Oil and Gas Evaluation Report : Oil & Gas Evaluation Professionals : Obsidian Energy Company : · Seismic Interpretation, Petroleum Engineering

When using a small dataset of wells in a shale play to predict U.S. resource gas supply, estimates can vary widely.   The U.S. Energy Information Administration (EIA) estimated in 2008 that the U.S. shale gas supply was 32.8 Trillion cubic feet (Tcf).  This is up 34% from 21.7 Tcf in 2007.  It is safe to say that 2009 and 2010 will see similar if not more explosive growth.  With this tremendous increase in resource comes increases uncertainty of that resource estimate.  Richard Nehring in the AAPG Explorer article by David Brown, "Uncertainty Clouds Gas Resource Estimates" suggests there are several risks about estimating reserves of these shale plays:

1. Shale production is new and not yet fully understood.   This point he refers to the uncertainty of the decline curve on an individual well.  He points out that because the shale plays are so new that the long term reserve number of an individual well and thus the total resource is still unknown.  An example he uses is the Marcellus Shale where the high resource estimate is 5X the low estimate.
2. Effects of economics on shale plays.  We all know that economics changes with time.  But we don't know how production of these shale plays will react to price variations.  With any downward movement in price the estimate should decrease.   On the other hand as price goes up will the shale plays in the Rockies and Alaska add to the resource estimates we see now?  Nehring states "We don't know a lot and we're not learning a lot about the higher-cost resource, because people are ignoring it."  It is a safe bet that as price increases more attention will be paid to these overlooked plays. 
3. Poor prediction of past estimates.   Much of the range in supply estimates stem from the wide range of methodologies used in determining these estimates.  A baseline approach used by the Potential Gas Committee (PGC) estimates a total natural gas resource base of 1,836 trillion cubic feet (Tcf).  The highest resource estimate in the Committee's 44 year history.  This assessment does not "assume a time schedule nor a specific market price for discovery or production of future gas supply".  The EIA estimate in the opening paragraph is a proven resource base confined by SEC rules and economic viability of the supply.

The resource estimates that we see are what they are, estimates.  As all shale plays mature, these resource assessments will be revised upwards and downwards.  If natural gas is to be a significant part of electrical generation and transportation in the future, a domestic resource that can meet these needs 30 to 50 years out is mandatory.  There's a lot riding on these projections.

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I recently had the privilege to attend a couple of presentations at the local ADAM (Acquisitions, Divestitures And Mergers) meeting concerning the future world energy demand and I thought I'd share a few observations.  The presentations I attended were given by Scott Nauman with ExxonMobil (April 1) and Dr. Economides from the University of Houston (March 4).

In Mr. Nauman's presentation he discussed ExxonMobil's long term global energy outlook where it is estimated global energy demand will increase 35% above 2005 levels by 2030 (this represents an annual growth rate of 1.2%).  The major driver of this increase will be in the form of fuel for electricity generation.

This increase in world energy demand is expected to be lead by the non-OECD (Organization for Economic Co-operation and Development) countries (India and China, mainly) with demand in OECD countries (US and Europe, etc) actually slightly lower than in 2005 due to increases in efficiencies.

By 2030 it is estimated that 65% of the world energy demand will be from non-OECD countries.  Today 1.5 billion (25% of the world's population) do not have electricity and a whopping 2.5 billion (over 40%) do not have access to modern cooking and heating fuels and must rely on burning wood, dung and other biomass.  There is a very strong correlation between economic prosperity and energy consumption as can be seen in Dr. Economides' graphic.

Several types of fuel can be used to generate electricity and in Mr. Nauman's presentation he showed a very interesting graphic depicting the costs of generating electricity with different fuels.  These graphics show coal is the clear winner for low cost electricity (followed closely by natural gas), but when the potential costs of CO2 are added to the equation other fuels begin to compete (nuclear, wind) and eventually overtake coal.  Natural gas, however, remains competitive with or without CO2 costs.  So if you're looking to build an electricity generation plant I would think you would look real hard at natural gas as your fuel of choice, and given the expected increase in electricity demand, this should bode well for the long term future of natural gas.

Transportation fuel choices are currently much more limited than those for electricity generation.  Globally 98% of transportation fuel is oil based.  Currently light duty vehicles (cars, SUVs, etc) account for the majority of energy used for transportation.  In the US 80% of the population own cars.  In Europe the number is less (about 50%), and in China the number is less than 3%. 

As economic prosperity grows in the non-OECD countries it is expected that the number of vehicles will also grow.  ExxonMobil's forecast is for a modest increase in vehicle ownership to only 8% of China's population by 2030, but that is still a very large number of cars and represents significant increase in transportation fuel demand.  It is interesting to note that the ExxonMobil model forecasts personal transportation fuel requirements in the OECD countries will drop 25% due to increased efficiency, while the non-OECD demand is expected to more than double.

Currently vehicle fuel is primarily gasoline and diesel with hybrids making up less than 1%.  ExxonMobil expects this to continue to be the case with hybrids (and other advanced fuels) market share increasing to 15% by 2030. 

So what does all this mean?  The long term outlook for energy demand is strong.  The world is currently struggling its way out of a recession and oil is holding its own around $80/bbl, with the prospect of strong demand increases in the future.  Currently natural gas is struggling in the low $4 range and there is a lot of hand-wringing about its future.  Certainly $4 gas is not attractive to those looking at multimillion dollar horizontal wells in shale plays, but unless there is some new fuel on the horizon that can compete with natural gas for electricity generation, the future for natural gas is also bright-- albeit a little scary in the short term.

