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 wellhead 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. 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 oil, water, and 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 sort of 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. 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 wellheads. You have the processing plant, which is your midstream companies-- they're 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 wellhead. 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 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. When we talk about working interest donors, 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 donor.
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-- these are the sales volumes, again, so we want to know 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 in-field drilling-- go ahead and drill an offset well.
Wells that start to decline-- there can be a recompletion. Now, that can be two different things. Recompletion 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.
Acid 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. Now, 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.
And 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. And so a couple of things here initially.
The Btu value-- this is what we're after. This is what we sell. It's the heating content, a British thermal unit. That's the amount of energy required to raise 1 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 to 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. And so you don't want these inerts in there because you want to fill that pipeline up with as much heating content as you can.
And 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't 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 I've already mentioned-- these are your wellhead participants. A producer has a working interest in the well. They're known as working interest donors. That means-- let's say, for instance, a particular well-- you had 10 owners. Everyone essentially contributed 10% of capital up front 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 recompletion 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 of the natural gas well. And so we refer to that as their entitlement.
As I mentioned before, the operator is also a working interest donor. 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 a equal basis at the end. Otherwise, this is-- we have a considerable number of lawsuits over these types of things.
And 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. And that's going to be a function of the pressure downstream into the pipe in which you wish to flow your gas.
And then we have to also recognize that there's going to be costs. The more compression that you use that you have 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 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. These are referred to as 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 up front, or the pipeline or a midstream company may do that.
Here'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 you back out are, in fact, laid out horizontally.
Compressors themselves-- they are two parts. You've got these large-diameter pistons, and those are the ones that draw the gas in and push it out-- in other words, increase 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 & Decker machines you might have in your garage that inflates car tires, bicycle tires, et cetera. There is literally a little piston in there that's moving in and out at about 1,000 times a second, and it is taking the air at roughly atmospheric pressure-- 14.75 pounds per square inch-- and 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. It would be drawing in gas from multiple wells out in the field.
Now, the lower right-- that's actually a turbine compressor. A 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 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.