METHOD OF USING A SURFACE JET PUMP TO MITIGATE SEVERE SLUGGING IN PIPES AND RISERS

Abstract

A slug mitigation system for subsea pipelines that includes a riser located between a low subsea level and an upper topside level of a pipeline. There is also a separator located at the top of the riser; and a surface jet pump located at a gas outlet of the separator. In another embodiment of a slug mitigation system, the surface jet pump is located downstream of an in-line separator on a gas outlet using high pressure gas from a downstream process or compressor.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims foreign priority benefits under 35 U.S.C. §119(a)-(d) to GB 1420234.5 filed Nov. 14, 2014 which is incorporated by reference in its entirety and relied upon.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to improved arrangements for slug mitigation in subsea pipelines, such as risers, as used in the oil and gas industry and particularly, according to the invention, utilising a surface jet pump (SJP) apparatus in such arrangements. It is also hoped the invention will boost production.

2. Description of Related Art

Most of the new discoveries of oil and gas reserves are being found further offshore, causing operators to delve further and deeper into the seabed. The transportation of production fluids to offshore platforms (for processing and further export) requires subsea pipelines followed by a vertical pipe to the platform; also known as a riser-pipeline system. The combination of such pipe configurations invariably cause a ‘low-point’, which encourages an undesired multiphase flow regime known as Severe Slugging (SS). From the flow assurance point of view, this pressure oscillation phenomenon is of particular concern for mature well/fields which have a declining operating pressure. This phenomenon also upsets top side operation of process facilities and introduces vibration in the riser piping system, leading to a possible mechanical failure.

There are a number of approaches being developed/deployed to mitigate severe slugging issues. For example:

On the top side of the platform:

• Installing a control valve at the top of riser to impose back pressure
• Making a gravity separator bigger during the initial stage of design
• Installing a large liquid slug catcher upstream of existing production separator (another gravity separator)

Bottom of riser (Subsea):

• Inject gas at the bottom of the riser to lighten static head
• Install an additional riser and send flow through both risers
• Perform subsea separation and use two risers for sending gas and liquids

BRIEF SUMMARY OF THE INVENTION

The present invention seeks to find a system that mitigates a severe slugging regime in a passive way without the need of active control whilst reducing the imposed back pressure on the wells (through process equipment, riser and connecting piping) also resulting in a higher production for the operator.

The current invention looks at the process role and location of a Surface Jet pump in the following way:

• To gain additional production/pressure boost, and also to drive weak backed out low pressure (hereinafter “LP”) wells in production mode
• As an added advantage, mitigate severe slugging in risers
• Changing the flow regime in the piping system to be more favourable and creating a mixture flow of lower design (than an all liquid case)
• Stabilising production
• Minimise flow oscillation and vibration in the riser
• Expanding gas reduces the static head imposed by vertical liquid column in the riser
• Improve the severe slugging stabilised operating region
• Minimise liquid dropout pooling in the low points in the pipeline (due to increase gas velocity and sweep velocity)
• Effective use of injection gas, which is currently used for liquid static head lightening

Surface jet pumps (SJPs) are generally known in the art. Drawing on the experience gained in the use of an SJP on a wellhead and separators, i.e. in how reducing back pressure helps increase the flow through a well, even for gas lifted oil wells (refer to patent application WO2013124625A2), the current invention is suggested for reducing severe slugging.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates an example where an SJP is located on the top of the riser at the platform;

FIG. 2 illustrates an example where an SJP is located on the top of the riser at the platform on the gas outlet of the production separator;

FIG. 3 illustrates an example where an SJP is located on the top of the riser at the platform upstream of the production separator on the riser;

FIG. 4 illustrates an example where an SJP is located on the top of the riser at the platform upstream of the production separator on the riser;

FIG. 5 illustrates an example where an in-line separator (I-Sep) is used to mitigate severe slugging effects in a riser;

FIG. 6 shows a commonly used prior art approach for severe slug mitigation in a subsea environment; and

FIG. 7 illustrates a modification to the gas injection approach of FIG. 6 at the riser base by introducing a subsea SJP.

DETAILED DESCRIPTION OF THE INVENTION

SJP Applications to reduce severe slugging are described in detail below. In particular, with reference to FIG. 1, an SJP is located on the top of the riser at the platform. The SJP can be powered by an available high pressure fluid source—either liquid phase or gas phase. The SJP will lower the backpressure (arrival pressure) at the top of the riser which will in turn reduce the back pressure in the riser, allowing gas to expand in the riser/pipe lines. This action will change the operating flow regime and minimise the severe slugging region within riser. The back pressure reduction will also allow the LP wells to produce more (based on their flow and pressure relationships), which is a benefit to the operator. If production is mainly from gas wells with some liquids then the SJP can be powered by the high pressure (hereinafter “HP”) gas stream. If LP well production is from mainly liquid wells, then the SJP can be powered by HP liquids. The outlet of SJP can go to an export line directly or to a downstream production separator.

