I also want all readers to note that I am writing about countries where all of the country’s oil is not nationalized (for example Saudi Arabia, Iran, Venezuela, Mexico). For an independent oil company to exploit oil in these countries, very special agreements between the independent company and the national oil company must be reached.

Exploration & Seismic

First you have to find the oil. We know the locations of where a lot of big oil fields lie in the world: places like Saudi Arabia, Western Canada, Gulf of Mexico, and the North Sea. We also know, in these locations, where the big oil fields are, and a lot of them are already drilled up pretty good. This kind of approximate location guides oil companies to where they need to look for oil. Once they find a plot of land where they think there is oil, maybe from other oil well logs or seismic data from close sections of land, they will run some tests on the plot of land. The most common is called a seismic survey. Essentially a seismic survey sends vibrations into the ground and records how these vibrations make it back up to the earth’s surface. In the past these logs were in 2D format, but as of recently 3D seismic data is now available. From the 2D or 3D logs from this type of survey, well trained geologists can determine (or guess) what kind of material is under the ground. Generally these vibrations are made by large trucks pounding the ground (for onshore wells) or ships with special equipment that set off little explosions (for offshore wells). There are images below showing how a seismic survey works as well as some 2D and 3D seismic data:

Source: Maritime Connector

Source: Wikipedia

Source: Gerard M. Stampfli (University of Lausanne, Switzerland)

Once the seismic data is collected, geologists look at the data and look for patterns similar to ones they have seen where oil has been found before. Many people in the industry will tell you that this part of the process is a little more of an art than a science, and therefore when they think they’ve found an oil pool, there is still uncertainty if it is actually oil or something else like water. Following this, some other research may be included, such as well logs from wells close to the location or from a similar formation.  A geologist will then recommend to the management team that the well should be drilled.

Land & Mineral Rights

Once the management is reasonably convinced there is oil there, they will start the process to obtain the mineral rights as well as the land access rights to that location. In some cases (but not always), these rights are held by the same entity. Either way a mutually acceptable payment or royalty must be determined to be paid to the land and mineral owners. If the land is held by an individual, typical contractual negotiations occur between the operating company and the land owner. Some countries (one fine example is Canada) where many of the mineral rights are owned by government (oil is not nationalized, the rights are just owned by the government) have very well established mineral rights auctions that occur at specific times of the month.

Drilling

Assuming that the geological data indicates the presence of oil and the proper rights are obtained, a company is ready to drill. A hole is drilled into the ground using a drilling rig. This is effectively a large machine with a long spinning rod and a bit at the end. Images of an onshore and an offshore rig are shown below.

Source: Dreamstime

Source: CIChem Research Group (Esbjerg Institute of Technology, Aalborg University)

Different bits are required to drill through different types of underground matter. For example, a different bit is required for drilling through sand than for drilling through hard rock. If you turn your attention to the image below, the middle-left bit and the far right bit would be used for drilling through softer material and the far left bit and middle-right bit are used for hard material. These are only a small sample of the bits that are used; hit up Google images to see some other types.

Source: Google Images

As the well is being drilled, a drilling fluid or, as it is known in industry, mud is circulated through into the well for a couple of purposes. The main purposes are cooling the bit as well as providing a medium to remove the material that is being drilled though. The right type, consistency, and makeup of the mud is particularly important to the drilling process, so important that I could write an entire post just on drilling mud.

A well will be drilled to the target formation. According to the EIA, in the U.S. this depth averaged around 5,700 ft. in 2006. Geologists can determine where the target formation is from well logs that are recorded based on the material that the drilling rig pulls out of the ground, as well as core samples from the well. The target formation has an area of what is called “net pay,” which is effectively the part of the formation that is economically producible. Net pay regions can range from as large as a couple hundred feet to only a few feet (all depending on the location and the formation). The wells with only a few feet of net pay really astonish me. Think about it: you drill 6,000 ft. into the ground to find a formation to produce that is only 10 ft. tall. That’s pretty impressive by any standard. And we get to enjoy all that technical expertise for only about $70 per barrel of oil (or 42 U.S. gallons, 159 liters).

After the well is drilled, metal casing is placed in the well to hold the hole open so oil can be produced. In cases where high pressure is expected, concrete can also be placed around the metal casing for additional structural integrity.

Completion & Tie-In

Following drilling, a well must be completed. “Completing” a well allows the well to produce oil.  The main part of competition is perforating (or “perfing”) the well. This is done through busting little holes into the well casing so oil can flow up the tubing of the well and to the surface to be produced. Additionally, the top of the producing region (the region of net pay) is closed off and a smaller piece of tubing is put down the well for the oil to flow up to the surface. In most cases, some chemicals are put down the well to clean out the tubing and casing as well as to stimulate the well for production.

