Transcription
Um, I will just go back and, uh, retrace my steps. Uh, so the completion system must provide an effective means of producing oil and gas. And there are three things that are very, very basic requirements in our completion design. The completion design system should provide an efficient and, uh, production. That means it should meet your production objective in terms of how much barrels of crude you can produce in a day. It should have a very safe production. That means it should protect the environment. It should not have uncontrolled exposure of hydrocarbons to the surface. But also, it should provide well security. That means, uh, everything is securely contained in your wellhead, and there is zero, uh, it, it is sealing perfectly. And then it should also be an economic, uh, completion design. That means you cannot have a very, very expensive completion design, uh, while your production is not matching and your ROI is just, is just spread over a huge period of time. You want to have a very short ROI, uh, to maximize your revenue.
Completions history and evolution. Um, it, it's, it's not a very new technology, but it has evolved dramatically in the last one century. The first wells that were dug in, in Caspian Sea, these were shallow wells, and that's where the first completion, uh, was deployed. But the major advancements actually happened in the early 1900s, where the gas lift, first gas lift devices were, were, um, invented. First dual completion happened. The ESP was invented in, uh, in 1926. And all of these technologies actually resulted in us, uh, producing more effectively, more efficiently from these wells. We could now dig deeper. We could now, uh, complete these wells deeper. And, um, with the advent of artificial lift technologies, um, in your completion design, uh, that actually meant that these wells that were drilled could produce for a longer period of time. So we actually had a very, very, um, now, it was more efficient and economical to produce from those wells which were previously deemed uneconomical. And then finally, in 1969, when the commercial coiled tubing services were introduced, that's where, uh, um, a huge boom in the oil and gas industry was actually experienced.
So the factors affecting the well, uh, are actually, there are three things that actually affect the well performance. Uh, the first and foremost is reservoir boundary. This is usually estimated during our appraisal stage, in which appraisal wells are drilled and geoseismic, uh, studies are conducted, so that you, you can actually determine the, the reservoir boundary. You can know how deep the reservoir is, how extended the reservoir is, what are the, what are the different boundaries of the reservoir. Uh, this can be estimated. The reservoir properties, that how much oil, how much gas, how much water, how much H2S is downhole, this can be measured. But the only thing that can be controlled is your completion design. So, so since the completion is the only area which can be controlled, there is an obvious need for the completion design and installation process to be carefully conducted. And this can be explained through this, uh, uh, flow versus time graph. This is a very, very simple flow versus time graph, that, but most of the length of the of the oil wells or reservoirs actually will follow this kind of a graph, where you have a very high flow rate initially when the well is drilled and well is completed and it is producing, just because there is just so much reservoir pressure that is pushing all that fluid to the surface. But over the period of time, as you will start depleting your reservoir, the, the flow will go down, the pressure of the reservoir will go down. And and now you, you have to make sure that your completion design is suitable for that entire time period, all the way from the well completion to, uh, to well abandonment.
So, uh, so the completion, the decisions we take at the, at the stage of completion, that selection of downhole packer, the selection of tubing, the selection of wellhead, it, it actually makes a lot of difference over the period of lifetime of the well.
In our previous lecture, we talked about the base rock and cap rock. Uh, I'm not going to go into a lot of details on that, but just a quick, uh, recap. Cap rock is essentially a non-permeable rock. Uh, this is the rock that will prevent the migration of oil and gas, uh, into a reservoir which is higher than the cap rock. So effectively, what you want to do is that you want to have your completion deployed all the way through the cap rock into the base, uh, reservoir or your producing reservoir. And you want to make sure that, uh, all your perforations, your zones, are actually, uh, perforated in your base reservoir.
And there are, there are different types of, uh, completion designs. The one which you see on the left-hand side, this is a very, uh, completion, straight vertical well drilled, no, uh, uh, no multilaterals or no deviated wells, no horizontal well, just a simple completion. This is how they used to do it early on in the early 1900s, all the way to, I would, I would, I would say even to the 1950s and 60s, where they will deploy a rig, they will drill straight down, and they will produce it from the reservoir. That's it. But it had a lot of limitations. And one of the first limitations which you can see is that once you have depleted that zone or once you have depleted the reservoir, now you have to drill more wells. So they were drilling more wells just to produce from the reservoir. While now the pro, the technology has evolved to a point where you don't have to drill vertically. You can actually drill what we call, on the screen, I will just point it with the pointer, uh, this is what we call a horizontal well. So effectively, what we'll do is you will come straight, and then you will, uh, what we call a kickoff point, where you actually start drilling horizontally. Now, what actually happens is that you can actually drill one well through the entire length of the reservoir, and you will be able to deplete it completely, not completely, but to a lot of extent. Um, and this has actually resulted in us drilling less wells, uh, while actually maximizing the production from the reservoir.