FIG. 2: An SJP is located on the top of the riser at the platform on the gas outlet of the production separator. The SJP is powered by the HP gas available from the export compressor outlet or from its recycled gas stream. The SJP will lower the production separator pressure which will allow backpressure reduction and change of flow regime in the riser and piping. Additional benefit would be backpressure reduction on the production manifold, leading to increase production on the same well. This increased production also adds in shifting severe slugging region towards a stabilised flowrate. In this application regardless of the type of production (gas dominated or liquid dominated), the gas driven SJP will be applicable to ease of severe slugging issues and allow additional production too.

FIG. 3: An SJP is located on the top of the riser at the platform upstream of the production separator on the riser. The SJP is powered by the HP gas available from the export compressor outlet or from its recycled gas stream. The riser flow can be diverted via the SJP in full or in part as per control requirement of the operator. The HP gas mixes with the riser fluid and goes as a low density mixture into the gravity separator. At the same time, the SJP also act as back pressure reducer on the riser to achieve benefits already highlighted for FIGS. 1 and 2. Depending on the location of the SJP on the riser itself the light density mixture can be created at various heights in the riser (this will also reduce the static head in the riser fluid column) and create stabilised flow within riser.

FIG. 4: An SJP is located on the top of the riser at the platform upstream of the production separator on the riser. The SJP is powered by the liquid pump using the part of the produced liquid as the HP source. This approach is also applicable in situations where no spare HP gas is available for the SJP. The riser flow can be diverted via the SJP in full or in part based on the control requirement of the operator. The outlet from the SJP enters as a well mixed gas/liquid mixture into the gravity separator. At the same time, the SJP also act as back pressure reducer on the riser to achieve benefits already highlighted for FIGS. 1 and 2. Due to additional liquid in the piping system the operating pressure of the separator/riser may rise, however, in this situation, the SJP will discharge flow at a higher pressure as required by the downstream process (separator, piping, etc.) while still maintaining the backpressure reduction on the riser to affect the severe slugging and increase production from the existing infrastructure.

FIG. 5: This option explores the ability of an in-line separator (I-Sep) to mitigate severe slugging effect in a riser as discussed in detail elsewhere (e.g. our co-pending patent application No. GB 1419947.5 which is incorporated herein by reference). We have suggested using SJP on the gas outlet using HP gas from the downstream process (compressor). The function of SJP would be the same as discussed above, mainly reducing back pressure to change flow regime in the riser and also to gain production from wells. In such case, the main production separator can be by-passed or operated in parallel with the I-SEP/HI-SEP system. The produced gas can go to the gas outlet and produced liquid will join the liquid line upstream of the liquid pump. The use of SJP with I-SEP will enhance the severe slug mitigation capability over the one already discussed in our co-pending patent application using I-SEP for slug mitigation.

FIG. 6 (Prior Art): This shows commonly used approach for severe slug mitigation in subsea environment, in which high pressure gas from the platform is injected at the base of the riser. This serves two main functions, first of all to reduce the mixture density of the liquid column in the riser, hence reduces the backpressure on the production line wells, secondly it changes the flow regime in the riser, so that severe slugging is mitigated. The issues of this approach is that due to extra gas in the system the topside separator pressure increases, which negate some of the back pressure reduction gained by lightening the static liquid head. Also this does not allow additional backpressure reduction on the wells to gain production the way SJP does.

FIG. 7: In this concept, we have modified the gas injection approach of FIG. 6 at the riser base by introducing a subsea SJP. The SJP will give added benefit of overcoming the incremental pressure rise at the inlet of topside separator (and in the riser) due to addition of HP gas. It will also allow back pressure reduction on the LP wells for maintaining or gaining additional production. It will also minimise any severe slugging effect while reducing the static head in the riser. The HP gas to power the SJP can come from the platform. Again, either part or full production can be diverted through the SJP as needed.

If there is no HP source available at the platform and there is a nearby subsea HP pressure manifold, then using this HP pressure energy additional backpressure reduction on the LP well can also be achieved via the SJP, while still keeping the benefits of severe slugging mitigation in the riser. Gas injection at the bottom of riser does not offer these stated benefits.

Claims

1. A slug mitigation system for subsea pipelines including:

a riser located between a low sub-sea level and an upper topside level of a pipeline;

a separator located at the top of the riser; and

a surface jet pump located at a gas outlet of the separator.

2. The slug mitigation system of claim 1 wherein the surface jet pump is powered by high pressure gas available from an export compressor outlet or from its recycled gas stream.

3. A slug mitigation system for subsea pipelines including:

a riser located between a low sub-sea level and an upper topside level of a pipeline;

a surface jet pump located at the upper topside level of the pipeline, downstream of the riser;

wherein the surface jet pump is located downstream of an in-line separator on a gas outlet using high pressure gas from a downstream process or compressor.

4. The slug mitigation system of claim 3 wherein a main production separator at the top of the riser can be by-passed or operated in parallel with the inline separator and surface jet pump.

5. The slug mitigation system of claim 3 wherein produced gas can go to a gas outlet and produced liquid joins the liquid line upstream of a liquid pump.