Oil is Flowing From a Well in a Continuous Stream

Marine Petroleum (Gas) Engineering and Equipment

Huacan Fang , Menglan Duan , in Offshore Operation Facilities, 2014

3.12.5 Production Analysis of a Flowing Well

Flowing well oil production uses the energy of the reservoir oil to spray the oil to the ground. The energy source is the reservoir pressure. The pressure that makes the crude oil from the reservoir flow to the bottom of the well is known as the flowing bottom hole pressure. When bottom hole flowing pressure is relatively high, the pressure can raise the oil to the wellhead, and even into the gathering manifolds and the separator. In addition, with the rising oil and gas flowing along the wellbore, the pressure will gradually reduce, and the gas will be separated out and expand its volume. The elastic expansion energy of gas is also one of the energy sources of the natural flow. Of course, as time goes on, the energy supplying the natural flow weakens, so the yield of the natural flow decreases. Therefore, it is necessary to study the relationship between the pressure and the production and to analyze the flowing characteristics of natural flow.

1.

The basic flow process of natural flow

a.: Seepage in the reservoir: flow from the reservoir to the bottom
b.: Flow in the wellbore: flow from the bottom to the wellhead
c.: Flow of crude oil through the choke after arriving at the wellhead
d.: Ground pipeline flow: flow from the crack to the separator

When analyzing the production of natural flow, the first and second flow processes are mainly taken into consideration.

2.

Flow characteristics of natural flow

The IPR (inflow performance relationship) flow characteristic is the relationship between oil production and flowing bottom hole pressure, and the curve that shows the relationship is called the flow characteristic curve or the flow dynamic curve. It reflects the ability of the first flow process where the crude oil flows from the reservoir to the bottom hole, and also is the base for analyzing production performance. The IPR curve is related to the reservoir type, as shown in Figure 3-96.

3.

Formula for single-phase flow yield

According to the percolation theory, the yield formula of a well at the center of the infinite formation is listed as follow with the Darcy's law.

(3-6) $q_{o} = \frac{K_{o} h (p_{r} - p_{w f})}{141.2 μ_{o} B_{o} (\ln \frac{r_{e}}{r_{w}} - \frac{3}{4} + S)}$

where

$q_{o}$ represents oil production, bbl/d

$K_{o}$ represents effective permeability of the reservoir, mD

$h$ represents the effective thickness of the oil layer, ft

$p_{r}$ represents average reservoir pressure, psi

$p_{w f}$ represents bottom hole flowing pressure, psi

$μ_{o}$ represents viscosity of crude oil, St

$B_{o}$ represents the reservoir volume factor

$r_{e}$ represents well drainage radius, ft

$r_{w}$ represents wellbore radius, ft

$S$ represents the skin factor

The parameter S is a coefficient relative to well completion, well contamination, stimulation treatment, and so on, and can be obtained from the analysis of actual production performance data. It is generally expressed by drill size, and other parameters may be obtained by the well testing, measuring wells, and logging data.

4.

Formula for two-phase flow in production of oil and gas

Vogel provides a simple formula which is used to draw IPR (inflow performance relationship) curve of the dissolved gas drive reservoir, namely:

(3-7) $\frac{q_{o}}{q_{\max}} = 1 - 0.2 (\frac{p_{w f}}{p_{r}}) - 0.8 {(\frac{p_{w f}}{p_{r}})}^{2}$

where

q_{\max}

represents the maximum theoretical yield of the wells when

ρ_{w f}

is zero, bbl/d. The symbols of the other parameters have the same meaning as in Equatoin (3-6).

Example 3-1: For the Z well in an oilfield in the South China Sea, the average reservoir pressure $p_{r}$ = 3600 psi, flowing bottom hole pressure $p_{w f}$ = 3400psi, and yield q = 3600 bbl/d. Try to use Vogel formula to draw the well IPR curves.

Solution:

a.

Calculation of $q_{\max}$ :

$q_{\max} = \frac{q_{o}}{1 - 0.2 (\frac{p_{w f}}{p_{r}}) - 0.8 {(\frac{p_{w f}}{p_{r}})}^{2}} = \frac{3600}{1 - 0.2 (\frac{3400}{3600}) - 0.8 {(\frac{3400}{3600})}^{2}} = 36911 b b l / d$

b.

