MOBILE BAY CORROSIVE GAS FLOW LINES USE NEW MATERIAL, DESIGN

Glenn A. Lanan
Intec Engineering
Houston

Don W. Barry
Shell Pipe Line Corp.
Houston

Development of the Fairway field, offshore Alabama in Mobile Bay, required installing four flow lines to transport high-pressure, hot, sour, and highly corrosive natural gas from wellhead platforms to the central facility platform.

The project employed several new technologies, including bimetallic pipe to control internal corrosion, a "zig-zag" pipe configuration to control upheaval buckling, and continuous steel coiled tubing for utility-line bundles.

HOT, SOUR GAS

The Fairway field is located in the Gulf of Mexico, approximately 4 miles outside the entrance of Mobile Bay. Offshore facilities are in state waters in Mobile Bay Blocks 113 and 132 (Fig. 1).

The field is operated by Shell and produces natural gas from the deep Norphlet formation at production rates currently averaging 40 MMcfd/well. In addition to having high wellhead pressures, the gas is hot, sour, and highly corrosive; it therefore poses special design requirements for the flow lines.

Gas produced from four outlying single-well platforms is transported through the flow lines to a central facility platform (CFP). There it is dehydrated and piped ashore to the Yellowhammer gas plant for treatment before sale.

Four trunklines between the CFP and the gas plant (16-in. primary gas, 12-in. secondary gas, 8-in. produced water, and 6-in. fuel-gas lines) were laid simultaneously from a single barge during summer 1990.

Lengths of the four flow lines connecting the satellite wellhead platforms to the CFP are summarized in Table 1. A fifth wellhead platform (JC) is connected to the CFP by a bridge.

Water depths in Fairway field range from 39 ft at the deepest wellhead platform to 15 ft at the shallowest point along the flow line routes.

Under normal operating conditions, the gas pressure will be reduced at the wellhead to less than 2,000 psig. The maximum design operating pressure for the flow lines, however, is defined by the maximum shut-in tubing pressure of 10,600 psig.

The gas is produced at temperatures up to 280 F. and cooled on the wellhead platforms to a maximum of 230 F. before entering the flow lines. The flow lines are not insulated and are trenched to a minimum depth of 6 ft.

The design natural gas-composition includes 2.1% hydrogen sulfide, 6.0% carbon dioxide, and 4.9% water.

A utility-line bundle was also installed between each of the four satellite wellhead platforms and the wellhead platform (JC) next to the CFP. The utility-line bundles each consist of six pipes (air, diesel, and water lines at 1.5 in. OD; and methanol, fuel gas, and spare lines at 1 in. OD) and a 5 kv electrical power/communications cable. Design maximum operating pressures for the utility lines ranged up to 6,000 psig.

All construction operations in Alabama state waters must be performed with great care to protect the sensitive environment. This concern required rigging all construction vessels for zero discharge of trash, sewage, bilge water, and rainwater runoff from the deck.

All waste was collected and barged to an approved shore-disposal site near Mobile. Waste management, pollution prevention, contingency oil-spill cleanup, and reporting procedures were followed throughout the field construction activities.

FLOW LINE DESIGN

Flow fine pipe and welding materials were tested for corrosion resistance to the Fairway field gas during 1989.

The testing program demonstrated that a 3 mm-thick liner of Incoloy 825 (API 5LC LC302242) was more than adequate for internal corrosion resistance. Incoloy 625 (UNS NO6625) was selected for the weld filler metal.

A bimetallic pipe configuration with a corrosion-resistant alloy (CRA) liner inside a carbon steel outer pipe was selected as more economical than a solid CRA pipe design.

The pipe diameter was defined based on a nominal 4.25 in. ID of the liner pipe. This definition resulted in nonstandard outside diameters for the carbon steel outer pipe.

Table 2 shows the characteristics of the flow line and of the flow line riser. The carbon steel wall-thickness selection did not take into account the strength of the CRA liner.

Competitive bids from qualified pipe manufacturers were received in early 1990. Nippon Steel's C-II pipe was selected for the straight pipe sections (OGJ, July 29, 1991, p. 82). This bimetallic pipe is manufactured with a CRA liner pipe joint inserted into a heated seamless carbon steel pipe and by hydraulically expanding the liner pipe as the outer pipe cools and contracts.

