The consolidation process and the overburden pressure forces water out of the shales. Relief of the confining force and re-exposure to water causes the water to adsorb very strongly onto the clay surfaces. The following changes also occur.
FUNCTIONS OF A DRILLING FLUID Drilling engineers know that muds have many functions in the drilling operations. At any one time in the operation, one function may be more important than the other functions for that drilling interval, which is why a mud program is essential in well planning. Some publications may list ten to fifteen different functions of a drilling fluid. Many of these are variations of the same function.
An excellent animation of Himalayan formation, featuring captions that date events in the formation of the Himalayas. Shown as a cut-away view of the earth, it's possible to see not only the continental collision, but also the mantle and the mountain root that is created in the collision.
Adjustable Cone technology enables the cone to change diameter during the expansion process. This capability allows the expansion cone to adjust the wellbore restrictions in downhole applications.
The current technology for drilling oil and gas wells is limited to using neither jointed pipe or coiled tubing. Reel revolution Limited have developed the Revolver: an API certified rig combining the benefits of coil tubing drilling with the ability to rotate the coil up to 20 RPM.... Clockwise or Anticlockwise.
In addition... the revolver is equipped with a snubbing unit which means it is entirely self-sufficient and can prepare and complete wells underbalance and overbalance. The Revolver is capable achieving the ultimate underbalance drilling goal of... "Underbalance for the life cycle of the well"
Watch video for more illustration:
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The technical background:
The revolver will be rigged up and operational within six hours of arrival upon location. The revolver is ideally suited to underbalance drilling with the enhanced well
Control features presented by coil tubing drilling. But it is not limited by frictional lockup, hole cleaning issues, and waits to be transferred. In addition, the revolver uses the existing BHA technology, therefore, driving down the price and raising the efficiency to levels never ever experienced in our industry before. The revolver trips four times faster than a conventional rig utilizes the same crew sizes as traditional coil tubing drilling operations and enables coil tubing drilling to overcome the limitations that have been holding back its implementation.
The revolver can be used with any underbalance separation unit. The heart and soul of the unit is the counterbalance in reel unit. The effective weight of the reel will vary as the coil tubing is pulled into and out of the well. The counterbalance moves automatically to maintain the hole assembly in perfect dynamic balance. Reel revolution have also developed a fully integrated UBD equipment components installed on a single trailer which brings enhanced efficiency to the revolver, reduces rig up times and crew sizes. The BHA can be deployed as the example using a lubricator for underbalance applications.
A number of BHA options are available from standard ppm applications using either the mud pulse technology or EMWD options for a variety of drilling applications.The connection to the coil tubing is made and pressure-tested. The BHA is run into the well to begin drilling. When tubing rotation is required, the reel and therefore the coil tubing can be rotated up to twenty rpm. If reactive torque is an issue, then the reel can also be rotated to the left. While directional drilling, rotation can be halted to achieve the necessary change in well trajectory. Once the necessary correction has been achieved the tension section can then be drilled. All of the tripping drilling is performed without connections thus maintaining steady-state downhole pressure conditions and preventing downhole pressure transients from potentially damaging the reservoir and negating the benefits of underbalance drilling. "The revolver is truly an underbalance drilling machine"
Surface pumping systems are ideal for injection and many other high-pressure applications. SPS incorporate the most dependable downhole component of any ESP. For pumping element, an SPS comprise industry standard electric motors: fifty and sixty hurts to pull speed, low in medium voltages, NEMA, above NEMA and I.E.C motor frames. The customer preferred brand in closure or bearing type and any available motor options can be accommodated. Natural gas or diesel engine driven SPS can be supplied for remote locations without a convenient electric supply. The motor is connected to the bearing housing or thrust chamber via an industry standard grade or gear style flexible coupling. One front in two rear ball bearings are lubricated by oil rings as shown in video. This method minimizes the volume of oil in the housing which in turn reduces operating temperature and extends run times. The bearing housing has a small number of moving parts and requires only occasional oil changes. Bearing housing modules can be replaced on location with minimum downtime. An adapter is located between the bearing housing and the suction chamber; this provides a physical opened atmosphere separation between the pumped fluid and the bearing housing.
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In the event of leakage of pump fluid from the suction chamber, fluid would be expelled through openings in the adapter and would not enter the bearing housing. Also shown in the video, a separate step shaft is bolted to the end of the bearing shaft by incorporating this step shaft. Replacement of the shaft is possible without having to replace the entire bearing housing. The suction chamber design provides minimal restriction to flow to assist suction or N.P.S.H. characteristics. SPS requires only one mechanical seal which is located in the optimum location within the suction chamber. The seal is exposed only to suction pressure. A wide variety of mechanical seals are available to suit the application and suction pressures up to three thousand psi. Single, double, and tandem API 682 cartridge seals with appropriate API flush and quench plans are available.