Calculation of the yield under different flow pressures:

$q_{o} = [1 - 0.2 (\frac{p_{w f}}{p_{r}}) - 0.8 {(\frac{p_{w f}}{p_{r}})}^{2}] q_{\max}$

$q_{o}$ is calculated according to the above formula and is listed in Table 3-6.

Table 3-6. Values Calculated in Accordance with the Vogel Formula

Flow pressure, psi	3400	3000	2500	2000	1500	1000
Yield, bbl/d	3600	10253	17544	23695	28708	32581

c.

Draw IPR curves

According to the data of Table 3-6, we can draw the IPR curve, as shown in Figure 3-97.

5.

Analysis of the natural flow production of the multilayer offshore reservoir

Because of the higher costs of oil production in offshore fields, we are required to produce more oil in a relatively short period of time. So commingling, multilayered reservoir production is widely used.

a.

The inflow characteristics of the commingling

In general, in the same strata or adjacent oil layers, if the oil layer's physical properties are little different, and the pressure system are the same, and the deliverability of each oil layer is little different, the commingling production technique is often used. The total IPR curve of multi-layer production well is the superposition of the IPR curves of each oil layer, as shown in Figure 3-98.

b.

Commingling and single production options

The choice of both production methods is related to production performance and the different development stages of the offshore oilfield.

In general, in the early development stage, when multi-layers' features in one well meet the commingled conditions as the above, multi-layers commingling can be used. As the production of one oil well is going, the characteristics of different oil layers in one well will change at different levels, which will affect the efficiency of the commingling. For example, the high permeability layer is firstly flooded by the injection water which affect the producing rate of middle and low permeability layers. So the blocking measures is taken to the high permeability layer. And the timing of sealing the high permeability layer is determined according to two aspects that whether the ultimate recovery of the layer decreases and whether the production rate of one well meets production requirements. After economic evaluation, some wells can flexibly use multi-layers commingling, round mining or blocking.

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Production Optimization

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

18.2 Naturally Flowing Well

A naturally flowing well may be the simplest system in production optimization. The production rate from a single flowing well is dominated by inflow performance, tubing size, and wellhead pressure controlled by choke size. Because the wellhead pressure is usually constrained by surface facility requirements, there is normally not much room to play with the choke size.

Well inflow performance is usually improved with well-stimulation techniques including matrix acidizing and hydraulic fracturing. While matrix-acidizing treatment is effective for high-permeability reservoirs with significant well skins, hydraulic-fracturing treatment is more beneficial for low-permeability reservoirs. Inflow equations derived from radial flow can be used for predicting inflow performance of acidized wells, and equations derived from both linear flow and radial flow may be employed for forecasting deliverability of hydraulically fractured wells. These equations are found in Chapter 15.

Figure 18.1 illustrates inflow performance relationship (IPR) curves for a well before and after stimulation. It shows that the benefit of the stimulation reduces as bottom-hole pressure increases. Therefore, after predicting inflow performance of the stimulated well, single-well Nodal analysis needs to be carried out. The operating points of stimulated well and nonstimulated wells are compared. This comparison provides an indication of whether the well inflow is the limiting step that controls well deliverability. If yes, treatment design may proceed (Chapters 16 and 17) and economic evaluation should be performed (see Section 18.9). If no, optimization of tubing size should be investigated.

It is not true that the larger the tubing size is, the higher the well deliverability is. This is because large tubing reduces the gas-lift effect in oil wells. Large tubing also results in liquid loading of gas wells due to the inadequate kinetic energy of gas flow required to lift liquid. The optimal tubing size yields the lowest frictional pressure drop and the maximum production rate. Nodal analysis can be used to generate tubing performance curve (plot of operating rate vs tubing size) from which the optimum tubing size can be identified. Figure 18.2 shows a typical tubing performance curve. It indicates that a 3.5-in. inner diameter (ID) tubing will give a maximum oil production rate of 600 stb/day. However, this tubing size may not be considered optimal because a 3.0-in. ID tubing will also deliver a similar oil production rate and this tubing may be cheaper to run. An economics evaluation should be performed (see Section 18.9).

