Wells – Processes – Heating – cooling or insulating
Reexamination Certificate
2002-09-23
2004-08-10
Will, Thomas B. (Department: 3671)
Wells
Processes
Heating, cooling or insulating
C166S057000, C166S366000, C166S367000, C405S129270
Reexamination Certificate
active
06772840
ABSTRACT:
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
Not Applicable.
BACKGROUND OF THE INVENTION
The present invention relates to apparatus and methods for a subsea tie back and more particularly to a pipe disposed within the flowline for conducting flowline operations and still more particularly to methods for treating a flowline utilizing the inner pipe.
Subsea tie backs are flowlines tying back the trees of producing wells in producing field to a processing facility. The production facility processes the well fluids received through the producing well flowlines by separating the gas from the oil and by removing unwanted constituents such as gas and water, which at low temperatures and pressures, form undesirable hydrates. The conditioned and stabilized oil is either pumped through an export pipeline or transported by tanker. Typically there is a separate gas line for the produced gas.
Referring now to
FIG. 1
, there is shown a typical tie back system that includes a production facility
10
on an offshore platform
11
with two insulated tie back flowlines
12
,
14
extending to a subsea manifold
16
. The manifold
16
is many miles from the production facility
10
. There are a plurality of christmas trees
18
in an oil field
20
having individual flowlines
21
extending from each tree
18
to manifold
16
where the production from each well is commingled. Electrical and hydraulic control umbilicals
22
,
24
, respectively, extend from platform
11
to manifold
16
to control the operation of manifold
16
. Particularly, the control umbilicals control valves on manifold
16
and trees
18
as well as the chokes (not shown) in the individual christmas trees
18
. A chemical injection line
26
also extends from the platform
11
to the manifold
16
and communicates with the flowlines
12
,
14
for chemical treatment in the flowlines
12
,
14
and in the wells.
The production from each of the trees
18
passes to the manifold
16
and then is commingled for passage through the dual flowlines
12
,
14
to the production facility
10
on platform
11
. The production from field
20
, of course, is raw production well fluids. The production facility
10
processes the crude produced by the trees
18
by removing, as for example, any water and gas in the well fluids such that only oil remains to be exported by an export pipeline
28
to shore. Instead of an export pipeline, a floating production, storage and offtake (FPSO) vessel may be used which not only process the well fluids but also stores the oil and gas for off loading. The production needs to be stabilized before it is exported either through the export pipeline
28
or the export vessel. To stabilize the crude means to place the oil in condition to put it in the export pipeline
28
and pump it a great distance. Although only field
20
is shown in
FIG. 1
, production facility
10
may also receive the production from other surrounding fields, such as oil fields
30
,
32
.
Although
FIG. 1
shows the platform
11
supported by the sea floor
34
, production now is occurring in deep water. Deep water is typically where the water depth is over 1,000 meters. In 1,000 meters of water, the production facility
10
would be on a floating platform anchored to the ocean floor or on a vessel. In deep water, the production facility
10
must be a floating facility such as a SPAR, a TLP (Tension Leg Platform) or an FPSO.
Using subsea flowlines to tieback subsea wells to a remote processing facility is an established method for developing oil and gas fields. The design and specifications of the subsea flowlines is driven by the needs of flow assurance management. Flow assurance management includes ensuring that the unprocessed well fluids: (1) are able to reach the process facility; (2) arrive at the process facility above critical temperatures (such as the wax appearance temperature or cloud point and the hydrate creation temperature); (3) can be made to flow again after planned or unplanned shutdown (particularly with respect to clearing hydrate blockages); (4) avoid hydrates, wax, asphaltene, scale, sand, and other undesirable contents from building up in the flowline; and (5) can be made to flow at a range of driving pressures, flowrates, and compositions. See “Emergence of Flow Assurance as a Technical Discipline Specific to Deepwater Technical Challenges and Integration into Subsea Systems Engineering” by Kaczmarski and Lorimer of Shell, OTC 13123 Apr. 3, 2001.
The typical methods used to achieve the many different demands of flow assurance include using highly insulated flowlines, pipe-in-pipe flowlines, active heating of flowlines, and dual flowlines. These approaches have a high cost, however. The oil industry therefore is continually attempting to increase tieback distances and to reduce costs. The challenge is to have longer tieback distances while at the same time achieving acceptable costs. This is proving difficult for the industry, especially because subsea tiebacks tend to be the approach used for the smaller reservoirs (which demand lower costs.) Deeper water exacerbates the difficulties of subsea tie backs with the added disadvantage that it is much easier for hydrates that can block the flowlines to form in deep water. See “The Challenges of Deepwater Flow Assurance: One Company's Perspective” by Walker and McMullen of BP, OTC 13075 dated Apr. 30, 2001.
Wax in the well fluids builds up on the inner surface of the flowline over time unless the temperature of the well fluids is maintained above the wax appearance temperature, i.e. the cloud point where particles appear in the liquid turning the liquid cloudy. The wax appearance temperature varies between 50 and 120° F. depending upon well fluid properties. It is important that the well fluids maintain a high temperature, i.e. are hot, as they pass through the flowline from the manifold
16
to prevent the wax from plating up the flowline. However, sometimes the cooler temperatures can not be avoided. For example, the well fluids adjacent the wall of the flowline are cooler than the bulk of the fluid passing through the central portion of the flowline. Thus, the wax will tend to plate up on the inner surface of the flowline where the temperatures are cooler, i.e., below the wax appearance temperature. Other undesirable constituents of the well fluids, such as asphaltene, scale, and sand, also tend to build up in the flowline.
A subsea tie back preferably provides for the use of a pig to be pumped through the flowline to remove the wax, asphaltene, scale, sand and other constituents in the well fluids that tend to build up in the flowline. “Pig” stands for pipeline inspection gauge. Dual flowlines with an end-to-end loop are preferred to provide a full circuit for the pig so that the pig can pass through the flowline from the production platform, through the tie back flowline, and then back to the production platform. Scraper pigs run through the flowline to remove wax and other build up on the inside of the flowline and are run at a frequency depending upon the fluids and other conditions.
Intelligent pigs can also be used to inspect the inside of a flowline. In most typical intelligent pigging, the pig flows through the flowline and the information gathered by the pig is discerned after the pig has passed through the flowline. If all the necessary information has not been gathered, then it is necessary to run the pig back through the flowline, particularly over a certain area of the flowline which is of concern. It would be preferred to have a system that provides “real time” information as the pig passes through the flowline. Real time information allows the operator to see the information gathered by the pig in real time as the pig passes through the flowline. This permits the operator to also control the inspection tools that are carried with or are part of the intelligent pig.
The undesirable constituents of the well fluids, such as wax, asphaltene, scale, and sand, may also be prevented or removed with chemicals. Chemicals may b
Beach Thomas A
Halliburton Energy Service,s Inc.
Rose Colin A.
Will Thomas B.
Wustenberg John W.
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