- In part one of this four part series we reviewed the worldwide potential for unconventionals as defined by the EIA in their 2013 study, and found those to be huge. In part two we reviewed some of the key factors associated with unconventional resources and the technology that allowed for their development. Now in part three we're gonna discuss specific geologic elements required for successful plays, what makes some areas positive and others not. And then we'll review a specific play where all these factors came together.

- We'll recall from the final slide of part 2 that even with the advent of horizontal drilling and multistage fracking, some wells were still sub-economic. So what are the key geologic factors required to produce a commercial well as compared to a sub-economic well? First we have to have a sufficient thickness of our resource in which these hydrocarbons can have been generated. We have to have a sufficient amount of shale or unconventionals, such that hyrdocarbons will be present in quantities that can be produced economically. Next is organic richness. There needs to be sufficient quantity or organic material in our resource such that a sufficient quantity of hydrocarbons can have been generated. This measure is defined by TOC or total organic carbon, and it is determined through whole core analysis. Next comes maturation. Not only do we need to have a sufficient amount of organic material to generate the hydrocarbons, but those hydrocarbons obviously must have been generated. Maturation is defined by vitrinite reflectance. Both TOC, total organic carbon, and vitrinite reflectance, will be discussed in greater detail later in today's talk. Once these three factors have been defined we can combine those results and determine what the hydrocarbons in place are. But this is only half the story. Mineralogy, the mineralogic make up of the unconventionals is very important. As discussed in part one, the mineralogy of successful unconventional plays is dominated not by clay, but by either quartz or carbonates. By having a high percentage of one of these two mineralogic groups, a mature formation will be brittle. When we have a brittle formation it can be fractured. When we can create these fractures we can create artificial, or man-made, permeability. Finally, pore pressure. An understand of a reservoir's pore pressure is important so that know what sort of pressures are gonna be required to fracture the rock and what sort of proppant is gonna be used to hold those fractures open. Now, a quick aside, proppant is simply another word for sand. This is part of the injection procedure that is used, or the mix that is used such that once the fractures are created, the sand goes into those fractures so that when it's de-watered, the fractures are held open, and the permeability is maintained. So with an understanding of these three factors we can now define the permeability of our artificial reservoir. Now that we've understood what the in place volumes are and what the permeability is, we can now determine what the produceability of this formation will be. We now know the various criteria required to define the produceability of a particular unconventional resource. What we next need to do is take a look at the actual values for those various criteria. Source rock quality. We're looking for a minimum of 50-100 feet of resource thickness and TOC, or total organic carbon, of between two and five percent. Normally the kerogens are type II or type IIIs and we're looking for porosities in these resources of between three and 10 percent. Source rock maturity. The maturity of the kerogen, which you will remember is measured using vitrinite reflectance in combination with the kerogen type, will define what sort of hydrocarbons are generated. Vitrinite reflectance is measured using a value of Rs of O. If we have values for Rs of O greater than 1.4, we'll expect to be in a dry gas window. Ro's between 1.1 and 1.4 we're generating wet gas, that's a condensate-dry gas combination. And Ro's between 0.6 and 1.1, we're in an oil window, we'll be generating oil. With regard to higher temperatures, those greater than 250 degrees C, the hydrocarbons degenerate into carbonacious solids. This transformation is known as metagenesis, and basically we've taken our resource and burned it. Structural complexity. Unlike conventional reservoirs that require structural complexity to form traps, in unconventional plays we're looking for structural simplicity, preferably monoclinal dip less than five degrees. By having this sort of structural simplicity, we're able to find large drilling programs for multiple rigs over very large areas, and thus define our resource in a most efficient fashion. Brittleness. Brittleness defines the tendency of a rock or a formation to fracture rather than bend, and is directly associated with its mineralogy. It's measured using a brittleness index, which is a unitless value. A formation with a high brittleness index tends to fracture when put under increased stress. A formation with a low brittleness index will tend to bend rather than fracture when put under increased stress. Those formations with a high brittleness index tend to have high percentages of either quartz or carbonates, and have a low percentage of clays. To define a formation's brittleness index requires direct measurement from core data. The presence of aquifers. When exploring for unconventional resources, there's a need to know what aquifers are present and how they are separated from the target formation. This separation is normally through the presence of one or more ductile formations that will isolate the resource during completion operations. Geomechanics. To optimize a well's productivity, an understanding of stress directions is required. To create the largest number of fractures and thus the largest stimulated rock volume, a horizontal well's horizontal section should parallel the direction of minimum stress. Fractures formed during the stimulation process will propagate orthogonal from these well bores, thus creating the largest stimulated rock volume, or SRV. Pore pressure. In order to select proper fluid types, pumping pressures, and proppant, one needs to have knowledge of the resource's pore pressure. This is a straight-forward measurement that's taken in all conventional and unconventional wells.

