GEOL 115: The Earth’s Energy Resources

We have considered the problems inherent in preserving petroleum at great depth; the stable forms of carbon at shallow levels in the crust are methane, carbon dioxide, or graphite.  The hydrocarbons in oil are trying to become one of those species depending on the chemistry of the system.  The speed with which hydrocarbons in oil will revert to one of those stable species increases as temperature increases with depth. There are equally significant problems preserving petroleum at very shallow levels in the crust.  Microbes are relentless and will always find a way to thrive provided temperatures are moderate (less than about 120^oC) and the organisms have access to food, oxidants (not necessarily oxygen), water, and nutrients.

Most very shallow oil fields have experienced some level of microbial degradation and many oil fields have experienced substantial biodegradation.  A major advance in our understanding of these processes has been the realization that these organisms don’t require oxygen to oxidize the oil. Whereas we breath oxygen, eat reduced carbon materials (e.g. carbohydrates, proteins, etc.), and exhale carbon dioxide, these organisms will “breath” sulfate ions (SO₄^2-) in the water in which they live, eat compounds in oil, and “exhale” carbon dioxide and hydrogen sulfide.  Oil degrading microbes eat hydrocarbons in a specific order: 1)n-alkanes, followed by 2)isoalkanes. 3)cycloalkanes, and finally 4)aromatics.  Oils affected by biodegradation are heavy, have relatively few short chain n-alkanes, and contain significant amounts of sulfur.  The oils are heavy because the short chain compounds have been eaten leaving only the larger molecules.  The sulfur content is high because the H₂S generated during biodegradation attacks the organic cimpounds and converts them to organo-sulfur compounds. They contain abundant metals, in part because the oil that didn’t contain metaals was eaten. They are; therefore, very viscous and yield little gasoline upon distillation (the gasoline range hydrocarbons have been eaten). The sulfur and metals must be removed before any reforming processes (metals and sulfur will poison the catalysts).

Although gasoline content controls oil value, viscosity controls whether a heavy oil resource can be produced and how it might be produced. Oils as heavy as 10^o API are produced routinely in many onshore areas. It is difficult to produce oils with API gravity values greater than 14^o in offshore areas. The difference in API gravity between onshore and offshore facilities is controlled by the fact that oil viscosity is related to temperature. Oil produced from offshore facilities will have to flow through pipelines on the seafloor. Heating these pipelines would be prohibitive; if the oil won’t flow at low temperatures, then the oil can’t be produced. This operational constraint limits offshore production to 14^o API or lighter oils.

Petrobras is attempting to develop a reservoir that contains 12.8^o API oil from the Siri field in the Campos basin.  This project got the go-ahead this summer and is expected to commence production in 2014-2016.  Ultimate daily production is expected to be about 100,000 barrels of oil per day.  This project is located in shallow water (311′) and it will be interesting to see how the technology gets ported to deeper water depths.

Production of most heavy oil and tar sands is currently accomplished either by mining the material and removing the oil from the sand using a caustic solution or by injecting steam into the reservoir and producing the warmer, less viscous oil. Steam flooding can be accomplished using continuous steam flooding with vertical injection and production wells, cyclic steam stimulation (huff and puff), or steam assisted gravity drainage (SAGD).

Production of steam is energy intensive and expensive. Thus the best operations incorporate cogeneration facilities which generate the steam during power plant operation. These facilities can also use the produced water from the wells as feedwater for the power plants. Because they are treating the water for use in the power plants they can treat all well effluent and sell the excess as irrigation water.

Most cogeneration facilities do not involve heavy oil production (in California only 83 out of 940 cogeneration plants are used for oil production). Most of these heavy oil generation plants use natural gas to produce the steam; they are gas-fired power plants. The situation is similar in Canada where natural gas is currently the fuel of choice for production of oil from the Athabasca Tar Sands. Continued exploitation of heavy oil therefore involves trading the energy in gas for electricity plus heavy oil that can be converted into gasoline. As conventional oil supplies diminish, exploitation of heavy oil will increase the demand on gas resources (probably driving up the price).