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Geothermal Energy

Vasel Roberts , in Advances in Energy Systems and Technology, Volume 1, 1978

D Miscellaneous Equipment

The noise created by open flowing wells and steam line vents has stimulated the development of mufflers, or silencers, and this technology is reasonably mature. Steam lines pose no particular problem except heat loss. Brine lines are prone to scaling where the rate of scaling is dependent on the chemical composition of the brine. Severe corrosion of pipe runs in certain hypersaline fields has been observed. Because of the tendency of geothermal brines to deposit scale, the maintenance of valves, pumps, and instrumentation will be higher than for fossil fuel plants. Improvements in scale-resistant brine pumps and in-process instrumentation are desirable.

In summary, hydrothermal geothermal development can proceed with today's technology. Several improvements are desired and if made will have two beneficial effects, the first being reduced cost of power, and the second being expansion of that portion of the resource base that can be developed. Development of other geothermal resource types such as hot dry rock and magma must await further technological developments.

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Wellhead Assembly

Wan Renpu , in Advanced Well Completion Engineering (Third Edition), 2011

Dual-String Christmas Tree and Tubinghead for a Flowing Well

There are two types of flowing-well Christmas trees and tubingheads used for dual-string separate-layer flowing production: (1) the dual-string Christmas tree, shown in Figure 10-5, and (2) the VG dual-string integral forged Christmas tree, shown in Figure 10-6.

The right side of a dual-string Christmas tree controls main-string production and test, and the tubing pressure gauge only reflects main-string tubing pressure. The left side controls sub-string production and test, and the tubing pressure gauge only reflects sub-string tubing pressure. Casing pressure gauge only reflects sub-string casing pressure.

A parallel dual-string tubinghead is generally used for dual-string production. The tubinghead spool for parallel dual-string completion is basically similar to that for single-string completion, except that a parallel dual-string tubing hanger consists of an overall tubing hanger and both main hanger and sub-hanger. The overall tubing hanger is seated on the spool, and the main hanger and sub-hanger are seated on the overall tubing hanger. The main tubing string, which has a packer, is used for lower-reservoir production, while the sub-string is used for upper-reservoir production.

The dual-string tubinghead for a parallel dual-string Christmas tree is shown in Figure 10-7, and the dual-tubing hanger is shown in Figure 10-8.

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Perforating

Wan Renpu , in Advanced Well Completion Engineering (Third Edition), 2011

Combined Tubing-Conveyed Perforating and Putting-into-Production Technology

This technology has been widely applied in flowing wells. It is safe and economical. Perforating and putting into production can be achieved by running the string once. Different wells adopt different structures of string and different packers. A releasing gun is generally adopted. The Halliburton combined system of tubing-conveyed perforating and putting into production is shown in Figure 6-5. A production packer is first run in on the wireline and set at the production casing, and then a string with a perforating gun is run in. When the guide sub of the string is run to the packer, the string is washed by circulating in order to remove dregs and sullage, and then the string is run further. After the string assembly is set, a bar is dropped from the wellhead in order to impact the detonator at gun head and perforate. After perforating, the perforating gun and residue drop to the bottomhole, and then the well is put into production.

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Subsea well control

Gerald Raabe , Scott Jortner , in Universal Well Control, 2022

Kick detection and fingerprinting

Accurately determining a positive indicator of a well flowing such as (1) Increase in Flow and (2) Increase in Pit Gains becomes difficult to identify. This is primarily due to vessel motion. As the vessel pitches, heaves and rolls, flowing returns will increase/decrease due to this vessel motion. Volume within the pits will appear to vary due to the sloshing of fluids within the pits. The floating vessels are outfitted with computerized vessel Pit Volume Totalizers which use sonic pulses placed on opposite sides of each pit, tracking volume movement and normalizing reading between points to develop accurate develop accurate "trend lines" or the normal range of mud contained within the pits. Unless the sea state is flat, these variances make it difficult to determine small kicks.

The motion also impacts flow detection due to compression and decompression of the riser slip joints. Surging flow as well as decreasing circulation can occur from sea state. The surge/decrease will affect the ability to discern small kick volumes. Once again, Automated Flow Devices must be properly calibrated to establish trend lines between surges and decreased flow, as well as Peak/Bottom of the amplitude of each flow wave. With all three established, small kicks should be able to be discerned.

