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

When it comes to developing the Spraberry field in West Texas, Pioneer continues to rewrite the book. In the past we have discussed the Spraberry field and how the addition of the Wolfcamp lead to the “Wolfberry” play. Now it appears the Strawn formation is being added below the Wolfcamp and the results are encouraging…thus the “Strawberry” is born.

Pioneer plans to drill 440 wells in their Spraberry/Wolfberry/Strawberry play in 2010. This is up significantly from their earlier estimate of 125 well. Of the wells remaining to be drilled in 2010, approximately 40% will be drilled down to the Strawn. Pioneer reports wells that have included the Strawn with the Spraberry and Wolfcamp have seen an increase of 20-30% in their IP rates above the average of 60 barrels of oil equivalent per day (BOEPD).

This increase in IP is significant because it allows for the faster recoupment of the investment, which increases the rate of return of the project. I have not seen any numbers reflecting the increased reserves associated with adding the Strawn, so I cannot comment on the affect the Strawn will have on the overall finding costs. Let’s hope the Strawn’s reserves can support the additional costs associated with drilling deeper and adding stages to the frac job.

The Spraberry, and Wolfberry, and no doubt Strawberry plays have always been very sensitive to developments costs. Pioneer has addressed this aspect by not only the sheer volume of development activity, but by also providing their own services. They currently plan on providing 30-60% of their own services internally by 2012. Pioneer is increasing the company-owned frac fleet from one to four, and the number of company-owned drilling rigs from six to twelve.

The results speak for themselves. Pioneer reports an average gross investment of only $1 million for the wells drilled in the first half of 2010 and an associated rate of return of 50% (BFIT). How much of these results include the Strawn is unknown, but if they can consistently increase their IP by 20-30% and continue to hold development costs down, the Strawberry Fields may continue for some time—but forever?
 

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Let me begin by first explaining that I am not an attorney, nor am I a landman. I have been involved with several unitizations and poolings, and I have relied heavily on the advice of attorneys and landmen during these procedures. The purpose of this entry is to give an overview of unitizations and poolings, their purpose, pros and cons, and things to consider should you find yourself faced with either.

Basically, the purpose of both unitizations and poolings is to combine individual leases into a single entity for the purpose of development. Pooling is usually associated with drilling a well when the individual lease size is smaller than the required statutory well spacing. For example, if there are several contiguous 10 acre leases and an operator wants to drill a well which requires 40 acres, then the operator will pool four of the smaller leases together to form a 40 acre pool on which to drill. The purpose is to prevent waste since drilling a well on a lease smaller than the expected drainage area would require each adjacent lease owner to drill a competing well to prevent drainage—in this example four wells would need to be drilled instead of one.

In pooling, as described above, the resulting “pool” is not intended to represent the entire reservoir (sometimes a reservoir is unfortunately called a pool). This is where unitization differs from pooling. Typically the purpose of unitization is to combine all the leases in a given reservoir or field for the purpose of enhancing the field’s recovery. This is usually necessary in the cases where a flood (waterflood, steamflood, CO2 flood, etc) will be pushing oil and gas around and may cause hydrocarbons to cross lease lines. It is much more efficient to design and operate a flood without having to worry about keeping lease A’s fluids from crossing over to lease B.

In both cases the most important thing is for everyone to get their fair share of the resulting production. In the case of pooling this is commonly done based on acres contributed—if your 10 acres are pooled into a 40 acre pool, then you get 25% of the pool. This is usually the case because the leases are small and the producing formation probably doesn’t vary much between the leases, and if there hasn’t been any drilling yet there usually isn’t much data available to argue about. This is not always the case however, and you can imagine if your lease is sitting on top of a structure and you are being pooled with down-dip leases you may feel you are entitled to a bigger portion.

Unitizations are usually much more complicated. This is because they are typically much larger, involve several wells, often with different operators, and since they are usually in preparation to flood a reservoir there is much more data available to argue about. Also, when converting a field from primary lease-based production to a unitized enhanced recovery flood often some producing wells will be converted to injection and the associated loss in production will take time to recoup. This means the cash flow being generated will be reduced at the same time capital investments are required to install the flood; which usually increases the anxiety in the room.

