Previous Lesson Complete and Continue  

  Comparison between Conventional & Unconventional plays

Lesson content locked

Enroll in Course to Unlock
If you're already enrolled, you'll need to login.


- In part one of this four part series, we reviewed the potential for unconventional hydrocarbons worldwide as defined by the EIA in their 2013 survey. We saw that their estimate was huge. Over 7,000 TCF of risk-recoverable gas and over 340 billion barrels of oil in the basins that they made estimations for, and those basins are not considered to be comprehensive. There is greater potential. We also learned that in order to effeciently develop any resource, we first needed to have a clear understanding of that resource and then use the most modern technology available in its development. In part two, we're gonna start learning about unconventional resources and then review the technology that has allowed for their development. Before reviewing unconventional reservoirs, I'd like to first discuss geologic factors associated with conventional reservoirs. First, hydrocarbons stored in conventional reservoirs are stored under pressure within the rock pores, which is known as porosity. As gas and oil are both lighter than water, they tend to be buoyant on water. So you'll normally find a water lake under a conventional reservoir. How do carbons in conventional reservoirs accumulate in either structural or stratigraphic traps? There's no significant hydrocarbon reservoir interaction. This is not the case with unconventionals which we will review later. And hydrocarbons stored by compression within specific pore space are calculated using temperature, pressure, and volume relationships. So the in-place hydrocarbons are a direct function of the effective pore space, or porosity, what portion of that pore space is filled with hydrocarbons or hydrocarbon saturation, what the temperature of the reservoir is, what the pressure in the reservoir is, and finally, what the composition of the hydrocarbons actually are, how much is oil, how much is gas. How much is inert, how much is volatiles. And in a normal, conventional gas reservoir, we'll expect to have recovery factors in the range of 60 to 90 percent of those hydrocarbons that are actually in place. So now we have a fairly clear understanding of the geologic factors associated with conventional reservoirs, let's move on to unconventional reservoirs. First, I need to mention that those unconventional reservoirs we'll be discussing are those composed of shales. We'll not be discussing things such as coals and coal bed methane. Now as we get into discussion of shales, we need to understand what shale is by definition. By definition, shale is not a mineral definition. It's a grain size definition. Shales by definition are made up of very fine silt or clay size minerals that in their uncompacted form would be called mud. Again, shale by definition, is grain size; not minerology. Minerology is extremely important in unconventional reservoirs, and it will be discussed later in today's talk. Another key element to unconventionals is they tend to be deposited over very, very large areas as we saw in the earlier slides by the EIA. Because the fact that we have this very low permeability, we don't require traps as are required in conventional reservoirs. As we don't require traps, again, these plays can take place over very, very large areas. Gas in shales is stored in a number of different ways. First, we do have porosity, but this porosity is very, very small. Very, very small pore spaces, as such we have very low permeability. It can also be stored in voids of natural fractures. It can also be adsorbed onto mineral surfaces or absorbed in both organic and mineral surfaces. Hydrocarbons found in unconventional reservoirs are self-sourced. Unlike conventional reservoirs where the hydrocarbons are generated in one formation and then have to migrate into the second formation, the reservoir. In unconventional reservoirs, the source rock and the reservoir are the same formation, thus no migration is required. So we've seen there are differences between conventional and unconventional reservoirs resources, how do we go about exploring and developing each one of those as compared to the other due to these differences? First we go to mapping. Mapping is extremely important in both cases. We need to understand where are resources in subsurface, we do this through mapping. Porosity. In a conventional reservoir, porosity's on the low end or around three percent. On the high end, they can be up to 35 percent. We see those kind of porosities in areas such as the Gulf of Mexico. In unconventional reservoirs, we're normally between one and 10 percent. Important difference here is that porosity in unconventional reservoirs is nano-pores, very, very small pore spaces. As such, when we get to permeability, you see that permeabilities range in conventional reservoirs between 0.1 millidarcies and into the darcy range. In unconventional reservoirs, we're looking at nano-darcy permeability. The permeability has to be created through fracking in order to produce these reservoirs. Source rock. We need to understand the source rock in a conventional reservoir. We also need to understand how that hydrocarbon, once