In deference to American literary icon Mark Twain, reports of the death of the Barnett shale play have been greatly exaggerated. Even though the active rig count has been falling.
Devotees of the pioneering, 5,000-sq-mi gas-dominant play in the Fort Worth basin of north-central Texas maintain that the dwindling rig count is only part of the story and in fact as the rig count has been falling the oil and gas output has been increasing with the aggregate field production recently reaching an all-time high of 5.6 billion cubic feet of gas a day. Long-time Barnett observer Gene Powell, publisher of the Powell Shale Digest, described the production figures as “phenomenal,” considering the lower number of rigs in use. Most of the wells in use at this time are in Wise county.
The Barnett Shale is going to be producing oil and gas for the next 30 years and probably much longer than that with the new techniques that are constantly being developed. Already we have:
•Multi-well drilling pads. Means that you don't need as many wells to be dug. One well site can now have up to eight or more horizontal wells going in different directions and at different depths.
•Extended-reach horizontal laterals, up to 10,000 feet in length. Originally Barnett wells were only 5,000 feet long. And 10,000 feet (2 miles) is only a start. There is one horizontal well in England that is 7 miles long.
•Optimization of hydraulic fracturing through micro-seismic imaging and enhanced interpretation. This increases the accuracy of the well placement.
•Drilling bits designed for specific shale and tight formations. Different parts of any shale formation will vary in the hardness of the shale and its permeability.
•“Walking” drilling rigs. You don't need as many rigs, because the newer rigs have the ability to move to a new site after completing the drilling of a well.
But even though you have fewer rigs, more waste water is being produced because each site has more horizontal wells. Hydrofracing, also called hydrofacking, is a process where a slurry is made with small amount of chemicals, frac sand and water. The ratio of water to sand is 99.5: 0.5. This slurry is then pumped into the wellbore and down into the subsurface rock bed at a rate of up to 265 liters per second. Pressure is then applied to the slurry, which can reach upwards of 15,000 psi.
This pressurized slurry forms cracks in the brittle rock bed where energy reserves are trapped. The oil and natural gas is allowed to escape after the slurry pressure is released. Much of the injected water also comes out with the initial oil and gas. This can amount to millions of gallons, and that is followed over time with the large amount of salt water that is found in the Barnett Shale along with the oil and gas.
Initial flow rates for new horizontal wells are very high, but the flow rate decreases rapidly over a period of about a year until it reaches a steady state flow rate which, even though it is substantially lower than the initial flow rate, is still strong enough to produce economic amounts of gas and oil and this output can last for decades.
Even so, it would be economically advantageous to increase the flow rates. It is now possible to stimulate older wells. A newly developed method of doing this is to enhance oil recovery with pulsed injection of water or chemicals. A tool installed in the well injects fluids in pulses—pumping like a heart pumps. Think of putting a kink in a garden hose. Pressure builds up and when the kink is released there is a strong pulse of water. This re-fractures, or increases the size of the original fractures, and so you get increased production of gas and oil, along with increased salt water production. This technology is efficient and companies can make money doing enhanced oil recovery with pulsed injection.
You can first start with pulse injection of an acid solution. Horizontal well tubing contains multiple holes along its length which lets in the oil and gas from the surrounding formation. Over time the holes start to get partially plugged with rock particles plus the tubing itself starts to fill up with rock particles. The acid dissolves this, cleaning out the tubing and the holes, and after this is accomplished, then you pulse inject the water or chemical solution.
This pulsing technology has also been modified for use in performance drilling tools. Fluid pulsing behind the drill bit and drill string agitation dramatically increases the rate of penetration, reducing drilling time by 20–40%.
An even newer experimental method to enhance horizontal oil production, that is just starting to be used, is to place a string of small ultrasonic vibration generators in a new or even old horizontal well and use the resulting ultrasonic waves to stimulate the oil and gas production. Other methods for stimulating the oil and gas production of horizontal wells are even now in the planning stages.
