Mexico’s Cantarell oil field, located in the shallow waters of the Bay of Campeche, is by far the largest conventional oilfield discovered in the Americas and the sixth-largest worldwide.
It’s estimated that Cantarell contains some 35 billion barrels of oil and can ultimately yield 17.5 billion recoverable barrels. But, like so many other supergiant oilfields around the world, Cantarell is slowly dying. Check out the chart below for a closer look.
The field was discovered in 1976 and went into production in 1979. When a new oil or gas field is first drilled and produced, underground pressures are high, driving strong initial production growth rates.
As the chart above shows, Cantarell had topped the 1 million barrel per day (bbl/d) mark by 1990 and stagnated around that level for a few years. In fact, Cantarell is the last field discovered anywhere in the world to reach that production milestone.
You’ll notice another inflection point in Cantarell output around 1997, the result of a nitrogen injection program initiated by Petroleos Mexicanos (Pemex), Mexico’s national oil company (NOC). This USD10.5 billion project involved injecting nitrogen gas into Cantarell in an effort to add pressure to the field and enhance recovery rates. To put it mildly, nitrogen injection worked: Cantarell’s production doubled to a peak level of more than 2.1 million bbl/d in 2004.
But Cantarell is now in the final phase of its life as an oilfield. Despite attempts to stem the decline, Cantarell’s production fell to less than 1.5 million bbl/d in 2007; Pemex itself estimates that the field will decline at an average annualized rate of 14 percent until at least 2015.
At that rate, production will plummet below a half million bbl/d by 2015–with devastating consequences for Mexico’s overall production and exports. And output is actually declining far faster than 14 percent annualized. Although oil will likely flow from Cantarell for decades to come, the field will no longer be the key producer it once was.
Cantarell’s decline is just one manifestation of a key shift underway in global crude oil markets: the end of easy oil.
The past 100 years of human history and prosperity have largely been built on petroleum, and the world has relied, to a great extent, on a handful of giant fields to enable that growth. But most of those fields, like Cantarell, are aging and entering a phase of decline.
It’s absolutely crucial to frame this scenario properly. The world isn’t running out of crude oil. In fact, it’s likely the last barrel of crude oil will never be pumped. The idea that global oil wells will suddenly run dry is total bunk propagated by those desperately searching for alarmist headlines.
Even as Cantarell peaked in 2004, it’s likely the field hadn’t yielded even a third of its total oil or 60 percent of its estimated recoverable reserves. And some giant oilfields in California and Texas have been in production for more than a century and still have more than half their recoverable reserves sitting in the ground.
The question isn’t how much crude oil is sitting in the ground. The issues are the rate at which that oil can be recovered, and whether flow rates can accelerate to meet rapidly growing global demand.
The Final Frontier
Meeting the world’s 81.5 million bbl/d of demand is getting harder and more technically complex. The supergiant oilfields of decades past could be produced using relatively simple technology and equipment.
Drilling rigs designed to produce shallow onshore oilfields are simple and cheap to build. And rigs capable of drilling in waters of up to a few hundred feet deep have been in use for decades. Furthermore, giant fields like Saudi Arabia’s Ghawar could be produced efficiently and yield millions of barrels of oil per day using a few dozen simple vertical wells.
But those days are gone. Some of those vertical wells in Ghawar and other supergiant fields are now producing as much as 10 barrels of water for each barrel of oil recovered.
To slow decline rates in existing supergiant fields, producers are forced to drill more advanced wells such as wells drilled horizontally through prolific zones of a given field. Such wells require more advanced rigs and cost far more to drill than vertical wells.
And drillers need to perform detailed three-dimensional (3D) seismic mapping of existing fields to locate smaller potential oil and natural gas pockets bypassed during initial production operations; most of the world’s advanced seismic mapping capacity is held by a handful of firms.
In future, producers will also need to turn increasingly to reserves once thought technically impossible to produce or simply too expensive to yield economic barrels. The list includes deepwater fields, fields in Artic regions and so-called unconventional plays in the US and Canada.