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SIZING TUBING

James F. Lea , ... Mike R. Wells , in Gas Well Deliquification (Second Edition), 2008

5.3.2 Critical Rate at Bottomhole Conditions

The previous analysis of critical rates used the well flowing surface pressure to calculate the critical rate at surface conditions. A similar analysis can be done at the bottomhole pressure conditions.

Using the Nodal solution pressure (bottomhole pressure at the Nodal intersections), the Nodal solution rate can be calculated. If the critical rate calculated at the Nodal solution pressure is less than the Nodal solution rate, then the Nodal solution rates are acceptable; if not, then the critical velocity condition is violated.

From Table 5-2 the biggest tubing that has enough rate (above critical) at the bottom of the tubing is the 1.50 in tubing. The larger ID tubings would have velocity at the bottom of the tubing less than the critical.

Table 5-2. Critical Rates Needed at Nodal Intersections Compared to Nodal Rates

Tubing ID (in)	1.000	1.250	1.500	1.750	1.995
Nodal Solution Pressure (psia)	585	435	355	335	335
Nodal Solution Rate (Mscf/D)	220	275	320	325	325
Critical Rate for Nodal Solution Pressure (Mscf/D)	167	226	294	388	505

Note that the calculation of critical rate at bottomhole conditions will depend somewhat on the particular method used to calculate the tubing curves. Multiphase flow correlations are developed for a range of fluid properties and tubing sizes that may not match your well conditions exactly. Different multiphase flow correlations can often result in drastically different flowing gradients. The most significant difference between correlations is usually in regard to how each calculates the beginning of the turn up or liquid loading at low rates. Thus, it is imperative to use a method appropriate for your well.

For lower rate gas wells with moderate liquids production, the Gray correlation is quite good to predict the tubing J-curve and is recommended unless you have specific data that indicates otherwise. Gray was used for the tubing curves in Figure 5-2.

The best way to ensure a good flowing bottomhole calculation is to measure the actual flowing bottomhole pressure and the associated well production rate and compare the different calculation methods to the measured data. Some software allows the user to adjust the calculations slightly to better match actual well data.

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Selection and Determination of Tubing and Production Casing Sizes

Wan Renpu , in Advanced Well Completion Engineering (Third Edition), 2011

Method of Analyzing Tubing Size Sensitivity Affected by Inflow Performance

The principles and methods of optimizing tubing size for flowing wells have been briefly described in the preceding sections. The inflow performance and outflow performance of a production well are influenced and conditioned by each other. The inflow performance is the internal factor of conditioning the system, whereas the tubing itself is only an external factor. Therefore, the effect of inflow performance change on tubing size should be analyzed.

The reservoir pressure may reduce with the production time, and that may lead to inflow performance change and gradual fluid property change, thus changing the tubing outflow performance and possibly changing the optimum tubing size. In order to simplify the analysis, the effect of inflow performance change on the optimum tubing size is only discussed here.

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Wellbore Instability Analysis

Bernt S. Aadnøy , Reza Looyeh , in Petroleum Rock Mechanics (Second Edition), 2019

12.11.2 Collapse When Communicating

The next issue was the actual breakthrough process where communication between the flowing well and the relief well was established. Here we used (at that time) the newly developed model for adjacent wellbores. Fig. 12.32 shows the scenario.

Drilling out below the relief well liner, the distance between the two wellbores reduces gradually. Fig. 12.32 shows the stress concentration factors between the wells. The curves are generated using the theory presented in Section 12.6. Because the relief well has the highest wellbore pressure, the corresponding tangential stress is lower.

Many engineers assume that fracture will occur between the two adjacent wells. In authors' opinion, this is not correct. A fracture would give a limited area and would not allow for a large flow. This flow would possibly be insufficient to kill the well. What actually happens is that the area between the wells collapse leaving a large hole in between. During the actual event discussed here, at a distance of about 1 m between the wellbores, the drill bit suddenly dropped 1 m, and substantial volume of mud was lost. After a short time, the flowing well was filled with kill mud and went dead. In authors' opinion, this field behavior is only consistent with a massive collapse between the two wells.

