OGPSS - Natural gas pipelines and regulation

In the last post on this topic I covered some of the earlier developments in the use of natural gas (NG) as a lighting source, and began to discuss its evolution into a widely used fuel. That use, and the international marketing of NG has largely come about as the increasing use of pipelines has made it easier to move NG from places where it is overly abundant, to those where it is not. A recent example of this has been the Rockies Express Pipeline (REX) which carries NG from Colorado to Ohio, and thence to points East. Out in the West NG is still abundant and so well head prices are low – in 2009 for example it averaged $3.21 per kcf in Colorado. That same year in Maine the residential price was $16.43 per kcf. (against $8.80 in Colorado). The well head price in Ohio fell from $7.88 per kcf, in 2008, the year before the pipeline was completed, to $4.36 in 2009.

The Rockies Express pipeline (Kinder Morgan )

As new fields, such as those in the various shale layers that are now becoming popular, are opened they only become significant as the gas that is produced from the well is connected into a distribution network. Pipeline costs have been estimated as around $1 to $1.5 million per mile. After the pipe is in place it is often hard to see where it runs, in the USA at least.

Pipeline route over the Marcellus Shale, after installation

In 2009 the US used some 22 trillion cubic feet of NG (Tcf) moving ahead of Russia to again become the world’s largest producer and consumer. In that year the greatest production came from five Western states.

Top Gas Producing States in 2009 (NEED )

The need for a network to supply other states, less fortunate in this resource, has largely been met, with new pipelines being installed as needed. However it should be noted that just having the production does not, in itself, create nirvana, since earlier this year New Mexico and the Southwest suffered from shortages since demand exceeded available supply due to an unexpected cold spell.

Natural gas pipeline network around the United States (EIA )

This network has made it much easier to ensure that gas is available to customers, when they need it. And while this has recently become more of an issue, as natural gas turbines are installed to provide back-up power to more intermittent power generators, such as wind and solar farms, NG fueled electric power stations have been the most, in fact almost the only, new power construction in the United States for several years.

As the experience in New Mexico showed, just having a network of pipes in place is not, in itself enough. The first need is that the gas must travel down the pipes to the customers at a given volume, and this requires that it be pumped under pressure. Rather than creating the driving pressure purely at the input end, the pipe travels through a series of compressor stations that raise the pressure along the pipeline length, as friction would otherwise reduce it to below viable levels. For safety reasons gas pressure is reduced as the pipes travel through urban areas, and the normal operating pressure can thus vary between 200 and 1,500 psi. For those that forget Boyle’s Law from high school science, at constant temperature, raising the pressure by a factor of 6 will cause an equivalent reduction in the volume of the gas that is being pumped.

However, if you consider the network as a schematic you will note a couple of additional features.

Flow Diagram of the US Gas Distribution Network (EIA )

The two additions are for temporary storage of gas for use at times when demand is high (Oops none in the Southwest - tsk !). The gas can be stored either as a gas, or it can be cooled to a liquid (which reduces the volume by a factor of 600 and stored in that form. The LNG facilities need a re-gasifier, and, if they are taking the gas from a pipeline, also a liquefaction unit to do the initial conversion. By using these facilities that are dotted around the country, pipelines don’t have to be as large to ensure that there is enough gas for the consumer at the high demand locations around the network.


Locations of storage facilities for natural gas including LNG import terminals (EIA )

I have used a map that shows the location of LNG import terminals, since this is an additional source of NG for the United States. Again the volume that is involved is a function of price, though often, to justify the cost of the parts of the supply train, there is a concurrent long-term commitment to a given price schedule, so that spot prices are not necessarily that valid, and what is paid in Japan, for example, is not indicative of prices elsewhere. That is particularly true at present since the loss in power from the nuclear reactors in Japan is expected to result in a long-term increase in LNG demand to replace the lost power.

Variation in the price of LNG in Japan (Mongabay )

As I write this the current quoted import price for LNG into the United States is $6.78 per kcf some $1.71 over the quoted Henry Hub price for NG.

One of the most powerful drivers in the growth of demand for natural gas has been as a result of its increased use in generating electricity. This is particularly evident as it takes market share from coal-fired power stations due to concerns over the emission of greenhouse gases.

Nationwide, coal-fired electric power generation declined 11.6 percent from 2008 to 2009, bringing coal's share of the electricity power output to 44.5 percent, the lowest level since 1978. Coal consumption at U.S. power plants paralleled the decline in generation, dropping 10.3 percent from 2008.

