A choke fitted to the coils of a steam exchanger provides additional control of the well fluid.

From: Well Testing Project Management, 2009

Nodal Analysis*

James F. LeaJr, Lynn Rowlan, in Gas Well Deliquification (Third Edition), 2019

Using chokes as solution

Discussion: using chokes

Several chokes were introduced at the surface for conditions that were used to generate the plots in Fig. 4.5. The chokes input were 24, 20, 18, 16, and 14 64’s, and the corresponding choke IDs are 0.375, 0.3225, 0.28125, 0.25, and 0.21875 in. Looking at the results, the combination of the TPCs and choke give outflow curves. When the choke is downsized to a size of 14 choke, stable flow is indicated while the other choke sizes still indicate unstable flow. A well can be stabilized by using a choke but the flow is still below critical. This is a point of confusion as to how to add pressure (with a choke) to the surface of a well and expect a stabilized flow? The answer is that if you just add a constant pressure (like into a higher surface pressure collection system), it will still be unstable and at a lower rate. However, if you add a pressure-dependent restriction at the surface of the well (i.e., a choke) then smaller chokes show the combination of the small tubing and the choke will show a stable outflow curve.

Figure 4.5. Using chokes.

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Subsea Control

Yong Bai, Qiang Bai, in Subsea Engineering Handbook (Second Edition), 2019 Choke Operation

The choke has two hydraulic actuators, one to open and one to close, that move the choke via a pawl and ratchet mechanism.

The choke is moved by applying a series of hydraulic pressure pulses to the appropriate actuator. On each pressurize/vent cycle, the choke will move by one step. To provide these pressure pulses, the SCM has two pilot valves, one for opening the choke, and one for closing the choke. These valves are not hydraulically latched and will only pass hydraulic fluid when the solenoid is energized. Figure 7-18 shows an SCM mode-choke operation chart.

Figure 7.18. SCM Mode-Choke Operation [1].

To operate the choke, the MCS sends a series of commands to the SCM. For example, if the operator wishes to move the choke by 20 steps, the MCS will send 20 appropriately timed valve commands to the SCM to energize the appropriate solenoid.

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Choke Performance

Boyun Guo Ph.D., ... Ali Ghalambor Ph.D., in Petroleum Production Engineering, 2007

Publisher Summary

Wellhead chokes are used to limit production rates for regulations, protect surface equipment from slugging, avoid sand problems due to high drawdown, and control flow rate to avoid water or gas coning. Two types of wellhead chokes are used: positive (fixed) chokes and adjustable chokes. Placing a choke at the wellhead means fixing the wellhead pressure and thus the flowing bottom-hole pressure and production rate. For a given wellhead pressure, by calculating pressure loss in the tubing the flowing bottom-hole pressure can be determined. If the reservoir pressure and productivity index is known, the flow rate can be determined on the basis of inflow performance relationship. This chapter presents and illustrates different mathematical models for describing choke performance.

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Systems and Equipment for Offshore Platform Design

Naeim Nouri Samie MSc Hydraulic Structures, in Practical Engineering Management of Offshore Oil and Gas Platforms, 2016

3.3.4 Choke Valve

Choke valves are the first instrument placed after Xmas Tree discharge (downstream wing valve) in the flow line. It is not part of the Xmas Tree block. However, its function is directly related to the Xmas Tree. Pipe segment between choke and wing valve has connections for chemical injections. Choke valves are supported by topside piping. Xmas Trees are installed after jacket and before topside installation. Therefore this segment will be installed offshore to enable catering for Xmas Tree installation tolerances.

Choke valve duty is to reduce/regulate well pressure/flow fluctuations to platform design pressure and crude flow. Due to this function pressure after choke is reduced from reservoir flowing pressure to platform operating pressure. These two values may be very different. For a better explanation, please refer to Section 2.8. Therefore some chokes that shall handle very large pressure differentials may have a two-stage construction.

