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

I recently had the opportunity to attend the SPE Annual Technical Conference and Exhibition (ATCE) in Florence, Italy (yes it was very nice). One of the highlights for me was a paper presented by Dr. Lee of Texas A&M University titled A Better Way To Forecast Production From Unconventional Gas Wells. The paper is SPE 134231 authored by Peter P. Valko and W. John Lee, both from Texas A&M University.

In this paper, and another paper authored by John Lee and Rod Sidle, Texas A&M (SPE 130102) a method for forecasting reserves using decline curves is presented. This method, termed “Stretched Exponential Decline” uses a different set of equations than most of us are used to using for forecasting these types of reserves. 

 Historically we have used equations developed by Arps in 1945 which describe three variations of the decline equations for exponential, hyperbolic and harmonic declines; the difference being the value of “b” the “decline exponent.” The general form of the equation is

 q= q_i/(1+bD_it) ^(1/b)

 Exponential decline (straight line on a semi-log graph) occurs when b=0. Hyperbolic decline occurs when b is between 0 and 1 and demonstrates a curved plot on a semi-log graph, like we have seen in shale gas wells during early time production; and harmonic decline occurs in the unique case when b=1.

 In practical experience, hyperbolic declines are often used to forecast tight reservoirs, such as shales, since the shape of the early-time production data can be matched using these equations; however, it is not uncommon for “matched” b factors to be well in excess of 1, which is outside of the parameters described by Arps.  The problem is when the b factor is 1 or greater the Arps equation will approach infinity; which is obviously not possible. In real life most evaluators deal with this problem by placing an arbitrary minimum limit on the production decline and forcing the forecast to an exponential decline late in the well’s life. This arbitrary minimum limit solves the problem of infinite reserves, but it is arbitrary and different evaluators may use different limits.

 Lee et al’s Stretched Exponential Decline takes a different approach. This approach is totally empirical and can be thought of as a sum of a series of individual exponential declines with differing decline rates. In other words, it’s like a given shale well is producing from multiple smaller volumes with each behaving exponentially (heterogeneity). The mathematics are a little more complicated, and definitely outside the scope of this blog, but supposedly Valko has developed software to handle the difficult parts (I have yet to see or use the software).

 The advantages of the Stretched Exponential Decline approach are many; including a bounded EUR (Estimated Ultimate Recovery) and a graphical straight line of recovery potential (rp) versus cumulative production. Experience with the Arps hyperbolic equation is that as more data become available over time for a given well the “matched” b factor is usually reduced from earlier matches suggesting early-time estimates of recoveries may be reduced over time (depending on how the “tail” was handled by the evaluator, as discussed earlier).

 Using decline curves to determine reserves is a very common and important methodology available to the evaluator. This is even more important in the shale-type resource plays where other traditional methods of determining reserves are limited by data availability and our understanding of the production mechanism, and is compounded by the need to determine expected reserves early in the life of a play for business decisions such as leasing and drilling. I don’t know if the Stretched Exponential Decline method will catch on and become the norm, I guess it will depend on the ease of use and whether the economic software providers support it, but I applaud the effort to understand the production mechanism and attempt to create a usable model for the evaluator.

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In a recent article Nissa Darbonne discusses some interesting issues surrounding the Oil and Gas industry in light of the well control events is the Gulf and Marcellus Shale.  These events, along with the publicity surrounding the large fracture stimulations being used in today's shale wells, will most likely lead to new regulations for drilling and completing wells in the US. 

What impact these new regulations will have on the industry and the profitability of some large development projects is yet to be seen.  We know offshore insurance rates will increase significantly for those who can find insurance, and many companies will be forced to self-insure or exit the Gulf.  This begs the question, how do you exit the Gulf in today's environment?  This is certainly not a seller's market for offshore assets.  So, if your company has offshore assets in the Gulf and you can't find affordable insurance, yet you can't afford to self-insure (assuming the government will allow self-insurance) and you can't find anyone willing to buy your assets for a reasonable price, what can you do?  This problem is only compounded by any offshore drilling moratoriums which could put into doubt future development programs, or at least their near-term timing. 

Regardless of these recent events and the public policy changes that may result, the country's energy needs are growing and will have to be met with an increased domestic supply of hydrocarbons.  So, despite the inevitable fact that the rules of the game will likely be changed, domestic oil and gas is not going away.  As Nissa Darbonne's article points out, this is another reason to diversify your portfolio. 

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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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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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In a recent article, Keith Schaefer asks the question whether there should be standardized rules for reporting IP (Initial Production) rates for newly drilled wells.  As Keith points out, currently there is no standardized methodology for these reported tests and some operators choose to report instantaneous rates while others report average rates over some period of time; however, even these average rates are not consistently reported (24 hrs, a week, a month, etc.).

This is even more critical when looking at horizontal wells drilled in tight formations, which are typically frac'd on completion-- shale plays.  These characteristics typically create linear flow near the well and expose a large amount of "virgin" reservoir, both of which give rise to high initial rates which rapidly drop-off before stabilizing at a lower rate.

The IP rate of a new well can impact the economics of the well because the greater the initial rate the more revenue the operator can use to repay the development costs, which directly impacts the ROR (rate of return).  The IP alone, however, has little impact on the well's ultimate reserves which is the key to the project's economics.

When determining the well's ultimate recovery, what happens after the IP is more important than the IP itself.  The initial decline rate of the well and the hyperbolic exponent (the rate at which the decline rate lessens) give character to the production curve and ultimately determine the well's reserves.