A mechanical bond with predictable residual stresses results between the liner and outer pipe. Under certain operating situations, loss of the bond between liner and outer pipe could lead to collapse of the liner.

Because of this possibility, a metallurgically bonded (co-extruded seamless) bimetallic pipe manufactured by Tubacex Inc. was selected for the riser and seabed expansion loop bends.

This metallurgically bonded pipe could be bent into shorter radiuses than the mechanically bonded pipe without losing the bond between the liner and outer pipe. The ends of the C-II pipe were seal welded and trimmed to a "J" bevel configuration at the pipe mill.

Through careful handling, none of the fragile end bevels were damaged during shipping, coating, or subsequent bending operations.

The high temperature and pressure for the Fairway field flow lines can combine to produce axial compressive forces of 400,000 lb if the pipe is fully restrained from movement. Expansion loops were installed at the ends of each flow line to accommodate the typical thermal-pressure growth of the unrestrained ends.

Away from the ends, however, pipe-soil friction causes the compressive forces to build, and the pipe will try to move either laterally or vertically to relieve these forces. Untrenched pipelines will deflect laterally" but high compressive forces on trenched pipelines can result in upheaval buckling. 2

This condition initiates when the uplift force on the pipe exceeds the combined downward restraining force because of the pipe's submerged weight, soil overburden, and bending stiffness. Upheaval buckles can start at the crest of over-bends, or high points along the pipe profile and can result in loss of cover and excessive bending strain as the pipe feeds into the buckle from both directions. 3

ZIG-ZAG PIPELINE

Several options were evaluated for both controlling upheaval buckling and limiting the size of the flow line expansion loops at the platforms. The selected method was to install the flow line in a horizontal zig-zag configuration. 4

An 8 bend was formed in the middle of each 38-ft pipe joint. The bends were then welded together in alternating directions and laid flat on the bottom of a pre-excavated trench. A long bend radius of 65 ft was selected to prevent loss of gripping stress between the CRA liner and outer pipe.

As Fig. 2 shows, the expansion bends deflect laterally through the soil in response to increasing axial compressive force. This configuration provides a continuous means of accommodating expansion along the flow line, thereby reducing the maximum predicted axial force in the pipe to 130,000 lb.

Upheaval buckling analysis with this reduced compressive load showed it was still necessary to limit the height of over-bends formed following installation to approximately 1.5 ft.

The bimetallic flow line riser pipe was placed inside a 10-in. casing pipe, and the annulus was grouted (Fig. 3). This design prevents the seawater from boiling at the surface and provides additional mechanical protection for the riser. Seawater contacting the pipe on the seabed will not boil because of the increased hydrostatic pressure.

The riser top flanges were 4 1/16 in. API type 6BX, 10,000 psi flanges with Incoloy 625 internal CRA overlay. A solid Incoloy 625 transition spool piece was used between the flange and the riser pipe for stress relieving the flange weld without affecting the strength of the riser pipe.

The flow lines were externally coated with 50 mils of Napgard Napwrap high-temperature, liquid epoxy-felt coating. Testing demonstrated that this coating performs satisfactorily at temperatures of 230 F. Field joints were also coated with Napwrap.

Cathodic protection of the three shorter flow lines was provided by electrically bonding the flow lines to the sacrificial anode system on the platforms.

The longer "JB" flow line also had a Galvalum III clump anode located at the midpoint. This system satisfied the high current density requirements for the hot flow lines and prevented the high auto-corrosion rates experienced by conventional bracelet anodes operated at elevated temperatures.

UTILITY-LINE DESIGN

Materials evaluated for use on the four utility-line bundles included flexible-pipe bundles, conventional 40 ft pipe-joint lengths, and steel coiled tubing.

Coiled tubing is used extensively for down-hole applications in drilling and production operations but has had very limited application in the pipeline industry. It was selected for use in Fairway field based on materials costs, delivery schedules, and offshore installation requirements.

Additionally, its use in Mobile Bay provided valuable information on its design, manufacture, and installation characteristics for possible applications in deep water. Principal characteristics of the utility lines are shown in Table 3.

