OGPSS - American stripper well production

The Total (oil company) discussion on Enhanced Oil Recovery has an illustrative graph to explain why there is a growing need to get as much of the oil in a reservoir as can be economically recovered.



When the large flows of oil that I have written about previously stopped flowing from the major production fields in the on-shore United States, that did not mean that the wells from which they issued were immediately shut-in. Rather, in many cases, although the driving pressure to move the oil to the ground surface had largely disappeared, there was still a sufficient imbalance within the reservoir that oil would flow to the well. And so, before moving on to discuss other fields, I thought I would spend this space covering the pump jacks or “nodding donkeys” that dot the landscape over many of the older oilfields of the United States (and elsewhere).

These “stripper” wells that remove the final volumes of oil from a reservoir make up by far the largest number of wells, by category, that produce within the USA. The EIA reported that there were 363,459 producing oil wells in the USA in 2009. Of these 35.1% produced 1 bbl/day (bd) or less, and 78.7% (a total of 286,109) produced less than 10 bd. For Texas alone, the EIA reports that there are 141,582 wells, and 79.4% of these produce less than 10 bd. (H/t Joules Burn).

So when oil production gets this low, and intermittent, how does the owner get the oil out? The short and simple answer is that the oil is pumped out. And if the well is running slowly, then the pump won’t run all the time, but rather intermittently depending on how fast the pump fills. The original pumpjack design was put together in 1925 by Walter C Trout, and provided the basic design for the units still dotting the American landscape.

Parts of a pumpjack (Lufkin catalog).

That basic design has largely remained the same, but the instrumentation and controls have grown more sophisticated over the years. A baseline estimate of the power requirement is that it needs around 0.2 kwh/bbl/1000 ft to lift the oil to the surface. (Which is quoted as being about a 66% efficiency). Deeper wells are reported to require from 0.27 to 0.81 kwh/bbl/1000 ft. And if the wells are 4,500 ft deep that can give an electricity bill of up to $2,000. (H/t to Joulesburn for raising the topic). Part of the problem and loss in efficiency comes from the need to start and stop the pump, because of the low flow of oil into the well.

The Web site dealing with Stripper wells (those defined as producing below 10 bd) notes:

In the United States of America, one out of every six barrels of crude oil produced comes from a marginal oil well, and over 78 percent of the total number of U.S. oil wells are now classified as such. There are over 400,000 of these wells in the United States, and together they produce nearly 900 thousand barrels of oil per day, 15 percent of U.S. production.

The average stripper produces around 2.2 bd (ibid). (The 25-minute movie “Independent Oil: Rediscovering America's Forgotten Wells” can be obtained from Amazon, or by dropping a note to the Stripper Well Consortium.

Further it points out the economic factors that inhibit re-starting these wells once they are abandoned.

When marginal wells are abandoned, significant quantities of oil remain behind-- sometimes as much as 1/2 to 2/3 of the total oil. In many instances, the remaining reserves are not easily accessible when oil prices subsequently rise again: When marginal fields are abandoned, the surface infrastructure - the pumps, piping, storage vessels, and other processing equipment - is removed and the lease forfeited. Since much of this equipment was probably installed over many years, replacing it over a short period should oil prices jump upward, is enormously cost prohibitve.

The site notes that between 1994 and 2003 some 142,000 wells were plugged and abandoned, losing the remaining oil that they might have produced. This oil is sufficiently important (since it makes up about 10 - 20% of the domestic oil production, depending on what is counted) that DOE has a program dealing with Stripper Well Revitalization (covered on CNN here) and funds The stripper well consortium that investigates ways of improving the technology.

Many of the advances have focused on improving the pumping systems used in these old wells, since the old conventional plunger system are not that efficient, relative to the new units. The large number of wells means that even where these improvements are significant, it will take some period of time to get enough new units into the field to have a significant impact on overall production.

The Gas Operated Automatic Lift (GOAL) PetroPump developed by Brandywine Energy & Development Company. The pump removes fluid from the wellbore more consistently than currently available plunger lift systems. Test results on wells in New York showed a 1.5 to 2.3-time increase in gas yield using the GOAL PetroPump over other casing plunger- type tools. The tool is inexpensive to operate because it requires no external energy source and limited manpower.

