 The first step in this logistical path of natural gas from wellhead to burner tip occurs at the wellhead itself. The pipe needs to be laid either to a central delivery point, which is a gathering point where multiple wells are connected directly to a transmission pipeline, or it's connected to the inlet side of a processing plant because it needs to be processed to remove contaminants and valuable heavy hydrocarbons. Here's a simple schematic of the natural gas industry very similar to the logistics schematic that you've seen earlier in the lessons. Another schematic here, breaking down the sectors. Upstream, you've already studied a little bit of that. We deal with the midstream and downstream. Midstream primarily being comprised of the gathering and processing. The downstream being transmission, storage and distribution. This particular diagram illustrates the names given to the industry players along the same path. So at the wellhead you're going to have operators and producers who own an interest in the wells, processing plants, again comprising part of midstream gathering and processing, transmission pipelines and storage facilities, the local distribution companies or gas companies, and then ultimate end users such as residential, industrial and commercial users. At the wellhead we are most interested in production and the term we use is deliverability. How much gas can the well produce in a given day? That represents the sales volumes. We're interested in that because that tells us how much gas every day we can market on behalf of the producer. And there are ways to increase this volume to increase the deliverability. There are multiple means with which to do that. Horizontal drilling is one that almost everyone is familiar with these days. It's the most popular method. You are horizontally perforating a reservoir to extract more natural gas from it than you would with a straight vertical pipe. In field drilling if you've discovered a well that successfully produces, you go ahead and drill another well in that same area down into that same reservoir. Recompletion is to go into the well if it's declining and use the same completion methods you did for initial production and see if you can enhance the production. Fracturing or fracking as it's most commonly known is to go in with various methods, break up the rock, sandstone, limestone, whatever the formation is to extract more minerals from it. We'll talk a little further about compression. This basically is a method whereby you can suck more gas out of the ground. And then lastly you can add, or excuse me, connect to a low pressure connect. Let's say for instance the pressure in your reservoir runs about 150 pounds which is not very much. You could have that well tied into a pipeline that more than likely will go into a processing plant and let's say that particular pipe may only run in about 50 pounds. So your 150 pound reservoir pressure well will easily be able to flow into the 50 pound downstream line. The issues at the well head, these are things that we need to figure out. What is the BTU value? After all in energy we are selling heat content in British thermal units. What's the level of water that's naturally occurring in the well head? We have to remove that. It has no heating value and pipelines will not accept above a certain level of water. Any types of corrosives, a lot of sulfur naturally occurs in the wells which can be converted into hydrogen sulfide which is a corrosive and a pollutant. Nitrogen in the gas stream just takes up space, it has no heating value whatsoever. The same with carbon dioxide, it's just taking up space in the pipe, has no heating value. The question has to be asked, is the gas processable? If the BTU content is high enough, that indicates an opportunity to extract the very much needed and profitable natural gas liquids. Also the question has to be asked, does it need processing? If it has water vapor, if it has corrosives in it, if it has nitrogen, if it has carbon dioxide, those have to be removed or at least reduced in the stream so they will have to be processed. And any type of other treatments, one of the ways to remove sulfur is through an amine process. So again each of these questions has to be asked at the well head because we're dealing with a raw stream and the appropriate processes have to be put in place to make this gas commercial grade or marketable. So who are the participants at the well head? Producers are also known as working interest owners. They haven't invested in the well. These can be individuals, they can be equity companies, they can be mutual funds. Anyone who chooses to invest in a well is known as the producer. They share a working interest. Working interest is just that. As long as the well is producing any initial, excuse me, any additional investments or expenses, all of the working interest owners share in that. In return they get a percentage of the reserves that is also known as their entitlement. They are entitled to that amount of natural gas out of that reservoir during the life of the well. The operator is also a working interest owner. They too have a percent of the reserves, which is known as their entitlement, but they're responsible for the day to day operations of the well and also what we call well balancing or allocations. Each producer has a right to his percentage of the reserves in that reservoir and it's the operator's job to ensure that everyone gets their fair share of the natural gas regardless of when they choose to produce it. They're also the initiator of a joint operating agreement. There has been a link provided to a sample of a standard joint operating agreement out on the website. I would encourage you to read through that. I will not hold you responsible for it, but it gives you a clear understanding of the relationships of the parties at a well. And if any of you ever decide to head down the path of being landmen or landwomen, it's going to be an agreement that you'll use constantly. Here's a diagram of a typical gathering situation. As you can see, there are three different wells. They're connected by gathering lines to a central delivery point. This point of sale is into the transmission or downstream pipeline. The custody meter merely is a term used to indicate the point at which this gas is transferred over to the control of the downstream pipeline. And so it's measured at both parties so that the amount of gas given to the downstream pipeline is a known number. Now in terms of gathering and connecting the wells, there has to be the question, as I mentioned earlier, does the well need some compression to draw out more gas and itself could freely flow based on the pressure in the reservoir? There is going to be some cost. Compression is done in stages. And so with each day, there's going to be a cost. And the more stages that are required to pull the natural gas out of the reservoir, the higher the expense. This is one of those points of the value chain that I mentioned before. You have whatever cost at the wellhead based on the exploration and production costs. And now if you have to have it gathered and that compression is needed to be supplied to the producer, this is a cost that's going to be added to that initial price. One of the determining factors is the downstream pressure. Where is the well being delivered? Is it being delivered into merely a gathering line, or is this particular well being tied into a transmission line where thousands of supplied sources are going into it and the pressure on that is going to be very high. And then connect the costs. Pipelines charge fees for wells to be connected into them. It's referred to as tapping a well. They will also have the requirement for electronic flow measurement. So the pipelines can see how much gas is flowing from that particular well, which helps them monitor their overall systems, pressures and flows. And as we mentioned earlier, is there some type of treatment that needs to occur prior to the gas getting into the transmission system? These are all costs that we will incur to get the gas just into the transmission pipelines. Here's a picture of a typical compressor being loaded onto a skid. Compressors are basically very large two-part engines. The compressor itself has large diameter pistons. They're on a crankshaft similar to the internal combustion engine. They are most like large diesel truck engines. When these pistons turn, instead of drawing in air and gasoline and internal combustion engine, they are pulling in natural gas and pushing it back out, repeating this process in essence to increase the pressure of that gas into the downstream piece of pipe. The majority of them are naturally natural gas fueled. You have natural gas right there at the site and so it might as well be utilized as a fuel source. There has been an increase in electrical compression. In a natural gas-fired compressor, you know what the cost of the natural gas is. If you're using electric compression, then you have to determine what the kilowatt cost is that the utility is charging you. More pictures of compressors. In the upper left, we have a small compressor that would be mounted at a wellhead. In the lower left, an even smaller compressor at a wellhead. In the upper right, this would be the size of compressor you would have at a central delivery point where the compressor is drawing gas from multiple wells out in the field and delivering them to a processing plant or a transmission facility. In the lower right, this is a turbocharged or turbine compressor, one of the most powerful and highly utilized compressors for large volumes or for large pressures. These are also used on the transmission pipeline systems themselves to push the gas along from the producing fields to the markets.