And this is another, this is what we call, uh, an angular drill or or angular completion. Um, effectively, you are going at an angle. It's not very common anymore, just because of the advent of the horizontal wells. We don't do it. But in the early 1990s and 1980s and 1970s, we, they were, they were actually drilling a lot of angular wells, just because you can see that it can actually increase the contact area with your reservoir. So you can produce better with, with the previous technologies.
So, uh, the function of a completion. There are a couple of functions of the completions. Why it's, why it's there. Uh, the first and foremost is protecting the casing. And, um, and I will show you in, in the next slide, uh, you have a casing, and then you have a tubing. Uh, effectively, casing is there when you are, you are drilling the well. So you will deploy your casing until the well is completely drilled. Um, once that is done, once you go to the completion stage of the well, you will deploy your, your tubing. Um, effectively, what you are trying to do is that you are trying to, uh, with your whole completion design, you are trying to make sure that you protect your casing. Number one, we don't want it to erode, because behind the casing, there is, uh, cement that is kind of, uh, acting as a barrier between the, the formation and the casing. Um, so you don't want to erode your casing, because it can result in a lot of other problems. You don't want it to be corroded as well. Uh, a lot of times what we do is that we use a lower grade of steel in the casing, um, and then we want to make sure that there is no contact of the formation fluid with the casing, because it can result in corrosion and erosion.
Tubing string removal. That is the second most important part of the completion. That means you want to remove your tubing string whenever you have a requirement for a workover. Sometimes you do workovers to, uh, have additional perforations. You do workovers to clean the well, for snubbing the well, for different coiled tubing operations, for milling operations. So you want to make sure that you have, or to remove the artificial lift, for that say. So you want to have to make sure that your tubing string design is removable, it's modular, uh, it suits a replacement or a workover.
And safety and contingency. Um, there are different types of safety devices that we deploy as a part of completions. One of them is called a safety valve. We are, we are going to discuss more about the safety valve, because it's an entire length of topic. But effectively, what you want is that your completion design should take into effect, uh, the requirement for a safety valve. It should make sure that you can actually deploy a packer downhole, and you can also kill the valve if there is a requirement.
And last but not the least is production control. Uh, all the components should provide you the, the flexibility to control your production. Uh, that means sliding sleeves, that means different types of flow control valves. You want to, for example, if you want to reduce your production or cut off your production, your downhole component should provide you that flexibility that you can actually curtail your production without having to deploy a plug or having to pull the tubing.
Different types of completions. Uh, type. There are two types of basic completions. One is called openhole completion, and one is called cased-hole completion. And the effectively the difference is very simple. What, what you will see in the openhole completion is that, uh, you will drill the well, you will deploy your casing, and then you will cement it. And below the, below the casing, there is just a big open hole, which is not secured by any liner, which is not secured by any, uh, uh, production casing. It's just, uh, open. Uh, what results is that it can actually result in unimpeded flow into the wellbore from the reservoir. But it can also result in other complexities. For example, uh, your hole can actually cave in, and it will reduce your production.
The other type of completions available is the gravel pack completion. There is a gravel pack that is at the very bottom. This gravel pack is actually packed with, uh, fine sand. And the reason for that is that you are trying to reduce the, the debris and the, the perforation cuttings back into the, to the wellbore, because it can actually reduce, uh, your production. So gravel pack completions, although were not very common, uh, they are still, they still kicking around. So you have to be cognizant that there is something which is called gravel pack completion.
Now, in contrast to the openhole completions, the, the closed hole completion will have casing going all the way through your zone. So it could be either cemented casing, or it could be either cemented liner. A liner, in simplistic terms, is also a type of casing, just because it is too small compared to a casing, it is considered a, it is called a liner. But your liner and your casing, in case of a cased-hole completion, is actually cemented all the way to the bottom of the well. Uh, and then you have your perforations. And these perforations are actually made inside the casing to make sure that your formation fluid can actually go from the formation through your perforations into your casing, and then it can be produced, uh, through either the casing flow, or either through the tubing flow. So cemented casing is the simplistic, uh, type of cased-hole completion. And after that, there is a cemented liner, which is also a type of cased-hole completions. But that's not just it. There, it actually goes more than, more than just these two types of cased-hole completions. And these are some of the other types of, uh, completions.