The 1 in. OD tubing and 1.5 in. OD tubing were manufactured in continuous lengths of up to 15,000 ft by Quality Tubing in Houston. Output from the inductive electric-resistance welding (ERW) tube mill was spooled and then coated with 100 mils thickness of a three-layer polyethylene extruded coating system.5

Each tubing length was then inspected and transferred onto 128 in. OD steel spools for offshore installation. The tubing manufacture and coating processes were carefully controlled to maintain continuous operations and minimize the number of tubing butt welds.

The utility bundles were installed by being pulled through J-tubes on the exteriors of the platforms. Separate J-tubes were provided for the tubing bundles and for the electrical cables.

The six-tube utility bundles were held together with steel bands, both along the routes and inside the J-tubes. The electric cable was left free from the tubes near the platforms, however, so it could be pulled separately into its J-tube.

PIPE FABRICATION

The flow line and utility line offshore installation contract was awarded in March 1991.

A day-rate contract basis was used rather than the typical lump-sum basis due to limited industry experience with several features of the Fairway field flow lines, most notably, offshore welding of CRA pipe.

Experience on key procedures was gained during onshore prefabrication, double jointing, and procedure tests prior to offshore installation.

Prefabrication of the flow line risers began in February 1991. Manual gas tungsten arc welding (GTAW) procedures were developed for welding the C-II, Tubacex, and solid Incoloy 625 pipes. Manual repair and tie-in weld procedures were also developed.

All welding procedures required that internal argon backing gas be maintained for 5 weld passes (four passes for automatic welding). All butt welds were machined to a "J" bevel configuration with a nominal land thickness of 0.059 in. (1.5 mm-0.3 mm).

The manual welding procedures were better able to compensate for the greater variations in land thicknesses found on the ends of the metallurgically bonded pipe ends than were the automatic welding procedures. Qualified manual welders were also retained under a subcontract for the offshore laybarge operations.

Manual procedures were used to make all necessary repair and tie-welds. During onshore fabrication, it took one welder approximately 12 hr to make the 26 weld passes on each riser-grade pipe butt weld. Gamma-ray inspection required approximately I hr for seven exposures on the heavy-wall pipe.

A subcontract was awarded for automatic welding of the C-II pipe. A combination automatic welding procedure was developed using a GTAW machine for the first three passes and then switching to a CRC-Evans pulsed gas metal arc welding (GMAW) machine for the fill and cap passes.

The 0.741 in. W.T. (0.623 in. X-70 plus 0.118 in. CRA) line-grade pipe required 3 passes GTAW plus 10 fill and cap passes with pulsed GMAW. The 1.141 in. W.T. (1.023 in. X-70 plus 0.118 in. CRA) riser-grade pipe required 3 passes GTAW plus 34 passes pulsed GMAW.

Welders were qualified and required to make production welds during onshore pipe double-jointing operations to help reduce the welding problems encountered during offshore operations.

The bimetallic flow line pipe was first coated; each joint was then bent and shipped to the contractor's yard for double jointing. A special internal line-up clamp was developed to provide the internal purge dams and was able to negotiate the 8 expansion bends.

Fig. 4 shows the double-jointed pipe being loaded onto the deck of the laybarge. During double jointing operations, it was noted that pipe-end demagnetization was a necessary step in the automatic welding procedure.

INSTALLATION

Dredging of the flow line trenches started in mid-May 1991. The laybarge arrived in late June, and at the peak construction period of late July, the following vessels were working on the flow lines and utility lines: one laybarge (McDermott DB28); three dredges (C.F. Bean 2, 6, and 10); one 140 ft long spud/crane barge; one inspection dive boat; one jack up work boat; and multiple tugs, material barges, and crew boats.

Additionally, two jack up rigs and one jack up work boat were working on the wells and platforms.

It was a continual challenge to schedule efficient operation of this many vessels in the relatively small field area. The flow line installation schedule was also influenced by the drilling rig moves between the wellhead platforms, the platform jacket and deck installation schedules, and the requirement for H2S safety equipment on vessels working near the drilling rigs.

Flow line trenches were pre-excavated to a depth of 6 ft with clam shell dredges. Two of the dredges worked on spuds, and the third was rigged with anchors to work in the deeper waters along the "JB" flow line route.

Soil conditions ranged from sand to clay, and spoils were placed along the right-of-way for later use in back-filling the trench.

