OTC 15334

Osprey Pipelines - Cook Inlet, Alaska R. T. Gilchrist/Cannon Associates, R. C. Visser/Belmar Engineering, and G. E. Carlson/Forest Oil Corporation

Copyright 2003, Offshore Technology Conference This paper was prepared for presentation at the 2003 Offshore Technology Conference held in Houston, Texas, U.S.A., 58 May 2003. This paper was selected for presentation by an OTC Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Offshore Technology Conference or officers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented.

Abstract Three pipelines were installed by the pull method to the Forest Oil, Redoubt Shoal Field, Osprey Platform in Cook Inlet, Alaska. This project took place in the summer of 2002 and utilized new technology in a number of areas. The pipes were all heavy wall seamless tubulars designed to remain stable in tidal currents up to 13-ft/sec. The pipes were coated with three layer polypropylene for abrasion resistance and reduction of friction factor. The pipeline shore approaches were 3 each 12.75-in diameter x 1800-ft long drilled approaches that were initiated from a bluff location 200-ft above Cook Inlet. Two different drilling and casing techniques were used and each is discussed. The pipelines, up to 8.625-in in diameter, were pulled into the platform through 234.5-in radius pull tubes completely contained within the 14-ft diameter platform legs. The pull loads were highest on pipeline entry into the pull-tubes. A simple chain jack designed and fabricated for the project was used to exert pull loads in excess of 270,000-lbs to successfully pull in the risers. Risers and pipelines were installed using simultaneous application of tension from the platform based chain jack on the pipe end and a barge deployed pull wire engaged 500-ft down line. Pipeline System

The offshore reaches of the Osprey pipelines are shown in Fig 1. Osprey pipelines general arrangement. Fig 2. Osprey platform & bluff crossed by pipelines is a photo of the project that shows the Osprey platform and about 2 miles distant the 200-ft high bluff that was crossed by directional drilling.

The pipelines were designed to meet the requirements of 49CFR192 Transportation of Natural and other Gas by Pipeline: Minimum Federal Safety Standards and 49CFR195 Transportation of Hazardous Liquids by Pipeline.

All offshore pipe was seamless quenched and tempered material.

Pressure design. The offshore portion of the pipeline system consists of three parallel pipes. These are: 8.625-in x 0.750-in wall thickness X-52 to convey

produced fluid (a mixture of oil, water & dissolved gas) from the Osprey Platform to the Kustatan onshore processing facility. Maximum allowable operating pressure (MAOP) is 3705-psig. Considering pressure only, there is a corrosion allowance of 0.323-in for the pipeline and 0.238-in for the riser.

8.625-in x 0.875-in wt X-60 for return of injection water from the Kustatan processing facility to the platform under high pressure. MAOP is 5000-psig. Considering pressure only there is a corrosion allowance of 0.376-in for the pipeline and 0.276-in for the riser.

6.625-in x 0.750-in wt X-52 spare line suitable for gas, hydrocarbon liquid, or injection water transportation. The design MAOP is 5000-psig in liquid service, 4177-psig in gas service. Considering pressure only in gas service there is a corrosion allowance of 0.308-in for the pipeline and 0.113-in for the riser. The derated pressure for gas service arose due to the requirement of 49CFR192.619 to hydrotest the riser to 1.5 x MAOP compared to the 1.25 x MAOP test specified by 49CFR195 for liquid service.

Stability. The pipelines were designed for a maximum tidal current of 13-feet-per-second at the surface of the Inlet. The tidal current was assumed to run 90-degrees to the pipeline alignments. The maximum tide is 30.2-ft. The maximum current occurs midway through the ebb tidal cycle when the actual water depth at any particular point is the minimum low low water depth plus 15.1 feet of tide. Ebb tide current dominates as numerous rivers and streams drain in to Cook Inlet yielding a net outflow.

In addition to the current, the stability calculations assumed simultaneous occurrence of 10-ft significant height wave with a period of 7.5-seconds. The angle of incidence of the waves to the pipeline route was a conservative 90-degrees.