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Apache's acquisition of Mariner is proof that much value exists in the deepwater Gulf of Mexico (GOM).  The deepwater (water depths greater than 1,000 feet) GOM is the playground of the "big boys".  The costs of exploration and development in the deep water GOM are immense.   This acquisition allows Apache to develop Mariners existing deepwater acreage position faster.   Although Mariners expertise in the GOM is important, Apache's brings to the table experience in offshore projects in Egypt, Nile Delta and Australia.  With resource plays driving most company's budgets these days, Apache steadily builds its asset base in the Gulf.  Look for more consolidation in the GOM and for Apache's 2.7 billion dollar flag to multiply.

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Enhanced Oil Recovery (EOR) has been getting a lot of attention lately in the media. There have been some who claim EOR will save the world from the pending Peak Oil anarchy and others who claim EOR, through carbon sequestration, will save the planet from the devastating effects of Global Warming. The purpose of this article is to give some basic insights into EOR, its benefits and limitations, and not to enter into the geopolitical debates.

In an earlier article I discussed water flooding and explained how a solution gas drive reservoir can benefit from water injection. In that discussion I mentioned through water flooding the oil recovery could reach as high as 40% of the Original Oil In Place (OOIP). Water flooding is commonly referred to as "secondary recovery" and despite this increase in oil recovered through secondary, there remains significant oil to be recovered through EOR, or "tertiary recovery." The additional oil recoverable through EOR varies widely, but an additional 10-25% OOIP is not uncommon.

There are several reasons that significant amounts of oil are left unrecovered in the reservoir even after large volumes of water may have been pumped through.  All of these various causes are basically due to the properties of the oil itself and the fact that the oil is contained within the small pore spaces of a rock.   

Oil is viscous, and some oils are extremely viscous and hard to displace.  Oil and water don't mix on their own and this causes interfacial tension (drops of oil in water) which can be difficult to push through small pores, and in some cases the oil sticks directly to the rock itself (like when your old VW drips on the driveway, no matter how hard to try to hose it off you can't get it all).  And, rocks themselves are not uniform and may contain streaks of high permeability which may allow displacing fluids to by-pass the oil.  EOR processes have been designed to address these issues.

There are basically three categories of EOR: Chemical flooding, miscible displacement and thermal. Currently, according to the DOE, thermal accounts for more than 50% of the tertiary oil being produced in the US due in part to its wide use in the heavy oil fields of California, while miscible displacement makes up about 50% and chemical flooding is less than 1% (these are government numbers so we shouldn't neccessarily expect them to add up).

Thermal includes both steam flooding and fire flooding. The basic concept is to heat up the oil in the reservoir to lower its viscosity and allow the oil to flow more easily through the reservoir. In steam flooding, steam is injected through dedicated injection wells into the reservoir and the heated oil is displaced to a producing well just like a water flood (after all the steam becomes hot water once it cools a little). Fire flooding is a little different-- in this case oxygen is injected into the reservoir and ignited, burning some of the hydrocarbons and producing CO2 and water vapor (steam), and of course, heat. Thermal recovery processes are most beneficial in heavy oil (high viscosity) reservoirs.

Miscible displacement involves the injection of a substance that mixes with the oil in the reservoir to form a homogeneous mixture. The most widely injected substance in miscible flooding (and the one getting the most publicity) is CO2, but nitrogen and hydrocarbon gas are also being used. The basic concept is the mixing of the injected fluid with the oil alters the physical properties of the oil-- reduces its viscosity, lowers its surface tension and causes the oil to "swell." All of these things allow the oil to move more easily through the reservoir towards the producer.

Unfortunately, the injected fluid is much lighter and less viscous than the reservoir oil. This causes the injected fluid to want to "over run" and "finger" through the oil thus reducing the ability of the fluid to displace the oil in front of it. This problem has been addressed by alternating between injecting a slug of gas and a slug of water, followed by another slug of gas, and so on. This process is called WAG (water alternating gas) and has been very effective at controlling the gas in the reservoir.

Since the injected gas is mixed with the oil, it will inevitably be produced along with the oil. This is the limiting factor in relying on CO2 injection EOR for carbon sequestration. While some of the CO2 will remain in the reservoir and perhaps the reservoir could be filled with CO2 at the end of the flood's life, during the flood process CO2 is constantly being cycled through the reservoir and produced with the oil.

The third category of EOR is chemical flooding. Chemical flooding includes the injection of alkaline and polymers. Alkaline (soap) is used to remove the oil from the reservoir rock so that it can be displaced by the water flood, and polymers are used to "thicken" the water (increase its viscosity) so the water can better "sweep" the oil without fingering through (much as the WAG process is used in a CO2 flood). Also included in this category is the use of microbes. Microbes are either injected from an outside source or in situ microbes are fed and cultivated in the reservoir. The microbes are used to produce natural detergents and CO2 within the reservoir while building biomass within the pore spaces of the reservoir forcing the oil out.

Chemical flooding currently makes up a small portion of domestic EOR production, but there have been advances and more acceptance recently, especially in remote areas where miscible gases are not readily available or the size of the reservoir doesn't justify the investment required for other EOR methods.

EOR is a very important part of the life on an oil field; however, not every reservoir is a candidate for EOR for a variety of reasons, the most significant of which is economics. These processes are not inexpensive and typically require significant up-front capital investment. However, with the increasing trend in oil prices and the growing worldwide demand for oil, more and more oil fields will become viable candidates for EOR.  As a wise man once said "The best place to find oil is in an oil field."

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