JPS6358000A - Method of treating pipeline - Google Patents

Abstract

(57) [Abstract] This bulletin contains application data before electronic filing, so abstract data is not recorded.

Description

DETAILED DESCRIPTION OF THE INVENTION The present invention relates to the elimination of residual free fluid buildup in generally horizontal sections of pipelines.

such as areas with offshore oil or natural gas reserves,
Anywhere in a hydrocarbon-bearing zone, at least one platform or offshore structure is usually constructed at a suitable location within a known area of the zone. There are at least two major functions of such a platform. Functionally, the platform provides a base for drilling the required number of oil wells into underground oil reservoirs and extracting the hydrocarbon reserves. Second, the platform functions to receive, process, and store hydrocarbons delivered from other wells within the reservoir zone.

Typically, other oil wells are distributed at predetermined locations in a defined reserve zone to provide easy access to the hydrocarbon source. Thus, anywhere in a productive reserve area, typically
A number of oil wells can be seen located on the ocean floor at various distances from the main platform.

A number of pipelines are laid across the ocean floor between the main platform and its satellite well locations. These pipelines include, for each well, a production pipeline, a test pipeline, a water injection pipeline, a gas transfer pipeline and a utility pipeline. After initial installation, at least some of these pipelines, particularly gas transfer pipelines, are free from water that has accumulated in the portion of the pipeline that extends generally horizontally across the ocean floor and occupies a large portion of its volume. To remove, flush o
ut) will be required. Such sections may be sloped from the horizontal plane due to unevenness of the seabed and are therefore spaced apart along the pipeline. @ There is a possibility that there is a mass of accumulated water. Furthermore, it is also important to prevent the formation of hydrates that can lead to blockage of the pipeline during subsequent use of the pipeline, especially in cold environments, especially in its narrow sections.

Such water build-up is typically addressed by introducing a pig in the pipeline, moving the big through the pipe, and applying pressurized liquid to the pipe to physically move the water. removed by bringing it into the line. This big can be mechanical or manufactured from a gelled material that conforms to the inside surface of the pipeline. However, some pipelines
For example, if the pipeline has formed various internally extending obstructions that tend to destroy the bigs, or if abrasives cause unacceptable wear of the pipe material, Big is not suitable for use.

The present invention provides a convenient and economical method for removing free fluids in pipelines where bigs cannot easily be used or where the present invention allows the use of conventional bigs. The purpose is to provide a method that can be used for

The present invention is a method of treating a pipeline containing a residual amount of fluid in one or more generally horizontal sections and removing residual fluid therefrom, the method comprising: having a high refoaming property; and injecting into the pipeline a pressurized high expansion foam containing an amount of blowing agent in excess of the minimum amount required for foaming that is compatible with the fluid in the section of the pipeline; Advancing the foam through the or each section of the pipeline in contact with the remaining layer of liquid, and agitation of the layer by frictional agitation by the layer causes the layer to move toward the remote end of the pipeline. moving, causing mass transfer of the blowing agent from the bed to the fluid; ceasing injection of the bed; and passing pressurized gas through the pipeline to create bubbles of fluid within the pipeline section. creating turbulence in the fluid containing the blowing agent left in the or each pipeline section and removing most of the foam left in the pipeline from its remote end; Provided is a method characterized by:

Here, "high expansion foam" means a foam with a gas phase concentration of at least 75% by volume. Preferably, the foam has a gas phase concentration of at least 98%.

"Refoamability" refers to the tendency of a foam component to reform the foam by agitation when the foam partially collapses or disappears.

"High" re-foaming property means that the tendency for re-foaming is about 80% or more of the initial foam capacity. This is a measure of "reproducibility" in foaming.

"Compatible" means that the foam does not collapse rapidly and , meaning that it has a foaming agent that can foam the fluid that has accumulated in the pipeline.