Several different parameters are typically used to determine each lease’s equitable share in a unitization. Since the primary purpose is to recover remaining hydrocarbons, the original hydrocarbon pore volume and remaining recoverable hydrocarbons per tract are usually very important parameters, as are the current production rates, usable wells, and sometimes acres and cumulative production are used. The goal is to get all the parties (operators and mineral owners) to agree on one formula that divides up the future production and share of the costs (for the working interests). Usually a lot of negotiating is required and sometimes very creative unitization formulas are the result.

Both pooling and unitizations have their purpose in developing an oil and gas reservoir and both have been used for years as a means to prevent waste and increase recovery. As with most everything there have been abuses and inequities in the past and there will no doubt be more in the future. The most important thing to remember is to be sure to understand what is going on, what your lease allows and what options you have available to you, because these things will be very important to you when you’re sitting in a conference room negotiating for your piece of the pie.
 

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I used to give a talk on reserve determination methodology to the "non-technical" staff at a previous employer.  Below is a summary of that talk.

First, let's make sure we are all on the same page.  Oil and gas is made up of hydrocarbon molecules of differing size.  The size of the molecule is determined by the length of the carbon chain.  The greater the length of the carbon chain the greater the size, weight and energy contained within the molecule.  Methane (CH4), for example, is the smallest of the hydrocarbons with only one carbon atom.  Methane is the lightest of the hydrocarbons and the main component of natural gas.  Octane is another molecule that most of us have heard of and it has a carbon chain consisting of 8 carbon atoms.  Octane is heavier than methane, contains more energy and is typically a liquid.

Petroleum in its natural state, that is when it's in its underground reservoir, usually consists of a complex mixture of hydrocarbon molecules.  The composition of this mixture combined with the reservoir's temperature and pressure determine whether the petroleum will be in a liquid or gas phase in the reservoir (it is possible to have a solid in some special circumstances). 

A petroleum reservoir is not a pool of oil floating in an underground cave.  The reservoir consists of "solid" rock; well nearly solid.  A reservoir rock has porosity (small holes within the rock that are usually not visible with the naked eye) and the hydrocarbons are contained within these pores in the rock.  There are three substances found in reservoirs (not including the rock itself): Oil (liquid hydrocarbons), gas (gaseous hydrocarbons), and water.  Hydrocarbons are lighter than water, so they tend to "float" and rise to the top of the reservoir.  Gas is lighter than oil, so it wants to be on the top of the hydrocarbon mixture. 

For a petroleum reservoir to exist it must have a means of trapping the hydrocarbons from floating away and forcing them to stay within the confines of the reservoir.  Since hydrocarbons were generated millions of years ago, these traps that make up today's reservoirs have to be pretty good barriers to fluid migration.

Okay, so now that we are on the same page we can discuss how we can determine the size of a hydrocarbon accumulation contained within a reservoir.  There are basically three different methodologies commonly used to determine the volume of oil and gas in reservoirs.  These methodologies are used both independently and in combination.  The selection of the appropriate method is determined by the characteristics of the specific reservoir, the judgment and experience of the evaluator, and the data available.

The first and most common methodology is the use of decline curves.  Decline curves are used when a reservoir has been on production for some time and has demonstrated an observable trend (decline) in production rates.  The technique is to construct a graph of production rate versus time on a semi-log scale (where production rate is on the log scale and time is on the normal scale) and then forecast the observed trend (decline) forward in time. 

The art is in the forecasting of the decline.  Some reservoirs exhibit a straight line (exponential decline) while others follow a curve with a lessening slope over time (hyperbolic or harmonic decline).  Obviously the selection of the appropriate decline shape makes a big difference in the production forecast and thus the reservoir's reserves.  The basic assumption in using a decline curve to forecast reserves is that the historical conditions that existed when the decline was observed will continue throughout the forecast. 

Decline curves are the most commonly used method for determining PDP reserves because they can be constructed and forecast quickly, but this also occasionally results in their inappropriate use.  Care must be taken to determine when it is appropriate to use a decline curve and when an additional or alternative method is required.

The second most common method of calculating reserves is to volumetrically determine the size of the reservoir.  This method is called "volumetrics" and requires some knowledge of the shape and size of the reservoir including its areal extent, thickness, porosity (percent of rock that is pore space) and relative saturations of oil, gas and water.  This may sound easier than it actually is.  Usually an experienced geoscientist is required to construct structure and "net pay" (the portion of the rock that contains hydrocarbons) maps of the reservoir and this in itself is subject to interpretation. 

