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

I drilled my first Bakken horizontal well back in 1990.  We had so many problems with well bore integrity we gave up after drilling only a handful of wells.  In fact, we were getting cuttings the size of hockey pucks at the shale shaker.  Fast forward twenty years and the Bakken is the most successful horizontal oil play in the world.  We knew there was oil and gas in that shale we just didn't have the technology to get it out. 

Bakken economics compare favorably to other horizontal plays. The table below compiled by Stephen Berrman from Pritchard Capital Partners, LLC illustrates this fact.  Notice the Haynesville play has a higher Gross EUR (Estimated Ultimate Reserves) but the F&D (Finding and Development) cost is higher.  At a 10:1 (gas to oil) conversion the advantage of an oil shale play is seen in F&D costs that are almost half of the Barnett and Haynesville. 

 Mr. Berman also reveals in the next table that lower F&D costs are a result of operational advancements.   Well costs have nearly doubled since 2006 yet EUR has increased 5.5 times.  This is typical of a shale play as the operators start to figure out the play.  In this instance, it's both hydraulic fracture technology and using super extended laterals that account for increase in EURs.

Rising acreages costs are a direct result of the lowering of F&D costs.  Below you can see that from January 2008 costs were below $1000 per acre.  Late 2009 saw over a 6-fold increase of acreage costs exceeding $6.000 per acre.  As the economics of the play improve, the operators can afford to pay more for acreage.

The above tables and graphs provide an excellent example of how the economics change as operators climb the learning curve of a shale play.  Not all plays are as dramatic as the Bakken, but with perseverance and a smart technical team these types of results can be expected.  It took close to 15 years to figure out the Bakken using horizontal technology.  I wish I knew then what I know now.

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These are scary times.  We all know about the tragic accident that occurred April 20th at Mississippi Canyon 252.  Transocean's Deepwater Horizon drilling rig contracted to BP experienced a blowout resulting in an explosion that killed 11 workers and began spilling an estimated 5,000 bbl per day into the Gulf of Mexico.  This incident was indeed a tragedy for the families of the 11 who died, the residents along the Gulf affected by the spill, the companies involved and their investors, and now potentially for the future of offshore production and the country's energy security.

The Gulf of Mexico is a significant source of oil and gas for the US.  In a recent blog, Stephen O'Brien points out the historical importance of the Gulf to total US domestic production.  As can be seen in the production plots of domestic onshore and offshore oil taken from his article, onshore oil production has declined significantly from its peak in the mid 1980's and appears to be leveling off around 100,000,000 bbl per day; despite the run up in oil prices over the past decade, indicating the maturity of this supply.

On the other hand, the plot of offshore oil shows growth, significant growth, over the past decade due to both higher prices and technological advancements that have allowed deep water exploration and production; this is indicative of a less mature source which has future potential for expansion.  If we are serious in this country about trying to be less dependent on foreign oil, we need sources that can be exploited to grow supply.

Meanwhile the government is debating increasing the liability limits for offshore operations in light of the pending environmental disaster and subsequent impact to the economies of the region.  In recent statements released by Alliant Insurance and Lloyd Partners Insurance it is apparent that if these liability levels are increased as currently proposed, sufficient insurance will not be available for offshore exploration and development projects and the insurance that is available will be very expensive. 

This will no doubt signal the end of the smaller domestic offshore producer leaving only those companies who can afford to self insure a significant portion of their exposure.  This leaves the large international corporations (Exxon, BP, Shell, etc) and foreign national oil companies (NOCs).  So much for less reliance on foreign oil, now supplies that are currently "domestic supplies" could be predominately controlled by foreign countries (like China).

 For an update of BP's efforts to control the flow from the damaged well watch this video.

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It's amazing to me how many people think that oil and gas exists in large caverns or pools in the subsurface.  On the contrary, hydrocarbons exist in rock or more specifically the pore space within the rock. This rock a can be any type of rock as long as this rock possesses porosity.  Porosity is defined as the fraction of the void space in a material.  There are many types of porosity (primary, secondary, fracture, vuggy, etc.)  Porosity varies from 0% to 50% depending on the amount of alteration both physical and chemical the rock had been subject to.   Typically, porosity values for the Gulf Coast both onshore and offshore range between 10% to 30% while interior basins in the U.S. have much lower porosity values of 5% to 15%.  Many shales have high porosity values reaching 20% to 30%.  The problem with shale (and coal) is the lack of interconnectivity between these very small pore spaces or the lack of effective porosity.   Effective porosity are pore spaces that are connected to one another.