In carrying out the method of the present invention for injecting pressurized, highly expanded foam into a pipeline, two operating conditions are possible, depending on the specific application, the amount of fluid in the pipeline section, and other operating conditions. It seems to exist. The "first mechanism" is that the foam passes over the layer of liquid in the pipeline, agitates the layer of liquid as described above, and also transfers the blowing agent contained in the foam to it. Conditions are such that the fluid is rapidly foamed by displacement and subsequent passage of pressurized gas through the pipeline to eliminate most of the foam remaining in the pipeline.

However, if the fluid occupies a sufficient volume of a section of the pipeline, the majority of such fluid may first be removed by mechanical "piston" displacement, here designated as the "secondary mechanism." Can be done. This second
According to this mechanism, a transaxial bubble-fluid contact area is formed in the pipeline and is passed through the pipeline at the minimum velocity necessary to maintain the contact area. being advanced so that the fluid mass leaves a residual amount of the above-described fluid in the pipeline, which is treated according to the above-described "first mechanism";
removed from the remote end of the pipeline by physical movement.

First, the amount of fluid in the pipeline in the direction transverse to the axis is
In places where there is insufficient contact area between bubbles and fluid, the removal of fluid in the pipeline is the "first mechanism"
Furthermore, if during operation according to the "second mechanism" the advancing speed of the contact area falls below said minimum flow rate, the subsequent removal of fluid takes place according to the "first mechanism". Furthermore, during the initial treatment according to the "first mechanism" in which the bubbles pass over the layer of fluid in the pipeline, sufficient depth of the fluid and sufficient pressure of the bubbles cause the bubbles to reach the surface of the layer of fluid. It is possible that a transaxial bubble-fluid contact area can eventually be formed that creates extreme turbulence and thereby allows further displacement of the fluid to occur by the "secondary mechanism". It is therefore recognized that during pipeline processing operations, fluid removal may occur different times, either by the "first mechanism" or by the "second mechanism." As mentioned above, in other applications,
This exclusion may be performed only by the "first mechanism".

Regarding the "second mechanism", the aforementioned minimum flow velocity required to maintain a contact area between the bubble and the fluid in a direction transverse to the axis called the "critical flow velocity" is determined by the diameter of the pipe, the viscosity of the fluid phase, It depends on factors such as density and therefore varies from application to application. However, drainage of subsea gas transfer pipelines generally requires advancing the aforementioned bubble-fluid contact area at a flow rate in the range of about 3 to 15 feet/second, and typically at least 5 feet/second. A flow rate of seconds is required. When the forward speed of the contact region falls below the critical flow rate, the foam phase will overtake the top of the fluid phase and the expulsion will therefore revert to the first mechanism.

In order to produce foaming when in contact with the gas phase, a relatively small amount of blowing agent, e.g. depends on the properties of the gas and liquid. However, in the method of the present invention, the excess amount of blowing agent causes the residual fluid left in the pipeline to foam, and subsequently is the same gas used in the gas phase of the foam. Good, used to remove that fluid by injecting pressurized gas. For example, when removing a relatively small amount of fluid from a pipeline, one blowing agent may be supplied in an amount of about 1 to 4% by volume of the liquid phase of the foam; may be similarly supplied in an amount of about 5 to 15% by volume.

In general, the present invention provides that the amount of residual fluid that is returned to the foam due to momentum effects regardless of gravity because the velocity of fluid movement is at or exceeds a "critical velocity" defined for a particular application. The area of contact between the residual fluid to be rejected and the displacement medium is selected as the area of contact between the residual fluid to be rejected and the displacement medium when the residual fluid is kept under extreme agitation such that the fluid moves completely in the direction of displacement with a minimum of High expansion foam fluids with rheological properties allow fluids, typically but not limited to Newtonian fluids, to be excluded from pipelines.

High expansion foaming fluids with surfactants that have good refoaming properties have been shown to maintain a well-defined contact area with fluids moving at or above a characteristic center flow velocity. It is a further advantage that by using a .

The method of the present invention uses high expansion foam to minimize the amount of fluid-carrying foam left on the pipeline wall.

With low viscosity, very low surface tension, and good refoaming fluids, at a given critical flow rate, all remaining effluent fluid, when used with a compatible gaseous displacement medium, is
guarantees foaming.