Cased completion. We already talked about it. Uh, your formation fluid will go through your, uh, perforations into your casing. You're flowing through your casing. This is very common for the formation fluids which are not very aggressive. There is not a lot of H2S, there are not a lot of paraffin that can actually, uh, um, clog your tubing or can result in scale buildup. Just for a very simplest kind of a well completion, in which there is a high water cut, that means you may have water cuts which are all the way to, um, 90, 95%.
Then you have your liner completions. As I mentioned, a liner is just a type of casing which is much more smaller than a conventional casing, and it is cemented all the way to the bottom of the hole. And then you have simple tubing completions, um, in which the production tubing, which you can see over here, is deployed, and you will have your perforations, and then the formation fluid, rather than flowing through the casing, it will flow through the tubing.
Taking it one step further, you have your tubing and packer completions. Effectively, you will deploy a packer downhole. This can be a hydraulically set packer, this could be a slickline set packer, or an electric line set packer. Effectively, what happens is that, uh, the formation fluid will come over here, and when the, the packer effectively seals the annulus, which is the space between your casing and the tubing. And, um, effectively, what is happening is that your formation fluid does not come into contact with the rest of the casing. It flows through the tubing and goes to the topside. Um, this is done for multiple of reasons. Some of those I explained earlier. Sometimes the formation fluid is so corrosive, or there are presence of corrosive elements in, in, uh, in the produced fluid, that, uh, it can actually erode and corrode your, um, your casing. So you don't want that to happen. So you deploy the packer, which provides the sealing, uh, between your casing and the tubing.
And then we have tubing and packer completions with the tailpipe. Tailpipe, effectively, is just an extended pipe, uh, which you can see over here. It deploys much more below the packer. Um, sometimes it is used for multizonal completions as well. And finally, it's the tubing with a packer element, uh, which is pretty much similar to this one, uh, but it can actually provide more flexibility in terms of production.
Single zone completions versus multizone completions. We already talked about the completion with the single packer. This is called a single zone completion. So this is effectively a single zone completion where the perforations are actually located below the packer. Um, and these perforations are made in the casing. Um, the packer is deployed, uh, above the perforations. Then you have your tubing string. Annulus is, talked about annulus. Annulus is the space between the casing, which is what you see in the black out in the at the OD of the well, and between the tubing, which you see on the ID of the well. So this is just that annular, annulus, or the annular space between the casing and the tubing. You have your production casing, which is cemented, and then you have your surface casing. Uh, surface casing is usually, uh, deployed at a very shallow depth. It doesn't go very deep, and, uh, it is much more bigger in diameter compared to the production casing.
Multizonal completions effectively have two or more than two, uh, two packers. And what you are trying to do is that you are trying to produce from from more than one zones. So this is your zone one, this is your zone two. The fluid from The Zone one will come from here, go to the tailpipe, into the production tubing, and that then it will commingle with the fluid that is coming from zone two, and then they will go to the topside. And what is actually happening is that you are producing from zone one, zone two, and the flow is actually comingled at only one single point. It is often used in reservoirs with complex structures, and production characteristics. That means, um, your one reservoir production reservoir would be at a higher pressure, and the other one would be at a lower pressure. And what you don't want is that you don't want, like, the production from the higher, uh, pressure, uh, reservoir going into the lower reservoir. So you actually, uh, let it complete through dual packer.
The efficiency gained by capability to select and control production, uh, of the individual zones. That means you can actually, for example, if you want to reduce production from the lower zone, uh, you can have, uh, the flow isolation valve at the, at the bottom, where you can actually stop the production from the lower zone, and you, you are just producing from the zone at the top of the, the first zone.
Completion elements. One of the first completion elements that we talk about quite a lot is your, um, tubing and drill pipe. Tubing is, uh, it's just a piece of tube, uh, which is made from specialty alloys. Um, what you want to do is, selecting the grade of the alloy, to match with the, with the reservoir characteristics, as well as the, the depth of the well, because, uh, alloys with a higher grade, with higher yield strength, with higher tensile strength, can actually be deployed in the deeper wells. With the alloys with the lower yield strength, can be deployed on the shallower wells.
