Offshore floating production method

Details Offshore floating production method Offshore floating production method

2002-04-04

2002-12-17

Neuder, William (Department: 3672)

Boring or penetrating the earth

Boring a submerged formation

C175S007000, C114S230100

Reexamination Certificate

active

06494271

ABSTRACT:

FIELD OF THE INVENTION
This invention relates to a method for the offshore production of hydrocarbons using a floating vessel.
BACKGROUND OF THE INVENTION
Numerous systems for producing hydrocarbons from offshore fields have been proposed and implemented since hydrocarbons were first produced from shallow water platforms early in the twentieth century. Initially,/these bottom-founded platforms facilitated production from fields generally brow the platform. More recently, industry has developed the ability to produce hydrocarbons from wells which extend outward from the region of, but do not necessarily terminate directly below, the platform. Broadly speaking however hydrocarbons produced from bottom-founded platforms derive from fields extending a limited physical area around the location of the platform, and a separate platform is usually required for production from fields which are not generally below a first platform's location. In addition, fields which are large in areal extent may require more than one platform. Once hydrocarbons have been produced, the platforms pump the hydrocarbons into available pipeline systems to enable the hydrocarbons to be transferred to appropriate markets.
As industry expanded its exploration activities into ever-deeper water depths, industry began to use compliant production systems. Compliant production systems are not rigidly fixed to the seafloor but rather are designed to respond to the are to carry the hydrocarbons to market. As with bottom-founded platforms, once a compliant production system is installed in the location for which it was intended, production of hydrocarbons derives from fields in the near region of the installation location.
One type of commonly used compliant production system is the floating production vessel (“FPV”). Initially, industry used FPV's for production, but relied on separate drilling vessels to pre-drill and workover the wells. To eliminate the cost of the separate vessel, FPV designs are now available which can drill, produce from, and workover wells; these vessels are often referred to as floating drilling production, storage and offloading vessels (FDFPSO's). Nevertheless, several limitations of these new-generation FPV's exist. These limitations include the complexity of incorporating the drilling system into the already complex turret system, from which the mooring system is deployed and around which the FPV weathervanes, or, in the alternative, restraining the FPV from weather-vaning and installing the drilling rig above a wellbay in the center of the vessel. The first limitation raises cost and operational complexity challenges. The second raises an operational challenge. Floating vessels should preferably retain the ability to respond to environmental forces, and for FPV's that means retaining the ability to weathervane in response to directional changes in those forces, or limiting the application to regions with mild environments. Finally, as with both bottom-founded platforms and other compliant production systems, FPV hydrocarbon production generally derives from field locations in the general region of the FPV. FPV's are held in place by spread mooring systems, and are confined to that location during the field's production life. As a result, FPV's generally suffer the same hydrocarbon production constraints that are inherent to bottom-founded platforms.
The problem faced by industry in the use of FPV's can be further described in association with FIG.
1
. Vessel
15
includes a drilling rig
16
and a combined moonpool/turret
17
. Drilling riser
19
and mooring lines
18
extend from moonpool/turret
17
. For the purpose of this simplified depiction of the problem faced by industry, production risers, which during production would extend from moonpool/turret
17
to template
20
, are not depicted. Wells
21
a
,
221
b
,
21
c
, and
21
d
extend from template
20
, which rests on seafloor
6
, to field
7
.
Moonpool/turret
17
allows vessel
15
to weathervane, in other words point itself towards the direction of the prevailing wind, wave, and current forces, but mooring lines
18
do not allow substantial horizontal movement and vessel
15
is therefore restricted to a central mooring location approximately above template
20
. This constraint results, among other reasons, from the need to minimize the bending stresses which would be created in riser
19
if vessel
15
horizontally moved substantially away from its central mooring location at a time when riser
19
was connected to template
20
. As a result, vessel
15
suffers a location constraint similar to the constraint inherent to bottom-founded platforms. In other words, the FPV suffers the constraint that all risers, whether production or drilling, must extend back to a surface location which is at the central mooring location, and which in turn is approximately above the subsea template.
The production efficiency problem that results from this constraint is exemplified by wells
21
a
,
21
b
,
21
c
, and
21
d
in
FIG. 1
, which extend vertical distance
11
from seafloor
6
to field
7
. Each well
21
also has a lateral reach
12
, which is the lateral distance between a vertical line extending through template
20
(line not depicted) and the physical location of the bottom of that well. For example, well
21
a has lateral reach
12
a
, and well
21
b
has lateral reach
12
b.
It is understood to those skilled in the art that in deepwater the ratio of vertical distance
11
to the lateral reach
12
for a well is typically limited to a reach ratio of approximately one to three due to operational and physical constraints on the drilling equipment and the casing pipes used in the wellbores. This limitation places production efficiency constraints on the FPV system. Specifically, hydrocarbon fields extending from a central location a horizontal distance more than three times the average of the field's depth below the seafloor may not be fully producible from a single FPV system, and a separate production system may therefore be required to produce all recoverable reserves from the field. Furthermore, in deepwater, if the field of interest is more than one or two kilometers below the seafloor, the maximum lateral reach of the wells drilled to produce that field is generally even more limited. The reach ratios for such deepwater wells may be as low as one to one, or less. Thus, even though FPV's are not bottom-founded, they suffer the same inherent constraint of bottom-founded platforms-remote portions of the field may not be fully producible due to the horizontal location constraints on the FPV system.
One alternative of addressing this problem is to use separate subsea wellheads, and not the single well template
20
depicted in FIG.
1
. Separate wellheads would allow wells
21
to extend to field
7
from different physical locations on seafloor
6
, thereby extending the ability of the overall system to extract hydrocarbons from the entire field. The problem faced by this alternative arises during the drilling and workover phases of operations. By placing separate wellheads on seafloor
6
, riser
19
must connect from vessel
15
, in its central mooring location, to the different physical locations of the wellheads on seafloor
6
, thus again creating bending stresses in riser
19
. In the alternative, the mooring system could be adjusted each time riser
19
must connect to a different wellhead location so that those stresses are minimized. Any such mooring system would require special design considerations, however, since standard mooring systems are not designed for frequent changes. In addition, it is operationally undesirable to be required to make repeated adjustments to a mooring system, due to the cost of the support vessels that are often required to make such adjustments. Finally, this alternative is undesirable because the production riser system, not depicted in
FIG. 1
, would then be required to have the ability to move laterally to all locations

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