Given this geological information, and using basic geometry, the volume of the reservoir and its hydrocarbons can be calculated.  This methodology results in the volume of hydrocarbons in place (OIP and GIP), but a separate determination must be made about how much of the hydrocarbons can be recovered (recovery efficiency). 

Often volumetrics are used to determine the reserves associated with development or exploration projects (PDNP, PUD, Probable and Possible).  This is because there usually hasn't been any production from the reservoir (the well hasn't been drilled yet) so the other methodologies, which rely on historical production data, can not be used.  This gives rise to the common perception that volumetrics are less accurate than the other methodologies.  This perception is not necessarily true, it's the project itself that has a greater degree of uncertainty.

The third methodology is more complicated and less intuitive to many.  This method is referred to as "material balance" and is based on the concept of mass balance.  Simply put, the mass of anything in a container is equal to the mass originally in the container, less what's been taken out, plus what's been added in.  Another way to think about it is if you have a large container of gas with a fixed, but unknown, size (like a propane tank for example) and you measure the pressure drop of the container as you pull out a known volume, with some knowledge of the expansion properties of the gas, you can back calculate the volume of the container.  

Material balance methods are complicated and require a lot of data (historical production, reservoir pressures, physical properties of the fluids, drive mechanism, etc), but when sufficient data is available they can give very good results; however, if the data is not available or is of poor quality then the results can be misleading. Computer based simulation models are typically based on the material balance methodology.  This methodology is nearly always utilized in conjunction with one or more of the other two methods and by comparing the results the evaluator can learn a great deal about the reservoir. 

All of these reserve calculation methodologies have their strengths and weaknesses and it is the responsibility of the evaluator to determine the most appropriate method.  Each method requires some degree of judgment on the part of the interpreter and it is important to know and understand the assumptions used and the potential errors that may result.

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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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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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Flooding an oil field with extraneous water has been a widely accepted method for increasing a reservoir's recovery since the 1950's, but to the uninitiated it may seem odd.  After all, water production is a bad thing; it increases lifting costs, puts more strain on equipment, and may even prevent flowing wells from flowing.  Plus, the produced water must be dealt with in an environmentally sound way, which also adds to the operating costs.

So why add water?  For two reasons: First, injecting anything into a reservoir will increase the reservoir pressure, and second, water and oil don't mix.  This second reason may again seem odd, but because they don't mix water, under higher pressure, will displace the oil it contacts.

So what does this mean?  First we need to understand that most oil reservoirs are solution gas drive reservoirs*.  This means as the oil is produced the reservoir's pressure is reduced and the gas that was held in solution begins to breakout and expand, thus "driving" the oil towards the producing wells.  This is a familiar process we see when opening a bottle of soda (Mentos added for emphasis).

The problem with a solution gas drive reservoir is when the gas breaks out of solution it is free to flow to the producing well and be produced, and once the gas is produced the reservoir's energy is lost.  Typically a solution gas drive reservoir will only recover 5-20% of the reservoir's original volume of oil leaving a large portion behind.

By injecting water in a controlled manner, the loss of reservoir pressure can be controlled and reversed.  Water is injected into dedicated injection wells strategically located throughout the reservoir, and the water itself can be used to displace the remaining oil towards the producing wells.  If properly designed and operated, a water flood can double the reservoir's oil recovery.

Even with double the recovery (10-40%), we are leaving large volumes of oil behind in these solution gas drive reservoirs, and with the ever-growing oil-thirsty economies around the world we need to do better.  This is where enhanced oil recovery (EOR) techniques come to play, but that discussion is for another day.

This all sounds great and water flooding has been used successfully for decades, however, it is important to take care to design and operate the flood appropriately, otherwise all the bad things we mentioned at the beginning may be all you get.  There are may factors to consider when designing a successful water flood including:

• reservoir permeability (both absolute and relative)
• beginning and ending fluid saturations (oil, water and gas)
• reservoir heterogeneity
• oil gravity and viscosity
• water source and compatibility
• formation clay content
• depth and lifting costs

But if done right, a well run water flood will significantly improve oil recovery and produce attractive returns for many years.

 *Most of the oil reservoirs considered for water flooding are solution gas drive; of course there are a great many oil reservoirs around the world that are not, but they are not the subject of this discussion.

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