Stability was also checked for a 100-yr return wave with a maximum height of 28 feet and a period of 8.5 seconds.

The required wall thickness for stability was calculated using two independent means. The first method used the computer program developed by the American Gas Association. Only the AGA level 1 analysis was applied as the AGA level 2 analysis incorporates self-burial effects not applicable in the environment of Cook Inlet. The second method used a spreadsheet with embedded macros to perform the calculations described in DNV RP E305 On-Bottom Stability Design of Submarine Pipelines.

2 OTC 15334

The submerged weight for stability was developed solely by increasing the thickness of steel pipe wall and not by concrete weight coating. Although more costly, adding weight by steel is efficient as weight can be added with no change in the outside OD of the pipe. Each pipeline was installed by pulling through a 12.75 x 0.408 drilled and cased shore approach. If concrete weight coating had been used the diameter of the casing would have had to be increased at considerable extra expense. Finally, the pipeline pull loads were kept low by using low friction factor polypropylene coating rather than concrete.

Vortex Induced Vibration. Another type of loading that can result from swift currents is vortex induced vibration (VIV) or strumming. For this phenomena to occur some length of pipe must be suspended in the seaway and free to oscillate. The pipelines were analyzed using a spreadsheet with embedded macros to perform the calculations described in section 7 of DNV CN30.5 Environmental Conditions and Environmental Loads. The calculations determine the maximum allowable unsupported length before a pipe becomes vulnerable to oscillation and fatigue damage. The calculated maximum span lengths for the Osprey lines ranged from 34-ft for the 6.625-in pipeline to 43-ft for the 8.625-in pipelines. However, Cook Inlet has seen a number of VIV pipeline failures and experience has shown that for an 8.625-in OD pipe failed spans are invariably in excess of 100-ft in length. With due regard for theory and experience the maximum allowable span was set at 50-ft.

Pipe Coating. The installation method required the pipe drag on the ground in the 4,600-ft long fabrication area, pass through a 1,800-ft long steel conduit to transition from land to sea, cross 10,700-ft of rocky seafloor and finally board the platform via a 12.75-in pull-tube with a 234.5-in radius bend. It was essential that a tough coating be applied to survive this installation regime. The coating selected was plant applied three layer polypropylene (TLPP).

TLPP consists of a layer of fusion bond epoxy (FBE) on grit blasted pipe, followed by a thin copolymer adhesive layer and a wrapping of polypropylene (PP) film. The FBE is the real corrosion barrier and the tough PP jacket ensures it is in place when installation is complete. The copolymer is actually a blend of finely ground FBE and PP. So the bond is formed by mechanical interlock of the gelled FBE and the PP particles that in turn bond to the PP wrap. The PP wrap is side-extruded whereby hot plastic is wrapped on the pipe in a multilayer spiral. The grain of the coating wraps around the pipe and is well oriented to resist splitting. The PP layer is bonded to the pipe at all points, so the even if the PP is slit in the course of installation the jacket will not ravel or peel off.

Normal thickness for TLPP coating is about 80-mils. For the Osprey project a thickness of 150-mils was applied to the offshore pipe. This thickness proved adequate as two of the three risers were electrically insulated from the platform structure upon completion of the riser installation sequence. These pipes were electrically bonded to the structure immediately after installation to ensure the pipes would not be galvanically sacrificed in the impressed current field that protected the platform from corrosion.

The girth weld field joints were sand blasted and coated with two part epoxy primer. This was in turn coated with PP shrink sleeves. To optimize pipe temperature for cure of the shrink sleeves every epoxy primed girth weld was precisely heated by electrical heat induction. Pull Tube Risers Osprey Riser Facilities. The legs of the Osprey platform are subject to ice loads. The legs are 14-ft diameter columns and the pull tubes are totally contained within the leg structure. The tubes have a bend radius of just 234.5-inand the tubes terminate with a downward orientation after 61.77 degrees of bend. See Fig 3. Riser initial entry into pull-tube. Pull Tube Loads. In every instance the highest pull-tube loads occurred during entry of the pipeline into the tube. The geometry at entry is shown