Alabama combined temperatures

There are fifteen USHCN stations in Alabama that start at Brewton and end at Valley Head. It has two GISS stations on the list, and they are at Mobile and Montgomery.

USHCN stations in Alabama (CDIAC )

The station in Montgomery is yet another where GISS is using a station that does not start its record until 1947. It is interesting to see how many times GISS is using these shorter truncated records when there are a significant number of other stations that have a full record back into the 1880’s. If one were cynical one might think that this was to hide the higher temperatures in the 1930’s.

Average annual temperatures for Montgomery AL, GISS station data

However there wasn’t such a temperature high in the ‘30’s, for Mobile, whose temperatures have remained relatively stable, so we’ll have to see if there was one for the state as a whole.

Average annual temperatures for Mobile AL, GISS station data

When looking at the difference between the average GISS and the average of the homogenized data for the USHCN sites for this state, the GISS sites are, on average 3 deg F warmer, but there is no trend in the data for Alabama.

Difference in average temperature, per year, between the GISS stations and the homogenized values for the USHCN stations in Alabama.

In terms of the temperature trend for the state, as a whole, even the homogenized data from the USHCN sites shows that the state has cooled over the last century.

Average temperature for the state of Alabama with time, using the homogenized temperature data from the USHCN.

When this is compared with the Time of Observation adjusted raw data (TOBS), that also shows a decline. It is interesting that in both there is a drop in the average temperature in 1958, which then seems to re-stabilize around a lower temperature

Average temperature for the state of Alabama with time, using the Time of Observation corrected raw temperature data from the USHCN.

Looking at the populations surrounding the different stations, using the citi-data sites for the communities, This does not work for Gainsville, which has a population of 192 according to HomeTownLocator. Saint Bernard is a little more of a challenge – so I go to Google Earth, and while close in it looks very rural (being in a Benedictine monastery/school) when one zooms out a little it is in the community of Cullman, AL).

Location of the station at Saint Bernard AL, Cullman is over the hill to the left.

Alabama is some 330 miles long and 190 miles wide, stretching from just under 85 deg N to just under 88.5 deg N, and from 30.21 deg W to 35 deg W. The mean latitude is at 32.84 deg N, that of the USHCN stations is 32.8 deg N, and that of the GISS stations is at 31.5 deg N. The elevation ranges from sea-level to 733 m, with a mean elevation of 152.4 m. The mean elevation of the USHCN network is at 122 m, while that of the GISS stations is 40.5 m. The two GISS stations have an average population of 197,648, while that of the USHCN is 14,866. (With a temperature change of 0.024 deg per m, the change in elevation gives a 1.6 degree difference because of elevation changes, and using a temp change that varies with 0.6 x log (pop) would explain another 0.7 degrees of the average 3.04 deg between the two mean temperatures).

Looking at the effects of state geography on temperature change, beginning with Latitude.

Average Alabama temperature as a function of latitude

Alabama is another state where there is a fall in elevation moving West, and so there is a temperature increase with longitude:

Average Alabama temperature as a function of Longitude

While the R^2 value for latitude falls, from 0.86 to 0.71, when the data is homogenized, the value for the longitude correlation increases from 0.14 to 0.28. This again helps explain my concern with the process used to fill out the data.

Looking at the elevation itself,

Change in average Alabama temperature as a function of the elevation of the observing station.

The final correlation is with population, and there is not a really broad distribution of population around the stations., so that when this is included with the other variations, gives a poor correlation in the state with a 5-year average for temperature. (The correlation is, oddly, in this state better over longer periods).

Correlation of Alabama temperatures with the population of the community surrounding the station.

And that leaves the final check, between the raw data and that which has been modified to give the official USHCN numbers. The plot is the official temperature minus the raw temperature averages.


Let me throw in one final fact, just glancing at Chiefio’s site, he has a post up on relative humidity in which he quotes as follows:

As an average, the International Civil Aviation Organization (ICAO) defines an international standard atmosphere (ISA) with a temperature lapse rate of 6.49 K(°C)/1,000 m (3.56 °F or 1.98 K(°C)/1,000 Ft) from sea level to 11 km (36,090 ft). From 11 km (36,090 ft or 6.8 mi) up to 20 km (65,620 ft or 12.4 mi), the constant temperature is −56.5 °C (−69.7 °F), which is the lowest assumed temperature in the ISA.