- This slide shows a Van Krevelen diagram. This diagram is used to type kerogrens based on their hydrogen carbon and oxygen carbon ratios. Kerogen is simply the soild material that is insoluble in organic solvents. And it is the diagenetic alteration of organic material that is laid down with sediments. Bitumen is the fraction of the organic material in sedimentary rocks that is soluble in organic solvent. Kerogen is important in that it is the precursor to fossil fuels. It's a very complex geopolymer with a high molecular weight. With increasing depth of burial and time, kerogen undergoes significant changes in structure, forming oil, and then white gas, and finally dry gas from types I and II kerogens. Type III kerogens generally form coals but can also produce gas. Type IV kerogens are deposited in oxidizing environments and as such have a very low initial hydrogen-carbon ratio. As such, type IVs do not generate hydrocarbons and are not part of today's discussion. The three different kerogen types of interest mature along three different evolutionary paths. As a given sedimentary rock becomes more mature during burial, kerogen becomes more depleted of hydrogen and oxygen relative to carbon. The X-axis on the Van Krevelen diagram represents the hydrogen-carbon ratio, and the Y-axis, the oxygen-carbon ratio. The hydrogen-carbon ratio helps us characterize the origin of organic material. Marine organisms and algae in general are composed of lipid-rich and protein-rich organic material where the ratio of hydrogen and carbon is high. This contrasts with carbohydrate-rich constituents of land plants. The oxgyen-carbon ratio is high for polysaturated-rich remains of land plants. Note that the maturation process on this diagram starts on the right side and matures to the left with both hydrogen and oxygen depleting in comparison to carbon. The color-coding on this diagram represents de-watering in blue, which happens first. Then we have the generation of oil in the green window, and finally the generation of gas in the red. As for the typing of kerogens, type Is are believed to have been formed in stratified water bodies where oxygenated surface layers had plankton and alkalive, but with anoxic bottom waters, thus permitting preservation of organic material. Type I kerogens show a great tendency for the rapid production of liquid hydrocarbons. Type II kerogens form from lipid-rich deposits under reducing environments, and tend to produce a mix of oil and gas. And type IIIs are formed from organic materials composed primarily of land plants, and tend to produce coals and gas. The generation of hyrdocarbons from the source rock depend on three main factors. The presence of organic matter rich enough to generate hydrocarbons, adequate temperature, and a sufficient amount of time to bring the source rock to maturity. Pressure and the presence of bacteria and catalysts also affect generation. At the demise of living matter, the organic material begins to undergo decomposition or degradation. In this breakdown, the process which is basically the reverse of photosynthesis, large biopolymers from proteins and carbohydrates begin to dismantle and form polymers. As noted in the last slide, these changes include the loss of hydrogen and oxygen as well as nitrogen and sulfur. These changes are associated with increasing depth of burial, the amount of time since deposition took place, and the temperatures reached. The aromatization process then allows for the neat molecular stacking of these sheets, which in turn increases the molecular density, and vitrinite reflectance properties, as well as changes in the spore coloration characteristically from yellow to orange, brown, and black, with increasing maturity. Vitrinite is a type of woody kergoen that is relatively uniform in composition. Since vitrinite changes predictably and consistently upon heating, its reflectance is a useful measure in source rock maturity. Vitrinite relfectance of less than 0.5 indicates a source rock is not yet mature, no hydrocarbons will have been generated. Reflectance between 0.5 and 1.35 is the oil window, with maximum generation taking place at approximately 1.0. Note that each generation window has a range and all overlap with one another, so the type of reflectance or the degree of reflectance is not necessarily a unique qualifier for hydrocarbon type. Remember the type of organic material, the temperatures reached by the source rock and the amount of time generation has been underway also play critical roles in the type of hydrocarbons that will be found. This slide shows several examples of spores, not kerogen, seen through a microscope, that are various levels of maturation. When viewing samples in this form, one is actually viewing thermal alteration, which is measured using the thermal alteration index, or TAI. The TAI can be directly related to vitrinite reflectance, and is also a method for defining source rock maturity. Note that the samples become more mature, they change from yellow to brown to black. One analogy to this maturation process is making toast, which I like to have for breakfast. Now I like my toast lightly browned, so that would correlate with an Ro of approximately 0.55. My wife likes hers a bit crisper, so her toast correlates to an Ro of, say, about 0.9. Now we recently had a situation, which of course was completely my fault, that the toast was left in the toaster to the point that the fire alarm in the kitchen went off. The resulting toast of that exercise had an Ro greater than 1.4.