In sharp contrast, natural gas-fired generation increased 4.3 percent in 2009, despite the 4.1-percent decline in overall electric generation. The natural gas share of generation increased to 23.3 percent—the highest level since 1970. Electricity's share of the total U.S. natural gas consumption has also risen rapidly, growing from 17 percent in 1996 to over 30 percent in 2009

There is a greater capacity for gas-generated power than these numbers reflect, since the utilities still tend to use coal over NG for longer-term operation as the costs are lower.

The growth of this market developed after the Second World War, and the development of a distribution network. However in the years immediately after the war the industry was heavily regulated, both in terms of price and volume, in much the same way as the Texas Railroad Commission had regulated oil. But because the gas entered and left inter-state pipelines it was regulated under the Natural Gas Act of 1938 which among other things forbade the construction of a new interstate pipeline into a state that already had one. In 1954 the Supreme Court voted that the FPC should set wellhead prices for NG. This removed some of the incentive to develop new wells, and from then until 1968 production and prices remained relatively steady. In 1968 however reserves fell from 20 Tcf to 12 Tcf, and in 1969 they were down to 8 Tcf. With the industry still controlled, reserve additions failed to keep up with demand for the next 12 years. However the Arabian oil (and gas) embargo imposed in 1973 led the price of NG to multiply 750% between 1972 and 1976. Consumption fell at these higher prices, and the market re-equilibrated until 1980. But the over-regulation of the industry led to serious problems.

The interstate pipeline experience during this period was an unmitigated disaster. To deal with the shortages in the interstate market, interstate pipelines submitted curtailment plans to the FPC describing how they would determine who got gas and who did not. The plans gave top priority to residential consumers. Boiler fuel users, such as electric utilities, were given lowest priority. Users who experienced curtailed deliveries could either shut down their operations or switch to alternate fuels. During the winter heating season of 1977-1978, gas deliveries in New York and New Jersey were curtailed for everyone except residential consumers. Commercial users received only 94.3 percent of requirements, industrial users only 79.2 percent of requirements and electric utilities only 13.5 percent of requirements.

Just as the regulations were being changed to help resolve these problems, and de-regulate wellhead pricing, the Shah of Iran was overthrown, and prices took off again. This encouraged new drilling and in 1981 for the first time since 1968 more gas was discovered than was consumed that year. Unfortunately this happened just as the rise in prices was moving consumers out of the product. The result was a drop in demand, which bottomed out in 1986. With the increase in supply this generated a “gas bubble.” In 1986 the Texas Railroad Commission changed the rules to ease sales of the gas to end users rather than just the pipeline companies, at the same time the Federal Energy Regulatory Commission began the series of changes that, by 1992, meant that you no longer had to own a pipeline to be able to buy natural gas.

I’ll write about where that took us, and the evolution of the gas producers and market as I continue with this short topic next time.

OGPSS - The Railroad Commission of Texas

This post originally went up last week, and in some wonder of modern technology was wiped out by Blogger, along with a lot of other posts which had gone up at about the same time. We were promised that it would be put back, it has not been. So here, as best as I can reconstruct it, is the post. My apologies for the delay and possible confusion.

When I have written about oil and natural gas production from individual wells, in previous posts, I have referred to the website of the Texas Railroad Commission as the source of my information. You might wonder why they are in charge. Well it all began back in the days after Texas first became a State, and the government wanted to encourage folk to move out into the state. Historically railroads had been built to connect existing towns and cities, but there weren’t any going West. And so, to encourage railroads to grow out west they were allowed land grants and a number of tax and other grants and incentives that would encourage rail, and the growth of towns along the track, as a result.

Now since this provided a sensible monopoly on transportation, the Texas legislature, as far back as 1853, had enacted comprehensive laws regarding the railroads. The problem was that they were not enforced, and for a number of years the railroads could charge as much as the traffic would bear. This led to many protests, particularly from farmers, and after many promises, in 1891 the Railroad Commission of Texas (RRC) was created:

An Act to establish a Railroad Commission for the State of Texas whereby discrimination and extortion in railroad charges may be prevented, and reasonable freight and passenger tariffs may be established; to prescribe and authorize the making of rules and regulations to govern the Commission and the railroads, and afford railroad companies and other parties adequate remedies; to prescribe penalties for the violation of this act and provide means and rules for its enforcement.