One area that they have just started work on involves the use of high-pressure jetting for drilling laterals, with the work being developed by Buckman Jet Drilling Inc. Since I jet drilled my first lateral of this type back some 30-odd years ago and have some considerable familiarity with both the promises of the technology, and some of the problems and other issues that have arisen, I suspect that I will be following this in a bit more detail than I usually allow. But that too will come in a future post, for the moment I will note that, having watched the promotional video I do have some significant concerns that arose out of an earlier incident where a somewhat similar technology was claimed to be able to achieve considerable improvements in well production. In that case my concerns were expressed in Federal Court.

One other recent breakthrough that they have highlighted recently involves the conversion of the significant amounts of water than come from these stripper wells, but which is often brackish, and thus difficult to dispose of, into water of potable quality (i.e. you can drink it). In a slide presentation by Texas A&M, who developed the membrane technology used, the resulting water is compared with Evian, Perrier and similar commercial products. Given the problems that Texas is currently facing with drought this could well solve two problems at one time. Further by lowering the cost of water disposal it, like other SWC developments, can encourage the economies of these small producers and sustain their production further into the future.

Each well may not contribute much, but in the aggregate even small changes can add up, when the totality of the wells affected runs into the hundreds of thousands. This improvement in the tail of well production, sadly, is only likely to be viable in the relatively small on-shore wells and close off-shore where the costs of maintaining the infrastructure above the well is minimal. Once those costs become significant it becomes more difficult to make the economics of the process work.

I’ll talk about some of the other ideas for stimulating these wells in a post somewhat later in the series. But this, from Total, is one I have written about before.

OGPSS - The East Texas field develops

Last week I discussed the start of oil production in the United States, and the evolution of the Appalachian fields which, for a while, were the most productive in the world, but which are now largely depleted. It was possible, however, to take the odd well to show that where production is largely managed, so the ultimate recovery from a reservoir can be continued for decades.

Appalachia was displaced as the production leader by the East Texas oilfield. This field, with oil held in the Woodbine sandstone, was first discovered in 1927, though there was no significant production until the end of 1930.

The first oil leaving the field went in thirteen tank cars of 10,000 gallons each to the Sinclair refinery in Houston. Later, in December 1930 Ed Bateman, a Fort Worth promoter who ran a poor-boy operation called Bateman Oil Company, completed a well ten miles to the northwest of the Bradford No. 3 in the E. G. Sevier Survey, Rusk County. It was the Lou Della Crim No. 1, and it flowed 22,000 barrels of oil per day from 3,653 feet. With four producing wells at the end of 1930, East Texas field reported a yearly production of 27,000 barrels of oil and no gas.

This led to an immediate frenzy of drilling, which in turn led to the first controls on well production, with the Texas Railroad Commission preceding OPEC by decades in the moves that it made to define targets for production. There are a couple of other relevant stories about the field, and so it is a useful second stop as we look at the evolution of American oil production.

There are (as with many things) rather a lot of oil and gas wells in Texas. In 2005 there were still 66,951 active gas wells and 151,605 active oil wells.

Producing wells in Texas in 2005 (Bureau of Economic Geology)

The state, and surrounding regions, have a number of different oilfields within their borders, with East Texas being where you might think.

Major Texas hydrocarbon basins (Bureau of Economic Geology)

A section along the B-B’ line gives some idea of the formations, and will be a useful guide when I come to talk about reservoirs associated with salt domes later in the series, although they were the cause of the first great Texas oil rush at Spindletop.

Section showing the rock structure in East Texas(Bureau of Economic Geology)

East Texas was not the first oil field in Texas to be brought into production,nor the mmost famous. That resides with Spindletop down near Beaumont in Southeast Texas which is remembered as the most dramatic, when it blew back in 1901.

On January 10, at around 10:30 a.m. the Lucas Gusher at Spindletop blew. The oil spray, which could be seen for ten miles, was fully six inches across and rose to over 200 ft above the derrick. . . . . .

Nine days and 800,000 barrels later, they cut the gusher off.

Over 285 active wells were drilled into the formation under Spindletop Hill. But the field rapidly declined in production over the next five years, although it was a major contributor to America being able to reach a production of 1 mbd in 1919.