Cartridge designs incorporate would group patented front pullout design which simplifies seal replacement and reduces downtime. Between the suction chamber in the pump element, a pump adaptor and a spline pump coupling facilitate access for easy replacement of mechanical seals. The pumping element is the heart of the surface pumping and many sizes are available to match flow and pressure requirements. Various configurations of material options are offered to ensure compatibility with corrosive and erosive liquids or liquefied gases. Pump elements are supplied as modules with bolted connections and spline shaft and they can be easily replaced in the field. The discharge had bolts onto the pump element and his size to suit flow and maximum discharge pressure. Standard connections to customer piping is via an ANSI B16.5 lap raised face or RTJ flange to simplify flange to flange alignment. All SPS components are mounted onto a patented skid which has been designed to capitalize on the flexibility of SPS multistage centrifugal pump technology. The skid is easily modified to accommodate any future changes to the motor and pump. The oil production process described is continuous and the operation of all the downhole pumps depends on the reliability of the surface injection pump. Since the late 1980s, producers have increasingly chosen to use the proven and dependable downhole pump technology for surface pumps over older technologies such as reciprocating plunger and split case centrifugal pumps. Producers are embracing the benefits of ESP's SPS surface pumping systems, reliability, extremely low a lifetime cost, minimal routine maintenance, negligible downtime during necessary repairs, and flexibility for changing operating conditions. The same benefits proven in oil production make the SPS ideal for a wide variety of high pressure pumping applications such as jet pump power fluid, mine dewatering, dust suppression long wall hydraulics, pipeline booster and gas services such as CO2, NGL, and LPG.
Reservoirs Fracturinghelps maximize production from unconventional gas reservoir. The primary goal of fracturing is to create a pathway for hydrocarbons to flow from the reservoir to the wellbore. Recently, we have introduced technology that enables achieving and maintaining a highly conductive fracture for improved long-term production. through ongoing research also learned how the fracturing process can damage the formation in the vicinity of the fracture face resulting in reduced gas production and increased water production .when the fracturing fluid initiates and extends fracture and then carries proppant into the fracture, water is drawn into the formation , sometimes several feet into the rock porosity. This movement of water into the formation is due to the capillary effect. The mineral grains in the formation are randomly sized and shaped. This results in voids of pores between the grains. These pores act just like a straw or capillary tube but on a microscopic scale.
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When fluids flow into the pore spaces, they are held there by capillary pressure and surface tension and can block formation gases from passing into the wellbore. Here is an actual video of fluid trapped in the porosity of formation rock. The fluid is under pressure but the capillary pressure exceeds the pumping pressure. It's clear that not much gas will be able to flow through this porosity. This is even more pronounced in unconventional gas reservoirs with the lower permeability result in increased capillary pressure. How serious is the problem? Water imbibed into the formation matrix can result in greatly decreased gas production and increased water production.
There is a mathematical simulation of water saturation in a non-damaged formation. Note that during 30 days of production, water saturation decreased dramatically, gas production was high, and water production was low. Here's a simulation of water saturation with 99% damage. Note that during 30 days of production, gas production was low and water production was high. Water saturation remained at almost 100% along a large portion of the fracture. The conclusions is that if the reservoir adjacent to the fracture face is filled with water, gas production will be greatly reduced and water production we'll be enhanced. It's clear that to maximize gas production, the water needs to be removed from the fracture face region. Unfortunately, reservoir pressure in ultra-low permeability formations usually is not sufficient.
This microscopic video shows phase trapping in which water and condensate phases are trapped in this pore network. Even with pressure applied, the imbibed water and gas bubbles cannot be removed. The combination of surface tension and capillary pressure is just too much for the formation pressure to overcome. After applying the new research results, this microscopic video was taken at the same conditions as the previous video. Note that the water and previously trapped phases pass easily through the porosity, leaving a clear pathway for gas production.
R&D Engineers role in fracturing stimulation process:
- Helps reduce damage due to phase trapping.
- Enhances mobilization of liquid hydrocarbon including condensate.
- Helps increase regained permeability to the gas following treatment.
- Improves load recovery.
- Replaces methanol for water block applications.
- Improves environmental and safety performance over existing alternatives.