So the tubing string specifications. Tubing generally provides a primary conduit from the producing interval to the wellhead production facilities. That means from your pay zone all the way to your, to topside. Therefore, a proper selection, design, and installation of the tubing is very important as a part of the completion system. The size and dimensions of the tubing must be sized to enable efficient production. That means you want to maximize the size of the tubing. You don't want to have a very small size of tubing, because it will constrain your production, just because of the smaller ID of the tubing. Um, so it should be selected to, to have an efficient production. The grade of the material, uh, as I mentioned earlier, the string should be designed to prevent failure from the tensile forces. There are a lot of forces in play, especially when you design, deploy a packer downhole. There is internal pressure, there are external pressure, there are tensile forces, there are compressive forces, and sometimes there is a combination of forces as well. So, uh, you want to make sure that, uh, uh, that taken into account the corrosive nature of the reservoir, uh, environment, you are selecting your material grade, effectively, and assembly of the components, uh, in a way that the string must be installed so that you can actually deploy all the components undamaged. That means you can deploy your, your safety, you can deploy your packer in a manner that will not let any damage happen to them, uh, because they actually are there as a barrier. They are used as a primary barrier.
Sometimes the tubing grades criteria are usually determined by API. They are very strictly controlled by API, which is American Petroleum Institute. American Petroleum Institute publishes standards and, and guidelines on how to to select your, uh, tubing grades, as well as, uh, on the tubing grade specifications. Some of those are J55, C75, C95, N80, L80, P105, P110. Um, these are different types of API grades. And sometimes there are special grades as well. For example, C95, C75, which are more designed for the H2S service. Uh, there are higher strength grades available. Sometimes we have grades that go all the way to 110 KSI yield strength. And these are there for more of the offshore production, deeper wells, subsea wells. And then they become very sensitive. Those grades are very sensitive to damage and defects. These defects can occur at the manufacturing, handling, transportation, and as well as hydrogen embrittlement. That means there are very strict controls that are in place when we are manufacturing tubing from the higher grades of steel, P110, C110, uh, for example.
And, uh, tail joints. So tail joints are effectively ends of your, of your tubing. Uh, they can have API threads. They can have premium threads. Premium threads, example of premium thread is, for example, Atlas, Hydril thread, a VAM thread. These are the, the proprietary threads which are developed by, uh, OCTG, which is Oil Country Tubular Goods suppliers. These premium threads actually provide more, uh, better tensile strengths. They provide more better compressive strengths. They are proprietary to the, to the, these manufacturers. Uh, they are sometimes used in, in challenging onshore completions, as well as offshore conditions.
So string design factors. Uh, there are few things that I will, you touch upon. We already talked about the production rate. The flow rate should be compatible, flow with the flow area. One thing other that we actually take into account is that, uh, the pressure and tension that the tubing will go through or will experience during the entire life cycle of the well. It should be less than 80% of the tubular yield. And this is the rule of thumb that you don't want to extend your, uh, uh, the, when you are selecting the tubing, you want to make sure that whatever pressures are available, are going to be downhole, whatever tensile forces are going to be available, that is usually dependent on the length of the string. By length of the string, you will know the tensile forces that the tubing will experience. It is less than the, less than 80% of the tubing yield. And also there, uh, the, the burst and collapse. That means your internal pressure that the tubing can experience, and the external pressure should be less than, um, uh, what is specified in the tubing specifications. It should be compatible with the reservoir fluid. That means it should be compatible with H2S, if it is present downhole, whatever the concentration of H2S, it, it's usually determined in terms of PPM, which is parts per million, as well as presence of the paraffins. And, uh, yeah, the last thing is that one of the key thing which I, I'm iterating again, is the forces and stresses that will, that it will experience throughout the life cycle of the completion. That means we are talking about 20, 30, 40, 50 years in some cases.
Why tubing specification is important for fracking? It's very important because in the fracking, you are pumping effectively a slurry at a very high pressure from the surface to fracture the reservoir. Uh, so size and dimension is very important so that you can actually achieve the flow rates that are required to fracture that reservoir through that tubing. The grade to prevent any failure from the tensile forces, because during the fracking, there can be a lot of tensile forces. And assembly in terms of providing the pressure tight seal, so that you do not have uncontrolled exposure of the wellbore fluids.