That created the RRC, and after some struggles, and a trip to the Supreme Court it succeeded in establishing that it had the power, which it enforced, to cut shipping rates. But how did that allow it to get into controlling the “oil bidniss”?

The simple part of the answer is that when the Commission was set up, its responsibilities included:

Determination of passenger fares, freight rates, and charges for all classes of common carriers in Texas.

As the boom in oil production began in Texas, production rates were initially high and, as I noted last time, many wells were being drilled in close proximity, with incentives (including the “right of capture”) that drove owners to produce their wells as fast as possible. And in 1931 an average of 8 wells a day was being drilled in Texas.

The result was a glut of oil on the market with prices falling from $1.10 before the Daisy Bradford #3 well was drilled (By H.L. Hunt) to $0.15 and even $0.02 a barrel on the spot market. (The Big Rich by Bryan Burrough ) Someone had to do something, and the choice pointed to “proration”. In this each well could be assigned a certain production or number of days in the month that it could produce, based on the number of wells and the amount of oil that the market was considered able to bear. But who should set the quantities.

Oil, once it is out of the ground, has to be transported and the early alternatives were either by rail car or pipeline. The rail roads were already under the RRC and in 1917 the Texas Legislature designated pipelines as “common carriers” which also brought them under the RRC. By 1919 this oversight was extended to include jurisdiction over Oil and Gas. And a new Division was born. (The agency continued to have some role in railroads until 2005, when that was completely phased out).

The RRC had unsuccessfully tried to control production earlier, and in 1931 it tried again, setting a proration order for the East Texas field of 160,000 bd at a time when it was producing half-a-million barrels. That didn’t go anywere either, but the impact on the economies of the states was becoming too great. It was the larger companies that largely argued for proration

Jacob Wolters of the Texas Company (Texaco), warned of the ruin of thousands of wells, as well as “the bankruptcy of producers, the loss of millions of dollars in revenues of the State, and the consequent increase of taxes on other sources in order that the public schools, higher institutions of learning, eleemosynary institutions and the departments of the State may continue to function.”

Up in Oklahoma City the city council had passed a law that restricted oil wells to one per city block, and their attempt to close wells was so challenged that the Okahoma Governor, William Murray, declared martial law and closed the wells, initially for a day. This in turn led him to place the 3,106 oil producing wells in Oklahoma under martial law from August 4, 1931 until April 1933.

Down in Texas, as Bryan Burroughs notes, H.L. Hunt and other large producers urged the Texas Governor to follow suit.

On August 16, declaring East Texas oilmen to be in open “rebellion” agaist the site, he declared martial law and sent in the National Guard to shut down the oil field.

It was re-opened three weeks later, but with individual wells limited to only producing 225 bd. As these controls began to limit production in the face of growing demand so the price stabilized and slowly began to creep up. By 1933 it had reached $0.99 before falling again. A “hot oil” market was making it too lucrative to flout the law and smuggle oil, and this led to the “hot oil wars.”

To enforce the proration limits the Texas Legislature began to pass tighter and tighter regulations giving the Railroad Commission greater powers. Further the governments of Kansas, New Mexico, Texas and Oklahoma got together to establish a common approach, out of which came the Interstate Oil Compact in 1936. At the same time the Federal Government passed the Connally Hot Oil Act giving it the power to enforce the directives of the Texas RRC in interstate commerce. The regulation of output was considered as one of the steps in increasing the estimated reserves of the East Texas field from one to five billion barrels.

From 1936 until 1972, with the exception of the War years, the RRC controlled production though proration. In this way, when the Iranian revolution in 1951 nationalized the oilfields there, Texas was able to increase production and fill the gap. It was able to do the same during the Suez Canal crisis in 1958. And then, as foreign oil became a glut on the market, the RRC cut production from the wells, down to only seven days a month in 1962. But production over time was depleting the fields. When the Arab-Israeli war broke out in 1967 production could not be brought high enough to meet demand, and in 1972 the RRC set the proration at 100%. The result was only a limited gain in volume, for American oil production had peaked. And Texas had taught the rest of the world’s oil producers a lesson, for OPEC was aborning.

The commission still monitors well production, and is a site where this information is available. The site notes that both oil and gas production and oil well completions this year are running behind last years numbers.

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 )