Since I am using meters for measuring elevation but degrees Fahrenheit for temperature, the gradient is thus officially 11.68 deg/1,000 m or 0.0117 deg/m. The rate that the data fits, as shown above, is 0.024 deg, or about twice the official rate. It will be interesting to test the actual data for the different states against this standard.

E.M. Smith (who writes as Chiefio) has some interesting points to make about the effects of humidity, which I haven’t even thought of looking at, but which might be an interesting place to go. Water vapor is, after all, as he notes, supposed to be a stronger GreenHouse Gas (GHG) than carbon dioxide, and yet more humid places may be cooler than those which are drier. (It just may not feel that way). Read the post, it is interesting!

Carbon Sequestration sites and their success

There are a number of questions on the ease with which carbon dioxide can be sequestered underground, and I alluded to some of them in yesterday’s post. That led me to a quick review of the status of the concept, and I thought I would pass on information from some of the papers that I looked at. Some of the different options that can be used for carbon dioxide injection underground are illustrated by a review of the Polish program.

Different options for carbon dioxide disposal underground.

Of these the use for enhancing oil recovery has, perhaps the longest history. Some sense of the work can, perhaps, be seen by looking at CO2 injection at the Cranfield site in Mississippi.


The site is in an oilfield that was discovered in 1943, and abandoned in 1966. Since that time, under the influence of a strong aquifer drive, it has returned to its original reservoir pressure. There is a layer of residual oil, under a gas cap..

Section through the Cranfield site

The site is actually a dome, folding in both directions, so that the residual oil forms a ring. It is a part of the Tuscaloosa Formation, which MIT has calculated should be able to retain some 10,000 million metric tons of CO2. Adjacent continuations in East Texas and the Gulf would add an additional 187,000 million tons of capacity. Validation of the performance of the test site would thus go a long way to answering some of the critics of the technology. Because of the limited volume of oil available, the project is also looking into injecting CO2 into the brine interval during the third phase of the program.

At Cranfield the CO2 has been injected continuously, starting in July 2008, at a rate of 500,000 tons per year. so that, as Professor Economides discussed, the injection pressure remains high. At present the analysis of the samples shows little change in the water chemistry as a result of the injection. Last November it became the fifth site in the world to store more than a million tons of CO2. Monitoring of the pressures as the third stage has begun, does show a pressure increase, although this may be injection rate sensitive.


Monitored pressures for Cranfield 3 (U of Texas)

A second site is being prepared in Alabama at the Citronelle oil field, near Mobile. Both carbon dioxide and water will be injected at that site, with the intent that the CO2 will allow an additional 15 to 20% increase in overall production from the field, before the site is left to sequester the CO2.

In the United States, CO2 injection has already helped recover nearly 1.5 billion barrels of oil from mature oil fields, yet the technology has not been deployed widely. It is estimated that nearly 400 billion barrels of oil still remain trapped in the ground. Funded through the D.O.E.'s Office of Fossil Energy, the primary goal of the Citronelle Plan is to demonstrate that remaining oil can be economically produced using CO2-EOR technology in untested areas of the United States, thereby reducing dependency on oil imports, providing domestic jobs, and preventing the release of CO2 into the atmosphere. . . . . . . When the 5-month injection is completed, incremental oil recovery is anticipated to be 60 percent greater than that of conventional secondary oil recovery by water flood. A recent study by Advanced Resources International of Arlington, Va., estimates that approximately 64 million additional barrels of oil could be recovered from the Citronelle Field by using this tertiary recovery method.

In the last Oil and Gas Journal survey (April 2008) they found 100 miscible ongoing CO2 projects and 5 immiscible ones, with enhanced oil production, at the beginning of 2008, running at 250,000 bd.
Costs for CO2 EOR have been given as $20.86 boe, divided out as follows:
* $3.68/boe for CO2.
* $5.72/boe for power and fuel.
* $3.34/boe for labor and overhead.
* $2.00/boe for equipment rental.
* $1.36/boe for chemicals.
* $3.05/boe for workovers.
* $1.71/boe for miscellaneous.

One of the Centers most active in the monitoring of CO2 plumes as they migrate from the wells out into the formation is at the University of Texas-Austin. Sue Hovorka, for example, monitored a CO2 plume migration after it was injected as part of a test in the Frio Blue sand, although in that test the injection was of the gas.

Several times a day during injection, trucks hauling 20-ton tanks of cold liquified CO2 arrive at the test site, where it is transferred to two 70-ton storage tanks. The CO2, which comes from a natural reservoir near a Mississippi salt dome, is transported most of the way by train.