In its broadest aspect, the method of the present invention has much wider application than to drainage pipelines connecting a main oil drilling platform and associated satellite well sites. The tree method can be used to remove other Newtonian or near-Newtonian fluids from pipelines. For example, removing hydrocarbon condensate from other gas transmission pipelines with generally horizontal sections or removing solid particles entrained in M9 liquid buildup left in other fluid pipelines. It is used to do things. However, when it comes to draining gas transmission pipelines, nitrogen is the preferred gas for use in the aforementioned method, and other gases, such as air or gaseous hydrocarbons, are compatible with the fluid from which the gas is removed from the pipeline. In some cases, it can be used for other applications.

Regarding specific applications of the aforementioned method, for example on the internal surfaces of pipelines to provide protection against corrosion or to precipitate substances such as methanol or isopropyl alcohol (IPA) to prevent the formation of hydrates. It is also preferable to perform a treatment. In such applications, the wood method introduces a pressurized turbulent flow of foaming fluid containing a surface treatment medium to eliminate any residual foam left in the pipeline and further removes such foam. Such a method, which preferably includes an additional step of disassembly in the pipeline, can also be used to inactivate pipelines that are no longer needed after production at a site has ended. can. All potentially harmful substances are thereby removed from the pipeline, which is thus sealed and buried in a safe manner.

Residual bubbles left in the pipeline can be treated with methanol or P
This allows most of the water still present in the line to become mixed with the methanol or IPA.

Helps reduce hydrate formation at a later date. The methanol foam front is forced to move at least to the end of the pipeline, where, due to its short half-life, all the foam decomposes, thus dissipating the methanol and displacing it along the desired length of the pipeline. Guaranteed to be distributed.

Loose debris in the free liquid contained within the pipeline is also transported and removed from the pipeline.

The advantages of using the method of the present invention for draining pipelines over the conventional methods described above include the ease of collecting and removing 9.1'A debris in the pipeline in foam;
The economy of using pressurized gas as the displacement medium compared to BIG's pressurized liquid displacement and the ease of inerting the interior of the pipeline to prevent corrosion that occurs after pipeline blockage. can be given.

Possible applications of the method of the invention include: removal of water from pipelines and vessels; removal of condensate and debris from pipelines and vessels; application of inhibitor coatings along pipelines; pipes in operation. These include removal of hydrocarbons from line depressions; and cleaning of abandoned areas and inactive pipelines and vessels. Since most fluids can be foamed, it is especially important to use sub-diameter systems.
seamulti-diameter 5ystezs
) has many other applications.

Embodiments of the invention will now be described by way of example and with reference to the accompanying drawings.

Referring to Figure 1, a marine platform or structure 10 is installed on an offshore structure. This platform 10 is suitably positioned to optimally yield the hydrocarbons contained in the reserve and the reserves within its subdivision. This platform IO comprises, first of all, a deck which is usually installed at a position of 15 to 27 m above the water surface. This deck usually collects the produced hydrocarbons.
Provide facilities for drilling wells, including receiving and treating them and housing the personnel necessary to operate the equipment. The deck also supports storage equipment, such as tanks, separators, and other equipment where liquid or gaseous hydrocarbons are initially processed and stored before being transported to land.

The latter (and other equipment) is completed by using a pipeline extending from platform 10 to land. Alternatively, tankers and other cargo ships carrying containers that can be loaded on this platform are used to transport hydrocarbon fluids.

Moved away from main platform 10. At other oil well drilling sites in oil reserves, a ring main line (ring m
An underwater production facility 11 is provided which consists of an oil well drilling structure having a multi-fluid pipe system including a ring main 50 and a ring main 51 as a passageway for production fluid from the oil well 12.

