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Flowlines

Topic last reviewed: 1 February 2014

Sectors: Upstream

In the oil and gas industry, flowlines are pipe lines that connect a single wellhead to a manifold or process equipment. In a larger well field, multiple flowlines may connect individual wells to a manifold. Then a gathering line may transfer the flow from the manifold to a pre-process stage or to a transportation facility or vessel. Flowlines may be in a land or subsea well field and may be buried or at grade on the surface of land or seafloor. Gathering lines are similar to flowlines but collect the flow from multiple flowlines.

Flowlines are located at the well site tied to a specific well. It may be a metallic pipe or a hose. Most flowlines are very short in length but others may be run for kilometers in onshore applications. In comparison gather lines are used after flowlines have brought the fluid to a manifold or other piece of process equipment, these lines may run for miles or up to a process ship if off shore. Flowlines are constructed onshore and may be lowered to the seafloor, and have terminal connectors that make installation at the well head easier.

Flowlines may be single wall pipe or hose and may be insulated or may include an outer pipe known as pipe in pipe (PIP) system to limit heat losses and protect the carrier pipe. As with any subsea installation, consideration should be given to connection orientation to reduce risks from snagging and to assist with installation. Helical pipe strakes are often added to the pipe’s surface to reduce pipeline vortex induced vibration that can lead to pipe fatigue.
Flowlines operate as one component of a pumping system. For additional information on energy efficiency opportunities involving pump optimization see the pumps for power topic

 

Application of Technology

The challenges in marine pipeline systems design range from ultra-deep water depths to extremely shallow water depths; from high-pressure / high temperature applications to extreme low temperature cryogenic applications; and from installation in arctic environments to installation in the tropics. Design of a marine pipeline system requires knowledge not only of the mechanics of the pipe itself, but also of the means by which the pipeline will be installed and of the environment in which it must operate.

Several types of flowlines are listed below, all subsea unless noted [Reference 1]:

  • Single Tubular: Single, simple tube system (onshore or subsea). This is the standard type of flowline for on-shore applications.
  • Bundled Line: these systems comprise of several export flowlines, injection and umbilical control lines of varying configurations.
  • Coiled Tubing
  • Riser: Flowlines carrying the hydrocarbon flow from the seabed to the surface facility
  • Flexible Catenary Risers (FCR)
  • Hybrid Riser: a riser bundle attached to a submerged buoyancy tank
  • Jumper: short flowline connecting a subsea well back to its manifold
  • Piggy-Back: an export line from the field carrying an externally attached import injection flowline to the wellhead
  • Pipe-In-Pipe: An external pipeline carrying an internal flowline. Pipe-in-Pipe systems are used for protection near the shore and for insulation in deeper waters
  • Steel Catenary Riser (SCR)

Technology maturity

Commercially available?:   Yes 
Offshore viability: Yes 
Brownfield retrofit?: Yes 
Years experience in the industry: 21+ 

Key metrics

Range of application:
Oil and gas well fields
Efficiency: Typical flow rate, pressure drop, pumping power relationship; undersized line will limit flow rate or have increased erosion, and force replacem or limit production. Insulation is used to reduce heat loss in cold conditions
Guideline capital costs: Flowline cost, connectors, insulation, material selection, installation, service vessels, weather impacts, ROV
Guideline operational costs: Due to location and harsh environments, system failures are costly and avoidance through system optimization is preferred
GHG reduction potential: More efficient flowline configurations can lower energy requirements for pumping
Time to perform engineering and installation: 1-24 months
Typical scope of work description: Flowlines are a part of the overall well field design from the beginning of a project. Efficient piping configurations can be a focus of Greenfield applications or can be addressed in brownfield applications following a detailed systems assessment. Brownfield applications must consider capital costs against the potential savings that accrue from system optimization.

Decision drivers:

Technical: Materials, design pressure and temperature
Rigid vs flexible
PIP (pipe in pipe), with insulation
DEH direct electrical heating
Buried vs on surface, trenching
Seafloor or ground topography, surveys
Ocean currents, strakes
Wellhead movement
Operational: Inspection and maintenance needs
Pigging, line cleaning
Commercial: Cost of installation
Materials
Lead time and availability
Environmental: PIP (pipe in pipe)
Monitoring, leak detection

Additional comments

Efficient Piping Configurations

In systems dominated by friction head (Friction head -usually in units of feet- is the amount of energy used to overcome resistance to the flow of liquids through the pumping system.) , there are multiple energy and money-saving opportunities that work by reducing the power required to overcome the friction head. The frictional power required depends on the flow rate, fluid pressure, pipe size (diameter), overall pipe length, fittings installed (valves, junctions, etc.), pipe characteristics (surface roughness, material, etc.) and properties of the fluid being pumped.

Optimizing the configuration of the pumping system involves several steps, which include determining a proper pipe size, designing a piping system layout that minimizes pressure and selecting fittings with low pressure drops. Determining the proper pipe size involves weighting the initial cost of the pipe against the cost of pushing fluid through it. Although, larger pipes create less friction loss for a given flow rate, they have higher material and installation costs. Although piping system layouts are usually subject to space constraints, there are often chances to minimize unnecessary pressure drops by avoiding sharp bends, expansions and contractions and by keeping piping as straight as possible.