Deepwater is a prime example of what I mean by “hard” oil. No producer would bother spending billions of dollars on a deepwater oil project if it could simply and easily ramp up production from existing oilfields. But deepwater is one of the final regions of the globe where there are large, untapped reserves of oil and gas to be exploited.
Most of the biggest oil and gas finds over the past few years have been in the deepwater. Chevron Corp’s (NYSE: CVX) successful test of its deepwater Jack field in the Gulf of Mexico in late 2006 and Petrobras’ (NYSE: PBR) more recent find of the deepwater Tupi field are just two prominent examples.
To make a long story short, according to Offshore Magazine and a recent survey published by energy analysts Douglas-Westwood, total global deepwater oil production will grow from 4.5 million bbl/d in 2007 to more than 8 million bbl/d in 2011. Over the same time period, deepwater gas production will nearly double from 1.6 million barrels of oil equivalent per day (boe/d) to some 3 million boe/d in 2011.
While deepwater will be one of the only regions of the world to see meaningful production growth in coming years, it’s also among the most complex and expensive to produce. A deepwater rig costs well in excess of USD1 billion to construct, and the process can take five years or more. In the current market, producers are paying upwards of USD600,000 per day to lease these rigs.
Far too many investors assume that the oil and gas industry is part of the so-called Old Economy. The truth is that the energy industry involves more complex cutting-edge technology than any other industry you can imagine. And if the world is to bring to market enough difficult-to-produce oil to meet rapidly growing global demand, the key will be new energy technologies.
How to Play It
It’s hard to imagine a company more synonymous with oilfield technology than services giant Schlumberger (NYSE: SLB). The term “services” is loosely defined and can refer to a large number of very different functions related to exploring, drilling and producing oil and gas fields.
For example, Schlumberger’s WesternGeco division is the world’s largest seismic mapping company. Seismic mapping involves the use of sound and pressure waves to create a picture of underground rock formations; by studying these formations, geologists can isolate and identify promising targets for their drilling work.
The earliest seismic surveys were fairly simple, offering two-dimensional (2D), black-and-white plots of rock formations. Although rough, these early surveys were a big improvement over prior techniques, such as simply looking for oil by surveying above-ground rock formations or looking for actual seeps of petroleum at the surface.
But simple 2D surveys became obsolete long ago. Seismic operators can feed data collected by a large array of sensitive seismic receivers into a computer system to create a highly detailed 3D image of what the subsurface geology looks like. And surveyors have even added a fourth dimension to seismic data; by performing seismic surveys periodically over time, operators can get a sort of time lapse photo of their fields, monitoring the changes as oil and gas is produced.
To add yet another level of complexity to these operations, consider exactly where operators are performing these surveys. The recently discovered Tupi oilfield is located on the edge of the Santos Basin, about 150 kilometers off the shore of Rio de Janeiro.
The company believes that Tupi could hold as much as 7 billion to 8 billion barrels of light crude oil; this would make the field a true supergiant and roughly double Brazil’s estimated 14 billion barrels in total oil and gas reserves.
But there are issues with Tupi. Chief among those, the field is located in waters ranging from 2,000 to 3,000 meters deep. (That’s 6,500 to 10,000 feet.) This makes Tupi an ultra-deepwater field, which requires the most advanced rigs that are capable of drilling in the deepest waters. But that’s only the beginning. The well Petrobras drilled to produce Tupi had a total vertical length of 20,000 feet and drilled through a tough-to-drill, mile-long layer of salt.
Seismic operators such as Schlumberger own fleets of seismic ships that can produce detailed maps and computer-enhanced images of subsea formations located two miles under the sea and a further two miles beneath the sea floor. With a Tupi oilwell costing well north of USD1 billion to drill, operators don’t want to place that well incorrectly, so detailed, high-resolution information is essential. That’s a quantum leap in technology from the 2D surveys of yesteryear.