One way around this is to use the heavy oil as the fuel to generate heat in-situ (in place) and forgo the cogeneration possibilities.  One of the best options may be the “Toe to Heel Air Injection” protocol discussed in class.  The key to success here is minimizing the distance that the heated oil has to travel to reach the well bore.  If the oil has to travel too far it won’t make it to the well bore and may simply get combusted.

Remember that the heavy oil resource base is immense; the Athabasca Tar Sands and the Orinoco Heavy Oil Belt contain trillions of barrels of heavy oil. Both of these resources occur in foreland basin systems that have generated enormous amounts of oil that has been biodegraded heavily. If the microbes hadn’t gotten to these accumulations we probably wouldn’t be concerned about future oil supplies.

The truly large unconventional gas accumulations are methane hydrates. Methane hydrates were laboratory curiosities until they were found to clog pipelines in cold climates and in deep water.

This phase diagram has been scaled in depth rather than pressure by assuming a hydrostatic pressure gradient (roughly 0.5 psi/ft). You can see by inspecting the diagram that methane hydrates will be stable only at pressures exceeding 250 psi and at low temperatures. As T increases the pressure required to stabilize methane hydrate also increases. The only places where methane hydrates are stable are in permafrost areas or in deep waters of the the oceans.

Methane hydrates are identified easily on seismic records. One simply looks for a BSR (bottom simulating reflector) that cuts across sedimentary strata and has a polarity opposite that of the water bottom. The BSR is the bottom of the methane hydrate zone. At the water bottom seismic waves will speed up as they pass from water to sediment. The reversed polarity of the BSR means that seismic waves must be slowing down at the BSR. The methane hydrate-cemented sediment will have a higher acoustic impedance than the uncemented sediment; thus, the base of the methane hydrate zone should have a polarity reversed from that of the water-bottom.

These systems are a potential energy bonanza: some workers have proposed that methane hydrates may contain more carbon than is present in all the fossil fuels known on the planet. They also represent a bit of a threat; destabilization of marine methane hydrates could cause tsunamis and the addition of large amounts of methane to the atmosphere could cause rapid climate change. One of the more rapid climate shifts in the geologic history occurred during what is called the Paleocene-Eocene Thermal Maximum (PETM). Temperatures during the PETM were probably considerably warmer than they are today and the event is coincident with a significant mass extinction. The wikipedia entry on the PETM is pretty good. Evidence is accumulating that destabilization of methane hydrates may have caused the rapid climate change. This is one of the reasons that scientists are concerned about climate change; we don’t fully understand the system and there is evidence that it can shift catastrophically under the right circumstances.

We’re learning about methane hydrates rapidly and are fortunate that one of the world’s experts is on faculty here at UNL.

Natural gas comprises largely methane. It can be thermogenic in origin; meaning that it is produced by the same processes that produce oil. Organic matter is exposed to heat and methyl groups break off the larger organic molecules while combining with hydrogen to form methane. Natural gas can also have a biogenic origin. Microbes will reduce combine hydrogen and carbon dioxide to produce methane and water following the reaction

CO₂ + 4H₂ = CH₄ + 2H₂O

In some sedimentary environments microbes can derive energy from this reaction and use it to fuel their existence.

Natural gas has traditionally been less valuable than oil. Recall the table in the PowerPoint file from the lecture that showed that you can get roughly three times the calories per dollar from natural gas that you can from oil (based on prices at the start of the semester). This differential exists for a couple of reasons. 1)We do not use natural gas as a transportation fuel (in the US). 2)Significant amounts of natural gas are produced as a byproduct of petroleum production (associated gas) and, therefore, ample supplies typically exist.

In the absence of a market or close proximity to a pipeline in the United States, Canada, Mexico, South American or Eurasia natural gas has little value. When you look at the pipeline maps you will note that many large natural gas fields (e.g. Urengoy) are in sparsely populated areas, however.