Pressure after choke valve (which is called platform operating pressure) has to be carefully selected. It shall be calculated based on onshore facilities requirement. The intention is to minimize pumping facilities and use well pressure as the main driving source for crude transfer. If platform operating pressure is selected to be too high, it may reduce downstream pumping costs in the onshore plant, but platform equipment and export pipeline shall be designed with a very high pressure rating. In addition to costs, this will increase explosion probability. Pressure drops in pipeline to onshore, in the platform piping system and equipment, and required pressure at onshore tie-in has to be estimated.

On the other hand, if a high-pressure reduction is selected, choke design may become very complicated. It may need to drop pressure in two stages. Platform design with too low operating pressure may cause unnecessary separation in the pipeline, which may block flow path.

Since during platform life reservoir pressure may drop considerably, therefore the choke shall be able to support a wide range of pressure reduction. Each choke is equipped with a PSV. Pressure safety valve is immediately connected to choke valve. Fluctuations in reservoir pressure within a range can be regulated by choke. Pressure fluctuations (surges) exceeding this limit (not confined by choke) will be controlled by PSV through venting to flare header. PSV function is to release excess crude pressure from set point to the flare line. This is to ensure pressure in piping/equipment downstream choke valve will not exceed platform intended operating pressure.

Due to its importance and high-pressure value, the choke actuator is controlled by the wellhead control panel. Its actuator requires considerably large hydraulic oil volume and pressure.

As a main difference, with on/off valves chokes may open crude passage from 0% to 100% in gradual steps. Of course its design shall be such that in normal operating condition less than 80% is open. To enable rapid closure of flow path, hydraulic power pushes a disk blocking flow passage to open hydrocarbon flow. Whenever HPU fails or hydraulic pressure is removed intentionally to shut down the well, this disk closes flow. Choke valve is a fail-close valve.

Choke sizing shall be carefully done. Fluid or gas velocity shall be limited. High fluid velocity with sand presence results in rapid erosion of the line. In addition high gas velocity while having erosion effect with flying solids induces vibration and noise in platform piping.

Choke valves change fluid direction sharply. This action induces a considerably large thrust force. It shall be supported by valve supporting system. Two different vendors may state different thrust force values for the same flow discharge and pressure change.

Choke body material shall be suitable for highly corrosive conditions of fluid passing the wellhead. In addition, all its electrical/instrument components shall comply with hazardous zone classification.

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Well Test Description

Paul J. Nardone, in Well Testing Project Management, 2009

Choke Manifold

Well test choke manifold controls fluid pressure using a combination of valves and flow restrictions. Figure 3.8 shows a typical choke manifold configuration. There are two flow paths through the choke manifold, one through an adjustable choke and the other through a fixed choke.

Figure 3.8. Choke Manifold Schematic

Each choke restriction has isolation valves upstream and downstream, and in some cases, a double valve on either side is required to provide dual barriers when accessing the choke. The design and manufacture of choke manifolds references API Spec 6A Specification for Wellhead and Christmas Tree Equipment.

The adjustable choke has a cone-shaped plug made of a hardened material such as tungsten carbide and a corresponding seat. Turning a threaded shaft adjusts the cone position to increase or decrease the gap between the cone and the seat, thereby providing an adjustable flow path size. During the cleanup or when changing chokes, the adjustable choke facilitates variable control of the flow.

The fixed choke is useful for stable flow conditions. It consists of a solid metal insert with bore of known size coated with tungsten carbide to provide erosion resistance. Every choke manifold comes with a range of fixed chokes to suit a variety of flow conditions. The flow through the fixed choke is less turbulent, and the restriction size is known with greater accuracy than that of the adjustable, the fixed choke is also less prone to plugging with debris. Access to each choke is necessary in order to change the restriction size or to perform routine maintenance, for example, to remove debris. Assorted fittings on the choke body provide for pressure and temperature sensors and sample access points.