All of this means that the wells in the Barnett Shale formation are going to be producing oil and gas, and salt water, for a long time to come and this means that IPRC will be making money for decades to come. Not only that, but they are going to be getting more business over time. At present they have been told by that they will be allowed, within the next 6 months to a year, to inject up to 30,000 barrels of salt water a day. From what I have read in other reports, even this limit might be increased. So over time the company is going to be able to pay off its bills and start working on its other properties. These could even be more lucrative than our salt water disposal well.
IPRC plans to use Enhanced Oil Recovery (EOR) methods on already proven oil fields where the oil is already known to be there, but where conventional methods no longer produce economical amounts of oil. Usage of EOR methods vastly improves recovery factors and there are minimal exploration costs and fewer uncertainties because you already know that the oil is there and where it is located and EOR projects usually are long-lived and very profitable.
While much attention has been focused on the massive oil production as a result of the technology of horizontal drilling, the technology of carbon dioxide (CO2) Enhanced Oil Recovery (EOR) may end up producing even more oil than horizontal drilling, Greg Dover, Vice President of Operations for Denbury Resources, told a crowd of several hundred people at the Montana Energy 2012 conference in Billings. One of the most intriguing aspects of CO2 EOR is that it allows the resurrection of wells once considered depleted. America is filled with oil fields that are no longer producing oil, but still have 60% to 80% of their oil in place and EOR methods will allow much of this oil to be removed.
It has been estimated that in employing CO2 technology there is 7.5 billion barrols of oil to be recovered nationwide. "And, the industry is just scratching the surface," said Devon. In Montana, Wyoming and North Dakota, alone, there is 3.2 billion barrels of recoverable oil.
This technology and process was developed out of necessity during the Organization of Petroleum Exporting Countries (OPEC) oil embargo in 1973, when two oil companies -- Amerada Hess and Occidental Petroleum -- were looking for ways to get oil out of U.S. fields that were no longer productive.
Technically, the process worked. But when the crude came up, it was heavily mixed with water, making it prohibitive to use in the existing production and refining processes.
Today, however, oil companies now have new and increasingly common technology known as de-watering. This not only makes the waterlogged oil from enhanced recovery workable, but also creates clean water that can be used for agricultural use or even human consumption.
CO2 pumping is going to be even bigger than fracking when it comes to getting more oil out of the ground. Up until now, traditional drilling and fracking has missed as much as 75% of the oil in a given well.
CO2 dissolves in the oil, reducing its viscosity, making it thinner and easier to flow, plus it also reduces the surface tension with the reservoir rock and so it doesn't stick as tightly to the rock pores.
In these applications, between one-half and two-thirds of the injected CO2 returns with the produced oil and is usually re-injected into the reservoir to minimize operating costs. The remainder is trapped in the oil reservoir.
Using carbon dioxide to churn out more fossil fuels—and permanently storing some of the CO2 in the process—might sound counterproductive to limiting climate change because those fuels, when burned, put more CO2 into the atmosphere. But it does reduce overall emissions by at least 24 percent, calculates petroleum engineer Ronald Evans, Denbury's senior vice president of reservoir engineering: every recovered barrel of oil eventually puts 0.42 metric tons of CO2 into the atmosphere, but 0.60 metric tons are injected underground recovering it.
As an added bonus, about one third of the CO2 pumped underground in the process stays there, and not only will this make the environmentalists happy, but the government might start crediting the companies that use this technique and pay them carbon credits which can be sold for cash.