generated, migrates into our trap. In unconventionals, it's very different. The source is insitu. The source and the reservoir are the same, there's no migration required. Seals. In a conventional reservoir, again, because we have natural permeability, if we don't have a trap, i.e. a lateral and vertical seal, we won't have a resource. The hydrocarbons will have migrated through. In unconventionals, again, due to this lack of permeability, vertical and lateral seals independent of the resource are not required. The resource actually defines those by again, this very low permeability. Drainage areas. In a conventional gas reservoir, we can be up to 750 acres per vertical well as far as being able to drain the resource. This is very much different in unconventionals. Here it's dependent on how long our horizontals are and how well we're able to create stimulated rock volume. But the areas are very, very much smaller than in conventional reservoirs. And productivity. Just an example, in the North Sea, we look to produce between 20 and 70 BCF per vertical well. In unconventionals, if you get up to 10 BCF in a single horizontal well, you've done very well. Most of the time we're talking more in the range, say, three to five. So based on that you can see it's gonna take a lot more drilling in unconventional reservoirs to realize the same size resource. William Aaron Hart, Bill to his friends, was a tinsmith who lived in Fredonia, New York in the early 1900s. In this portion in New York, gas seeps from shales were well known by both the Native American Indians and early settlers. Bill came up with the idea to drill a well to a depth of 27 feet into these lights in order to see if he could tap the gas that was seeping to the surface. This was done in 1821. He succeeded and by 1825 was piping gas to a local village through hollowed out logs held together with tar and rags to supply two shops, two stores, and one gristmill with metered, sold gas. So the first commercial unconventional gas dates back to 1825. Fracking conventional reservoirs to improve the productivity of those intervals dates back to the 1940s. Like producing gas from unconventional resources, fracking is also not a new technology. Fracking conventional reservoirs to improve their productivity dates back to the 1940s. So like producing gas from shales, this also is not new technology. What is new and a game changer is the idea of drilling long, horizontal wells and then conducting multi-stage fracks in order to create an SRV, or stimulated rock volume, and thus being able to produce hydrocarbons from these previously impermeable formations. This exploitation methodology was not discovered as a hallelujah moment. George Mitchell, Mitchell Energy, spent tens of years back in the early 1980s determining how to produce hydrocarbons from shales or unconventional reservoirs. This exploitation methodology was discovered by George Mitchell in Mitchell Energy back in the 1980s. And this was not a hallelujah moment as will be demonstrated in an upcoming slide. It took George and his engineers years to develop the methodology that allowed hydrocarbons to be produced from what was previously impermeable intervals. George, a true visionary, passed away in 2013. He was a man of many accomplishments, but will surely be remembered as the father of this paradigm shifting new energy source. Mr. Mitchell was also the embodiment of the entrepreneurial spirit. He did not discover hydrocarbons in shales. Those had been known about for decades by geologists. He also did not invent fracking. That again, dates back to the 1940s. View great entrepreneurs invent something entirely new. He was convinced that technology could unlock the vast resources that lay in south Texas in the Barnett Shale. In the early 1980s, most of the oil industry considered George to be just barking up the wrong tree. Poor George didn't have an idea what he was doing. Well I can guarantee the industry changed its tune when in 2001, he sold Mitchell Energy to Devon Energy for 3.1 billion dollars. This plot shows the gas production from the first unconventional reservoir, the Barnett Shale. Y-axis represents first gas production, first six months of gas production from individual wells, and time is shown on the x-axis. The white symbols on this plot are vertical wells, the green dots are directional wells, and the red dots are horizontal wells. Time starts in 1981 and extends to 2013. Note that a number of innovations were tried in the early 1980s and 1990s, such as cross well fracking without a great deal of improvement on production results. Further note that the first couple of horizontal wells that were drilled were not much better than their vertical counterparts. It was not until the early 2000s when a combination of horizontal drilling and multistage fracking brought on huge improvements in production. You will further note that this improvement in production is not universal. Yes, there are a number of wells, the red dots, that have fantastic initial production, but also notice even as late as 2013, that there are a number that are very substandard. In part three of this four part series, we'll discuss what geologic factors are required in specific wells to have these great production results.