 In this lesson, we're going to talk about the entire logistics and value chain now for natural gas, since we've already covered the one for crude oil itself, and the phrase we tend to use for this is well head to burner tip. On the left is just a picture of a low pressure well, kind of a small well. That's known as a Christmas tree, the configuration of the various valves, and to the right is what's known as an oil gas separator. The first thing that happens when the raw natural gas comes out of the ground is to separate the heavier components, the oily substances, which in essence are what we call condensate. Here's a schematic just kind of showing the overall industry and the different paths that the natural gas goes through. You can see you've got the gas well, you're going to have separation between the oil, water, natural gas. It's going to go through gas processing plants. There are some opportunities for storage here, and then ultimately it's going to get to the end users. Here's another setup of kind of how we separate upstream, midstream, and downstream within the natural gas industry. The upstream is obviously the production portion of it, but gathering, processing, and transmission and even storage are considered midstream along with the trading type functions, and then ultimately downstream is going to be the actual end users for that. Some of the players, some of the labels that we talk about on the various participants, you've got operators and producers at the well heads, you have the processing plant, which is your midstream companies, their gatherers and processors, storage operators, which a lot of times can be independent storage, or they can be pipeline and storage operators, and then we have what's known as the city gate, which really is the distribution point where the gas company or LDC picks up the gas from the transmission system and distributes to all of its customers. So we're going to start at the well head. This is the production. This is what we're interested in once the well is completed, starts producing. We're interested in how much volume it can be sold on a daily basis. This is known as the deliverability. Now, this depends on the type of reservoir that you have. Some reservoirs, once they start producing, cannot be shut in. That is they can't be turned off because you can actually lose the production. Also the operator of the well, there's an entity or participant who actually operates the well. That means they are responsible for the day-to-day operations of the well. They also have an interest in the well. We talk about working interest owners. Those are the ones who actually have invested in the well and have an ongoing investment commitment to any operational costs. Now the operator is also a working interest owner. And then the joint operating agreement, or JOA, is the contract between the operator of the well and the various working interest owners. And it spells out exactly how things are going to happen, shared costs, how revenue is going to be dispersed, and those types of things. Again, because we're interested in the production of the deliverability, the sales volumes again. What are the ways in which we could actually increase the amount of gas flowing from a natural gas well? Well, I think by now we're all familiar with horizontal drilling. Horizontal drilling allows you to pull more out of the reservoir than straight vertical drilling. Another method would be to basically drill another well, or what we call infield drilling. Go ahead and drill an offset well. Wells that start to decline, there can be a re-completion now. That can be two different things. One can be where you go down in and you attempt to do something additional to the existing reservoir, or you find another reservoir, another layer, another producing zone, and you go back down and you complete that. Of course, fracking is a form of initial releasing of the production. It can also be done multiple times if you think that there's more to be released. That is one of the ways in which wells are completed. It's an older method instead of fracturing, but if you have a well that's in decline, then you may agree as a producer and an operator together to go ahead and try and use some acid to free it up. This works mainly in places like sand formations. Compression is going to be another thing where you can use natural gas compressors to draw additional gas up out of the reservoir once. The reservoir pressure itself has dropped to the point where the gas can't just free flow into the connected pipeline. The other course is to look for what we would call a low pressure connect. This is generally a service that's provided by midstream gatherers and processors where they have compression at their plant, which can draw the gas from your well if the pressure of your well can't by itself exceed the pressure of the pipeline that it's connected to. The quality of the gas, this is very important because it's going to end up in a pipeline and then eventually some type of end user, whether it's a power plant or it's someone's home hot water heater. A couple of things here initially, the BTU value. This is what we're after. This is what we sell. That's the heating content, the British thermal unit. That's the amount of energy required to raise one pound of water, one degree Fahrenheit. Again, this is what we are marketing, water vapor. We don't want water in the gas stream nor the pipelines. Any types of corrosives, there is sulfur, which naturally occurs in the raw natural gas down in a well. It can actually lead to the formation of hydrogen sulfide, which is a corrosive. That is it can eat away at the steel pipe. Nitrogen itself just takes up space. It has obviously no heating content, the same thing with CO2. Carbon dioxide just takes up space in the pipe. You don't