Novel single-pipe, direct heated tieback connects Stær, Svale to Norne FPSO

The Norne field is at 66° North and subject to strict environmental requirements. Statoil selected clad steel pipe for use on Norne because of the pipe’s resistance to corrosive fluid without the need for chemicals. The pipeline was thermally insulated to avoid hydrate formation and wax appearance during normal production. DEH technology maintains the temperature in the pipeline above the critical temperature during shutdowns as well so hydrates and wax formation is avoidable even when fluid is stagnant in the line.

Installation was performed using the reeling method, the first instance of a clad steel pipeline being installed this way. Reeling saved cost, especially considering added complexity due to the in-line “T” and the DEH system.

Selecting a single, common pipeline for a multi-phase well stream from two reservoirs is an operations challenge because startup, slug control, multi-phase metering, and system dependencies all have to be taken into account.

The reservoirs get progressively shallower northeast from the main Norne field, so reservoir pressure and temperature decrease. The oil also becomes more biodegraded, which means density and viscosity increase as the gas-to-oil ratio (GOR) decreases. This makes well stream transport to the FPSO challenging. Both the Svale and the Stær reservoirs require water injection for pressure support and continuous gas lift to make the oil flow to the FPSO.

Water injected from the Norne FPSO is raw seawater, so sulfate reducing bacteria (SRB) generate H2S in the near wellbore region of the water injectors. This causes reservoir souring with time, especially for the relatively small Stær and Svale fields, where injected seawater circulates into the oil producing wells in less than a year.

Statoil conducted a pilot test injecting nitrate into the seawater on the Norne field to stimulate nitrate reducing bacteria that decreases SRB growth and H2S generation.

Nitrate injection has been used on Norne since 2001 to increase oil recovery and to reduce H2S generation in a method known as microbial increased oil recovery (MIOR). When material selection was made for the Urd field, MIOR was not yet proven. So, the Urd production piping was designed for sour service.

Strict environmental requirements

Norne is the northernmost field operating in the Norwegian Sector, and is subject to strict environmental requirements. X60/316L clad steel was selected because continuous use of chemicals is prohibited.

Hydrate and wax appearance temperatures for the multi-phase well stream are similar and range between 19° and 22° C (66° and 72° F) for operating pressures. The sea temperature is 5-10° C (41-50° F) close to the seabed at 390 m (1,280 ft) water depth. The best hydrate and wax control solution with respect to cost, environmental impact, and operation was thermal insulation of the production pipeline to U = 4.0 W/m2K combined with direct electrical heating, which was required only during shutdowns.

Main tieback alternatives

Statoil chose the following tie-back solution:

• Two four-slot templates at Svale; one with three production wells plus one spare and one with two water injection wells plus two spare
• One four-slot template at Stær, with two producers, one injector, and one spare
• One common, single umbilical
• One common, single water injection pipe-line
• One common, single gas lift pipeline
• One or two multi-phase production pipeline(s).

Main tieback alternatives.

The final question was whether to select dedicated production pipelines to both reservoirs or a common, single production pipeline. Hydrate and wax control was fundamental to the single-pipe solution. Control was achieved by combining thermal insulation with DEH of the pipeline. The latter required qualifying DEH for clad steel and for a pipeline with an in-line “T” branch. Other technical challenges for the single-pipe concept were production consequences, minimum flow considerations, slug control, regularity loss, increased system dependency, startup procedures, and area considerations. Statoil studied these challenges in detail before selecting the single-pipe concept.

Production consequences

The operator carried out an evaluation for the single-pipe case with respect to the following:

• Production profile interaction due to production of two reservoirs into a common pipeline
• Minimum flow considerations
• Flow scenarios for Stær alone and Svale alone
• Riser bottleneck - maximum riser diameter
• Qualification of DEH for a pipeline with an in-line “T” for Stær
• Future potential in prospects adjacent to Stær and Svale
• Regularity impact of shutting-in one reservoir while testing the other.

Detailed production flow models allowed Statoil to evaluate production consequences.

“Long-term” tool - A reservoir simulation model was established in “Eclipse” from the reservoirs to the inlet manifold on theNorne FPSO turret in order to investigate production consequences of one-versus-two production pipelines.

“Short-term” models - The short term tools are not connected to the reservoir simulation model and therefore represent snapshots of the flow. A short term analysis was run for every year. Models were established in OLGA (multi-phase flow simulation normally used for pipeline systems), Prosper (well hydraulics), and Gap (network analysis of wells and pipelines). The Prosper/Gap models were calibrated against the OLGA model for various viscosities, water cuts, liquid rates, and GOR.

The analyses concluded that the same production could be achieved from the single-pipe and dual-pipe concepts if the appropriate pipeline diameter were selected.

Regularity versus flexibility

Regularity clearly is affected when using a common, single pipeline instead of dedicated pipelines because there is always a need for well testing. Statoil installed subsea multi-phase meters on each well to minimize well testing.

The regularity loss for a single-pipe installation was estimated to 2.4% for the first year and 0.8% per year thereafter compared to loss encountered using a dual-pipe approach because of calibration, well test, workover and startup considerations using a single pipe.

Reservoir simulations were performed with 1.5% reduced regularity factor for single-pipe compared with dual-pipes. No difference was found on the production profiles.

