With depths as deep as 10,000 ft (3,000 m), flow measurement in subsea oil and gas production systems is a challenge. The complexity of subsea production systems ranges from single satellite wells with independent tie back lines to complex multiple well sites with a network of lines, manifolds and other modules. Oftentimes multiple production lines feed a single vertical riser leading to the surface and eventually extend to a fixed platform, floating production storage and offloading vessel or a pipeline running to a land-based operation. At the same time, enhanced oil recovery techniques push gas and liquid back to the ocean floor and deeper to more well sites and tie backs.
Flow measurement is required in all phases of these operations, especially at well heads and where lines merge or diverge. Flow meters allocate production liquids, gases and gas condensates to specific wells, monitor critical processes and directly measure enhanced oil recovery techniques such as water injection, chemical injection such as MEG (methyl ethyl glycol), and dry gas for injection and gas lift. New technology is making subsea compression a reality as well, adding the need for subsea compressor control and anti-surge systems. Subsea oil and gas production thus requires vanguard precision equipment and instrumentation.
In addition to normal considerations for selecting a flow meter, such as accuracy and repeatability, subsea module manufacturers face demanding space constraints and must plan for transportation to and implementation on the ocean floor. There is thus only so much space available within subsea modules. When equipment such as flow meters need extensive upstream and downstream metering runs for accurate flow measurement, module builders are faced with complications.
In order to obtain the required space for straight pipe runs, piping engineers must juggle other equipment to accommodate the metering runs. This usually leads to a domino effect whereby other vital pieces of equipment must be rearranged as well within the module or the layout of multiple modules must be configured. This rearrangement compounds over and over, creating highly complicated layouts, not to mention the additional weight and space of extra piping. The added weight caused by additional piping and complex layouts further complicates other considerations such as transportation and installation.
Turndown, maintenance needs, and life expectancy are critical issues in the harsh and remote subsea operating environment, where modules are designed to last 25 years or more with no maintenance or retrieval. While the general oil and gas industry requires high accuracy and repeatability over a wide flow range, subsea systems require even tighter standards of quality to ensure long life with consistent accuracy and repeatability. It is imperative that equipment installed on the ocean floor is designed to such a degree that the operator never needs to actually see it after it is installed. Failure of a single component in a subsea system not only means production downtime and lost revenue but also added logistics utilizing remote operated vehicles and support ships costing hundreds of thousands of dollars per day.
Although several flow meter technologies meet these requirements, nearly all of them require a minimum 10-dia straight pipe upstream and 5-dia straight pipe downstream from the subsea flow meter to accurately measure the flow. Elbows, T-Junctions, valves, manifolds, and other equipment in the pipeline disturb the fluid flow, creating swirls and other irregular velocity profiles that degrade flow meter measurement accuracy. In densely packed subsea modules, where every fraction of added volume escalates complexity and costs, the addition of 10 to 15 diameters of heavy, space-consuming straight pipe for each flow meter is a major issue. When multiplied across the multitude of metering points in the system, major expenditures in both engineering time and piping quickly add up, causing significant revenue reduction.
The ability to eliminate the straight pipe runs for flow meters while meeting or exceeding the necessary technical specifications reduces/shrinks installation real estate and allows for flexible layouts while cutting overall pipe weight, material, and installation costs.
The V-Cone requires straight pipe runs of only up to three diameters upstream and one diameter downstream. This smaller footprint requires up to 70 percent less straight pipe without being affected by flow-disturbing equipment upstream or downstream, and is more compact than any other differential pressure (DP) meter for subsea use. This allows the flow meter to be placed exactly where it is needed without the addition of extra pipe and complicated space-consuming layouts.