Example, what you see on the screen is that it is telling you that for a particular OD and particular weight of the, of the tubing, you are, uh, getting collapse, what are going to be your collapse resistance, that means your external pressure resistance, your internal yield strength, and then what is the wall thickness, and what is the drift diameter. And the drift diameter is another important thing which I'm going to briefly touch upon. Drift diameter is effectively what is the maximum OD of any tool that can actually pass through the tubing. In this case, if we look into 2.857 inch tubing, um, with a weight of 8.7, pounds per feet, the effective drift diameter is 2.65. That means the maximum OD of the tool or maximum OD of a bottom hole assembly that can actually pass through this tubing is 2.65. If you have something which is more than that, it will result in that bottom hole assembly getting stuck in the tubing. So that's very important when we are designing, um, the tubing as well, because one thing which you have to anticipate is that that well can actually go through different workovers over the period of time. For example, you may have to reperforate the well, you may have to relog the well for the production logging, you may have to run different type of tools, if there is artificial lift downhole. So you want to select your tubing in a way that you are anticipating for all of those things that are going to pass through that tubing in the future.
What might happen to the tubing during fracking? During fracking, there are multitudes of forces that can be experienced by the tubing. If there is a packer that is deployed downhole, you can result in a compressive as well as tensile forces experienced by the tubing. So you have to anticipate that when you are selecting the grade of the tubing, the OD of the tubing. And there are four different principles that can cause the change of length of the tubing. The first and foremost is the piston effect. The second is buckling. Then it's, and is accompanied by ballooning and theature effect. And we are going to talk about them in the next slide.
So pressure buckling. Effectively, pressure buckling happens when there is an unequal force distribution caused by a large internal pressure, tubing pressure differential. That means you have higher pressure on the top of the tubing, lower internal pressure at the, at the, at the bottom of the tubing. It can result in pressure buckling. Now, this is actually aggravated by if there, as you know that the tubing is running all the way from the topside all the way to the bottom of the completion. So if there are minor changes in the wall thickness of this tubing from top to bottom, it can also actually amplify your pressure buckling. Minor variations in the wall thickness of the tubular goods will initiate pressure buckling. Pressure buckling only occurs when there is a high internal differential tubing pressure and contributes very little to the tubing length contraction. So the tubing length contraction only will happen if there is a packer that is available down here. So the packer will kind of acts like an anchor, so it will not let your, your tubing to expand or contract. So, so that is very important when you are doing the hydraulic fracking, that if there is a packer downhole or not.
In reverse ballooning, what effectively happens is that you have a high pressure zone at the top, lower pressure zone at the bottom. If there is a packer downhole, it will shorten the string and increase the tension of the pipe. While in case of reverse ballooning, there is a high pressure zone at the outside of the tubing and a low pressure zone at the outside of the tubing at the top section. So what effectively happens is that it tries to lengthen the string and reduce the tension.
The piston effect is effectively a force that is up and down at the end of the tubing. So it actually, it is pushing the tubing up and down. Uh, it happens during the thermal cycles or the, or when the tubing actually goes through thermal cycles. The tubing will contract when you are pushing a cold fluid, for example, a kill fluid, through it, and it will expand when you are trying to push a hot fluid through it, for example, a perforating or a fracking fluid. So if the tubing is restrained from moving, a tensile force will be applied to the packer. That means when I say the tubing is restrained from moving, is that there is a packer available downhole. In that case, there will be a tensile force. If the average temperature of the tubing is increased, that means you are actually pumping a hot fluid through the tubing, then the tubing will actually elongate. If it is free to move, if there is a packer downhole, then the tubing is actually restrained, and in that case, there will be a compressive force that will be applied to the pipe.
I've been talking about packer quite a lot. Let's look into what a packer is actually. A packer is actually what we call a subsurface tool that provides a seal between the tubing and casing, thus preventing any movement of fluids past the sealing point. That means past the sealing point, there will be no fluid going into the annulus, which is the space between the casing and the tubing. Why we are running the packer? There are two main reasons why we are running packer. One is for the production control. The other one is for the intervention. For the production control, we are trying to protect the casing from the corrosive fluid. We have talked about it in the previous slides. It is also resulting to keep off the high formation pressure from the casing. Sometimes the casing cannot handle the high pressure of the formation. So we are trying to isolate that. We are trying to isolate the casing from that high pressure. Sometimes in the multizonal completions, we have seen it is to isolate the production, and the zonal isolation as well. And then, uh, for the intervention purposes as well, for the well testing, for the well repair, for the stimulation. So sometimes we have to deploy completion when we are doing stimulation, where is fracking or or perforating, as well as for the sand control, because, uh, if you will have a lot of sand going between the annulus, if packer is not present, it can actually erode your casing.