In some cases, the pressure of the oil in the target formation is large enough to push the oil up the tubing and to the surface, but in many other cases a pump jack and/or some other type of removal assistance will be used. A picture of how a pump jack works is below.

Source: Wikipedia

As of recently, fracturing (“fracing”) a well has become quite common. Effectively fracing forces high pressure fluid with small rocks or sand into a formation creating small cracks in the formation so the liquid oil can then flow through more easily. I speak more on the effects of natural gas well fracing in a previous post.

Typically after these steps the well is set to produce. It just needs to be tied into a pipeline or other type of liquid transportation system, and production can begin.

Costs

The bottom line is, how much does this all cost? Well a lot more than you’d probably guess. As a result, somewhere in the entire process, many companies will look for a partner to assist in providing capital for the project in return for a portion of the profits from the well. To get a sense of the magnitude of the cost, the EIA reported that in 2007 a typical onshore U.S. oil well cost around US$4 million to drill and complete. Offshore wells cost substantially more, typically in the US$35-100 million+ range (depending on the location and the depth).  These values vary substantially and are just averages, but the point is, it’s really expensive to drill. And since one can never be sure if there will actually be oil in the well (i.e. they might drill a “dry hole”), it’s best to share the risky capital with other partners in case there is no pay at the end of the day.

Final Thoughts

This short summary only touches the surface on what drilling and producing an oil well entails, but it helps to know that there’s a lot of science, risk management, and knowledge that goes into each drop of gasoline in your car’s tank.

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Let’s look at where the money and research has gone for electricity generation as of late:

Source: The Business Insider

From the Bank of America/Merrill Lynch graph above, we see that wind and solar make up about 81% of the capital investment in renewable technologies recently. And because of this capital investment, wind and solar technology have become quite impressive in terms of the efficiency (relative to a few years ago) and the number of seriously interested parties and installations.  There, however, is one, fairly large, problem that both technologies exhibit: The wind ain’t always blowing, and the sun ain’t always shining. This characteristic has been a killer drawback for both technologies. Consumers want electricity when they demand it, not just when the wind is blowing or the sun is shining, and therefore nearly all wind and solar technologies, with current technology, can’t be used for base load electricity generation, they can only be used as an auxiliary source. A power company still needs to have enough coal-fired generation plants, nuclear plants, natural gas plants, or hydro plants to provide that minimum base load of electricity to consumers and only use that renewable technology when it’s generating power and is demanded. As things stand, it’s pretty inefficient.

But this is where storage comes in. If the wind is blowing, turning the wind turbines and generating electricity in west Texas all night and this electricity can be stored in some big battery type device until the following afternoon when it is actually needed to cool the office building and homes in Houston, then wind energy is looking a lot better and a lot closer to a viable base load technology versus an auxiliary one. The case is the same for solar, if the electricity generated on one hot sunny day can be stored and used on a rainy one, solar is looking a lot better too. Storage is indeed the Holy Grail of cleantech.

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Source: Bloomberg

To preface this post, I’d like to say that I am not attempting to fully answer the question of why natural gas prices are lower as of recently, nor am I predicting where they are going, but I’d like to provide some perspective to some of the technical factors that have driven prices down lately.

First, some fundamental information about natural gas. Not surprisingly, natural gas (at typical terrestrial temperatures) is in gas form. Now this is quite trivial given the commodity’s name but has very important implications for natural gas, especially when comparing it to its good friend crude oil (which is a liquid). Since natural gas is in a gaseous state, the way in which it can be transported is much different than oil. With most kinds of sweet light oil (the stuff that’s traded at WTI prices), you can effectively flow in a pipeline directly from a well into a tanker and then to anywhere in the world.

Natural gas, however, is a very different story. Natural gas is in gaseous state; therefore it cannot be transported as easily as crude oil. This is because it takes up a lot more room and more importantly is dangerously volatile. To transport natural gas it must be done through a pipeline or on a liquefied natural gas (“LNG”) tanker (compressed natural gas exists as well, but plays a minor role currently). To utilize LNG, infrastructure has to be in place that will liquefy the natural gas, which means that there needs to be a facility that will cool the gaseous commodity to -162°C. And, as is obvious, to pipeline something the location must be “pipeline-able” (as I like to call it). Essentially that means that you can’t build a pipeline across the Atlantic ocean (well you can, but it’d be pretty silly), but you can from Alberta, Canada to the Chicago or from the Gulf of Mexico to Galveston. The pictures below show you oil and gas movement in the world.