During injection, the liquid CO2 is pumped through a heat exchanger, which warms it up to 21 degrees C (70 degrees F), converting it to a gas. Then it is pumped through the injection well head and a mile down the well. The CO2 enters the porous sandstone and brine through perforations in the well casing and spreads out in a plume.

She also described, briefly how the process was supposed to work.

Before the first tests, the scientists had predicted that an effect called residual saturation, caused by capillary forces, would cause the brine-filled pores in the stone to trap and hold about 20 percent CO2. The other 80 percent moves on to the next set of pores, and as it moves, it’s continuously diminished. In other words, the plume smears out. Hovorka said the effect is intuitive.

“It’s the same reason you can’t get grease off the stove,” she said. “You can’t wash it loose with water, you have to use soap.”

The 2004 test confirmed this prediction and now initial results from the 2006 test seem to reconfirm it. “It means we got the physics right,” said Hovorka. It also means she and her colleagues can predict the CO2-trapping ability of other sites before injection begins, a powerful and necessary tool for carbon sequestration to become a common practice.

Polish trials have looked at displacing natural gas with CO2 in a program that has been going on for over 12 years Part of the process at the Borzecin site was to inject the gas into the underlying aquifer beneath the natural gas pocket. The CO2 dissolves into the water and so the migration to the gas pocket occurs only very slowly, the gas is at 1,500 psi (just above the critical pressure) when it enters the reservoir). The gas displaces natural gas that had previously been dissolved in the aquifer, yielding about 60% of the injected volume of CO2, as natural gas from the production wells.

One event that this test showed, which perhaps Professor Economides had not considered is that the dissolved CO2 appears to have interacted with the water, over time, to form a carbonic acid, that ate into the carbonate rock, and increased the permeability of the formation, lowering the pressure required for injection, rather than, as he had anticipated, having it rise. The site has now accepted more than 1.4 million scm.

CO2 has also been tested as a means of displacing methane from unmined coal seams. The initial project was completed in 2005

During the project 203 tonnes of CO2 were supplied to the site and stored in tankers. The CO2 is taken from the tankers where it is already stored under pressure and then injected at the injection well (MS-3 well). The injection well was a new well drilled down to a depth of 1120m for the purpose of this pilot project. The target seams were thin coal layers that were bounded (above and below) by highly impermeable shales. The pre-existing coal bed methane (CBM) production well (MS-4) is 150m from the injection well. A tank by the production well stores the saline water which is a by-product. This is emptied and disposed of on a weekly basis. The produced gas (naturally - 97% methane, 2% CO2) is flared. Since December 2004 there has been a gradual rise in CO2 content of the produced gas, the latest figure is 8% which may represent breakthrough of injected CO2 at the production well.

Modeling of the process is not yet fully functional, and in contrast to the more conventional reservoirs for oil and natural gas, the large fracture patterns in coal, known as cleat, play a greater part in the performance of the coal beds and must be included in the analysis.

Nevertheless the tests of the different methods for storage, and use of CO2 injected into the ground have been successful. The most widely recognized, however, is that carried out by Statoil, with Sleipnir the most documented. By 2004 Sleipnir had been injecting CO2, which is produced at an unacceptable 9% in the natural gas extracted at the site, at a level of a million tons a year, since 1996. Because of the length of time that the injection had occurred it has been possible to map the migration of the CO2 over that time. The initial injection is at a depth of 1,000 m below sea level.


Pattern of CO2 injected flows from the injection well at Sleipnir after 3 years

If I read the plots correctly the injection point is aligned with the deepest point in the picture and the flow path is about 2 miles long on its greatest extent.

The site continues to be monitored, as injection continues, with migration being downward under the containment of the cap rock.

Seismic surveys of CO2 migration at Sleipnir

It is expected that the CO2 will slowly dissolve into the brine (over hundreds of years). The scale of the above is exaggerated vertically since the height of the plume is around 600 ft.

The success of the program has led to the Snohvit Project which again takes the CO2 from a natural gas supply (in this case at 5% CO2) and stores it underground.

The success of these projects, and the changes in conditions from the simple models initially assumed to the more complex considerations that have had to be undertaken as the storage has continued to accept high levels of CO2 in some cases, and only high injection rates in others, nevertheless combine to suggest that Professor Economides models may be overly conservative.