Schlumberger’s Q-seismic technology is widely considered the most advanced in the world. Moreover, the company has one of the largest fleets of seismic ships in the world. WesternGeco will clearly be a huge player in the production of “hard” oil.
And that’s only one of Sclumberger’s operational divisions. The company is also a world leader in a long list of advanced services, including wireline logging, logging while drilling, production testing and directional drilling services.
Wireline logging is the process of placing specialized equipment into a well to evaluate the entire length of a given reservoir. Wireline logging offers producers good information about how productive a given field will be, whether that field contains oil or gas, what the quality of the oil is, and how best to drill the well. Obviously, wireline equipment, like seismic, has evolved by leaps and bounds in recent years, and only a handful of services providers are capable of handling the intense pressures and temperatures encountered in a field such as Tupi.
Directional drilling is another key service for producing tough and complex oilfields. Early wells were drilled vertically through a column of rock. But nowadays producers guide wells horizontally and vertically to produce certain key targets. Some wells look much like fish bones, with multiple smaller wells branching from a single main pipe. These wells are far tougher and more expensive to drill, particularly in difficult fields such as Tupi.
In addition to its breadth of service offerings, Schlumberger also benefits from its widespread geographic exposure. The company handles projects in the Middle East, Africa, South America, Russia and just about every imaginable oil- or gas-producing region of the world. Schlumberger operates in more than 100 countries, with a locally trained workforce in many locales.
Better still, Schlumberger’s business has little to do with the daily gyrations in the oil and natural gas markets. Most of the international oil projects Schlumberger handles were started based on oil prices around USD50; those multiyear, multibillion dollar deals are unlikely to be canceled or delayed barring an outright collapse in prices. Trading at its cheapest valuation in years, Schlumberger rates a buy under 100.
Paris-based Compagnie Generale de Geophysique-Veritas (NYSE: CGV, CGGV) rivals Schlumberger as the world’s largest provider of seismic services. The company owns a fleet of 20 advanced offshore seismic vessels capable of producing detailed images of deepwater reservoirs.
Like Schlumberger, CGGV performs two basic types of seismic survey, multi-client surveys and dedicated surveys. Multi-client surveys are maps of a wide area of deepwater acreage; CGGV sells this data to a wide variety of operators. Producers buy this data to aid in their decisions about which prospects to drill and/or how much to pay to lease a particular block. Once an operator decides to lease a certain block, it will often do a far more detailed seismic shoot; these data are produced for a single producer.
CGGV’s Sercel division develops and sells high-tech seismic equipment. Sercel has a truly huge R&D budget and has been increasing that budget sharply in recent years; recent innovations include a range of wireless seismic equipment.
Traditionally on a land-based seismic shoot, operators would place hundreds or thousands of devices on the surface above a given reservoir. The seismic operator then produces sounds and pressure waves using a specialized truck that literally vibrates the earth. These individual geophones intercept the waves as they bounce off underground rock formations. Data collected from these geophones are used to produce computer models of subsurface formations.
But this has traditionally been a complex process, as each of these geophones has been hard wired to a sort of network, creating a mass of wires, equipment and cables. The situation is not dissimilar to that mess of power and data cords sitting behind your desktop PC, except on a much grander scale. But Sercel has developed wireless equipment that allows these individual geophones to be placed and transmit data wirelessly. As you can imagine, this cuts down on the cost and time involved in producing a seismic shoot.
CGGV has been hit in recent months because of fears that a new wave of seismic ships due to enter the market in coming years would depress growth and margins. Those fears are overblown. Deepwater activity is truly exploding, so there’s plenty of demand to absorb the incremental supply. So far there’s little evidence that WesternGeco and CGGV are seeing any real growth constraints. Buy Compagnie Generale de Geophysique-Veritas under 40.
Back to the USA
Producing incremental volumes of oil involves more than simply finding and producing gigantic new fields in difficult-to-access and far-flung regions of the world.
There’s also a large number of so-called unconventional oil and natural gas plays around the world that were once thought uneconomic to produce. One example is the Bakken Shale oil play located in the US and parts of Canada.