It is at the choke manifold that some of the most critical test operations occur. The choke manifold regulates fluid production through the adjustable choke as conditions change during the cleanup. This protects downstream equipment from excessive pressure. Continuous close monitoring is essential during the early cleanup as fluids and conditions change rapidly; for example, a change in fluid phases from liquid to gas may require adjustment of the choke setting to limit pressure downstream. During the main flow, adjustments at the choke manifold involve changing choke sizes to increase or decrease production from the well according to the program.

Figure 3.9. Adjustable choke and seat

Choke changes require set procedures in order to prevent unplanned disturbances to the flow, such as accidental well closure. Consider a well producing through a fixed choke, the procedure to switch to a larger choke is as follows. This procedure requires two operators; each controlling one set of valves, with the well flowing through the fixed choke on one side, the adjustable choke on the opposite side is set to the same size as the fixed choke and the downstream valve opened in preparation. An operator gradually closes the upstream valve on the fixed side whilst at the same time the other operator gradually opens the upstream valve on the adjustable side. The operators monitor the pressure upstream and downstream to regulate the changeover in order to maintain constant flowing conditions, afterwards, it is possible to increase or decrease the adjustable choke to the desired new setting. An operator closes the downstream valve on the fixed side and opens a needle valve in the fixed choke chamber to vent the trapped pressure between the upstream and downstream valves to atmosphere, removing a cover permits access to change the fixed choke. The operators repeat the above procedure to switch from the adjustable choke to the new fixed choke.

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Operational Aspects of Oil and Gas Well Testing

In Handbook of Petroleum Exploration and Production, 2000

Fixed choke

The fixed choke is almost universally of the bean type. It has a cylindrical shape, which allows it to screwed into the choke body and a cylindrical hole of some fixed diameter passing through the centre. The diameter of the hole is made to a close tolerance and has a very smooth surface finish to minimise turbulence.

The inlet to the fixed choke suffers from a great deal of erosion during flow so they are typically manufactured about six inches long to give a reasonable service life.

The majority of chokes are manufactured in tungsten carbide. The best chokes however are manufactured with the body in tungsten carbide and have a ceramic insert, which greatly reduces the amount of erosion. Although the absolute size of a choke during well testing is not of great significance other than for media reports, the flow stability is important. Any erosion to the choke will result in an increase in the choke diameter. During the course of a long flow test this will be reflected in a steadily increasing flowrate and a decline in bottom hole and surface flowing pressure. These factors add a further degree of complexity to the well test analysis.

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Valves, Fittings, and Piping Details*

Ken Arnold, Maurice Stewart, in Surface Production Operations: Design of Gas-Handling Systems and Facilities (Second Edition), 1999


The flow of fluid leaving a choke is in the form of a high-velocity jet. For this reason it is desirable to have a straight run of pipe of at least ten pipe diameters downstream of any choke prior to a change in direction, so that the jet does not impinge on the side of the pipe.

Often on high-pressure wells two chokes are installed in the flowline—one a positive choke and the other an adjustable choke. The adjustable choke is used to control the flow rate. If it were to cut out, the positive choke then acts to restrict the flow out of the well and keep the well from damaging itself. Where there are two chokes, it is good piping practice to separate the chokes by 10 pipe diameters to keep the jet of flow formed by the first choke from cutting out the second choke. In practice this separation is not often done because of the expense of separating two chokes by a spool of pipe rated for well shut-in pressure. It is much less expensive to bolt the flanges of the two chokes together. No data has been collected to prove whether the separation of chokes is justified from maintenance and safety considerations.

Whenever a choke is installed, it is good piping practice to install block valves within a reasonable distance upstream and downstream so that the choke bean or disc can be changed without having to bleed down a long length of pipeline. A vent valve for bleeding pressure off the segment of the line containing the choke is also needed. This is particularly true in instances where a positive choke is installed at the wellhead and an adjustable choke is installed hundreds of feet away in a line heater. If block valves are not installed downstream of the positive choke and upstream of the adjustable choke, it would be necessary to bleed the entire flowline to atmosphere to perform maintenance on either choke.