This underwater structure 11 is connected to the main platform 1° by a series of pipelines extending along the seabed, of which only the main gas transfer pipeline 13 and the production test pipeline 14 are shown in FIG. The gas transfer pipeline 13 is a flexible riser pipe (flexi
ble riser) 15 to the main platform 10. This pipeline 13 has a reducing pipe (reducing 5 pool) at the other end.
16, a non-return valve 17.18 with a decoupling unit 19 between them.
．． Manual gate shutoff valve (manual gate 1
solation valve 20 and flexible jumper 1ea
d) communicates with the annular main line 50 on this structure through a disconnection device consisting of 21;

Although this FIG. 1 depicts a multi-well installation, the invention applies equally to a single satellite well.

After installing the above equipment, at least some of the pipelines connecting the main platform IO to the structure need to be drained. FIG. 2 shows an annular main line 50 passing through the gas transfer pipeline 13 and above the structure 11.
．． 51 and a device installed on the main platform 10 for supplying foaming liquid to the gas transfer pipeline 13 for draining both the gas transfer pipeline 13 and the production pipeline 14 through the production pipeline 14; shows. In this case, the device has a number of 150.0OO
It consists of an SCF nitrogen tank 70 and a nitrogen pump unit 71 which can be connected through a gas line 72 to a T-piece of a conventional foaming device 52 for foam generation. A liquid line 53 is provided to supply liquid from the pump 54 to the foaming device 52. Pump 54 is also in line with a water storage tank 55 which in turn connects with a storage tank 73 for surfactant and delivers aqueous liquid containing surfactant by means of pump 54 to foaming device 52. 5
It can be connected through 7. Pump 54 can also be selectively connected to another tank 56 storing methanol. The foam generator 52 has a foam outlet line 60 which can be connected to supply foam to the main gas transfer pipeline 13 at a pressure sufficient to effect the displacement of residual water therein by the method of the invention. are doing.

Liquid surfactant and water are transported through this gas transfer pipeline 1
3 will be introduced. A foaming device 52 is fed to produce pressurized, high expansion nitrogen bubbles. One of the characteristics of nitrogen foam is its ability to constantly re-foam and reproduce itself. However, for this to occur, the bubbles are constantly displaced by the turbulent flow flowing within the pipeline.

As this foam is rapidly pumped through the pipeline, the mass of water that has accumulated in the vibrator line in front of this foam is flushed forward by "piston displacement" according to the "secondary mechanism" described above. The residual water is such that, by dilution of the surfactant, it is possible to generate compounds that cause some of the foam to mix with the free water in the Vibrine according to the "first mechanism" described above. Becomes entrained by bubbles. The surface tension of the entrained fluids is lowered to allow them to foam and be carried out of the tube.

This combination of exclusion and entrainment is used to drain water from pipeline 13. All of the crumbly debris pieces are likewise carried forward and removed from the pipeline by the viscous turbulence. Once this process is complete, the pipeline is substantially filled with water and surfactant foam. A high velocity stream of pressurized nitrogen gas is passed through the pipeline to foam the internal surfactant-containing liquid and then remove the foam mass.

Once most of the ice mass has been removed, residual foam is removed by pumping methanol from tank 56 into foaming device 5 by pump 54.
2, it is displaced by methanol bubbles. This foam is injected over the complete pipeline length in order to disrupt some of the residual water, causing it to foam and be physically removed. The foam mass remains in the pipeline and decomposes into liquid and gas components within the pipeline. Any residual water that is still present helps prevent hydrate formation when mixed with methanol and hydrocarbon gas is injected into the pipeline. The required amount of methanol in the foam is required to add a sufficiently high level of water to the water remaining in the pipeline to prevent foaming of the aqueduct under the pipeline's pressure and temperature operating conditions. Affected by volume.

Nitrogen bubbles can be injected from the platform into the pipeline immediately after determining that the free fluid has been treated. All equipment is limited by the size of the platform, which allows this operation to be carried out, and which allows the calculated amount to be used before ordering containers containing relatively large amounts of methanol. This is the equipment installed in.

In the above-described application example of the method of the invention, bigs are not used due to the nature of the pipeline.

However, bigs may be used in pipelines to separate fluids and gases from bubbles for debris removal or chemical operations.