- We've now completed our review of the organic portion of our discussion on unconventionals, but this is only part of the story. The inorganic elements are of equal importance in any oil and gas play, whether it be conventional or unconventional. This slide shows the general mineralogic makeup of several unconventional plays in the Americas using a Ternary diagram. Ternary diagrams simply show the three primary mineralogic components of each basin. Remember this is a generalization, and that the mineralogy within each basin will vary both vertically and laterally across that basin. On this diagram we have 100% clay minerals in the bottom left hand corner, 100% carbonate at the top, and 100% quartz plus feldspar in the bottom right. That's an example, note that the average shale mineralogy, which is highlighted on this Ternary diagram in green, is at the bottom of the Ternary diagram to the left of center. In this position we realize that the average shale is relatively low in carbonate content, low in quartz plus feldspar, and high in clay content. This is not a good candidate for unconventional exploration. Even if it was high in TOC, total organic carbon, and that TOC was mature, the fact that this rock is high in clay means that it's gonna be ductile. A ductile rock can't be fractured efficiently, as such it can't be produced as an unconventional reservoir. The shales that are good candidates are those in the circle to the right. These shales are relatively high in either carbonate or quartz plus feldspar, and low in clay content. As such they're brittle, that means they can be fractured, that means they can be produced and make good unconventional reservoirs.

- What we have on this slide are computer generated interpretations of logs, or CGI logs, for generalized sections from five basins in the Americas. What we see on these logs is very similar to what was presented on the previous slide on the Ternary diagram. Each log shows that percentage of the mineralogy that is interpreted for each one of these areas. Now the CGI can actually present 18 different mineral types, but we're only concerned with the three dominant ones. First there are the clay minerals, those are in gray. Carbonates, those are in blue, and finally the quartz is in yellow. Note that the Eagle Ford log on the far left of this display has a generally low clay content, and a relatively high carbonate content. Because of the mineralogy, the Eagle Ford formation is brittle. As it's brittle, it's a good candidate for fracking. As it's a good candidate for fracking, it's a good area for unconventional development. In contrast to the Eagle Ford, note that the logs from the Haynesville indicate a much higher clay content, almost 50%, and approximately the same percentages of both quartz and carbonates. Due to this mineralogy the Haynesville is a much softer, more ductile formation. As such wells can be produced in an unconventional sense in the Haynesville, but their productivity's gonna be much lower than similar wells found in the Eagle Ford. Key takeaways from this slide are that the mineralogic makeup of each basin is different, and that the makeup of that mineralogy is key to defining how productive each area will be. It should also be noted that there are variations in the vertical sections in each one of these basins. It's critical to understand that, so that you know where to land the wells to optimize their production. We've now reviewed the key geologic factors, both organic and inorganic, required to create a successful unconventional play. We'll next review an area where all these elements have come together for a successful unconventional play. This slide from the EIA shows a map of south Texas. The small map on the right will help you orient yourself for the larger map. The area of interest lies in the highlighted northeast-southwest multicolored band, which is between Austin and Houston, Texas. The Eagle Ford shale, which is our unconventional play, was deposited in the Maverick basin during the Upper Cretaceous, more than 65 million years ago. It outcrops, or comes to the surface, in this semi-circular area highlighted in back on this map. From that location it gently dips monoclinally to the southeast as noted by the depth contours, into the Gulf of Mexico. Remember, in an unconventional play, we're looking for very simple bed geometry. There's no need for structuring in unconventional plays. The gross thickness of the Eagle Ford varies from 300 to 500 feet, much greater than the 50 feet we mentioned earlier as the minimum. As highlighted on the Ternary diagram earlier in this presentation, the Eagle Ford has carbonate content of approximately 67%, about 20% quartz, and only 8% clay, so this is a very brittle formation, easily fracked. The TOC ranges from two to seven percent, and the Ro or vitrinite reflectance in the area being developed varies from 1.0 to 1.27, putting us in the wet gas region. Finally, porosity in the Eagle Ford varies from three to 15 percent, which is excellent. As mentioned, the area under development is in the wet gas window. So these wells produce both gas and condensate, but the maturity of the greater Eagle Ford varies. The three color bands on this map highlight the variation in maturity. To the northwest, in the green band, the formation is relatively shallow, it's less warm, lower pressures. As such it's not as mature, and is still in the oil window. The central band is deeper, which means it's a bit hotter, higher pressure, and as such it's reached the wet gas window. And finally we have the deeper red band, which again is still hotter, higher pressure, and is in the dry gas window. The red dots on this map indicate drilling activity. Note that there are only a few wells drilled in the green area, no wells drilled in the red area, and the majority of the activity in the orange band or wet gas band. There's very limited activity in the green belt due to a combination of hydrocarbon type, which is oil and more viscous, and the fact that we have lower pressures, lower energy, that will not produce at attractive levels. Note all the activity is basically in the orange belt. Here we have hydrocarbons in a gaseous state in the sub-surface, which means they'll flow easily, and we have higher pressures which means we have more energy which will create more attractive wells. Finally, we have the red, or dry gas window. Here there's no activity and that's due to the fact of low gas prices and high well costs for these deeper, higher temperature wells. Just don't provide for economic production.