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Ocean Circulation and Climate

Janet Sprintall, ... Herlé Mercier, in International Geophysics, 2013

5 Discussion

The choke points formed at high latitudes by the separation of the Southern Hemisphere continents with Antarctica, and in the tropics via the Indonesian archipelago, provide natural locations for observing and monitoring interocean exchanges. Indeed, there have been many concerted efforts to sustain long-term monitoring programs in these regions, although in the past the geographical (Southern Ocean) and logistical (Indonesia) isolation of these extreme locations has made this difficult. Nonetheless, in the more recent decades, the many ongoing observational programs along with remotely sensed measurements have successfully provided valuable information on the variability over a range of timescales of interocean exchange through these choke points and their importance to the global climate system.

In the Southern Ocean, the fast-flowing ACC provides an efficient equalizer of interocean properties acting to reduce the contrasts between each of the major ocean basins in the Southern Hemisphere. Nonetheless, energetic eddies in the Agulhas region counteract the strong eastward flow of the ACC and inject salty Indian Ocean water that can be traced across the South Atlantic and potentially influence the MOC. While the strong air–sea interaction, tidal and wind-induced mixing within the Indonesian seas significantly alters the Pacific source water masses that comprise the ITF thermohaline profile that enters the Indian Ocean, its signature appears to be largely overwhelmed possibly by the saltier RSOW by the time the Indonesian waters reach the Indian Ocean western boundary.

As with interocean exchanges, the exchanges between the oceans and their adjacent seas carry different weights with respect to their relevance for variations of the global MOC and climate. The Arctic Sea and the Labrador Sea are the most significant members, with a strong influence on changes in the MOC. The freshwater injection from these subarctic marginal seas will counter against the contribution of saltier waters from the Agulhas system as well as the Mediterranean, and subsequently have a competing influence on the stabilization of the MOC of the North Atlantic. Other marginal seas influence the mean oceanic circulation, but apparently not its variations. However they provide important markers in water mass properties that can be used to identify changes in the transfers between atmosphere and ocean, and in the budgets of heat, salt, carbon, nutrients, and other properties. Notwithstanding the open question of MOW pathways, it is clear that the Mediterranean outflow results in strong property signals in the North Atlantic and in part of the South Atlantic, above or as part of the NADW. Similarly, the outflow from the Red Sea and the Okhotsk Sea has a strong influence on water mass properties at intermediate depths in the Indian and North Pacific Ocean, respectively. However, on decadal timescales, it was shown that source property changes in MOW were too small to have a significant effect on the open Atlantic. This may also prove to be the case for decadal changes in the Red Sea and Okhotsk Sea waters, impacting their adjoining basins. Nevertheless, all these marginal sea inflows can be thought of as indicators of climatic change affecting larger regions.

Deep ocean passages between neighboring oceanic basins permit throughflows of deep and bottom water from one basin to the next. Deep passages are also choke points that, due to their limited extent, potentially provide a relatively easy monitoring site for the amplitude and property variability of the deep branch of the MOC. We focused our discussion on the deep passages that control the spreading of the NADW in the Atlantic Ocean and AABW in the world oceans, and we reviewed the characteristics of these flows. These deep passages are of considerable interest since they are the location of high levels of turbulence, strong water mass modification, and impact the dynamics of the upstream basin (Whitehead, 1998). Mixing is intense (~ 10 2 m2 s 1) in deep passages due to the unstable nature of the strongly sheared flows. Downstream of a critical point, the flow becomes supercritical and mixing may be even more intense (values as high as 10 1 m2 s 1 were reported by Ferron et al., 1998 for a hydraulic jump region in the Romanche Fracture Zone). This enhanced mixing strongly affects the deep and bottom water properties of the downstream basins. Accurately modeling these regions of intense mixing in general circulation models (GCMs) remains a challenge (Legg et al., 2009).