The failure mechanism can be seen from Fig. 12.32. At a distance, the stress concentration is low in both wells. As they get closer (moving toward left in Fig. 12.32), adjacent stress effects arise, and the corresponding stress concentration increases. At a given point, the stress exceeds the rock strength and the blowing well fails. This leads to an even shorter distance between the wells leading to more failure. In fact, the collapse starts in the blowing well and expands in an explosive way toward the relief well. This is consistent with the field behavior seen, bit dropped suddenly, and a lot of mud lost instantly.

Fig. 12.33 illustrates the explosive collapse process further. Once initiated the collapse grows instantly.

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Continuous gas lift troubleshooting

Ali Hernández , in Fundamentals of Gas Lift Engineering, 2016

11.3.1.3 Failures or malfunctions of gas lift and completion equipment

There are many sources of downhole equipment failure (compared to a natural flowing well), that can create serious operational problems or inefficiencies.

■

Unloading valve that remains open (dirt accumulation). An unloading gas lift valve (that is supposed to be closed) can remain open because a solid particle could be trapped between the ball and the seat. This problem can be confirmed if the following two field tests give these results: (1) a communication test (as explained in Section 11.5.1) shows that there is no hole in the tubing, and (2) if the surface gas injection is shut off (without shutting in the well) and the injection pressure drops to values less than the surface closing pressure of the operating valve installed in the well. For the latter test to be used all unloading gas lift valves should be IPO valves and there should be a calibrated valve (also IPO) at the point of injection (as opposed to an orifice valve). The impact of having an upper unloading valve open will depend on the gas flow rate that this open valve will allow to pass from (1) a mild increase in the injection gas/liquid ratio to (2) a low injection pressure, high injection gas flow rate, and a reduction of the liquid production. One procedure to get the valve closed is to shut in the well while keeping the gas injection unchanged. The injection pressure will rise to values greater than all of the valves' opening pressures. Then, the well is suddenly opened to production (verifying first that this operation will not cause any harm at the flow station; it might be necessary to install a choke far away from the well, or at the flow station, to protect surface facilities). Then, after the liquid production has stabilized, gas injection is shut off again to see how far down the injection pressure gets. This procedure is repeated until the injection pressure does not drop to values less than the surface closing pressure of the operating valve.

❏

Unloading valve that remains open (getting it to close as expected). Continuing with the subject from the previous paragraph, to get the valve to close as expected some operators perform the following procedure:

a)

Wellhead annulus and tubing pressures are equalized by closing the well to production and injecting gas into the tubing using a high pressure hose or simply by closing the well to production and waiting for the injection pressure to reach line pressure (the surface production pressure will also increase but not necessarily to line pressure). In any case, when the gas flow rate drops to zero (because the injection wellhead pressure becomes equal to the injection manifold pressure) the surface gas injection control valve is manually closed.

b)

Then, the surface injection pressure in the annulus is rapidly vented 100 or 200 psi (while keeping the well closed to production) less than the large production pressure trap at the surface.

c)

Then the wellhead production pressure is vented 100 or 200 psi less than the surface annular injection pressure reached in point "b."

d)

The surface annular injection pressure is again vented in the same way it was done in step "b" until it is 100 or 200 psi below the surface tubing pressure reached in step "c" and this procedure is repeated until the tubing and production pressures become very small.

This causes repeated flows across the gas lift valve that might finally close it. This procedure should not be tried if sand production is going to be a problem.

■

Unloading valve that remains open (other causes). Another reason for a gas lift valve to remain open is because the bellows has been damaged (flat valve) or the seat is so large that, once the valve is uncovered, the following events can happen: (1) the injection pressure drops because of the high gas flow rate these seats can allow, and (2) the high gas flow rate cools the valve, lowering its closing pressure to a value less than the design closing pressure.

■

Salt depositions in gas lift valves. In marine environments (or when using certain types of completions fluids), salt depositions could be the solid keeping the valve open or plugging it (if the valve is plugged, the injection pressure will be high and there will be a reduction in the liquid production). In these cases, fresh water can be injected down the gas injection annulus (unless CO₂ or H₂S in the injection or formation gas could cause corrosion problems, for which special precautions should be taken). If fresh water causes formation damage, a standing valve should be installed at the bottom of the well, keeping the water from reaching the formation.