The DB-28 (420 x 120 x 30 ft combination derrick and laybarge) normally lays single 40 ft pipe joints through the center pipelay ramp. Modifications made to lay double-joint lengths of bent pipe included the following:

• Building a 20 ft make-up ramp extension cantilevered over the barge bow to handle the double-joint lengths

• Installing flat pipe rollers to support the zig-zag pipe bends as they passed down the make-up ramp

• Modifying the tension machine shoes to grip the bent pipe

• Modifying an existing stinger to support the flow lines and utility bundles (Fig. 5).

Four work stations were used.

At the first welding station, line-up, internal gas purge, three passes of automatic GTAW, and the first pass of pulsed GMAW filler were performed. At the second welding station, the pulsed GMAW fill-and-cap passes were completed by the two welders.

The remaining two stations were used for radiographic inspection and repair welding and for field-joint coating. The average lay rate during normal pipelay operations was 7 double joints per 12-hr shift; the peak rate was 11 joints/shift. Overall weld repair rates averaged 8%.

UTILITY-BUNDLE INSTALLATION

The six utility lines and the electric cable were installed simultaneously in the predredged trench with the bimetallic flow line. Three spools each of 1 in. and 1.5 in. OD tubing were mounted on a single large base and positioned above the pipe make-up ramp (Fig. 6).

The six tubes were then pulled from the spools without straightening, drawn through a roller box, banded together, and guided onto the stinger. The electric cable was fed from a separate spool on deck level and banded to the tubing bundle.

The utility bundle was directed through guide rollers on either side of the stinger at a 6-ft separation from the flow line. Divers checked the position of the flow line in the predredged trench and the utility-bundle separation from the flow line following each barge move-up.

Where the utility lines and flow lines were too close, they were later separated to prevent exposing the utility bundle to the high temperature of the flow lines.

The flow line risers were installed by the surface-lift method.

Prefabricated pipe spools were welded together on the laybarge deck and positioned over the side using the main derrick and the starboard gantry crane. The over-the-side tie-in welds required precise alignment, a controlled environment, and considerable time to complete.

The contractor prepared several aids for these tie-ins, including a large work platform which was suspended over the barge side and then swung out from beneath the pipe before lowering the riser.

With two welders offshore, it took approximately 12 hr to measure, cut, bevel, align, weld, inspect, and coat each tie-in weld. with the spud barge. Utility-line riser pull tubes were clamped to the exterior of the platforms.

Several methods were used to position the utility lines in front of the pull tube bellmouths and then pull them through. These methods included: using DB-28's main derrick, direct pull-in using the wellhead platform crane, and lateral deflection using a tugboat.

The flow line vertical profiles were plotted from pneumo-gauge depth measurements and used to compute the overbend heights. The divers then returned and hand jetted down the high points, even though in many cases the flow line depth of cover already exceeded the minimum required.

Significantly less overbend correction work was required on the second two flow lines installed than on the first two. This reduction resulted from improvements in dredging accuracy, placement of the flow line in the center of the trench, and the vessels used to support the diving work.

The flow lines and utility lines were hydrostatically tested in September 1991 following completion of the trench backfilling operations. The risers were pretested ashore to a minimum pressure of 15,900 psig, and the completed flow lines were tested to 13,250 psig.

Gas flow from Fairway field started in early December 1991.

REFERENCES

1. Craig, I.G., Nash, N.W., and Oldfield, G.A., "Upheaval Buckling: A Practical Solution Using Hot Water Flushing Technique," Proceedings of the 22nd Annual Offshore Technology Conference, OTC 6334, Houston, 1990.

2. Palmer, A.C., Ellinas, C.P., Richards, D.M., and Guijt, J., "Design of Submarine Pipelines Against Upheaval Buckling," Proceedings of the 22nd Annual Offshore Technology Conference, OTC 6335, Houston, 1990.

3. Nielsen, N.R., Lyngberg, B., and Pedersen, P.T., "Upheaval Buckling Failures of Insulated Buried Pipelines: A Case Story," Proceedings of the 22nd Annual Offshore Technology Conference, OTC 6488, Houston, 1990.

4. Lanan, G.A., "Subsea Pipeline Expansion Bends," U. S. Patent Pending.

5. Reuser, H.C., Plummer, R.A., and Lanan, G.A., "Bonded Three Layered Epoxy Polyethylene Coating to Continuous Steel Coiled Tubing," Proceedings of the 24th Annual Offshore Technology Conference, OTC 7033,

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