In a regular oil field, when you drill a well, the oil comes up under its own power because microbes in the formation have produced large quantities of gas which produces a large pressure gradient and the oil gushes to the surface. Over time all the pressure is released and no more oil flows out under its own power, but even though no more oil is coming out, it doesn't mean that there is no more oil in the formation. Most of the oil is still there, usually 80% to 90% of the oil is still in the formation. Oil operators used to inject water under pressure into the formation with the hope that it would push out the oil, and it worked so-so, but water is thin and slippery and it would mostly just slide past the oil. So then they started adding a small amount of a polymer chemical to the water which would turn it into a jell and make it the same thickness as the oil. This worked much better than just water, but the oil, which is located in the pores and tiny cracks in the rock formation, tends to stick tightly to the rock, and so only the oil that was free and not adjacent to the rock cavities was pushed out of the formation. Soapy chemicals break this bond, but these chemicals are rapidly degraded in the harsh environment of the oil formation and some other method had to be found. Alkaline chemicals react with oil and form soap. In fact that is how soap is made, by mixing alkaline wood ash with grease. Wood ash, which is largely composed of potassium hydroxide, when added to an oily compound such as lard or even olive oil, forms soap. So by adding small amounts of an alkaline chemical to the water-polymer mixture it would react with the oil in the formation, forming a soapy surfactant which would break the bond holding the oil to the rock, and this greatly increased the amount of oil that was forced up to the surface.
Lightstream Resources, which uses horizontal fracing in shale formations, says that most of the oil and gas is not recovered with regular fracing procedures and that they are now using enhanced oil recovery methods to increase their output. Normal Alkaline-Surfactant-Polymer (water flooding) methods won't work because the “incredibly poor quality” of shale, with its tiny pores, makes injecting fluids unworkable. Chief Executive Officer John Wright said, however, that CO2 easily enters the tiny pore spaces. Enhanced oil recovery, or EOR, is not a new concept in the development of oil and gas reservoirs, but applying it to tight oil reservoirs is new, he stated and it has greatly increased our oil and gas production rates. It also increases the production of produced water. Over time more companies, such as those working in the Barnett Shale formation, will use CO2 to increase their horizontal shale fracing output and this will prolong the fields life and even increase its rate of output.
Before going on, it might be useful to mention how an oil field originates and how this affects its composition. Oil is called a fossil fuel because it originated as material from plants and animals that lived millions of years ago. Usually these plants and animals lived in an ocean environment and when they died, this carbon-based (organic) plant and animal material settled on the bottom and mixed with sand, silt, and sediment. Over thousands of years the layer of sediment accumulated and turned into sedimentary rocks, such as sandstone, limestone, and shale. Pressure, temperature, and time resulted in the transformation of the deposited organic material turning into hydrocarbons, such as oil and natural gas. Over geologic periods of time, these could form thick oil and gas formations. But in other cases, such as shallow inland seas, at times the sea would dry up and then you would get a layer of just sand without organic material in it. Then the sea would reform and you would get another layer of oil bearing sand or shale. In this case you could produce multiple, usually thin, layers of oil bearing formations. These types of layered formations require horizontal drilling to be economical. If the pore spaces were very tiny, such as in shale, the oil or even gas, would be unable to move from the surrounding shale to the well that was drilled, and so in addition to horizontal drilling you had to use fracking.
The oil and natural gas that is formed in the rock exists in the pore space of the rock formations. Pore space is the open area between the solid grains of material that make up the rock. For example, when water is poured on a piece of sandstone, it is absorbed by the stone–it is flowing into the pore spaces which exist between the sand grains that make up the sandstone rock. The measure of the open space in the rock is called porosity. How well the pore spaces are interconnected determines how quickly and effectively fluids flow through the rock. The measure of this interconnectedness is called permeability.
Horizontal wells are about 2 to 3 times more expensive to drill than vertical wells, but there are numerous studies showing that directionally drilled wells have been able to extract up to 25 times more oil or gas than vertical wells drilled in the same oil or gas field.
In 2000, there were fewer than 50 horizontal drilling rigs in the U.S.A., but today there are more than 1,200, which is why we've gone from talking about peak oil to now pondering American energy independence within the next five years or even sooner.
Clearly, in low permeable formations, such as shale, horizontal drilling wouldn't be viable without being combined with hydraulic fracturing. However, when done in combination, the results are absolutely game-changing. Consider the following quotes from Pioneer Natural Resources CEO Scott Sheffield on the company's most recent quarterly conference call. In talking about a recent horizontally drilled well in the Permian Basin, he said: "What's interesting, in six months, it's reached 140,000 barrels of oil equivalent." But what's truly mind-blowing is "Our typical vertical well takes 30 to 35 years to produce a 140,000 on a vertical well. So we did that in six months." By simply shifting from a vertical well to one drilled horizontally, the company was able to pull forward three decades of oil and gas production.