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Now, before discussing the design of Gas Lift systems, Let's understand the Gas Lift valves. A Gas Lift system requires a source of gas and sufficient pressure to inject it at the proper place in the system. The injected gas may come from production operations or an outside source of supply, often sufficient supply and pressure is available from the high-pressure separator. If you're available operating pressure is not high enough, then a compressor will be needed. Prior to injections against typically passes through a flow control choke which controls the injection rate. Gas Lift valves located in the tubing are sized and spaced according to the overall design. The method of operation and the type of installation depend largely on the type of valves used. As you might expect there are different types of Gas Lift valves.
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Simply, we should discuss three types: - The Casing pressure operated valve, - The Fluid operated valve, and - The Throttling valve. Later we should discuss a 4th type called the Pilot operated valve. They're distinguished by their sensitivity to the casing pressures including pressures needed to open and close them. The Gas Lift in history categorizes Gas Lift valves according to which pressure has the greater effect on the opening of the valve. The sensitivity is determined by the mechanical design of the valve because it is the pressure exposed to the largest area in the valve that controls the valves operation. "Remember that P=F/A .So, F=P*A. a schematic of a typical Gas Lift valve installed in a tubing string is shown here. Nitrogen is normally injected into the dome and charged to a specified pressure. The bellows serve as a flexible or responsive element. Movement of the bellows causes the valve stem to rise and fall, and the ball to open and close over the port. When the port is open, the annulus and tubing are in communication. Because the area of the bellows A (b) is much larger than the area of the port in A (p), and since the bellows is exposed to casing pressure, it is casing pressure that controls the operation of the valve. This type of valve ten is referred to as a casing pressure operated valve or, more simply, a pressure operated valve. It requires a build-up in casing pressure to open and a reduction in casing pressure to close."
Now let's look at a graph of Flow Rate (q) verses Tubing Pressure (P). It will help us understand the performance characteristics of the Throttling valves. The vertical axis is flow rate and the horizontal axis is tubing pressure. At very low tubing pressure to the left of point 1, the valve is closed. As the tubing pressure reaches point 1, the valve begins to open and gas close from the casing to the tubing. The flow rate increases as the port continues to open. Throttling occurs from point 2 point 3 at which point the point is fully opened and throttling ends. The maximum flow rate occurs at point 4 as the giving pressure increases from point 4 to point 5 the tubing and casing pressures become balanced and the flow rate drops to zero. During the reverse cycle as the tubing pressure decreases, the valve opens at point 5, throttling takes place between points 3 and 2 and the valve throttle close between points 2 and 1. There other valves referred to as Combination valves which are also available for Gas Lift operations. Information on these and other special-purpose valves are available for manufacturers. The type of valve to be used for a given installation depends on whether the well to be placed on intermittent or continuous lift. But it is not certain which type of Gas Lift operation will take place as in cases where wells performance is borderline then valves maybe selected which are suitable for both continuous and intermittent lift. Values used for continuous flow must be sensitive to tubing pressure when in the open position. As the tubing pressure decreases, the valve should begin the throttle closed so as to decrease gas throughput.as the tubing pressure increases, the valve should open so as to increase gas throughput. This proportional response to increase and decrease in tubing pressure, maintains the established flow in tubing pressure and intends to keep a constant pressure inside the tubing. The ideal valve for continuous flow Gas Lift then is the Throttling valve. Don't Forget to support us, just like our Facebook page below. Also you can subscribe for us...
Hole Cleaning in Complex Wellbores such as Extended-Reach Wells, 3d Designer Wells and Wells with Wellbore Stability Problems present unique challenges that requires a completed system approach to the overall drilling process. The hole cleaning challenge begins at the planning stage of a well. Making sure that the well-designed focuses on the critical hole cleaning problems - is a key element to the success of these wells. When these elements are overlooked, the inherent risk of these wells increases. Once the plan is in place, the next step is to ensure that the entire rig team understands the downhole environment and the detailed response planned for tight hole. Understanding that tight hole in these wells is almost always cuttings related - is the first step towards a successful well. The Hole Cleaning System can be divided into three distinct environments. The first is the vertical hole section which generally ranges from zero to about 30 degrees. The next section ranges from 30 degrees up to about 65 degrees. And the final section is above 65 degrees of inclination. Each of these environments requires different set of rules for effective hole cleaning. Vertical hole certainly has its challenges. However, from a hole cleaning perspective, it is the easiest to clean.