Unconventional fields are nothing more than reservoirs that can’t be produced economically using traditional oilfield techniques. But the development and widespread acceptance of 3D seismic mapping, hydraulic fracturing and horizontal drilling enable unconventional production.
I explained 3D seismic and horizontal drilling earlier in this article. The final technological innovation to enable unconventional gas production is the development of hydraulic fracturing techniques. Most unconventional plays have plenty of oil or gas in place, but the reservoirs lack permeability. That means that there are pores and cracks within the reservoir rock that are holding gas or oil, but those pores aren’t well connected. Since the pores aren’t connected to one another, there’s no way for the gas to flow through the rock into a well.
Hydraulic fracturing involves pumping a liquid into the reservoir under tremendous pressure; this actually cracks the rock, creating cracks for the oil to flow through the formation and into a well. In short, fracturing improves the permeability of the field. Producers also introduce what’s known as proppant–typically sand, sand coated with resin or ceramic material–into the fracturing fluid. As the name suggests, the proppant actually enters the cracks caused by the fracturing and holds, or “props,” those cracks open. This prevents the newly formed cracks from closing as soon as pressure is removed.
To give you an idea of the scale of a fracturing, or “frac,” job, it’s not unusual for liquid to be pumped into a well at pressures of 8,000 pounds per square inch or more. A single, three-stage frac job can involve pumping more than 5 million gallons of fresh water into a particular field.
Fracturing also isn’t a new technique, however the technology and availability has improved greatly in just the past five to 10 years. Producers now routinely do multistage fracturing jobs and experiment with different techniques to determine which works best in a particular field.
Ignore the hypesters: Despite these technological advances, production from unconventional fields such as Bakken will never be enough to return the US to 10 million bbl/day or more of oil production. However, wells drilled in Bakken have proved among the most prolific wells drilled onshore in the US in the past three decades. Production from unconventional reserves can certainly help stem the rate of decline in US oil and gas production.
The Bakken Shale is located in North Dakota, Montana and across the Canadian border in Saskatchewan. The US side of the play offers thicker deposits of oil; the Bakken looks like a commercial play in Saskatchewan as well. Here’s a map of the US side of the Bakken from the US Geological Survey (USGS).
Source: US Geological Survey
The USGS recently updated and vastly revised upward its estimates of the total amount of oil and gas in the Bakken play. These estimates are “risked,” meaning that the USGS believes there’s a 95 percent chance of at least as much oil as they estimate being present. That also means that once producers start drilling the play more aggressively and collecting more data, it’s quite possible reserves will prove much higher.
On that basis, the USGS estimates 3.7 billion barrels of oil, 1.85 billion cubic feet (bcf) of gas and 148 million barrels of natural gas liquids (NGL). To give you an idea of scale, BP (NYSE: BP) estimates that the US has 29.4 billion barrels of proven oil reserves. If the USGS estimates are accurate, the Bakken would be one of the largest oil plays in the US. And some other estimates peg Bakken oil reserves at far higher levels. Some believe the play could contain north of 400 billion barrels.
But, as with any other reserve, what counts isn’t the amount of oil in the ground but how fast that oil can be produced. Don’t be fooled by hype that claims that the US can achieve full energy independence because of Bakken. It’s an impressive, high-potential play that will make investors a great deal of money in coming years, but it’s not a panacea.
Check out the graph of Montana’s and North Dakota’s combined oil production over the past several years.
Source: Energy Information Administration
Combined Montana and North Dakota oil production appeared to be in a state of terminal decline toward the end of the 1990s. But the development of the Bakken play over the past few years has totally altered the picture; these two states are now producing 218,000 bbl/d, surpassing the 1981 production peak. That production could surge more than 500,000 bbl/d over the next few years.
Granted, this level of oil production is small when you consider the US uses more than 20 million bbl/d. But it can certainly be significant for producers with quality acreage in the Bakken.