EXAMPLE The present invention for removing water from a main gas transfer pipeline and a production test pipeline having a length of approximately 8 miles and a nominal diameter (0/D) of 8 inches according to FIG. Specific embodiments of steps for carrying out the method are described.

This gas transfer pipeline is a multi-diameter pipeline. The table below shows their respective diameters.

Rise pipe 15 4.1 fitting (Spo
ol Piece) 30 3.828 Main gas transfer line 13 7.825 Disconnection assembly 16-20 3.828 Flexible communication conduit 21
4.00 Gas transfer annular main line 50 5
．． 187 Oil well bypass pipe (Crogsover) 61
2 gas transfer chain yoke 62 0.25-0.
50 The presence of free fluids within the system will result in the formation of water contaminants within the gas transfer line as soon as hydrocarbons are injected, resulting in blockage of the entire pipeline, so the line must be adequately drained. I need to be there.

Subsequent attempts at draining pipelines using gelled polymers instead of gas were not successful as pipelines were not suitable for this technology for two reasons. First, the pipelines varied in internal diameter and had probes and other internal protrusions that could cause big failure.

Second, the use of gas as a displacing medium only partially displaced the gel. Mechanical lugs usually can cause the gel big to move back to reduce gas protrusion. This is because it prevents gel from remaining in the line. This resulted in 15% of the pipeline's volume remaining filled with water.

The steps of the drainage method according to the method used for draining the pipeline are as follows:

Stage 1: The pipeline is purged with nitrogen, hydrocarbons are purged, and a pressure/volume correlation test is performed to indicate the volume of liquid left in the line.
The maximum flow rate at some of the blockages is then determined to see if this poses an obstacle to the intended bubble removal method.

Stage 2: Drainage of the pipeline is carried out using aqueous foam and removal of ice blocks in the gas transfer line.

3rd floor: Methanol bubbles are forced through the pipeline and methanol is applied throughout the length of the gas transfer line.

Stage 4: At a remote underwater production facility, gas transfer is initiated to the well 12 and production from the well 12 is initiated.

LL 1 - A total of 255.600 standard cubic feet (scf) of nitrogen was used during the purge of the purge gas transfer line. An additional 15,000 scf of nitrogen was used in the second series of pressure/volume tests (the first series was
215.00 in the final stage, where the gas was flowed at high speed to settle the pressure imposed by the geographical proximity of the pipeline (carried out at the beginning of the purge stage).
0 scf nitrogen was used. Therefore, the total nitrogen consumed during the entire first stage is 485.600 scf
(i.e., 4 tanks).

A nitrogen purge was performed at a pressure between 150-210 psia at the main platform end of the gas transfer line. The average flow rate was 300 scf/min and the pipeline temperature was approximately 40°F (4°C).

From the pressure/volume correlations performed for these tests, a liquid content of the gas transfer line on the order of about 250 barrels, or a liquid content of about 10% in the gas transfer line, was calculated, which is, for example, Higher values are possible, up to about 20% liquid content.

At the end of the purge phase, at least 250 barrels of water still remained in the gas transfer pipeline to be removed. Direct addition of methanol also reduces the volume of methanol required and the structure 1
The ability to add sufficiently high concentrations at one end is also impractical.

Two types of aqueous foam treatments (Case 1 and Case 2) were performed because the first treatment ended prematurely to sufficiently open the blockage in the gas lift pipeline. It is believed that the limits presented by these are too large for liquid to pass through, while at the same time maintaining sufficient foam velocity within the line.

For these two treatments, the surfactant used was SF 12 (NOIIISCO), an ammonium salt of alcohol nithioxylate sulfate.

Kono surfactant is N0WSCOWELL 5ERVI
It is commercially available from CES (UK) Limited.

Figures 3 and 4 each show the pressure in the gas transfer pipeline at the end of the main platform during two types of processing.

Immediately after the start of bombing in case 2, there is a slight decrease in pressure due to the tip of the bubble descending down the riser 15 (see Figure 4).This effect is more pronounced in case 2 than in case 1. is more clear. A high concentration (10% of the liquid volume) of surfactant was used in the lead foam, with the view that it would be introduced into any liquid at the bottom of the riser 15. Five gallons of surfactant stock solution was introduced into the system at the start of the operation for the same reason.