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Normally vertical hole cleaning is accomplished by plug flow of the drilling fluid that is designed to suspend the cuttings when the pumps are shut off. The cutting in this case has thousands of feet to fall before it reaches bottom. Fluid rheology is generally the key factor for affective hole cleaning in this section. A close-up of this is clearly shows the slower hindered settling typical of vertical intervals. In this environment, as cuttings begin to move downwards they run into other cuttings. They also display fluid as they move downwards which creates an upward flow that further slows the cutting. In this clip, some cuttings are actually moving up the hole, others seem stationary and still others are moving downward with the pull of gravity. As the angle increases over 30 degrees new challenges begin to come into play. Watch how the settling environment changes as this is tube moved from vertical to about 45 degrees. Those cuttings that once had thousands of feet to fall, now reach bottom in a matter of inches. Pipe that was once concentric in the wellbore is now lane on the low side of the hole and fluid that was flowing all around the pipe now primarily flows on the top of a hole. We get a better picture of the pipe and flow situations later on this video. One phenomenon of cuttings behavior entangled wellbores call Boycott settling shown here at 45 degrees shows the clarified layer along the upper side and the slump along the lower side of the tube. This boycott settling causes some particles to move upward with the flow stream. Others are momentarily suspended while still others form a bed along the bottom of the hole and slumped opposite to the direction of flow. Here a highly dispersed mud is flowing at a 35 degree angle. Notice the rapid cuttings avalanche even when the pumps are shut off. These cuttings will slide downhole until they pile up on top of the P.A.J. or until they reach a high enough angle in the well and stop creating a large cuttings bed. As the well inclination reaches about 65 degrees, the cuttings will stop sliding down hole. Now, instead of a large cuttings bed forming in the well, along more evenly distributed cuttings bed will develop.
Very large volume of cuttings can exist in these hole sections. For example, a 2 in cuttings bed in a 10,000 ft section of 12 ¼in hole is approximately 85 barrels of cuttings in the well. Here during transport, a form of saltation flow is a typical transport mechanism. All this provides for a movement of a large volume of cuttings up the hole. It does not provide efficient hole cleaning. As we replayed this clip again notice how the movement of cuttings is very sudden with almost no cuttings movement on either side of the dawn. Movement of cuttings on a continuous basis only occurs at the top of these beds. Water in turbulent flow at 200 ft/min in a fully eccentric horizontal annulus can efficiently clean the hole. The same water at 45 degrees also in a fully eccentric annulus does not clean this interval at the same annular velocity. The net movement of the cuttings is downward clearly showing that effective hole cleaning in one interval does not necessarily translate to affective hole cleaning in the next interval of the same well. An essential element of high angle hole cleaning that needs to be understood is the fact that if cuttings are flowing over the shale shakers, the hole is being cleaned. The question now becomes how faster we cleaned the hole. Are we generating cuttings into the wellbore faster than we're getting them out? and is there a way that we can measure this? The first step towards answering these questions is to define the elements that affect efficient hole cleaning. There's no doubt that all of these elements play a role in how fast we're able to get cuttings out of the hole. Elements such as hole size, washout, drill pipe size, and wellbore instability all affect flow rates while rotary speed and mud rheology will play a role in how efficient we're able to get cuttings into the fluid flow. How the drilling fluid interacts with the rocks being drilled is also an essential element of the hole cleaning system.
If we are joined with the dispersive system where the drilling fluid can penetrate the cutting and dissolve it into solution than most of the hole cleaning is accomplished through this mechanism. However if the drilling fluid is fully inhibitive such as this clear base soil then the entire cutting must be removed from the hole mechanically. Each of these systems have their place in high angle drilling. However, a very good rule of thumb is not to get caught in the middle between a highly dispersive and a highly inhibitive system. This drawing represents a section through the high angle portion of the wellbore. Here the drill pipe lays on the low side of the hole and the mud following the path of least resistance flows primarily on the top of the hole.in inhibited mud environment the cutting will lay on the low side of the hole away from the fluid flow that's preventing their efficient removal from a well. This computer simulation demonstrates the flow patterns as the center pipe becomes progressively more eccentric. Very high flow rates are seen along the top of the hole with little-to-know flow around the drill pipe at the bottom of the hole. Sweeps in high angle holes have proven largely ineffective. This clip demonstrates how the sweet deform zone along gates along the top of the hole. If high-speed rotation is introduced to stir the cuttings, the drilling fluid around the cuttings contaminates the sweep destroying its original properties. This clip demonstrates how fluid flow in a concentric annulus on the left differs from that of an 80% eccentric annulus on the right. Note the flow filling the hole on the left and the flow primarily along the top of the hole in the right.