want these innards in there because you want to fill that pipeline up with as much heating content as you can. Then the question of whether or not the gas is processable. In other words, can it be processed? Is the BTU content high enough to extract natural gas liquids, which are valuable on their own? The other side of that question really is, does it need processing? The pipelines are only going to accept a certain maximum amount of BTU content. If you think about it, something volatile like propane, which I think we're all fairly familiar with, you can't have that in someone's home hot water heater. You also can inject propane into a boiler at a power plant. You will literally have an explosion. And then any other kind of treatments. Just some of the folks that have already mentioned, these are your well head participants. A producer has a working interest in the well. They're known as working interest owners. That means, let's say for instance, a particular well, you had 10 owners. Everyone essentially contributed 10% of capital upfront to drill the well, and now because they're working interest owners. They are on the hook for any additional operating costs or investment of things like the re-completion of a well or drilling an offset well. So as a result of that, they're entitled to 10% of the production coming out of the reserves, the natural gas well. So we refer to that as their entitlement. As I mentioned before, the operator is also working interest owner. They've got a percent of reserves or their entitlement. They are responsible for the day-to-day operations. They're also responsible for what we call well balancing or allocations. In other words, if you've got 10 owners, if that well plays out eventually, in other words, it's depleted, then every one of those owners should have at some point in time received their 10% of those reserves that are in the ground. If not, then the operator has to cash balance that out so that everyone is on an equal basis at the end. Otherwise, we have a considerable number of lawsuits over these type of things. As I mentioned previously, the operator initiates this joint operating agreement among all the working interest owners. Here's just a quick diagram of how these things might be set up in the field. You've got gathering lines. They're going to come to a central point, a common point, and then go into a pipeline. Generally speaking, this pipeline is going to go to a processing plant. So that the gas can be cleaned up as well as natural gas liquids extracted. In terms of how you would connect these, a question might be whether or not you do need compression. That's going to be a function of the pressure downstream into the pipe in which you wish to flow your gas. We have to also recognize that there's going to be costs. The more compression that you use that you have to to boost up the pressure of your well relative to the downstream pipeline, it's done in stages, and there's going to be a cost. A lot of them run on natural gas. Some run on electricity. So there is a cost inherent there, not to mention just the regular O&M type costs. Connect costs. You're going to have to eventually connect your well, and there's usually a fee of some kind. Number two is taps. And then most pipeline companies these days require what's known as electronic flow measurement. They want to be able to see from a remote location how much gas is actually flowing in. And then again, in terms of the point at which you connect to a downstream pipeline, there may be additional treatment that may be needed at that spot, and either you pay for that upfront with a pipeline or a midstream company may do that. There's just a quick picture here of some compressors. This is what's known as a horizontal compressor. The actual pistons that draw the gas in and push it back out are in fact laid out horizontally. Compressors themselves, there are two parts. You've got these large diameter pistons, and those are the ones that draw the gas in and push it out and know it's increased the pressure by using these pistons. And these are driven by a crankshaft. The other part is really an internal combustion engine. A lot of these resemble large diesel engines you might find in a semi-tractor trailer. And as I mentioned before, if you're using natural gas there in the field, then there is a cost of that, the cost of that gas, because you're not able to market it. You are actually consuming it at your pad site. Or if you're running electric compression, there's going to be a charge by the electric utility. The best way to think about these is if you've ever seen one of those little electric black and decker machines you might have in your garage that inflates car tires, bicycle tires, etc. There is literally a little piston in there that's moving in and out at about a thousand times a second. And it is taking the air at roughly atmospheric pressure, 14.75 pounds per square inch, boosting it up to, let's say for instance, in terms of car tires, it may be anywhere from 32 to 40 pounds per square inch. And then just here are some more compressors. The upper left and the lower left, these would be at a well site, at a small well, whereas the upper right would be at a central location, sort of that common point that I showed you in a diagram a few slides back. That would be drawing in gas from multiple wells out in the field. Now the lower right, that's actually a turbine compressor. Turbine compressor is literally a jet engine type of setup with fan blades and everything else running at a very high speed using natural gas. Now a turbine compressor generally is going to be used at a processing plant to circulate the gas around through it. This would be a very, very large scale version of little turbines that might be added to car engines or turbo diesel type of engines.