This results in a sharp increase in pressure at the end of the main platform, the rate of increase being higher in the first case than in the second case.
The case was larger. This coincides with the removal of liquid in the gas transfer pipeline at the lowest point of the riser bottom. From this it appears that in case 2 there is less (if any) liquid than in case 1, and the pressure response confirms this.

Once the pressure increase was above 3007400 psi, liquid pumping was stopped to stabilize the system and nitrogen was used to maintain the bubble flow rate on its own. This procedure was repeated throughout the scheme whenever pressure peaks occurred. The liquid injection rate, surfactant concentration and gas flow were varied as the system was completed.

In case 2, a more controlled response was maintained as shown in the pressure response graph. This is believed to be the result of two factors: less liquid in the pipeline and better control technology for this process.

In case 1, when pumping finally stops (
A subsequent gradual decrease in pressure over a period of 2-3 hours (indicated by point A in FIG. 3) indicated that liquid was flowing through the occlusion.

This is the point at which it was decided to completely open the blockage and prepare to open to the sea. These two operations include
Diaper intervention was required.

The pressure response at the structural end of the gas transfer pipeline more clearly shows the restriction in flow caused by the blockage. FIG. 5 is a graph of the recorded pressure values, and a clear change in the expected slope can be seen with a one-step change.

In the second aqueous foam treatment (Case 2), the surfactant concentration of the foam is increased to compensate for the low flow rate caused by the restriction of the occlusion and also allows the foam to do its work most effectively. Utilize methods that are likely to produce good results in the first step under conditions that are expected to agglomerate.

A gas transfer pipeline opened to the sea.

Stop the bubble generation and add nitrogen at about 3000 scf/
Pump for 20 minutes to maximize turbulence and allow the foam to re-foam.

The slag collector was emptied four times during the aqueous foam treatment. The first two of these were all oil;
The last two times it was almost all water. Each time, the readings for bottom sediment and water (referred to as B S & W) were 0, respectively.
%, 3%, 100% and 98%. Additionally, water remained in the test pipeline and was recovered in the third and fourth stages.

2 “Parameters The initial foam pumping pressure is 200 psig,
The ambient temperature in the pipeline was 40'F (4°C), varying depending on the nature of the system's operation.

JLJL Treatment 1 Treatment 2 Nitrogen scf/min 1500-250
0 1000-2800 liquid barrel 7 minutes 010.25 010.25 surfactant
Capacity% 3 5-10 processing time
Hours 3.5 2.5 Nitrogen usage
scf 447.000 5B5.0
00Amount of surfactant used Barrel / Gallon / Water content of foam / Barrel
Calculated amount of 1011 water 300 barrels ± 25% discharge into the sea/increase in purge pressure: 55
．． 000scf and high speed nitrogen circulation after purging 55.
These results, including 0OOscf, showed that the foam was stable enough to displace liquid in a piston-like manner and that the regeneration ability of the surfactant where "disappearance" occurred appeared to be satisfactory.

The treatment was generally successful, leaving the gas transfer pipeline substantially free of water bodies.

3 A similar equipment configuration was used for the production of methanol foam as for the methanol water-based foam. The following logical and safety features are noteworthy: The methanol bubbles are mixed to maximize the flow rate for a given nitrogen injection rate, and the flow rate is within the tolerance of the blockage in the gas transfer line. pump at the lowest pressure the system will allow. The starting pressure was about 100 psia and the end of pumping was about 350 psia.

The process was well controlled to avoid peaks in the pressure response, which is an indicator that the pipeline is substantially free of liquid.

It was shown that there was no pressure increase at the ends of the structure until the bubbles were reached. Figure 6 shows this pressure response.