■

Gas lift valve plugged by iron sulfide depositions. In some wells, iron sulfide (FeS) depositions that can plug gas lift valves are common. The best way to deal with these depositions is to inject water with special detergents or chemicals into the well. If the operating valve is plugged, the injection pressure will be high and there will be a reduction in the liquid production.

■

Gas lift valves with cut seats. Unloading the well at a high injection gas flow rate before reaching the first valve can cut gas lift valve seats which will then leak gas once the well is in operation. Cut seats are very common and usually, but not always, the gas flow rates that leaking valves allow to pass for this reason are not very significant, even if they are easily detected by means of down hole temperature surveys; however, it is recommended to unload the well very slowly to avoid this type of valve failure because sometimes they do represent a serious problem. More importantly, unloading the well at a high injection gas flow rate can damage the gas lift valve's internal check valve, creating a serious well integrity problem.

■

Gas lift valve's tail plug failure. A leaking tail plug of a gas lift valve (Fig. 6.4) could allow the dome pressure to increase so that the valve will only open at higher than design opening injection pressures. If the tail plug leaks, every time the pressure surrounding the valve is higher than the nitrogen pressure, the dome is going to be pressurized and the valve might not open unless the injection pressure is very high (the dill valve, shown in Fig. 6.4, that is used to charge the gas lift valve with nitrogen, allows gas or liquid flow into the valve but not in the opposite direction). This might be due to errors that, from time to time, are made at the shop when the valves are being calibrated (the tail plug is not tighten correctly, the operator forgets to install the cupper gasket, etc.). The injection pressure can reach line pressure and the well does not take gas.

■

Gas lift valve failures (other causes). For a variety of reasons, the valve can also be set at the wrong opening pressure at the shop (wrong calibration temperature, not properly aging the valve's bellows, faulty test-rack instruments, etc.). Another operational error that is sometimes made by wireline crews is to install the valves in the wrong mandrels. All of these errors have consequences that could completely confuse the person analyzing the well because they are not directly revealed by any available calculation procedure.

■

Pilot valve failure. A downhole gas lift pilot valve intended for intermittent gas lift could fail open for one of the reasons given in chapter: Design of Intermittent Gas Lift Installations and, in consequence, gas is injected in a continuous fashion into the production tubing. This usually, but not always, causes a high injection gas flow rate with a low surface injection pressure. Other times, the pilot valve's piston gets stuck in such a way that the gas flow rate is very small compared with what a fully opened gas lift pilot valve could allow to pass. In both cases, it might be possible to fix the problem by venting the casing–tubing annulus. As explained in chapter: Design of Intermittent Gas Lift Installations, if the check valve of the pilot valve is an integral part of the piston (it is located inside the piston) then a communication test would wrongly indicate a hole in the tubing if the piston gets stuck or the check valve is plugged. If the check valve is not an integral part of the piston but it is located at the nose of the valve, which is the usual place where check valves are located, then a communication test will indicate a hole or casing–tubing communication only if there is indeed such communication.

■

Surface intermitter failure. A surface intermitter might fail open and the surface gas injection flow rate into the well could be so large that it would not be possible for the pilot valve to close. The injection pressure in this case could be very high. Intermitters are used in intermittent gas lift wells to control the surface gas injection into the annulus of the well at regular time intervals.

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collinsfultarly.blogspot.com

Source: https://www.sciencedirect.com/topics/engineering/flowing-wells

Oil is Flowing From a Well in a Continuous Stream

Marine Petroleum (Gas) Engineering and Equipment

3.12.5 Production Analysis of a Flowing Well

Production Optimization

18.2 Naturally Flowing Well

Geothermal Energy

D Miscellaneous Equipment

Wellhead Assembly

Dual-String Christmas Tree and Tubinghead for a Flowing Well

Perforating

Combined Tubing-Conveyed Perforating and Putting-into-Production Technology

Subsea well control

Kick detection and fingerprinting

SIZING TUBING

5.3.2 Critical Rate at Bottomhole Conditions

Selection and Determination of Tubing and Production Casing Sizes

Method of Analyzing Tubing Size Sensitivity Affected by Inflow Performance

Wellbore Instability Analysis

12.11.2 Collapse When Communicating

Continuous gas lift troubleshooting

11.3.1.3 Failures or malfunctions of gas lift and completion equipment

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