Associated gas (gas produced during the production of oil) will typically be flared if a pipeline is lacking. In recent years it was realized that flaring this stranded gas (gas that cannot find a market) represented a significant CO₂ input to the atmosphere and was a wasting a resource. The amount of gas flared would satisfy 27% of US demand for natural gas. You can go here for a video tour of gas flares around the world (warning: its a big file). The World Bank has made reduction of gas flaring a priority. We will consider a method to increase the value of stranded gas later in the semester.

Although there are seven Liquified Natural Gas (LNG) import terminals and one export terminal operating in the US, there is considerable public resistance to construction of these facilities.

Unconventional gas accumulations are exploited in areas close to markets. These plays include tight gas sands, gas-bearing shales, and coal bed methane. All of these accumulations may occur off structure and may require hydraulic fracturing of the reservoir. These plays have generated tremendous interest in the petroleum industry. The Barnett Shale (TX), is probably the best known gas-bearing shale. Tight gas sands are nearly ubiquitous and this article will give you an idea of their widespread nature. Although a variety of basins produce coal bed methane the activity seems to have been particularly intense in the mountain west (in the USA). These accumulations are possible because of the low permeability of the reservoir. As the gas is generated it either is adsorbed on organic matter in the source rock, migrates into pores in the source rock or migrates into a “reservoir” rock. If the rock is insufficiently permeable to allow much migration of hydrocarbons, the gas will only displace the water in the pore spaces. The pore spaces will fill with gas which can migrate only slowly through the rock. In coal bed methane systems the methane is adsorbed on the organic matter in the coal. In all cases you drill into the rock, fracture it if necessary, establish a pressure gradient (by producing any formation fluid such as water) and produce the gas.

Every President since Nixon has sought the holy grail of U.S. energy independence.  Some have stated this goal more explicitly than others.  Implicit in this goal is the suggestion that the declining US production trend can be reversed. The Hubbert analysis suggests that it can’t, at least for conventional petroleum resources. In this lecture we took a qualitative look at whether there are potential large conventional petroleum provinces that remain untapped.

There are a few onshore provinces that we did not examine (MidContinent Rift, ANWR). But outside of these it is unlikely that there will be large discoveries onshore in the US. (By large I mean 500 million barrels or more). Even a 500 million barrel field is insufficient to reverse the decline in US production. Most US oil producing states have production profiles that look something like Oklahoma’s, they seem to be in an irreversible decline.  That’s not to say that production doesn’t exhibit short term increases in response to sharp price spikes.  These increases are small and transient however.

Moreover, there is little interest in petroleum exploration in places like Oklahoma. You can see this by notices of intent to drill in the state or in a more qualitative ways. In the 1950’s every major oil company had a large exploration office in the state of Oklahoma; now relatively few do. There are a large number of oil companies in Oklahoma but they are smaller, have lower reserves, and more restricted operations. Oklahoma has gone from being a vigorous center of the oil industry to being something less than that.

We looked at offshore areas. Its important to note that before the Santa Barbara Channel oil spill there was little resistance to petroleum exploration anywhere. The oil industry was able to nominate interesting areas for lease, the federal goverment held lease sales, and drilling proceeded with little objection.  A number of the areas off California would generate interest if offered for lease today. But the interest would still be tempered by the industry’s experience with the Pt Arguello field (a large field that didn’t produce as hoped).  Petrobras is developing techniques for the retrieval of heavy oil from offshore reservoirs.  The success of those efforts may be critical to future efforts off the central and northern California coast.

The colors on this map actually tell the story.  The basins in light blue and green are part of prolific petroleum systems and are actively developed.  The basins in pink may lack sufficient overburden to cause the source rock to mature and may lack good reservoirs.  The basins in purple contain good source rock that has probably not been buried sufficiently to generate oil.  The basins in brown contain substantial amounts of heavy oil; probably on the order of a few billion barrels.  The basins in yellow lack good source rock.