The other thing to keep in mind here is that the company isn't just pulling production forward, but it's accessing oil and gas that would never have been recoverable before. That's because companies are able to significantly improve what are called estimated ultimate recoveries, or EURs. In fact, production is so good at its recent wells that the company, which had estimated it would ultimately be able to recover about 650,000 barrels of oil equivalent from its wells, is now, based on what it's seeing, estimating that it could pull out more than a million barrels in some cases from its wells.
In one final example the company gave on its conference call, it noted that in 10 months one of its Jo Mill wells produced an average of about 60,000 barrels already. That's truly staggering when considering that it was thought that a traditional vertical well in the Jo Mill would produce only 20,000 barrels in 40 years. It's pretty clear: Horizontal drilling changed everything. And now you can drill multiple horizontal wells from one site which will increase the efficiency of the technique even further.
What many people don't realize, is that horizontal drilling is not just for shale formations. Many regular high permeable oil/gas fields are not very thick and so a vertical well would only be in contact with a small length of productive oil bearing rock, say 100 feet thick. If instead you drilled a horizontal well 5,000 feet or longer, you would be producing 50 times as much oil and/or gas.
The same efficiency also applies to enhanced oil recovery techniques. If you inject CO2 into a vertical well it will penetrate only a small amount of the formation, but by injecting it from a horizontal well, you will be penetrating a much larger area of the formation.
IPRC can benefit in two ways from the above discussion. As companies working in the Barnett Shale start using these newer techniques, such as pulsed injection and drilling multiple horizontal wells from one site, and then using enhanced oil recovery methods, such as CO2 injection, on older wells, the Barnett Shale is going to be producing much more oil, gas, and produced salt water, than originally expected and for a much longer time period than originally estimated, and so our salt water disposal well is going to be working at maximum capacity for years, decades to come, which means that our salt water disposal well is also going to be much more profitable than was originally expected.
In addition to that, once IPRC starts developing its oil/gas properties it can use these techniques to get better yields. Management has previously written that it is very familiar with water flooding to increase the yields of old fields and plans to use this technique as it acquires leases on past producing fields. I would hope that they will use Alkaline-Surfactant-Polymer solutions instead of just water and will e-mail them in regards to this, although they probably know more about it than I do.
IPRC has said that the first property that they plan work on, once they have a good cash flow from their salt water disposal well, is their Nunnelly #1 well in Montague County Texas. This is actually part of the Barnett Shale formation, but it is now being called the sweet spot in the Barnett shale because it turns out to be "wet shale", which is shale that has a large percentage of oil and other hydrocarbon liquids, such as propane and butane, instead of just dry gas, and so is much more profitable than the other parts of the Barnett Shale which only contains dry gas (mainly methane). This Combo play, as it is now being called, turns out to be a balanced mix of oil, natural gas, and natural gas liquids and so instead of being mainly dry gas, two thirds of the hydrocarbons in the shale are the more valuable liquid hydrocarbons.
The Nunnelly #1 lease is 35 acres in size. 35 acres does not sound like a large position, but that is a plot of land 7,300 feet on a side, which means that you have the option to drill horizontal wells instead of just vertical wells. However there is already a well on the property, the Nunnelly #1 wellbore, and rather than spend the money to drill a new well, vertical or horizontal, IPRC can re-enter the Nunnelly #1 well and deepen it, at nominal cost as the company puts it, and reactivate it using techniques such as pulse injection and maybe CO2 stimulation and see what type of output they get from it. However, the Company may decide, as works progress, that the most cost effective course would be to drill a new well to access the Project’s potential reserves.
To get an idea of how profitable this lease can be I looked up how another company in the area is doing.
EOG Resources has a large position in Montaque county. They state potential reserves for the Combo play in Montague county are estimated to exceed 110,000 barrels oil and 275 million cubic feet of gas per acre, and we have 35 acres.