As documented in other parts of the world oceans, there have been recent significant measurable changes both in the properties and fluxes at interocean and interbasin exchange sites. It is remarkable that all of the examples discussed in this chapter, with the exception of the Red Sea outflow, indicate increasing temperatures over recent decades, thereby strongly suggesting a response of the oceans to global warming. Long-term changes in the Pacific tropical tradewinds have resulted in changes to the ITF transport (Wainwright et al., 2008). While model studies suggest that the poleward shift and intensification of the Southern Ocean westerlies have led to an increased Agulhas leakage (Biastoch et al., 2009), the impact of these wind changes on ACC transport itself remains less clear. Although there is much recent evidence that property changes have occurred in the deep ocean (e.g., Fukasawa et al., 2004; Johnson and Doney, 2006; Kawano et al., 2006; Johnson and Gruber, 2007; Rintoul, 2007; Zenk and Morozov, 2007; McKee et al., 2011), unfortunately no long-term transport measurements in deep passages are presently available. The extreme complexity of abyssal topography along with the technological challenges of making long-term observations of the relatively small signals at low temperatures under immense pressure in remote locations complicates our ability to maintain an optimal sampling array in the deep ocean. Garzoli et al. (2010) recommended the setup of sustainable measurements in the deep passages that are not yet instrumented (e.g., Vema Chanel, Romanche Fracture Zone, Samoan, and Amirante Passages). Indeed, the observed changes highlight the need for long-term monitoring in all interbasin choke points that ultimately connects the MOC system. Such measurements are critical for climate monitoring and GCM validation.

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Centrifugal Compressors

Jason Wilkes, ... George Talabisco, in Compression Machinery for Oil and Gas, 2019

Gas Recycling

Opposite the choke, when the compressor does not get enough flow, the antisurge valve opens to avoid surge. Some amount of discharge flow is cooled to feed back to the compressor. The energy of recycling gas is wasted. Replacing higher flow stages with smaller stages is an effective way to accommodate the lower volumetric flows. After restage, the wasted power can be used to increase pressure ratio for more capacity or more oil production.

Besides economic reasons, running in recycle mode causes high discharge temperatures if insufficient cooling is supplied. DGSs, balance piston babbitt, and antisurge valves can be damaged during long period of recycling.

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single orifice air valve

In Handbook of Petroleum Exploration and Production, 2000

14.7 Choke Manipulation During Testing

The choke is the primary control device during flowing of the well. It generally consists of two sides, a fixed choke side and a variable choke side. For a well test the variable choke is usually a bean and stem type as described in section 13.9 and can vary between 0 and 2” maximum ID. The fixed choke side allows various sizes of fixed choke to be inserted as required. Sizes usually increase in steps of 4/64” up to 1” and often in 8/64” steps up to 2”. It important to ensure that a full set of choke sizes is sent to the rig before the starting the test.

By use of a block and bleed system, fixed beans may be changed whilst flowing the well via the adjustable choke. Thereby allowing step rate testing without shutting in the well and causing the minimum of pressure surge.

When operating the choke, much better test results are obtained if it is adjusted sparingly and then left alone. Poor results will obtained if the choke is continually adjusted to obtain a specific flowrate. Once the initial flow period is completed, the choke size strategy can be decided upon. To assist with this, some choke performance equations are listed in Appendix C, which allow flowrate predictions to be made.

Critical Flow

Critical flow occurs through a choke when the velocity of fluid flow exceeds the velocity of sound in the fluid. Under conditions of critical flow, any disturbance to the fluid stream occurring downstream of the choke cannot be communicated upstream of the choke. In sub-critical flow disturbances can be transmitted upstream of the choke, for example a change in separator pressure may resulting in a pressure variations at the bottom hole gauges.

Shutting In The Well

If a downhole tester valve is used in the string, the well should be shut-in at the tester valve first and then once closure is confirmed by a drop in the flowing WHP, the well should be closed in at the choke manifold by closing the upstream valves.

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