A key configuration improvement is to establish a uniform velocity flow profile upstream of the pump. Poor flow profiles are a result of inefficient piping configurations that promote uneven flow and/or turbulent flow, which diminishes pump performance. Consistent velocity profiles can be achieved by making sure a straight run of pipe leads into the pump inlet. If an elbow must be placed just upstream of the pump due to space restrictions, a long radius elbow should be selected. To correct any disruption in flow in the elbow, a flow straightener, such as a baffle plate or a set of turning vanes should be installed with an elbow. A flow straightener creates a more even velocity profile but consideration must be taken to ensure that the pressure drop across the straightener does not cause cavitation.

In addition, suction and discharge piping close to the pump should be properly supported by hangers. Properly supporting the piping near the pump allows the pipe reaction to be carried by the pipe hangers rather than by the pump casing itself, thus reducing strain on the pump. Moreover, proper support of the piping near the pump stiffens the system, which can reduce system vibrations.

Surveys, planning, calculations, and optimization efforts would be done before construction and installation of a flowline would proceed. Complex flowlines would be built off site and delivered as multiple spools to the site for installation, where as simple designs may be assembled on site.

 

Alternative technologies

No practical alternative exists other than to use a pipe or a hose to transport media. Alternatives may be present in the design of the flowline, its size, features, and length.

Operational issues/risks

Flowlines require proper installation, inspection, and maintenance. Two phase flow, sand solids, high temperature, pressure or flow, currents, corrosion, or erosion must all be considered in the design of a flowline to maximize the component expected service life.

Opportunities/business case

Efficient flowline design can significantly reduce the energy required to pump produced oil and gas to the manifold, saving money and reducing greenhouse gas emissions. It can also help improve the trade-off between capital costs and the cost of the energy for pumping, minimizing overall costs. Reducing capital costs often also reduces the ‘embedded energy’ of the system – i.e. the energy required for the mining, manufacture and installation of the equipment.

Flowlines can also be bundled together to carry different fluids or gas. They can be used to reduce capital costs by combining many wells into a network that connects to common terminal point.

Industry case studies

1. Oooguruk Offshore Arctic Flowline Design and Construction, 2008 Offshore Technology Conference, Document ID 19353-MS, Authors Glenn A. Lanan, http://www.onepetro.org/mslib/servlet/onepetropreview?id=OTC-19353-MS#

The Oooguruk offshore Arctic flowline system design, construction and operation satisfy the unique conditions presented by this shallow water Beaufort Sea location. The bundled 3-phase 12 x 16-inch pipe-in-pipe production flowline, 8-inch water injection, 6-inch gas lift/injection and 2-inch diesel fuel flowlines were installed along with power and communications cables offshore the North Slope of Alaska during 2007. The maximum water depth along the flowline route was only 7 feet but the location immediately offshore the Colville River Delta presented challenges with the flowline loading conditions, thermal interactions with the local environment and construction procedures. Key features of this flowline system include addressing flow assurance requirements for combined offshore/overland sections, strudel scour, subsea permafrost thaw consolidation, upheaval buckling, limit state design for bending, winter construction procedures and flowline leak detection systems. The subsea power cables consisted of separate cables for each conductor in order to be compatible with trucking all materials to the remote site. The dual fiber optic communications cables were utilized with a distributed temperature sensing system to monitor the flowline burial conditions and supplement the multiple flowline leak detection systems.

2. Free-Span Remediation Studies for the K2 Pipe-In-Pipe Flowlines, 2006 Offshore Technology Conference, Document ID 18312-MS, Authors U. Eigbe http://www.onepetro.org/mslib/servlet/onepetropreview?id=OTC-18312-MS#

The ENI Petroleum K2 field production flowline system consists of two HT/HP (high temperature and pressure) pipe-in- pipe (PIP) flowlines that tie back three oil wells located at Gulf of Mexico Green Canyon 562 to the Marco Polo TLP in a maximum water depth of approximately 4,300 ft (1,310 meters). The flowlines traverse very rough seabed terrain, including an escarpment along the selected route. It was determined from preliminary analysis of the surveyed flowline route and confirmed with as-laid flowline survey data that seabed intervention by use of engineered supports was required at some of the flowline spans, including the escarpment. In particular, at the escarpment it was determined that operating loads during start-up would create excessive bending at the sagbend (due to feed-in) and overbend (due to uplift), exceeding the DNV OS-F101 code-specified limitstate design requirements. The focus of the K2 free span remediation studies was to assess the impact of span supports and overburden with regard to the structural integrity of the flowlines. This was accomplished with a global expansion, bottom roughness and lateral buckling analysis. The bulk of the analysis consisted of 'real time' ANSYS finite element modeling of as-laid flowlines, and as-built span supports and overburden design on board the vessel MSV POLAR KING on location at the K2 field. During the course of construction, contingencies for span support were investigated as adjustments had to be made to the construction schedule in order to meet the hydrotest timeframe and First Oil milestone dates. The results of the analyses were verified with as-built start-up survey data, including confirmation of lateral buckling within the monitoring stations identified from the ANSYS analysis. An end product of the remediation studies was a fully vetted and field-proven HT/HP PIP analysis tool available for similar applications in future projects.


References:

  1. Infield, The Energy Analysts