Because the pressure across the blockage responded positively to fluid flow as opposed to gas flow, a liquid slug of methanol could be introduced into the bubble and detected at the structure end of the gas transfer pipeline. As shown in FIG. 6, a sudden increase in pressure (B in the diagram) occurs almost exactly when it is predicted that the slag will reach the structure. At this point, the system is closed for several hours to allow the bubbles to break up. This foam treatment allows highly concentrated methanol solution to be
We succeeded in reliably supplying the areas where it was needed most (such as closed ends and low points in structural piping) and where gas transfer operations were ready to begin.

This pure methanol slug (12 barrels) was introduced approximately 30 minutes after the start of foam pumping, when the travel distance was calculated to be 8200 feet along the gas transfer pipeline (100 psi pressure). This line is approximately 42,000 feet long and has a travel distance of 48.0
A pressure response occurred at the position when the pressure was calculated to be 0.00 psi) (180 psi). At exactly 42,000 feet, a pressure recorder on the structure indicated that the bubbles had just passed through the blockage.
It showed a small pressure increase (10-15 psi) (see Figure 6C), proving that the liquid phase in the structure was indeed methanol rather than water expelled by Big. .

Immediately before shutting down the system - a second methanol slug (12 barrels) is placed at the bottom of the riser and all that may be collected at this site while the line is still in process. with the intention of adding it to the liquid of
Pumped.

Amount of nitrogen used in the methanol slameter 210.200 scf Amount of surfactant used 300 cells containing ethanol in the bubble receiving layer Amount of methanol in a 5.55B US gallon slag 24 barrels Amount of preliminary methanol, 43θ
Calculated flow rate for US gallons of foam approximately 8 feet/
Seconds Processing Time 3 Hours Water Production 0 The surfactant used was a methanol blowing agent called FC431, commercially available from 3M Company. This is a fluoro-carbon methanol blowing agent.

The blowing agent is usually present in an amount of about 1-25% by volume, for example 5% by volume of the liquid phase of the foam.

No method of predicting the pressure peak and gas transfer pipeline responsiveness to methanol bubble treatment location was found for third stage targets. The line was treated with methanol along its entire length and an ethanol slug was present within the structure.

The method, in which the calculated exclusion condition is matched by the actual pressure response of the system, establishes that there is no liquid mass in the line and that the water treatment was successful.

4 Gas' of P. The transfer gas was introduced into the gas transfer pipeline at pressures up to 1750 psig.

Exactly 12 hours have passed after the end of the third stage,
Four hours is typically considered the minimum time required to allow sufficient time for the methanol bubbles to break up and for the methanol content to dissipate into the water left in the line.

Twelve barrels of methanol slag was left at the bottom of riser 15 at the end of the methanol foaming stage. 2 more
Zero barrels of slug were introduced at the beginning of hydrocarbon gas pumping to further process any liquid that could be collected and fully saturate the gas entering the line. Addition of methanol to the gas was initiated at a higher than normal rate of 5 gallons/minute. This continued for exactly 7 hours.

Pressurization in the gas line was performed at a rate of about 30 psi every 10 minutes with a gas flow rate of about 4 mm standard cubic feet per day.

Initially, the pressure is increased to approximately 650 psi for the gas transfer line valves that reach the structure and are located there, and then to approximately 1100 psi for the test line valves that extend from the structure. It was strengthened to the point.

Consequently, gas transfer was initiated with two main platform injection pressures: 1530 psia annular main line pressure 1590 psig tube head (Tab
ing ) lead) 310 psig well 12 gas transfer valve location is 4110 ft B
K B (Below Kel17 Bushin
g) (540 feet).

Gas transfer was accomplished by closing the gas transfer line and monitoring well head pressure. All these results are shown in FIG. Furthermore, when the gas flow increased so much, the gas returned to the main platform 12.