In order to effectively remove the cuttings from the high angle portion of the well, we must mechanically disturb the cuttings either with turbulent flow which is impractical in hole sizes over 8 ½ in or three pipe movement. here the addition of pipe rotation at 150 rpm effectively stirs the cuttings into the flow regime noticed the hopping motion of the cuttings as gravitypulls them back out of the flow and the pipe movement pushes them back up. It's not just rotation that pushes the cuttings into the floor regime, but a combination of high rotary speed pipe eccentricity and mud rheology. Most of the hole cleaning takes place across the drill pipe tube. The high rotary speed and the viscous coupling between the drilling fluid and the drill pipe cause the fluid to span around the pipe. This fluid movement picks the cuttings up and carries them into the floor regime on the top of the hole. Without this viscous coupling hole cleaning in a laminar flow environment is reduced dramatically. In order to effectively maintain this viscous coupling, we recommend a 6 rpm reading of "(1.1 - 1.5)* Hole Size (inches)". This insures effective transfer of energy from the pipe to the fluid and then to the cuttings. The better the transfer of energy to the cuttings, the better the hole cleaning. Notice the poor transfer of energy to the cuttings on the left and the excellent energy transfer that's generating the helical flow pattern of the cuttings on the right. The importance of pipe rotary speed cannot be overlooked.
The primary means of moving cuttings into the flow regime comes from pipe rotation. For all sizes over 8½ in, rotary speed is the single most important hole cleaning factor in the system. Field experience has shown that cutting flow over the shakers drastically improves that high rotary speeds and that it dramatically drops off as the rotary is slowed. Hurdle speeds of one 120 rpm and one 180 rpm have been repeatable regardless of hole size, drill pipe size, drawing fluid type. At these speeds significant increases in cuttings flow over the shakers is generally observed. The hole cleaning environment in a high angle well can be viewed like this conveyor belt. If the rotary speed and fluid rheology are not appropriate to get the cuttings onto the belt then hole cleaning efficiency is going to suffer. Likewise fluid flow rate represents the speed of the belt and that's the rate at which cuttings are being removed from the hole.
In summary, hole cleaning efficiency is primarily affected by three things. Flow rate: flow rate moves along the top side of the hole and access the conveyor belt moving cutting out of the well bore. Rotary speed: rotary speed acts to get the fluid moving around the body of the drill pipe to throw cuttings up into the flow regime. Rotary hurdle speeds must be met in order to maintain effective hole cleaning.In flow rheology, fluid rheology acts to create a viscous coupling with the drill pipe. It further acts to help to suspend the cuttings momentarily in the flow regime. It also has to provide hole cleaning in a lower angled portions of the wellbore. Getting the right combination of these critical parameters and then keeping them in the desired range throughout the drilling process requires full-time attention to detail. Good hole cleaning doesn't just happen, it requires a commitment from both the office and rig teams and a clear understanding of the downhole environment. Complex wells must be treated as an entire system with hole cleaning as the center of that system.
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Transcript: The types of valves to be used for intermittent lift depend upon whether we are going to install a single point for multipoint injection system. In single point intermittent gas lift operation, all of the gas necessary to move the liquid slug to the surface is injected through the operating valves, generally the bottom valve in the string. Let's look at a single point injection on the gas lift simulator. For this type of installation, the valve should expand to a large port size as soon as it is open and remain in the fully open position until closing. Depending upon the completion configuration, the port side will range in diameter from ⅜ to ⅘ of an inch. For multipoint intermittent gas lift operation, each valve intern should allow sufficient gas to pass so as to move the slug to the next higher valve. The pressure under the slug opens the valve that has just passed and supplements against being injected through the lower valves.
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As the slug moves to the surface, the valve normally remains opened until the slug is produced at the surface. Because the opening and closing of the various valves in our gas lift systems are so important to its operation so we should understand how and when a valve will open, when it will close and what a difference in these two pressures. Here we have a casing pressure operated valve; it is a single element valve for which we would like to calculate the opening and closing pressures. To do this,
For given bellows and tubing pressures, we may reduce the spread by reducing the size of the poor opening. This is particularly important in intermittent gas lift installations because it controls the volume of gas used in each cycle. As the pressure reduction or spread required to close the operating valve increases, remaining gas injected during the cycle also increases. A small port size though increases horsepower requirements and therefore a balance must be done between gas conservation and horsepower requirements. The pilot valve was developed in response to the need for a larger ports size while maintaining cost control over spread characteristics. It has a small port which is used for split control and a larger port which is used for more efficient gas passage. The pilot valve then answers this twofold need and as often used for intermittent gas lift operations.