The V-Cone measures fluid flow by utilizing the conservation of mass theory, which states that in a closed system, the mass entering the system must equal the mass exiting the system. In the case of a flow meter, the mass entering the flow meter must equal the mass exiting the flow meter. Similar to other DP technologies, a restriction is placed in the pipe, forcing the fluid to accelerate and thus creating a pressure drop to maintain mass conservation
Unlike other DP technologies, the V-Cone is a V-shaped conical intrusion located centrally in the line, redirecting the fluid around the cone instead of forcing fluid through an orifice at the center of the pipe. One pressure-sensing tap located upstream from the cone measures static pressure while another pressure-sensing tap measures the low pressure created by the cone on the downstream face. This pressure difference is incorporated into a derivation of the Bernoulli equation to determine fluid flow. As the fluid moves past the cone, very short vortices form, resulting in a low-amplitude, high-frequency signal that is optimal for signal stability.
The V-Cone primary element maintains +/-0.5 percent accuracy and +/-0.1 percent repeatability over a 10-to-1 turndown, and the cone conditions the fluid such that there is relatively low permanent head loss with system accuracy better than +/-2 percent. Low permanent head loss achieved is derived from the shape of the cone, which minimizes energy losses commonly caused by areas of low flow, cavitation, and erratic flows. The cone can be sized to meet desired application requirements and may be specifically designed to have high rangeability or low head loss. Regardless, the overall energy consumed by the V-Cone is minimized because of its inherent characteristics.
The cone employs no moving parts and measures abrasive, dirty, and particle-laden fluids over a wide range of flow without wear or clogging, delivering a standard 25-year operating life with generally no need for maintenance. The turbulent vortices produced by the cone condition the fluid flow to be homogeneously distributed and extremely stable. Accelerating the fluid up the cone and ejecting it past the beta or metering edge forms a protective boundary layer. This prevents wear of the beta edge from erosion as well as particle buildup that would cause metering errors.
Normal surface deterioration in flow meters, piping, and other equipment occurs as a result of fluid shear stress. Shear stress creates a problem where there is a solid boundary layer in direct contact with the walls of the pipe. This solid boundary layer occurs in laminar flows and erratic turbulent flows. The V-Cone’s stable turbulent flow all but eliminates this shear stress, preventing surface deterioration. Additionally, due to the shape of the cone, there is no cavitation on the backside of the cone to erode the surface.
Given the substantial distances between the well head and final destination of the fluid being moved, the V-Cone’s low permanent head loss results in much lower energy requirements to move the product. Cavitation, eddies, and areas of zero flow that can form on the downstream side of DP devices are actually energy consumers. This energy loss directly equates to the need for larger pumps to move fluid.
In subsea operations, as with land-based operations, there are many locations where flow is measured. Flow is measured at well heads to ensure production efficiency, monitor well life, and provide information for allocation/custody transfers. For custody transfer information, it is imperative to measure flow in each tributary where lines merge. Subsea operations require sustained high pressures, corrosion resistance, stringent standards, and pre-tested equipment coupled with pipe and umbilical connections alike. Versatility and lower energy consumption combining with little to no maintenance and tremendous space and weight savings means a much lower cost of ownership and a trustworthy flow meter on the ocean floor.
Subsea applications can be served effectively by the conical flow meter due to its stable operation at internal pressures up to 15,000 psi (1,035 bar), absence of moving parts, and absence of wear along the beta edge of pipe. All of this results high accuracy and repeatability over a long operating life without maintenance and recalibration. The V-Cone has been supplied in line sizes from 2 to 16 in with most types of end-connections, and can be manufactured out of various materials and to almost any pressure rating. It has been installed within subsea modules, trees and other units commonly used in underwater operations.
Nicholas Voss is V-Cone product manager at McCrometer Inc., a global provider of flow measurement solutions, including differential pressure, electromagnetic, propeller, and variable area technologies. Its flow meter products are used in many liquid, gas, and steam fluid processes in various industries, such as chemical, electric power, facilities, food, HVAC, irrigation, oil and gas, and water and wastewater. For more information, visit www.mccrometer.com.