broader concern with half-cycle and full-cycle well development. Below is a slide I used a while back in a series of private briefings to investors in the U.S. and Europe. Interestingly, it largely considered production basins other than those comprising the primary Permian trends (with those trends appearing in the center of the diagram). It now appears the Permian situation comprises a case worse than those considered here.


To maintain an acceptable production rate versus operating expense calculation, companies have been emphasizing half-cycle development. This involves basing further expansion on mature fields already having all cap ex completed, infrastructure and support in place, with “new” drilling comprising the spudding of wells close to those already in production (called in the business, “step out” wells).

This cuts expenses but also may level off production return at an earlier date, since later wells tend to “capture” portions of reservoirs tapped by earlier drilling. However, as the above slide indicates, a producer must capture a proportionally greater return on a lowered expected lifting volume than what would be expected from a full-cycle drilling program (i.e., one requiring new cap ex and infrastructure).

The reason, of course, is obvious. Even though this comprises an additional development stage at already mature fields, half-cycle wells are much cheaper. The hope is for the discovery of additional reserves from what amount to “discounted” wells. But the realization here has been sketchy at best.

In addition, companies have continued the process of setting up DUCS (drilled but uncompleted wells). These inflate the number of wells existing but are not yet on line. When they are put in service, most of them simply replace earlier drilled wells that are being moved out of production.

Therefore, DUCS do not add as much new volume to the aggregate as their numbers might imply.

Though Expensive, Full-Cycle Wells are the Answer

The situation surrounding associated gas is merely accentuating the reliance on expanding mature fields with short-term half-cycle wells. Ultimately, the need to find genuinely new sources of crude requires a move into more expensive full-cycle projects.

To date, companies have been hesitant to embark on this revision. In most cases this is due to the expense and the residual concern that pipeline and operational constraints will lower profitability at the wellhead (where the producer makes its revenue in the first arms-length transfer to a second party distributor). Wellhead prices are set at a level much below the U.S. market price for oil quoted daily in trading benchmarks led by the WTI (West Texas Intermediate) rate.

Unfortunately, unless more full-cycle fields are developed, both Permian production potential in particular and U.S. production broadly, will begin to feel the pinch. That will serve to further reinforce a floor for oil, always a nice prospect for investors interested in profiting from it.

But it also creates a distortion in production perspectives at the company level. Movement to more full-cycle projects also means the increasingly vexing associated gas problem is addressed as well.

And that cycle continues.

Sincerely,


Kent

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  1. April 23rd, 2019 at 11:32 | #1

    Hi, Kent.

    I am a business data analytics graduate student at Colorado State University. Can you please tell us what Big Data sources are publicly available online for us to analyze that contribute to your knowledge base and industry predictive analytics?

    Thank you for your courtesy and consideration.

    David P. Jurist

  2. April 23rd, 2019 at 23:53 | #2

    I doubt the loops in the gas pipelines are for storage. They are more likely expansion loops that act as springs to account for the expansion of the pipelines during the day as the pipes are heated up, and the contraction of the pipelines during the night as the pipes cool off. Gas does note absorb and carry the heat with it as oil does, so you need lots of loops compared to oil pipelines. Maybe you need a contact in the field of pipeline engineering.

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