Most of offshore Alaska lacks good oil-generating source rock.  The exceptions here are the Chukchi and Beaufort areas.  These latter areas are being actively explored.  We know that good source rocks are present in the National Petroleum Reserve-Alaska.  Are there “game-changers” up there?  Probably not.  We would need to find something comparable to Ghawar to really change the long-term conventional petroleum supply picture.

There has already been considerable drilling activity on the east coast of the US.  Again source rocks seem to be the problem there.

The bright spot is the deepwater Gulf of Mexico.  Here a large petroleum province may have been discovered that will be about the size of production to date from the Gulf of Mexico OCS.  It will be interesting to see how the production from this province measures up over time.

It looks like Hubbert was about right on the U.S.  Finding additional large provinces will require some new ways of thinking and finding more supplies of hydrocarbons will require utilizing unconventional resources.

Corporations are right to seek the right to explore domestically; in fact they have a fiduciary responsibility to do so. It is probable that there are a number of giant oil fields that could be discovered. Such discoveries would be very important to an individual corporation. A 500 million bbl or 1 billion bbl discovery won’t change the overall energy picture for the USA however.

Little thought had been given to the finite nature of domestic oil supplies prior to the 1970’s. The domestic oil industry was viewed as an industry that required protection from cheap foreign imports. Thus, prior to 1971, the Texas Railroad Commission limited the production from oilfields in the State of Texas and from 1959 to 1973 there were strict limits on the amount of oil that could be imported into the US. But in the 1970’s major oil companies began to feel the arithmetic pinch between the amount of oil that they could sell in a single year and the amount of oil that they would typically discover in a year.

Two events drove this new order. One was the occasion of the US reaching peak oil production in 1971. The second was the nationalization of Mideast oil production. The Saudi government assumed full responsibility for Saudi Aramco and the Kuwaiti government nationalized the Kuwait Petroleum Corporation. Production was also nationalized in Iraq and Libya. A number of major oil companies had controlled reserve totals that were large compared to their annual production, that was no longer the case after nationalization.

Recall that giant oil fields (those will yield more than 500 million barrels) are rare beasts. In the decade of the 90’s approximately 35 giant oil fields were discovered worldwide and only 2 were discovered in the USA. A large oil company like ExxonMobil or Chevron will produce on the order of 900 million barrels of oil each year. Consider the number of fields that a company would have to discover annually to replace that production. If the average size of the discovery is 50 million barrels then the company has to discover 18 oil fields every year. That’s not easy. But most oil fields in any one province are (such as the Gulf of Mexico) are small. Large oil companies are therefore looking for large oil accumulations; only giant fields can keep them in business.

The problem is even worse when viewed from the perspective of a country. The US uses 7.5 billion barrels of oil each year; you need to find 15 giant oil fields annually to feed that beast. But if we look at the discovery date for the largest fields on the planet we find that they are all old. We haven’t been discovering supergiant fields are the rate that we need to to assure a continued supply of petroleum.

We also looked at some reserve data obtained from OPEC that seems to indicate that the reserve data you see tossed around for many OPEC countries are “unusual.” Many OPEC nations seemed to have increased their reserves dramatically in the 1980’s. These increases may be real. On the other hand, the sharp, coincidental increases in reserves for so many OPEC countries, combined with the stable reserve numbers over years of production are reason to view the values sceptically. Because those values are used to assess world petroleum supply it is likely that those estimates are not very accurate.

In this lecture we looked at the technique that Hubbert apparently used to make his estimate of ultimate US oil recovery and the years of peak production. Deffeyes has good chapters on this subject in his books and I advise you to read them (its on reserve in Love Library).

The Hubbert technique plots annual production rate (P; measured in billions of barrels per year) divided by the cumulative total production (Q; measured in billions of barrels) against cumulative total production (Q). The value P/Q starts at 1 and begins to fall; eventually reaching 0 when production ceases. Hubbert apparently realized that he could extrapolate P/Q values to zero and read the ultimate cumulative total production from the intercept of the extrapolated line with the abscissa (x-axis).

We looked at some examples in class.  Each of the OPEC examples is suggestive that much less oil will be recovered than what many nations list as “reserves.”  The value to Hubbert’s technique is that it doesn’t rely on nations to tell the truth or to be good at petroleum production; it merely looks at what they do.