EOG Resources (NYSE: EOG) is one of the biggest players in the Bakken Shale and is investing heavily in the region. EOG has about 320,000 acres in the Bakken play, primarily in North Dakota. The company has a total of eight rigs operating, seven in the core fairway of the play–the most prolific known areas–and one prospecting some outlying areas. In total, EOG is looking to drill 80 wells this year and 100 in 2009.
In its second quarter conference call, EOG offered some more details on wells it’s drilling and what it sees for the play. The company mentioned one well drilled in the quarter that flowed at a peak rate of 3,744 bbl/d day. Again, this may not seem like a big number, but it’s truly huge for an onshore US well; most US oil production is from extremely mature wells with declining production. Consider that more than 80 percent of US oil wells are so-called stripper wells, meaning they produce less than 15 barrels of oil per day.
All told, the average EOG Bakken well drilled in the first half of 2008 produced at an initial production rate of 1,732 bbl/d. On average, each well offers about 850,000 barrels of reserves. These wells offered EOG a more than 100 percent return on its investment.
Most analysis of the Bakken you’ll read will discuss the Elm Coulee field in Montana as the core of the Bakken. But EOG’s stellar drilling results are in North Dakota’s Parshall field. EOG recently revised higher its reserves in this area from 50 million to 80 million barrels. It’s likely EOG will revise that estimate far higher in coming quarters as it accelerates drilling activity.
The company is also experimenting with downspacing wells–drilling wells more closely together–and drilling in some non-core regions. Early drilling results in non-core acreage suggests a highly economic play offering some 250,000 to 450,000 barrels of oil reserves per well drilled. The Bakken remains one of EOG’s most exciting fields and avenues of growth.
In addition to Bakken, EOG is a huge producer from other major North American fields such as the giant Barnett gas field in Texas and an emerging gas field in British Columbia, Canada.
And EOG is even taking the lessons its learning in the US and applying them abroad. EOG recently purchased a gas field located in China’s Sichuan Basin from ConocoPhillips (NYSE: COP). Prior operators had developed the field using simple vertical wells and basic fracturing techniques with only modest success. EOG is planning to apply horizontal drilling and fracturing techniques to enhance production.
EOG stock has been hit by falling commodity prices in recent weeks but remains among the most innovative unconventional producers in the world today. Buy EOG Resources under 105.
Producing unconventional fields also requires more advanced and powerful equipment. Nabors Industries (NYSE: NBR) is a contract driller that owns primarily land rigs that are leased out to producers in exchange for a daily fee known as a day-rate.
Drilling the relatively complex horizontal wells needed to produce in unconventional gas plays requires fairly sophisticated and powerful land rigs. Producers typically contract with Nabors to build fit-for-purpose rigs to handle their specific needs; these producers are paying high guaranteed day rates under locked-in, long-term contracts for these purpose-built rigs. Nabors has added 20 such rigs this year at highly attractive rates and expects to add even more.
And Nabors is also a major player in complex international oil and gas fields. The list includes supplying rigs capable of handling the extraordinarily harsh operating conditions in Russia’s Siberian expanses. One of Nabors largest projects to date is a deal it won in late 2007 to do work with services provider Weatherford International (NYSE: WFT) in Western Siberia for TNK-BP. Weatherford is providing some major services for the deal, while Nabors is supplying the drilling rigs necessary to conduct the project.
Nabors’ presence and history in Russia gives it an inside track on new deals. In addition, Nabors builds some of the most powerful land rigs in the world, including some that were built with harsh Alaskan weather in mind. This is exactly the sort of cutting-edge rig needed to handle Russian contracts. Overall, Nabors’ international business is expected to expand at a 40 to 50 percent annualized pace for the next few years.
The stock has been beaten down due to weakness in US natural gas prices and Nabors’ traditional reliance on North American gas drilling for growth. But international projects and the need to tap unconventional plays in the US are game-changing trends for Nabors. Trading at its cheapest valuation in years, Nabors Industries rates a buy under 35.