Oil Trade

Source: BP Statistical Review of World Energy 2009

Natural Gas Trade

Source: BP Statistical Review of World Energy 2009

Since natural gas has historically been a regional commodity, the supply and demand characteristics are also regional. This is one of the main reasons why we see the wide variances in natural gas prices around the world, whereas oil prices are pretty closely tied together (generally, differences in price are due to differences in quality of the oil). Up until just recently, things were looking pretty dismal for the United States on the natural gas front. There were diminishing US supplies but increasing demand—and no real in-country way of adding supply to offset the rising demand.

As of recently, though this problem has been solved by new technologies that can tap into in-country natural gas resources which previously were unrecoverable—which is another way of saying that with current technology and  prices the natural gas was either uneconomic or technologically impossible to recover —are now recoverable. These resources are known as shale natural gas. Previously, shale did not have the permeability to let natural gas flow in a manner that was economic and technologically possible to produce. New technologies, most notably the hydraulic fracturing of a well, can make the previously uneconomic shale economic by increasing the permeability. Essentially what fracturing a well does is create cracks in the rock formation in which the natural gas is present so that the natural gas can flow through the rock and above to the surface. These cracks are created by pumping a fluid with grains of sand or rock (to hold the fracture open) into the well at high pressure forcibly breaking the rock formations and increasing permeability making the natural gas recoverable. This technology has been and continues to be industry-changing.

In June of this year, the Potential Gas Committee reported that estimated natural gas reserves increased by 35% over the past year to 2,074 trillion cubic feet in 2008 (up from 1,532 trillion cubic feet in 2006). This is the biggest increase in 44 years. The massive increase in prospective supply has had a profound impact on the market for natural gas in the United States and has contributed, from a technical perspective, significantly to the drop in the price of natural gas.

This technological advancement once again reminds us that we’re not running out of fossil fuels by any means; we just need to find more clever ways of producing what are now unrecoverable resources.

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I like to follow the stuff that peak oil guru Matt Simmons publishes on his website and one of his main thesis is that energy (particularly oil) is way too cheap. He has a slide in one of his presentations where he supplies the following pricing statistics.

I also did a few other calculations, which are quite astonishing:

• An average bottle of wine at a nice restaurant, $202/gallon
• A beer at a ball game, $68/gallon
• An average Starbucks drink, $28/gallon

Now obviously you aren’t buying a gallon of Vicks NyQuil at any given time, but there are a lot of people who drink a gallon of beer on a Friday night (that’s about 10 bottles), or consume a gallon of Starbucks coffee over a week (that’s about one grande drink a day). The question then is, how much utility do you get from that Starbucks drink every morning or a few beers at the ball game versus driving in your car?

Well, let’s look at what a gallon can do for you in your car. A gallon of gas in an average subcompact, assuming a mix of city and highway driving, can take you about 30 miles (18 km), or about on a 45 minute drive (driving at an average of 40mi/h (64km/h)). By any standards, that’s a long ways to go for only $2.50. For comparison sake, go through the list below and decide what’s giving you more utility, 45 minutes in the car or approximately:

• 1/3 of a gallon of water (three bottles)
• 1/3 of a gallon of Coke (three cans)
• 1/5 of a gallon of Budweiser (two bottles)
• 1/10 of a gallon of a Starbucks drink (a tall beverage)
• 1/20 of a gallon of beer at a ball game (half a cup)
• 1/100 of a gallon of wine at a nice restaurant (a drop)

Maybe $4 a gallon isn’t that expensive when you look at it from a comparative perspective. Maybe energy really is way too cheap.

If this post intrigued you, I would suggest you read some of Matt Simmons’s presentations on his website or watch one of the interviews on YouTube.

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Plus, there are many technical reasons to go forward with this plan:

• It is estimated that 15% of the EU’s electricity demands could be satisfied by such a project.
• DESERTEC (a foundation with the mandate to provide Europe with electricity through solar thermal applications in deserts) has announced a preliminary financing plan for their solar thermal project.
• Green, renewable technologies are the latest hype right now.
• Solar thermal, in the right application, is arguably an economically viable electricity generation alternative.

There is a lot going for this project. But there is also a lot going against it, particularly on the social side. The sentiment of European Imperialism is still in Africa. And coming in and exploiting yet another resource is not going to go over well. Look at how Shell has been treated in Nigeria over the past couple of weeks. They have been forced to shut-in oil production (i.e. stop producing wells) because of massive destruction of their facilities there. Additionally, and more importantly, is exploiting a resource from a historically poor continent for use in a historically wealthy continent something that a socially responsible company does?

But socially it’s not all bad. This project could have a lot of positive effects on an economy. The typical increase in jobs that comes with any new development would be excellent for the economy as well as quality of life of the citizens. Furthermore, this kind of solar thermal allocation would require skilled labor, which requires additional education of citizens, another great benefit to any country.

It’s is a great concept from a technical perspective, and if the cards are played right, it could be a great development from the social side too. The question is, how are the cards going to be played?

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