This lecture was about formation evaluation. Formation evaluation is that set of techniques that is used to determine whether a well can produce oil or gas at commercial rates. Formation evaluation includes mud logging, geophysical logging, and well testing. Mud logging is the process of examining and recording the material that is returned as the drilling mud circulates out of the hole. Mud logging geologists have three primary responsibilities. 1)They look for hydrocarbon “shows” by searching for evidence of oil in the drilling mud and the cuttings that are returned with the drilling mud. 2)They monitor the amount and composition of gases (methane, ethane, propane, iso-butane, and butane) that are returned with the mud. 3)They examine the lithology (type of rock) of the drill cuttings that are returned with the drilling mud. They then make a mud log that displays all this information. Geophysical logging examines the physical properties of the formation.  The most important physical property is the resistivity -a measure of the formation’s resistance to conducting electricity. The figure to the right is an example of what a resistivity log looks like. The numbers in the middle are the depth, the curve on the left does not measure resistivity but another parameter. That curve will deviate to the left when the tool is passing through a good reservoir and to the right when passing through seals. The curve on the right displays the resistivity of the formation. High resistivity (to the right) is good, low resistivity is bad. These data can be used to calculate the water saturation from equations similar to S_w = [(0.81*R_w)/(φ²*R_t)]^0.5 That’s simple enough. S_w is the water saturation, R_w is the resistivity of the water in the formation, and R_t is the resistivity of the formation at depth. As you might guess, measuring all those other parameters can be pretty tricky. I should note that ExxonMobil (among others) has developed a technique to measure formation resistivity remotely (from the surface). This is an interesting development and suggests that we’re getting close to a detailed understanding of the fluids in formations prior to drilling. Drive mechanisms are also important for forcing the oil out of the reservoir. Most reservoirs are initially solution gas drive (shake up a bottle of Pepsi and open it). Solution gas drive is pretty ineffective and will only force a small fraction of the oil in place out. Better mechanisms are gas cap expansion (the overflowing soft drink in the drive-through example), water drive, or gravity drive. Water will normally displace oil (because water oil floats on water) and almost all reservoirs have a natural water drive. The real question is how strong a water drive is likely to be. If there is reason for water to flow in a particular direction in the subsurface and if the reservoir is permeable and porous then a water drive can be quite strong and can systematically flush the reservoir. Remember that the East Texas Field was saved from reservoir damage by over drilling because it has a thick permeable reservoir and a strong water drive. Gravity drainage can be very effective but is typically observed only with very heavy oils.

Hydrocarbon exploration still boils down to drilling. The primary drilling device used in the oil industry is the rotary drilling rig. This piece of equipment is so essential to the energy industry that the number of rotary rigs in operation is monitored continuously and the results are followed with great interest. By considering where rigs are working and how many rigs are working, one can quickly assess the state of the oil and gas industry.

Offshore exploration wells are not drilled from platforms but rather from Jack-up rigs, ship-shaped drilling vessels or semisubmersibles.

The best vessels in operation are semisubmersibles and drillships that can drill in 7,000-8,500 feet of water and support a crew of 200 people for months without significant resupply. They are dynamically positioned and in some cases can drill two wells at once.

One of the most important pieces of equipment on a drilling rig is the BOP stack (Blow out preventer). The BOP stack helps the drilling crew keep control of the well. There are three sets of rams in the BOP stack. 1)The pipe rams clamp down on the pipe and keep it in the well. As long as you control the drill pipe you have a good chance of getting control of the well. 2)The blind rams close when there is no drill pipe in the hole and the 3)Shear rams cut through drill pipe that is in the well. Use of the blind rams or shear rams indicate that you’re having a bad day.

Blow-outs occur when fluid in the formation flows to the surface under circumstances that are not controlled. These can be quite spectacular and dangerous. Blowouts start when formation fluid enters the well bore. This is called “taking a kick.”