This interconnectivity is referred to as permeability. Take for example a Styrofoam cup.  Styrofoam is very porous (which gives it excellent insulating properties) yet it has no permeability because your drink does lot leak out of it.  Permeability is a measure of a porous material (i.e. rock) to transmit fluid.  Without permeability you can't get oil or gas in or out of the rock.  Typically, as porosity increases permeability increases and vice versa.  Although there are exceptions, both porosity and permeability generally decrease with depth. 

So how does a shale produce oil and gas to a wellbore if low permeability exists?  Or to state it another way.  How do we increase the effective porosity of a shale?  This is where technology steps in.  With the development of hydraulic fracturing, permeability can be produced in a rock that has very little naturally occurring permeability.  It's this man-made increase in deliverability of hydrocarbons to the wellbore that makes an economic or an uneconomic well.

The important thing to remember is you must have both porosity and permeability to have a producible reservoir.   Porosity is static.  Permeability can be enhanced

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With the failure of BP's recent attempt to control the blowout being attributed to the formation of gas hydrates, I thought it might be helpful to discuss hydrates in general.  A gas hydrate is a crystalline structure that forms in cold temperatures under high pressure.  The crystal is formed with water molecules surrounding a hydrocarbon molecule and resembles ice...ice that will burn.

Hydrate formation is something the oil and gas industry has been fighting for some time.  These crystals are an unwanted obstacle to production and they can form whenever the conditions are right (composition, temperature and pressure).  The offshore environment, especially deep water, is particularly susceptible to the formation of hydrates both in producing wells and in underwater pipelines.

The usual treatment for dealing with hydrates is first to attempt to design around them (try to keep the product from entering the hydrate formation envelope) but if that doesn't work, to treat with chemicals that will "melt" the crystals-- usually methanol.  And in fact I read where BP is considering a "top hat" device that will allow for methanol treating to melt the hydrates.

Here is a link to a Texas A&M article on hydrates which has more information and discusses naturally occurring hydrates as a potential future energy source.

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I was recently asked the question "what's in a BOE?"  At first this seems like a fairly straight forward question-- a BOE is a barrel of oil equivalent.  So exactly what is a barrel of oil equivalent to?  Most oil and gas evaluators would tell you a barrel of oil equivalent is equal to one (1) barrel of crude oil or six thousand cubic feet (6 MCF) of natural gas, and If you press further they will tell you this is based on the equivalent heating value of oil and gas. 

According to the DOE one barrel of crude oil has the heating capacity of approximately 5,800,000 BTU, and one standard cubic foot of gas contains about 1,028 BTU.  If you do the math you'll see this means it takes 5.642 MCF of natural gas to equal a barrel of crude oil.  This may not seem too far off since 5.642 rounds up to 6, but it represents a 6.3% discrepancy which could be significant when dealing with millions of barrels.  The definitions section of the Petroleum Resource Management System (PRMS), which forms the basis for the new SEC reserve reporting guidelines, recognizes the conversion factor commonly used ranges from 5.6 to 6.  In fact a quick search around the internet found BOE conversions ranging from 5.487 to 6, this represents a 9.3% variation!

But why are we concerned about BTU equivalence anyway?  Oil and gas haven't traded anywhere near 5.5 or 6 to 1 for years.  In a perfect world maybe we would buy our fuel based on its underlying utility, after all that's why we are buying it, and we might even buy our food on the same basis, it's a type of fuel too.  I did a little research (very little) and put together the following table showing the relative cost for various items based on their BTU value.

Two things jump out at me from this table:  First, we don't buy and sell things simply based on their heating value, and second, oil and gas are a pretty good deal.  This comparison isn't really fair since potatoes don't compete with natural gas for fueling a power plant, at least not yet, and I don't know anyone who willingly eats oil.  There are a number of factors that go into the relative 'value' of oil and gas including supply and demand, and the versatility of the products as both a fuel and a feedstock. 

Currently oil is trading around $80 per barrel and natural gas is around $4 per MCF, this represents a "value conversion factor" of 20 MCF per BOE.  This is higher than it's been in a while reflecting the "depressed" gas market and recovering oil market.  The simple fact that the oil and gas markets do not track each other very well gives rise to this ever changing value conversion factor, and this is no doubt why companies have resorted to the more stable BTU conversion methodology, even though there is a fairly wide range of BTU conversion factors being used.

So when buying and selling oil and gas assets we need to be very careful not to just rely on the total reserves reported in BOE.  We need to understand that an oil BOE is more valuable than a gas BOE in today's market, and be sure we are not comparing apples to oranges-- which by the way have an amazingly similar value per BTU ($2100/MMBTU for the apple, and $2200/MMBTU for the orange).

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