EOG Resources’ typical combo wells reportedly have an EUR (Estimated Ultimate Recovery) factor of approximately 300 thousand barrels of oil. The company reports strong results from 4 new wells, with production of 400 – 600 barrels of oil per day and 700 – 900 thousand cubic feet of natural gas per day.
EOG said that the average initial production rates of wells drilled in the Barnett Shale Combo play are:
Oil – 300 barrels per day.
Natural Gas Liquids – 130 barrels per day.
Natural Gas – 940 thousand cubic feet per day.
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Natural gas prices are $3.50 per thousand cubic feet, and it is expected that the price will rise to over $5 per thousand cubic feet
Natural gas liquids average $35 per barrel
Oil is about $100 per barrel
If IPRC's wells get an output averaging these figures, then counting a natural gas price of just $3.50, plus natural gas liquids of $35 and oil at a price of $100, that would work out to $38,000 a day. You would have to subtract operating costs from that, plus take into consideration that the output would decline over time. Over a three year period of time, the out put of wells in the area decline about 75% before reaching steady state production, but that would still work out to $10,000 a day cash flow, and considerably more than that for the first three years. Also, using pulsed jet stimulation, you might get better fracking and so increased daily output, plus when the output declines you can use stimulating techniques such as CO2 injection.
IPRC also has the Chisholm Trail Prospect Resource Play in Oklahoma with agreements in place to take a 50% working interest participation in 5,000 acres of this major resource play in Oklahoma. The area is low risk because a number of wells nearby have been with great success. ALL the wells drilled are producing and the produced oil is sweet with a high API specific gravity. The gas is also sweet, with a very high BTU content commanding a premium price.
The Chisholm Trail formation contains multiple producing layers. The Hunton is the primary horizon, but the formation also includes other producing horizons such as the Oswego Limestone, Manning, and the Cherokee Sands. All of these are accessed with horizontal drilling.
Nostra Terra Oil & Gas company has been drilling in the area. Their first well was drilled in November 2012 and in July of this year they announced the completion of their fifth well. Well #1 is producing 258 barrels of oil equivalent per day (81% liquid hydrocarbons), the other wells are producing 555, 348, 505 and 448 boepd. This comes out to an average of 423 boepd per well. The company states that all the wells have shown a very shallow decline curve.
IPRC states that they plan to drill 15 wells as a start, but that eventually they could drill over a thousand wells. And don't forget that when they do start drilling, they can take advantage of all the new methods that have been discovered that increase the efficiency of the wells, such as pulsed injection which makes much larger fractures, compared to regular injection techniques. Of course it will take time to build up the number of our wells. It will start very slowly, using the cash flow from the salt water disposal well and the Nunnelly well to finance the drilling, but as more wells come into production, IPRC will have increasing cash flow to fund further drillings. Since the wells in the area have shallow decline curves we could expect 400 barrels of oil a day production to last for a long time, and as the gas/oil was depleted in a drilled layer, a new horizontal well, from the same site, could be drilled into the next lower producing layer. At 400 barrels of oil per day per well, that is $40,000 per day per well.
As we start drilling wells in the Chisholm Trail formation and start getting increasing cash flows, our stock price will start rising. Previously, with just the prospect of our salt water disposal well, our stock price was over a dollar a share. Over time we could vastly exceed that price. Some people are waiting for our stock price to go back down, which may happen, but with a press release that says that our salt water disposal well is making money, our stock price could start climbing and never look back. So the present price of around 6 cents a share sounds like a good buy in price, or at least to buy some shares at that price. 60 cents a share somewhere down the line sounds like an almost sure thing, which is ten times its present price, and even higher prices are a good possibility. As long as the company keeps advancing its prospects, such as actually drilling wells in the Chisholm Trail and maybe even acquiring more properties, possibly regular worked out properties where you can inexpensively re-enter previously closed wells and use simple enhanced oil recovery techniques, such as Alkaline-Surfactant-Polymer injection methods, to re-stimulate oil production, our stock price should continue to climb. Eventually our stock could be worth multiple dollars a share.