These are different types of packers. They can get very complicated very quickly. But some of the basic packer components are the mandrel. The mandrel is effectively your entire packer body. There are two main things. What are what is called slips? Slips are they're just like, uh, very hardened teeths that will actually anchor themselves into the casing. They are just there to, to make sure that the packer doesn't move once it's set. The second most important element is what we call a packer element. This is made up of elastomers, and effectively what happens is that once you set your packer, this element will expand, and it will provide that sealing between the, between the casing and the tubing. And then you have slips at the top of the packer as well, just to anchor it again to the casing. There are different types of ways in which you can set the packer. There is a hydraulic setting. It can be set through the slickline. It can also be set through the electric line or wireline.
Evolution of perforations. Perforations, it's, it's a topic that is not, uh, very commonly discussed out there, but it is very important when we are, uh, producing the wells, when we are completing the wells, when we are producing the wells, because it will actually determine how effectively you are drawing down your reservoir. This is just a quick evolution of the, of the, of the perforations. Initially, in the 1800s, they were just deploying an explosive downhole, just detonate and just fracture the reservoir, just blow the hell out of it. We have gone away from it. We don't do it anymore. In the 1900s, they were mechanically puncturing the tubing. So there, there was this tool that will go down and it will puncture the well. It is not very effective because it can actually just puncture the casing. But as the, as the perforations started evolving, what actually happens is that you will deploy what we call a perforating gun downhole. This gun has explosive charges or shaped charges, um, and they will detonate, and they will actually detonate and create these channels inside the reservoir, um, so that your oil and gas can actually flow into the, into the perforations, into your tubing, and now you can produce. Um, so now we have gone to a point where we are actually perforating to 10 to 30 feet of the reservoir. Initially, it was 5 feet or less, when the perforation, perforating technology first started happening. But now, with the, with the advancements, but we can actually perforate to a, to a greater distance. So, so perforating is just effectively a process of creating a clear channel of communication between the reservoir and the reservoir. One of the things is that this should be achieved without actually damaging the inflow ability of the surrounding formation, to ensure that the perforations do not form a restriction on the tubing. We don't want to damage the reservoir. We just want to create the channels, because if you damage the reservoir, it will result in the advent of debris that will just clog all those perforations, and now you're not producing anymore. So, uh, and this is very critical when you are, uh, that the perforations do not form a restriction on the production capability of the completion wells.
So, uh, perforating gun components. The principal components of any perforating gun or a system includes, uh, a charge carrier. Uh, so there is your primary detonating cord, then there is your charged liner, then your explosive charge, your charge case, a gun body, and then, and what will happen is that once your detonator cord will detonate the charge, uh, it will produce a string of fluid, a string of, uh, it's a very high pressure fluid traveling at a very high velocity that will actually puncture your, your casing into your cement, into your reservoir, into your formation. So the principal components of any perforating gun system will include charge carrier, uh, charge carrier is where your gun components are placed and connected, and your detonators. Um, the detonators are used to initiate, uh, your, uh, uh, the pyrotechnic sequence at the time of perforations. The safety systems are there to allow perforating guns to be assembled and deployed, safely. Uh, are typically attached to a detonator.
So, this is just a very simplistic, uh, uh, example of the perforating gun. These are, this is just an example of, uh, different steps of perforation. You can see the time is over here, 0 seconds to 4, 10, and 17, microseconds. So it's a very, very quick process. Uh, effectively, what happens is that, uh, your detonator cord will actually prime and and detonate your charge. Your detonate charge at a tip, it will start deforming, and the jet tip will actually perforate your casing into your cement, into your reservoir. So it's a very high jet velocity, 7,000 meters per second, very high pressure, because it's a sonic wave, so millions of PSI, sorry, um, at a very low temperature, and the gaseous jet does the work. So effectively, you are not blowing up the well. You are the explosive in a shaped charge form, in a conical shape, uh, is focusing on a very small area in a very short period of time, to create that shock wave and make that, uh, uh, that perforation.
Just, this is just an example of a perforated, uh, casing. Uh, effectively, an extremely high pressure jet, at in a very short period of time, will create that perforation. Then the perforation debris will flow back into the reservoir and flow through the tubing, and, uh, and then you will have your clean, stable perforation tunnel, and it will ensure that your oil and gas is actually flowing at a very, uh, in a smooth manner without any restriction.