If the formation fluid includes gas, as the gas flows toward the surface the gas bubble will expand rapidly. The expanding gas will displace the drilling mud from the drill pipe. When the drilling mud is lost, the formation pressure will exceed the pressure exerted by the fluid remaining in the well bore, the well flows to the surface, and excitement ensues. Take a look at the flowchart that drillers must go through when they realize that they have taken a kick. As you can imagine, the text doesn’t quite convey the excitement inherent in those steps that are highlighted in pink. This link has a several videos of blowouts and their results (I am not responsible for the content at that link).

Among the hazards associated with blowouts is fire. Once a fire occurs the rig typically collapses and you have to move a bunch of scrap away from the hole before you can put the fire out. If you want to see the basic steps in putting out an oil well fire (circa 1968) check out the first 15 minutes or so of the old John Wayne movie titled “The Hellfighters.” For a more modern and less dramatic view you can check out this link provided by one of the successors to Red Adair, Boots and Coots and other pioneers.

You could probably trace the beginning of the environmental movement to the Santa Barbara Channel oil spill. On January 28, 1969 a drilling crew on Platform A in the Dos Cuadras oil field took a kick while tripping out of the hole.  Because of the shallow reservoirs at Dos Cuadras, Union Oil had obtained a waiver allowing them to set only 238 feet of casing below the seafloor.  Casing was set to a drilled depth of 514′ but the rig floor was 88′ above sea level and the water was 188′ deep (88′+188′+238″=514′).  There is nothing odd about such a variance.  It does represent one of the small misfortunes that led to the catastrophic nature of that blow-out, however.

This graph (go to the course documents section of Blackboard and download “Pressure Graph to go with Blog post for Lec 20-22″ if the graph isn’t visible to your right) illustrates the pressure conditions relevant to the A21 well. The blue line indicates the hydrostatic pressure gradient (0.44 psi/ft) whereas the buff line indicates the lithostatic pressure gradient (1 psi/ft).  The hydrostatic pressure gradient is the pressure that would be exerted by a column of salt water whereas the lithostatic pressure gradient is the pressure exerted by a column of rock.  Pressures can’t exceed the lithostatic gradient because they would lift the overlying rock up.  The red line designates the typical pressure gradient in the trend of oil fields of which the Dos Cuadras field was a part.  The pressure at the bottom of the A21 well was only a little in excess of the hydrostatic pressure.  The problem was that the drilling crew had difficulty controlling the kick.  A series of mishaps ensued when they attempted to control the well.  The crew finally closed the blind rams, but only after all the drilling mud had been ejected from the well and a natural gas mist had begun flowing from the well bore.  Although this controlled the well bore,  the well bore was now filled with gas rather than mud and the bottom hole pressure was transmitted to the formation at the bottom of the casing.  This is where the waiver regarding the casing program was important.  The seafloor was doomed to fail if the well bore filled with gas from a depth of 3000′.  The hydrostatic pressures at 3000′ are well in excess of the lithostatic pressures at 514′.  The well bore did fill with gas, the pressures exceeded the lithostatic pressures and the seafloor failed in the area of the platform.  Oil began to flow into the Santa Barbara Channel.

At least 11.5 days passed before the blow-out was controlled. There are many natural seeps in the Santa Barbara Channel and environmental regulations at the time did not require that seeps on leases be mapped before exploration or production activities commenced.  We will, therefore, never know to what extent the well was finally controlled.

Prior to that blowout offshore oil development generally proceeded with little organized opposition. There has been considerable opposition to offshore petroleum development in areas other than the Gulf of Mexico ever since.  It matters little whether the exploration is within sight of land.  Significant progress has been made in the science of well control in the ensuing 40 years.  Blowouts remain rare, but potentially catastrophic events.

We also discussed subsurface blowouts in class.  Although these lack the spectacular fires and other visual effects that accompany surface blowouts, subsurface blowouts are serious problems.   Subsurface blowouts occur when formation fluids leave their current “home” enter a well bore and then flow into a formation that is at lower pressure.  These fluids can eventually reach the surface.  This is what apparently has happened with the Lusi Mud Volcano.