[Brief explanation of the drawing]

Figures 1 to 7 explain the method of the present invention.
The figure is a schematic diagram illustrating a main IOL drilling platform and associated satellite oil well drilling templates and production lines connected by main gas transfer lines. FIG. 2 is a schematic diagram showing the arrangement of equipment on the main platform for supplying pressurized foam to the gas transfer line for drainage therein; FIG. Figure 3 shows the pressure in the gas transfer line at the end of the main platform during the first aqueous foam treatment in % Figure 4 shows the pressure in the gas transfer line at the end of the main platform during the second aqueous foam treatment FIG. 5 is a pressure diagram schematically showing the pressure recorded at the template end of the gas transfer line during aqueous foam treatment. FIG. 6 is a pressure diagram schematically showing the pressure recorded at each end of the gas transfer line during methanol foaming, and FIG. 7 is a pressure diagram schematically showing the pressure recorded during the gas transfer initiation procedure. FIG. 10... Main platform, 11... Underwater production equipment, 12... Oil well, 13... Main gas transfer pipeline. 14... Production test pipeline 15... Flexible riser pipe, 19... Separation unit, 21... Flexible connection conduit, 52... Foaming device, 54... Pump, 70... Nitrogen tank . Fig, 3 Gas transfer line pressure (psia) Pressure (psig) Pressure (psia) Pressure (psia)
Gas transfer line pressure (psi)

Claims (1)

[Claims] 1. In one or more generally horizontal parts,
A method of treating a pipeline containing a residual amount of fluid and removing residual fluid therefrom, the method comprising: treating a pipeline containing a residual amount of fluid and removing residual fluid therefrom, the method comprising: injecting pressurized high-expansion foam containing more than a minimum amount of blowing agent into the pipeline; introducing the foam into that section or each of the pipelines in contact with the layer of liquid remaining therein; advancing a foam through the section, and agitation of the layer by frictional agitation by the foam moves the layer toward a remote end of the pipeline and causes mass transfer of the blowing agent from the foam to the fluid; ceasing the injection of the foam; and passing pressurized gas through the pipeline to create fluid bubbles within the pipeline section to remove the foam remaining in the or each pipeline section; A method characterized in that it creates turbulence in the fluid containing the agent and removes most of the bubbles left in the pipeline from its remote end. 2. At least a portion of the mass of fluid in the section of the pipeline has the minimum amount necessary to inject the foam into the pipeline and maintain a transaxial foam-liquid contact area. , or more, forming the region advancing through the pipeline, displacing the fluid mass from the remote end of the pipeline, so as to
The method of claim 1, wherein a residual amount of said fluid is removed in a pipeline treated according to the method of claim 1. 3. The method of claim 2, wherein the contact area is advanced at a speed of about 3 to 15 feet per second. 4. The method of claim 3, wherein the contact area is advanced at a speed of at least 5 feet per second. 5. The gas/liquid (volume) ratio of the foam is at least 75%
The method according to any one of claims 1 to 4. 6. Claim 5 in which the ratio is at least 98%
The method described in section. 7. The method according to any one of claims 1 to 6, wherein the pressurized gas is the same as the gas in the gas phase of the bubble. 8. A method according to any one of claims 1 to 7, wherein the pressurized gas is selected from the group of nitrogen, air and gaseous hydrocarbons. 9. The method according to any one of claims 1 to 8, wherein the foam is an aqueous foam. 10. The method of claim 9, wherein the liquid phase of the foam contains about 1-15% by volume of the blowing agent. 11. The method of claim 10, wherein the liquid phase of the foam contains about 3-10% by volume of the blowing agent. 12. Pressurized foam containing a treatment agent is injected into the pipeline to eliminate any residual foam left in the pipeline, and the foam is then broken down within the pipeline so that it can be deposited on the pipe wall or into the solution. 12. A method as claimed in any one of claims 1 to 11, including the further step of precipitating the treatment agent in the pipeline with the liquid remaining in the pipe. 13. The method according to claim 12, wherein the processing agent comprises at least one of methanol, isopropyl alcohol, and a corrosion inhibitor. 14. The method of claim 13, wherein the pressurized foam containing a treatment agent has a liquid phase containing at least about 75% by volume treatment agent. 15. Claim 13 or 14, wherein the pressurized foam containing the treatment agent has a liquid phase containing about 95% by volume of the treatment agent.
The method described in section.