The overabundance of wells at Spindletop led to a rapid decline in production. After yielding 17,500,000 barrels of oil in 1902, the Spindletop wells were down to 10,000 barrels a day in February 1904.

In 1926 there was a second surge in production, which was more controlled and gave the field peak at 21 million barrels in 1927 (out of a total field production of around 153 million barrels), but this had petered out by 1931, just as East Texas was surging. Spindletop is credited with being the first well to use drilling mud, rather than water, as the cooling and transportation fluid to get the cuttings out of the hole, while keeping the hole itself stable.

The production potential of the Woodbine sandstone in East Texas, in contrast, was greatly helped because the oil lay over water, and this underlying water helped to sustain the driving pressure that helped keep the wells in production over longer time intervals. Of course that only holds true to a degree. And back in 1931 there was little constraint on how close wells could be.

Wells at Spindletop in 1902 (Spindletop- Gladys City Boomtown Museum )

This led to a great rush to bring wells into production, given that the this production was governed by what is known as “the rule of capture.” This, in essence said that if the well came into your well by flowing out from under your neighbors yard, then that was just tough for him/her, providing that your well remained on your land all the way. That ruling came about ultimately through an 1889 Pennsylvania Supreme Court decision. However it should be noted that the well has to remain on your property. There was a considerable scandal in East Texas in 1962 when it was discovered that some wells had “bent” so that instead or remaining on the owners property they ended on someone else’s lease, and took that oil. That is not allowed, and became a scandal when the scale of the mischief was discovered.

It was learned that operators had drilled slanted holes from barren acreage beyond the limits of the field back into the Woodbine formation, tapping into productive leases owned by major companies. During a series of investigations, inspectors found 380 deviated wells in East Texas field and shut them down. An estimated $100 million worth of oil was stolen over several decades from legal owners. Many of the oil pirates were leading citizens of East Texas communities.

Yet this wasn’t the greatest problem with the field. So productive did the wells become that the amount of oil available saturated the market available, and within months the price of oil had plummeted. It began the year at $0.99 a barrel, but by July was down to $0.13 a barrel, and something had to be done. The industry answer had been to increase production at individual wells as the price fell, but the problem with increasing production can perhaps be illustrated by example.

If you take a cup of black coffee and very carefully pour cream into the cup over the back of a spoon at the level of the coffee you can “float” the cream on top of the coffee. (And if you are of that frame of mind you can do this will various different alcohols in a bar). If you put a straw into the cream and suck gently you can pull most of the cream into the straw, and thence into your mouth (production) without getting any coffee. But if you suck too hard then the coffee comes up through the cream into the straw and you can’t reverse the situation.

So it is with an oil well. If there is water under the oil (as there is in East Texas) then sucking too hard (relatively) will pull the underlying water up into the well rather than the surrounding oil. The process is called “coning” and can be illustrated.

Water coning (Schlumberger )

Obviously this is not desirable, but if the alternate to pumping like crazy to get all the oil out from under your derrick before it all flowed to your neighbors was to lose the production to them, folk just hoped coning wouldn’t happen to them. The combination of damage to the field, and the glut of oil that this produced had an immediate effect on price. Something had to be done, and it was.

On August 17, 1931, the governor ordered the Texas National Guard and Texas Rangersqv into the ten-month-old field to shut in all of its 1,644 wells and to maintain order. The field resumed production on September 5, 1931, under a new proration order that limited its production to 400,000 barrels of oil per day, permitting each well 225 barrels and giving no consideration to its potential or to the characteristics of the lease. New wells came on line, and by October allowables were reduced for each one to 165 barrels per day.

And it was from those days that the Railroad Commission of Texas acquired its power. But that is a sufficiently interesting story that I will go into it more next time.

In the interim, let me leave you with this thought. The production of oil in Texas peaked in 1972, and in March of that year the Railroad Commission lifted restrictions on produced volumes for individual wells.

The peak in Texas oil production (U of Texas )

However the profile of that peak, and the resulting decline (in which period there were no longer regulatory restrictions) has, as Westexas has noted, been similar to the decline of other fields. It thus allows modeling and a prediction of future oilfield production post peak. But that too is a topic best left for another day.

A similarity in peak profiles (Westexas )