It’s worth looking a little more closely at the Winner’s Curse. The term Winner’s Curse describes the phenomenon that the winner of an item in an auction is usually the individual that has most egregiously overvalued the item. Although the best examples are sealed bid auctions (apparently the term was coined to describe the phenomena that occur in OCS lease sales), the behavior isn’t limited to sealed bid auctions. Consider free agent athletic contracts (google Derek Sanderson sometime), or political celebrity book contracts.

A classic example of the Winner’s Curse is the Point Arguello saga. In 1981 a partnership consisting of Chevron and Phillips purchased a number of leases. Three of these leases were over the north end of the Point Arguello field. The Chevron-Phillips partnership was one of two groups participating in this lease sale that knew that there was oil in the Pt Arguello structure. Despite having more information than the other groups Chevron still overpaid for the leases quite dramatically. The second highest bid on the tract for which the Chevron-Phillips group paid $333 million was $161.1 million; less than half of Chevron’s winning bid. Irrespective of whether the investment paid off in the long-run (and it didn’t) the Chevron group was successful winning the leases because they valued the leases far differently than their competitors. You can sort through the results of a lease sale from this year and find examples of the Winner’s Curse. This phenomenon doesn’t disappear.
Other countries typically have larger lease blocks (hundreds of sq miles in area) and require that exploration entities present an exploration plan. This exploration plan must list in detail the prospects that they identify and how they expect to produce those prospects. The quality of the exploration plan is evaluated rather than a specific dollar bid.

As long as exploration costs are significant, companies will form partnerships to spread their risk during exploration irrespective of the type of system that is sued for awarding acreage. The basic idea is to prevent the future viability of the business from being dependent on the success or failure of a single venture. This is kind of hard for most people to understand at first and I blame professional football. I touched on this in a blog post last winter. In the NFL, the worst team gets the first pick of all the collegiate players the following year. This pick is guarded jealously and almost never traded away. This behavior occurs despite the fact that a single player almost never lifts an NFL team from bad to even mediocre. Moreover almost all bad teams are bad because they typically make bad decisions. No matter, they roll the dice on a single high stakes bet and almost always lose, again. Oil companies don’t operate that way. They spread their risk, avoid Gambler’s Ruin, and try to keep in business.

The search for energy resources is a world-wide effort. We therefore took a moment to consider the different types of energy companies that are involved in this process. There are state-owned oil companies that limit their exploration and production activities to a single country and that bear sole responsibility for all exploration and production activities in the country in question. The best known examples of these sorts of companies are Saudi Aramco (oil operations in Saudi Arabia) and PEMEX (operations in Mexico). In class I put PDVSA in this category, it turns out that they are a little different as they don’t bear sole responsibility for production operations in Venezuela. On the other hand there are state-oil companies that are traded publically and have international exploration and production operations. Petrobras (link to their US subsidiary), StatoilHydro, and Gazprom are three examples of the latter. The state has a minority interest in Lukoil.

You can’t produce energy unless you can get access to land. Mineral rights may be administered by private citizens or by public officials on behalf of citizens of states, the USA or sovereign native tribes. In the USA land acquisition works many different ways.

Companies negotiate with private individuals for mineral rights on private land. Often multiple landowners must be approached to acquire all the rights for a specific prospect. Some prospects that are being developed now such as the Barnett Shale or the Bakken are large acreage plays. In the modern world this means that the landowners build websites! The websites are used to organize neighborhoods to cut deals as a single entity, provide info on dealing with oil companies if you have surface rights but not mineral rights, the going rate for acreage, and rumor control.

States and the federal government typically offer acreage though lease sales. There are a variety of mechanisms for this. Typically a governmental agency announces that certain areas will be offered for lease, defines the size and locations of the leases, and announces the terms of the sale. Interested parties nominate specific tracts to be offered in a lease sale. The agency then compiles the tracts of interest, produces a final announcement of the sale, and holds the lease sale. The federal entities that perform that function are the Bureau of Land Management and the Minerals Management Service.