Let me summarize this section on valves. A gas lift valve is categorized according to the pressure which has the greater effect on its opening. The casing pressure or pressure operated valve is dominated by the casing pressure both to open enclosure. The fluid operated valve depends on the tubing pressure to open and close it. The throttling valve or alternatively the continuous flow valve depends on the casing pressure to open it and the tubing or casing pressure to close it. See the whole video for more…
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Exploration geophysics: Gas Lift Module, Petroleum Production Performance series, The basic technical video library for the exploration and production specialist, Part 1. Welcome to the first module of a series on petroleum production engineering. On this module, we should learn how oil is produced from a well by Gas Lift, one of the important methods of artificial lift. Objective should be to discuss Gas Lift applications in general, point out the different types of Gas Lift installations, illustrate the various pieces of surface and subsurface equipment needed for Gas Lift system, and finally we should show you how to design Gas Lift installations. But first, let's visit briefly on California. "Believe it or not, a good example of a Gas Lift installation is located in that building behind us, here in downtown Los Angeles
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We shall be visiting it soon, but let's first see how Gas Lift fits into the life of a producing well." they've already considered the life of a flowing well. I'm going to calculate the pressure and flowing relationships that exist throughout the flowing well system. We found that, as the average reservoir pressure decreases so does the flowing production rate. We also found that at some point in the life of most wells, flow to the surface stops. at that point or even earlier, the well maybe place an artificial lift using either a Gas Lift ,the topic of this module, or one of several possible pumping systems. The purpose of any artificial lift system including Gas Lift is to reduce the bottomhole pressure in order to allow the well to flow under the existing formation pressure. With Gas Lift, this can be accomplished by forcing gas through a choker valve located at the surface down the annulus through valves in the tubing. Injected gases allowed to aerate the liquid column in the tubing.
The aeration reduces the bottomhole pressure caused by the weight of the column of liquid in the tubing. With sufficient aeration, the bottomhole pressure may be reduced to a point where the well once again begins to flow. The continuous aeration of the fluid column in the tubing will cause more oil to flow from the formation into the wellbore and then to the surface. Overtime though, the more fluids are produced, the average reservoir pressure decreases requiring increasing amounts of aeration to maintain a constant production level. The lifting of fluids can be accomplished by either continuous or intermittent gas injection. in continuous flow Gas Lift, a continuous volume of high-pressure gases introduced into the annulus in the tubing at a fixed rate causing a continuous flow of fluids from a well. Thus, artificial with method is usually applied to high productivity index wells which have high bottomhole pressures relative to their depth. For normal tubing strings, it is possible to lift from 200 to 20,000 barrels per day. But we choose instead to inject gas down the tubing and produce the fluid off the annulus. It is possible to lift up to 80,000 barrels per day using continuous Gas Lift. When small Macaroni tubing strings are used, it is possible to obtain production rates as low as 25 barrels per day using a continuous lift.
The range of continuous Gas Lift then is anywhere from 25 to 80,000 barrels per day. The other Gas Lift method involves intermittent rather than continuous injection of lift gas. With generally applied only when a limited amount of fluid is flowing from the reservoir into the wellbore. Under these conditions, it becomes necessary to wait until the fluid volume in the wellbore builds up to a level worth lifting. once the fluid builds up to a high enough level, a slug of gas is injected down the annulus through a Gas Lift valve into the tubing, there by pushing the column of fluid to the surface as a slug. Cycling is regulated to coincide with the buildup of the fluid level in the wellbore. Intermittent injection and therefore intermittent production is accomplished by the use of a time cycle controller and adjustable choke located at the surface on the gas injection line. Intermittent flow Gas Lift is ideally suited for the well which has a high productivity index but a low average reservoir pressure, or alternatively a well with a low productivity index but high reservoir pressure. The major advantage of Gas Lift in an artificial Lift mechanism is the fact that the specific gravity of gas is so much less that oil or salt water. The following example illustrates the statement. "Assume that we have three 6000ft wells each completed with tubing on a packer and each having a surface pressure of 100 psi. The first well is filled with salt water, the second with oil and the third with gaps.