Single-pipe slugging

Dynamic multi-phase flow simulations were performed with OLGA for a single, common pipeline with an internal diameter of 320 mm (123/5 in.). The analyses showed that terrain slugging can occur with only two to three wells producing. In later production years, slugging can occur because of reduced flow rates even with all of the wells producing.

Increased gas-lift rates reduce slugging. So, the gas-lift system capacity was increased to be able to run 40% above the maximum expected required rate.

Hydrate, wax control

The single production pipeline is insulated thermally to a U-value of 4.0 W/m2°K (related to the inner pipe diameter) to ensure the required arrival temperature is maintained so hydrate formation and wax deposits can be avoided during normal production.

DEH provides hydrate control during production shutdowns. In a shutdown, the temperature in the well stream is heated above the hydrate formation temperature before production begins. The Set value temperature is 25° C (77° F) with a sea temperature of 5° C (41° F).

DEH is based on the fact that an electric current in a metallic conductor generates heat, (Nysveen et al. 2005). In the DEH system, the pipe to be heated is an active conductor in the electric circuit formed by the DEH riser, the armored feeder cables, the piggyback cable, and the pipeline. The current comes from theNorne FPSO topside power system through the DEH riser (two conductors) and armored feeder cables. At the FPSO end of the pipeline, one of the armored feeder cables connects to the pipe, while the other connects to the piggyback cable, which is strapped along the pipeline to the outer end.

Implementing DEH for Norne was possible after successful qualification for clad steel application and for a pipeline with an in-line “T” branch.

The DEH system heats the clad steel pipeline on the seabed, but does not heat end zones like manifolds, tie-in spools SVALE, and the flexible riser. Instead, these sections are inhibited with methanol for hydrate control.

The rating of the 50-Hz DEH system for the 9-km-long (5 1/2 mi) production pipeline was performed for two cases:

1. To keep pipe content at 25° C (77° F) with no production, a system current of 1,190 A, supply voltage 4.3 kV, and 1.4 MW power are required.

2. To heat pipe content (liquid) within 48 hours from 5°C to 25°C (41° F to 77° F), a system current of 1,400 A, supply voltage 5.1 kV, and 2.0 MW power are required.

Nexans Norway AS provided the DEH system, which enables efficient commissioning. Following the system pressure test with the pipeline filled with freshwater, the DEH system was activatetd for 48 hours to allow liquid in the pipeline to reach 25° C (77° F), after which the first well was started up. The pipeline content - initially freshwater - was taken straight into theNorne FPSO processing system. The DEH system made it possible to start oil production three days after system pressure testing the pipeline.

Reeling the clad steel pipeline

Technip Offshore Norge AS installed the 381-mm (15-in.) clad steel pipeline with DEH and an in-line “T” using the reeling method. This was the first time a clad steel pipeline has been installed by reeling. This reduced costs, especially considering the added complexity of the in-line “T” and the DEH system (Endal et al. 2006).

The Japan Steel Works Ltd. was contracted in Nov. 2003 to deliver the clad line pipe, which consists of an internal corrosion resistant liner metallurgically bonded to the carbon steel pipe. According to DNV OS-FIOI (2000) the selected pipe has designation SAWL 415I PDF Clad-316L. Statoil chose to use X60 backing steel rather than X65 i to improve reelability.

The cladding material strengthened in pure bending. In fact, the bi-metal cross-section’s resistance to local buckling was found to be equivalent to a full thickness carbon steel cross-section (Ilstad et al. 2006).

Two welding processes were used - a manually welded root/hot-pass and infills/capping with mechanized gas metal arc welding. This sequence was chosen to meet Statoil’s request for full integrity on the clad layer. The root gap was 5 mm (1/5 in.), allowing the welder to inspect the inside of the root. Had mechanized welding been used, inspection would have come after a complete weld. Repairing defects at that point would have slowed production. NDT of the clad pipe girth welds was performed with Automatic UT after comprehensive qualification.

A full-scale bending test of the clad steel pipeline simulating reeling was performed for verification prior to installation.

Operational experience

Installation took place in the summer of 2005, and oil production started from Svale on Nov. 8, 2005. The mid-line field, Stær, went into operation Jan. 3, 2006.

The DEH system works according to design and provids an efficient measure for commissioning and hydrate control of the single pipe.

Initially there were slugging challenges with the first one or two wells from Svale producing alone. This was controlled by tuning the active topside choke.

The two oil fields now produce slightly above expectations, and the subsea multi-phase meters are working as intended.

The total investment for the tieback was paid off six months after startup. The production from the satellites is expected to continue for a decade.

Acknowledgements

The author thanks the management of Statoil for permitting publication of this paper.

Looking ahead

With the development of the Norne satellite Urd, direct electrical heating of a pipeline with in-line “T” is proven technology. This concept is tailor-made for satellite tiebacks, enabling series connection of fields, and controlling hydrate with minimum chemicals.

The next DEH pipeline project is Tyrihans, due to be installed in 2007, with four templates producing into a 43-km-long (27-mi) common, single 457-mm (18-in.) pipeline by connection to in-line “T” manifolds. The pipeline is to be prepared for future multi-phase compression.

Developing several other fields with DEH pipelines is under consideration. Statoil’s DEH technology is currently qualified for a 52 kV cable that can be applied to pipelines exceeding 100 km (62 mi) in length. Work is under way to combine electrical pipeline heating for hydrate control during shut-downs, with power to subsea pumps during normal production. Also, qualification programs to qualify DEH for deeper water and for melting of hydrate plugs are running.