There are three types of perforation pressures, uh, or three types of bottom hole pressure conditions that generally occur during perforation. One is called balanced, second one is called underbalanced, and the third one is called overbalanced. Effectively, in the, sorry. So, uh, perforating while the pressure is balanced, that means your bottom hole pressure in the wellbore is same as your reservoir pressure. If it is equal, it is generally not advised to do perforations because it will not offer any benefits. In case of an overbalanced perforation, your well fluid pressure is greater than your reservoir pressure. Then, in that case, perforating with the kill weight fluid volume in the, in the wellbore, after the perforation is created, the pressure within the wellbore acts to compact the. So what effectively happens is that, um, once the perforation will happen in the overbalanced drilling or overbalanced perforation, the pressure in the wellbore will compact your for, uh, your, your perforation cuttings in that area, and it can actually impede your flow. The best condition in which you should do a perforation is what we call underbalanced, uh, condition, in which your bottom hole pressure in the wellbore is less than your reservoir pressure. That means, uh, once you will do the perforations, the formation fluid will go into the tubing, and then you can produce it, uh, without much of, uh, an effort. And it also reduces the likelihood of near wellbore damage.
This is just a, a, um, a visual of how the perforation is done. The perforating gun is deployed, it is primed, it is charged, and it is, it is fired. Your perforations are created. It will fracture the reservoir around, uh, the perforations. Then, uh, you actually frac it. That means you will push the proppant into those fractures to prevent them from closing down.
So, general production concept. There are two types of wells, um, in terms of, uh, production. There are wells that are flowing naturally, and then there are wells that require artificial lift. Only 6% of the wells in the world are actually flowing naturally. That means 94% of the wells actually need some sort of artificial lift system to push the formation fluid all the way to the surface. When the well fluid is actually flowing naturally, your P not is less than your PWF. So what is your P not and what is your PWF? Your PWF is your, what we call, formation pressure, and P not is your bottom hole pressure. That means in case of the well that is flowing naturally, your P not, or the wellbore pressure, is less than the PWF. That means your well, your, uh, your formation pressure is more than the wellbore pressure. But in case when your P not becomes greater than the, than the formation pressure, then you need to deploy artificial means, artificial lift system, because now the well cannot flow naturally.
So this is just an example of what we call a tubing performance curve, TPC, between the natural flow and the artificial lift flow. Although the artificial lift systems may be installed later in the life of the reservoir, there is a clear benefit in preparing for the artificial lift system when preparing for the construction of the well. That means you need to plan ahead for this. Relatively small modifications to the well configuration can provide the flexibility and enhancements which benefits the long-term production capability and capacity of the well. So these are all the factors that need to be considered when you are constructing the well, when you are selecting and designing the artificial lift system for the well.
There are different types of artificial lift methods. The first and foremost, what is very common around the world, is the rod pump. We are going to see what the rod pump looks like in the next slide. Uh, this is followed by the gas lift system, which is one of the simplest systems of artificial lift. ESP, or electrical submersible pump, is the, it's not a complicated, but it's, what it is, one of the most complex methods of artificial lift system, because it requires deploying, electrical submersible pump downhole, through the tubing. And then piston pump, jet pumps, plunger lift, these are other systems of producing a well artificially without incurring a lot of capital expenditure. These are very economical means of artificial lifting.
So rod pump is perhaps one of the most common type of artificial lift system. You have seen it around the world. It's like kind of an icon of the oil field, oil patch. You have your prime mover, which can be a gas engine or your, uh, or your electric motor, uh, effectively running a reciprocating pump. This is what we call a walking beam. This is a stuffing box and polish rod. Stuffing box is, it provides sealing, uh, so that your wellbore fluid do not get exposed to the surface. And then your production valves are usually on the, um, at a tee, so that you can actually produce it and get your production fluid to a separation facility. So that was the, the, the surface, uh, system. That rod pump, or that, uh, beam pump, is actually connected to what we call a rod pump. And rod pumps account for almost 60% of the onshore artificial lift completions. It's a very economical method of producing oil and gas. Um, and it is deployed very widely around the world. It does have some limitations. Although it's very economical, it is maintenance intensive. That means you have to maintain all the surface, uh, uh, surface infrastructure that rod pump. It has a gearbox, it has a motor, it has sometimes, uh, what we call, uh, engine as a prime mover. So, uh, uh, it is maintenance intensive, and it is mostly deployed in the vertical wellbores. If it is a horizontal wellbore, then it is not a very suitable method of artificial lift. So it has some deployment efficiency limitations as well.