Our objective is to calculate the bottomhole pressure of each. Let's begin with the well filled with salt water. the specific gravity of salt water is 1.07 which is equivalent to a hydrostatic gradient of 0.465 psi per ft. the static bottomhole pressure for this well then will be 100+0.465(6000)=2890 psi. Now let's turn to the oil well. if the column is filled with 0.8 specific gravity oil with the pressure gradient of 0.346 psi/ ft, then the static bottomhole pressure will be 100+0.346(6000)= 2176psi. This is more than 700 lb less than that for the well filled with salt water. Now we turn to the gas field well. we are told that it has an average specific gravity relative to water of 0.16 which gives an equivalent pressure gradient of 0.069 psi/ft. this gives a static bottomhole pressure of 514 psi. This is much lower than those for oil and water. The pressure profiles for the conditions obtained in each well are shown graphically in the video. we see the very low bottomhole pressure that exists when a well is filled with gas." we conclude from this that if we have a well filled with oil or water and can saturate all or a portion of the liquid column with gas, the bottomhole pressure will be reduced significantly. With a reduced bottom pressure, fluid in-flow from the formation will be increased and perhaps become continuous. But, is the design engineers job to select the gas volumes, points of Injection, and frequency of injection? Yes, so as to optimize the production from the well. We shall see how this is done later on in this module. Don't Forget to support us, just like our Facebook page below. Also you can subscribe for us...
An increase in slurry density may be necessary in order to control high-pressure wells or to prevent the deterioration of fragile wellbores.Wetting agents in the form of either heavy materials or dispersants can accomplish this. Sand, Barite, Hematite, Ilmenite and Salt are heavy materials that create greater slurry density because of their high specific gravity. Table in the video lists the specific gravity is of these materials and the maximum slurry density. Dispersants increase density by reducing the amount of water in the slurry. They permit the cement slurry to remain pumpable even with these lower water ratios and help maintain turbulent flow with all pumping rates. Turbulence is essential in removing mud and assisting for good cementing. Common dispersants are Lignosulfonate, Organic acids and certain polymers. In addition to increasing the density of the cement, dispersant can also serve to reduce fluid loss. Watch video for more illustrating.
Test for free water is only necessary for class G and H cements. The purpose of free water control is if you have free water break out of the slurry and your well is deviated, then the water can rise up, breakout and form a channel on the high side of the well. If it does that and can communicate between the zone of high pressure and the zone of lower pressure then the only force holding the higher pressure zone back would be the way of the water which is significantly less than the way that the cement and it allows flow after cementing which is one of the major difficulties in cementing. In the test for free water, the cement slurry is stored in a consistometer for 12 minutes. It's allowed to stand for a period of time. Then remixed it in the blinder for 35 seconds and placed in a graduated cylinder for 2 hours.
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Since free water volume can be significantly affected by hole angle, free water tests for deviated wells are often conducted with a graduated cylinder placed in various positions in addition to the API specified vertical position. Supernatant water is then measure; its volume should be less than 3.5 milliliters for 250 millimeters of initial slurry.
Our goal in planning a well profile is to determine the most economic path from the surface to the bottom hole location. We first have to determine the target coordinates with respect to the proposed surface location. At the same time, we have to assign the target radius based on our well objectives. This target radius indicates how tightly we have to control the well trajectory. The degree of control is much less critical for a relatively thick homogeneous interval than it would be for a thin steeply dipping zone. Dog-leg Severity limits are based on drill string operating specs, completion considerations, and other factors. Note that it's possible to run into problems even when the departure from vertical is within an acceptable range. Here even though the inclination is within its assigned limit of 3˚/100ft, the dog-leg severity is too high. This illustrates the importance of measuring both inclination and direction even on vertical wells.
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In laying out the well trajectory, we may start by looking at 4 general patterns: the (Build and Hold), (Build, Hold and Drop), (the Continuous Build) and (the Build, Hold and Build). Type1, the Build and Hold employs a shallow initial deflection from vertical and discreet angle approach to the target. It's good mainly for reaching single targets of moderate depths and sometimes for drilling deeper wells with large horizontal departures. Type2, the Build, Hold and Drop pattern likewise employs a relatively shallow deflection and holds angle until it reaches most of the desired lateral displacement. But then, the angle is reduced or brought back to vertical to reach the target. This pattern is primarily for wells and multiple pay zones or whether lease or target constraints. The Continuous Build pattern as a relatively deep initial deflection at which point hole angle is maintained to the target. This pattern is appropriate for salt dome drilling, fault drilling, sidetracking or re-drilling. The build hold and build pattern describes horizontal wells of which there are several types. Selection of this pattern is based primarily on reservoir engineering considerations. We can define well profiles in terms of several key parameters. The inclination angle is the deflection from vertical at a given point. While the kickoff point is the depth of which we first begin building the inclination angle. The Azimuth refers to the angle in the horizontal plan with respect to true north. The turn-off point is the depth of which we change Azimuth. The turn rate angle represents the incremental change in azimuth over a measured course length. While the build rate angle refers to the incremental increases in inclination. Conversely, the drop rate angle on a Build, Hold and Drop pattern is the incremental decrease in hole inclination. The lead angle measured in the horizontal plan from the left of the target area accounts for the tendency of a rotary bit to walk to the right. Its value depends on local drilling conditions. But remembered that there's a lot more to planning a well profile in drawing a curve from point A to point B. many other factors: well spacing, casing and completion requirements, read capacity hydraulics, drill string design and specifications, drilling parameters and so forth come into play. There are a number of software packages that can be used to optimize well trajectories while accounting for these drilling variables..