I reviewed the boundary between Federal and State waters. Louisiana is like most other states: the states have control over acreage from the Mean High Water mark ( I said low tide level in class) to a point 3 nautical miles offshore. There are two exceptions: 1)Texas and 2)the Gulf Coast of Florida. Both of these states have control of states from the Mean Low Level Water mark to a point 3 leagues offshore (9 nautical miles). Why is there a difference? Ya got me. I’ll have to check that out in the future.

We started to compare the leasing process in US federal waters with those in foreign countries. Lease blocks in the US are small (3×3 nautical miles) compared to the exploration concessions awarded by most other countries. They are awarded using a sealed bid-bonus system. This means that the lease rental, royalty and other terms of the lease are specified by the Feds up front. The bidding entities then submit a bonus, a onetime payment for the right to acquire the exploration rights to that lease. This system lends itself to a phenomenon known as the Winner’s Curse. The entity that wins the lease is typically the one that ascertains the value of that lease incorrectly by the greatest amount. This is a small thing to you and me but it drives exploration managers nuts. Funds that “they leave on the table” aren’t lost but they do represent funds that could have been used to pursue other ventures if they were better able to value the lease and predict their competitor’s behavior.

Today we also started to look at exploration techniques in earnest. Using geologists in the field is cheap. In the early days of the oil business geologists could do surface geology to find oil fields directly. This ranged from simply drilling on oil seeps (the Jed Clampett technique) (here’s an old paper on seeps that you need to be on a campus computer to access) to mapping the surface exposures of anticlines. This image
View Larger Map
shows the surface expression of an anticline in the Zagros fold belt of Iran. The NW-SE trending oval structure near “A” is an anticline. It looks a little like a hot dog that has been sliced in half (along its long dimension) and placed on a flat surface.   These are easy to find, as you can imagine, and virtually all of them have been found. Although there are almost no locations today where a geologist can map a structure on the surface and use it to find an oil field at depth, geologists can learn a great deal about potential reservoir and source rocks from surface work. Clever geologists will also be able to predict the occurrence of rocks in the subsurface from exposures at the surface.

We noted that surface geochemistry is sometimes used in exploration. Cynics would argue that surface geochemistry is best equipped to find known oil fields. The basic principle is sound: all petroleum-producing basins contain seeps. Surface geochemistry attempts to find the very small seeps that must issue from almost all petroleum and gas accumulations.

In the days when there are few wells drilled in the US OCS, oil companies would group into consortia to drill COST wells (Continental Offshore Stratigraphic Test). This technique could still be used in any area where geological data were unavailable. The companies select a location and drill a well for the purpose of getting geological information.

The most common exploration method; however, is seismic exploration. A source of seismic energy is used to cause seismic waves to travel through the Earth. These waves are reflected by layers of rock and observed using geophones or hydrophones. The data can be processed to produce a crude image of the shallow crust.

Geophysicists realized that the differences in seismic velocities between rocks saturated with salt water and those saturated with gas could be considerable. This pronounced change in acoustic impedance would produce a response seen on seismic reflection profiles called a bright spot (see also here). After this phenomenon became known and understood it increased success in petroleum and gas exploration. Another direct detection technique is known as a flat spot. Flat spots are seismic reflections produced by the horizontal interface between gas and water in reservoir rocks. As geophysical processing has become easier and more sophisticated more techniques have evolved. The fundamental problem when trying to explore for oil is that the change in acoustic impedance between oil saturated and water saturated rocks is not great. The second is that geologists must always endeavor to understand why particular phenomena appear in geophysical data and not merely rely on empirical interpretation. You can check this out if you are really interested in some of the science behind “bright spots” and using seismic data to identify hydrocarbon-charged rocks.

None of these techniques requires that the exploring company acquire anything other than the right to be on the surface of the land. This is usually easy to get and may be free if the lands are public and the activity will have no impact (e.g., doing surface geology). When it comes time to drill everything changes.