Gas lift is another method in which a gas lift valve and a mandrel are deployed as a part of your tubing. Effectively, what happens is that you will press, you will actually push a high pressure gas through the annulus, uh, and it goes through the gas lift valve. It will commingle with the fluid. It will mix with the fluid. It will lighten the fluid column. And then once it will start lightening up that fluid column, it will push it all the way to the surface. It's a very, very reliable method of completion. It is very economical. It is deployed onshore, offshore, just because it's so reliable. But that would mean that you need to have a surface compressor, uh, on the topside, uh, to inject that, uh, that, uh, high pressure gas. It is wireline serviceable. That means you don't have to actually pull the tubing. Um, so it is, uh, it is very economical to do a workover on a gas lifted well. It has few mechanical components. That means it is reliable. Very less mechanical rotating components. And it is very tolerant to sand and, uh, debris.
And the other last method of artificial lift is the ESP, or electrical submersible pump. Effectively, it's a motor with a pump downhole, completely submerged in the formation fluid, which is being run through an electrical motor, which is also downhole. The electrical motor is actually connected through a cable running from the motor all the way to the surface. It is actually clamped along the length of the tubing. Um, and then what effectively happens is that your pump, your motor will run a pump, and your pump will pump, will push the fluid all the way to the surface. It is also a very reliable method. It is now widely deployed offshore as well, just because it can actually produce a higher flow rates. Uh, it does accompany higher installation and operating cost. In terms of operating cost, just because it is being run by electricity, so you need to account for that, uh, additional electricity consumption, uh, when you are designing your surface facilities. And it is suitable for low gas to oil ratio wells only. If there is a high gas to oil ratio wells, then the more suitable method is either rod pump or the gas lift.
And then, uh, one of the, although it's becoming less and less common, these pumps are becoming more and more reliable, but initially when they were deployed, um, there were reliability issues as well, because the electrical components can get damaged. And last but not the least, wellhead configurations. Wellhead is your, uh, some some areas call it a Christmas tree, some people call it wellhead. Effectively, your wellhead is anchoring your, it, it has your casing hangers, it has your tubing hangers, it has all the flow control valves, so your master valves, your wing valves, your swab valves, and it is containing all that pressure within, uh, within this wellhead configuration. So, this is the last piece of completion that you should be, uh, putting a very keen eye on and ensuring that it is actually selected in a proper manner.
I think that's pretty much it. Okay, thank you so much, San Ali. Now it's time for questions. Anybody? You can raise your hand by going down below and under reactions, you'll see a bar to raise your hand, or you can ask a question in chat. These are technical things. These are technical issues. Do you have questions? Uh, well, then I would say, San Ali, do you have a question that you would like to ask everybody? And then they write their answers into chat. Just again, yeah, sure. Uh, so there were types of completions that I mentioned in my presentation. If you can name three of them, that would be awesome. Name three of the types of completions and write your answers into that. If you can, if you can remember one or two, write those. If you can remember three, write those. Write down what types of completions you remember from the presentation, or what do you think is the most important completion? What do you, what do you remember is the most important completion? Do you see them there? That's just two of them. I see two of them on the screen right now. Yeah, in the previous slide though, we saw a couple more. Yeah. Leonard says, the new one with more holes is interesting. So this is what we call a multizone well, a multizone completion. This takes some study to really understand. I would suggest coming back here. We go. Anna says, openhole, linear, and perforated. Yeah, so I think, uh, that is, so that is correct. Uh, a openhole completion is, uh, is this one in which you don't have a cemented casing at the bottom. And then linear completion is, um, like a, a, a cemented, it is a, what we call a cased-hole completion, but with the liner at the bottom. So, yeah, that is correct. And Calib, last time you mentioned deviated well. Can we use the types of completion with deviated wells? 100%. You can use these completions with the deviated wells, especially the completions that include packers. Yes. And where's the perforated? Did you, did you explain the perforated? Yeah, so these, the perforations are usually below the packer. There you go. As you can see. Leonard says, I would like to know the requirements for carrying out this type of completion and on what type of soil is it recommended? It depends on multiple factors. Um, one of the first thing which I can tell you, this type of completion is usually more in, um, areas where you have corrosive well fluid. So you are trying to isolate your casing from that corrosive well fluid. Um, and if you have a very high formation pressure, um, because if your casing has a very, sometimes you don't want to expose your casing to a high pressure, um, because casing, because of the larger surface area, has a lower, uh, uh, specification in terms of, uh, internal pressure. Uh, so in that case, you sometimes deploy a packer to isolate that pressure, and then you produce it through the tubing. Any other questions, bro? Hello.