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This about-fishing-operations video technically covers the techniques and common tools used in wireline pipe recovery operations with animated simulated explanation. covered points:
Fishing definition,
String sticking causes,
String sticking solutions,
Free point determination, and
Pipe cutting tools.
Fishing services are frequently used to retrieve unwanted objects from the well bore such as tools or equipments and twisted or broken sections of pipes or tubing. Fishing also includes the recovery of stuck drilling or production strings. Stuck drill pipe or tubing results in costly downtime and occurs into often both in openhole and cased hole situations. The causes of string sticking are numerous. Sand or heavy mud in the well bore can build up in the annulus to create sticking.
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During drilling and tripping, the string can make a groove into the high side of an openhole. This groove called a key seat can lead to sticking on all types of wells. Differential sticking can occur when a hydrostatic pressure of the mud column exceeds the pressure exerted by the porous underground formation. As the mud filter cake increases in thickness, the likelihood of differential or well-stuck drill cutters also increases. There are other reasons for string sticking but, whatever the cause, the object in all cases is to determine at what point the string is stuck and at what point it's free. The free point can be determined with a special electronic free-point tool run on wire line. The free point tool is security attached to the wire line and both are small enough to be run inside the stuck well pipe or tubing. As the driller applies torque or stress to the string, this free point tool measures the difference in pipe stress in the section between the two fixed points. The stress in the section of the pipe is sensed by the downhole detector and electronically transmitted to the surface panel where this is displayed on readout meter. The downhole free point reading is directly proportional to the amount of torque or stretch being applied to re-string from the surface. After making calculations to estimate the stuck point, experienced wire line operators begin taking readings slightly above the calculated stuck point. As the stuck pint is approached, readings will wait until the detector is in the stuck section of the string indicating no pipe movement. Through this method of data interpretation, a skilled wire line operator determines the free point precisely. Only by combining all available well bore information with specialized experience, expert operator can compensate for various downhole conditions to determine the actual free point. The Stresstectors is extremely sensitive to torque and stretch. It can detect even sudden movement including intention, compression, and right or left hand torque. Reading left hand torque is essential in certain fishing situations. Another advantage of the Stresstector design is its durability. It can be run in combination with string shot explosives which reduces the time involved in freeing the stuck string. A new version of the Stresstector, the Stresstector II, is introduced for slim hole, coil tubing and high temperature situations. The smallest sized Stresstector II of 5/8 inch diameter has been developed to handle pressures up to 20000 psi and over 400 degrees Fahrenheit. Regardless of which detectors is used once the actual free point is determined, the free pipe can be removed from the well bore after backing-off from the stuck section of pipe. A backoff is made by applying left hand torque and holding that torque by the controlled explosive charge placed across a connection is detonated. The explosion allows the connection to be unscrewed without damaging the threads. The freed pipe is then removed from the well bore. It is often necessary to cut a section of pipe or tubing to remove it. Among the cutting tools available is the Chemical Cutter which uses hydrofluoric acid to cut pipes. The chemical cutter cutes the tubing without leaving a flare or debris. This makes it easier to recover with an overshot fishing tool. Another cutting device is Jet Cutter severs pipe with the shaped explosive charge. Like the Chemical Cutter, the Jet is matched to the size of tubing being cut. The Jet Cutter is also used to cut drill pipe casing, and crusted pipes. The Jet Cutter leaves a flared fish top which must be prepared before the fish can be caught. Still another tool used in fishing is the Severn Tool. The Severn Tool utilizes the powerful explosive charge run on wire line which serves drill pipe, heavy weight drill pipe, and drill colors when conventional back-off techniques are not possible. Watch the video for more information about it Don't Forget to support us, just like our Facebook page below. Also you can subscribe for us...