When I read a press release which includes IPs it's usually with a great deal of skepticism.  The only thing you can tell for sure from an IP test is that the well isn't dry.  Only after several wells have been on production in a given area and a "type curve"  established, can the IP rate be used to approximate reserves.

There are several stories in the oil patch about the company who drills a well and based on it's IP, constructs a flowline, production facilities, and stakes several more offset wells (no doubt booking them as PUDs) only to have the well fizzle when put on production.  As bad as it would be to be the engineer on a project like this, it would be worse for the investor.

So, as Keith says, when it comes to reported IPs Caveat Emptor.

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Volumes of oil and gas that have been discovered, but yet to be produced are referred to as reserves*.  One barrel in the ground is not necessary equal in value to another.  In an earlier entry I discussed the hazards of using simple yardsticks such as $ per barrel in the ground as a means of valuing an asset, and this is why. 

Risk is the main differentiating factor between the types of reserve categories and their associated values.  SPE (Society of Petroleum Engineers) categorizes reserves as follows:

• Proved
• Probable
• Possible
• Contingent Resources (not actually a reserve category since a contingent resource doesn't meet the criteria of a reserve)

The above list is in order of increasing risk, or decreasing chance of occurrence.  Since the value of an asset is a function of it's projected future cash flow, the lower the chance of occurrence (actual production) the less valuable the barrel.  So this list is also in order of decreasing value to the investor.

Proved reserves are considered to have reasonable certainty or a high degree of confidence of being recovered.  Often this is determined by a 90% probability of occurrence (P90).  Probable reserves are less certain than Proved, and Possible are even less than Probable. Probable reserves are often referred to in combination with Proved reserves as Proved + Probable (or 2P), and typically represent a 50% probability of occurrence (2P=P50).  In other words, we have an equal chance of recovering more, or less, barrels than our Proved plus Probable reserves.  Possible reserves when added to the Proved + Probable reserves make up what is referred to as 3P reserves, and these represent only a 10% probability of occurrence (P10).  So you can understand the investor's attraction to Proved reserves, and to a lesser extent Probable reserves, and often skepticism of Possible reserves.

When evaluating an asset we break these categories down further into their stages of development..  The Proved category is broken down into:

• Proved Developed Producing (PDP)
• Proved Developed Non-Producing (PDNP)
• Proved Un-Developed (PUD)

This list is again in order of increasing risk and decreasing value to the investor.  While all three of these categories are Proved reserves, and therefore have a high degree of confidence, there is increasing risk of occurrence and decreasing value simply due to their degree of development.  PDP reserves are already developed and are currently being produced, while PDNP reserves have had most of the capital necessary to develop spent, but are not currently producing and may require some additional capital to get producing, or may be waiting for a future event to occur before they can be produced.  The PUD category typically represents future drill wells where significant capital must be spent to recover these reserves which makes them less valuable compared to reserves that have already been developed.

The degree to which an investor is willing to pay for these different reserve categories varies widely and is determined by the risk tolerance of the individual investor.  It is very important for any investor to understand the risks associated with the reserves they are buying and to rely on an experienced and trusted evaluator to determine the associated risks.

* This of course is an over simplification and not all hydrocarbons in the ground meet the criteria to be called "Reserves."  For a more detailed discussion please refer to the SPE PMRS definitions.  Natural gas is often referred to in terms of barrels of oil equivalent, BOE, and the conversion is 6 MCF of gas = 1 BOE

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"The evaluation of oil and gas properties is a calculation which involves many variables. The interrelationship between the variables is too complex to be described by a simple formula."  Dr. William M. Cobb, P.E.  President William M. Cobb & Associates

I recently read a blog post that suggested oil companies actually trade oil and gas assets based on simple yardsticks such as $ per barrel of daily production, or $ per barrel of oil in the ground, and the implication was that this is an accepted way of doing business.

This is one of many misconceptions about the oil business and one hopefully I can help clear up.These single formula yardsticks are useful for screening purposes and getting a general idea of the size of a deal, and perhaps in comparing large company stock prices, but certainly not appropriate for buying and selling assets.

When putting a price tag on an oil and gas asset its all about Cash Flow, and timing.  Cash flow itself is a function of many variables:

• Production Rate and Reserves
• Product Prices
• Operating Costs
• Capital Investments
• Taxes
• Royalties
• Overhead
• Ownership

Once all of these variables are carefully evaluated the cash flow must be adjusted for the time value of money and risk to arrive at an appropriate value for a specific asset. There are a lot of moving parts and plenty of potential pitfalls to avoid, and every property has it's own unique characteristics.

An offshore asset may be worth only $20,000 per barrel of daily production while a property in West Texas could fetch $90,000 per barrel or much more. This is due to several factors:  Offshore properties typically produce at very high rates for a short period of time, so while they generate a lot of cash flow it doesn't usually last long.

Also, the cost of producing a barrel offshore can be quite different than in West Texas. Then there is the undeveloped potential of the properties that need to be considered, and the cost of abandoning the wells and facilities once production has ceased.  When comparing the value of assets on a $ per barrel in the ground basis, it's important to know how much investment is required to recover those barrels and sometimes that investment in itself isn't palatable to the investor.

So you can see Dr. Cobb's point-- each of these variables needs to be carefully evaluated when determining an asset's value to the investor, and using a single formula yardstick may get you close, but being close is only good enough in horseshoes and hand grenades.

In future posts I will discuss the various classifications of oil and gas reserves and why these different classes are handled differently when determining the value of an oil and gas property.

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