Deepwater wet gas developments typically have high pressure and high flow rates, making it difficult to detect water production profiles. Furthermore, at such depths the wells and pipelines are vulnerable to saline and unchecked water, which can impair flow and can impact production capabilities.
The increasing number of deepwater wet gas fields, many more than 100 km (62 mi) from shore, and the need to manage production costs and to circumvent the requirement for fixed production platforms has led to a growth in the number of subsea tiebacks.
With long distance tiebacks in place, (a number of 160-km [100-mi] tiebacks are installed, and fields with tiebacks of more than 500 km [311 mi] are being planned), the elapsed time between the occurrence of water breakthrough in a well and its detection at the surface could be days. By that time, the damage would have been done.
While the costs of surface facilities are eliminated, subsea tiebacks increase the importance of real-time flow measurement to detect flow assurance problems.
The Snøhvit wet gas field in the Barents Sea is one example. The untreated well stream is piped 160 km (100 mi) from the field to a liquefaction plant onshore Norway. Not having real-time flow monitoring would make the risk of losing control of the multiphase pipeline system unacceptably high.
Increasing flow assurance
With more than 70% of the world’s oil and gas production coming from fields over 30 years old and with global energy consumption expected to triple over the next 50 years, oil and gas companies are experiencing increased pressure to not only discover new fields, but to increase flow assurance and optimize production from existing ones.
Multiphase production from individual zones and branches monitored downhole. Noise generated by sand production is monitored continuously in each producing zone to ensure it stays within limits. As the oil/water and wet gas contacts move, individual zones can be adjusted to optimize the aggregated well flow, monitored at the wellhead.
The need to increase flow assurance and production is even more critical in subsea developments, where operators have traditionally had less information to go on and subsequently less ability to monitor and intervene proactively to optimize production and flow assurance. Estimates vary, but it is commonly believed that subsea wells produce up to 20% less information than their topside counterparts.
The Norwegian Petroleum Directorate together with Statoil and Norsk Hydro reported in 2004 that Norwegian continental shelf production was 59% dry tree wells and 41% subsea wells. Two main reasons were cited for this gap: 1. Accessibility and lack of maintenance of subsea wells and 2. Lack of data from subsea wells.
Securing such information is not getting any easier with the growth in wet gas fields because of their characteristics.
The United States Energy Information Administration estimates world proven natural gas reserves to be around 5,210.8 tcf. And much of this gas is wet - defined as being 98-100% gas void fraction (GVF).
Many of today’s wet gas fields are in deepwater. The 2006 World Deepwater Market Forecast estimates annual deepwater operations expenditures will exceed $20 billion by 2010. According to the report, deepwater gas output is expected to grow strongly from 2.12 tcf/d in 2005 to 3.8 tcf/d in 2010.
Independence Hub
Anadarko Petroleum Corp. operates the Independence Hub joint venture with partners Dominion Exploration & Production Inc., Norsk Hydro, and Devon Energy Corp.
Located in the Gulf of Mexico 298 km (185 mi) southeast of New Orleans, Louisiana, theIndependence Hub is in Mississippi Canyon block 920. The Hub will process production from 10 natural gas fields in 2,438-2,728 m (8,000-8,950 ft) water depths, with the longest tie back exceeding 72 km (45 mi). When the $2-billion facility comes online later this year, it will be the deepest offshore production facility in the world.
“Producing high gas fraction wells at these water depths requires the very best in flow assurance monitoring of individual fields and wells to ensure that hydrate formation does not affect production integrity,” says Bob Buck, senior engineer, worldwide deepwater operations, Anadarko
The issue of production allocation also was central toIndependence Hub development. With 10 fields having different ownership interests and royalties, the wet gas meters need to provide accurate, real-time subsea measurement and allocation. Accuracy is essential to ensuring production revenue streams are split correctly among the partners.
By continually measuring formation-water production, each well will be able to operate at the limit of its water production. The result will be fewer wells required in the reservoir, greater efficiency from those there and increased production over the life of the Hub.
Sand and Independence Hub
Sand monitoring technology plays a role in wet gas field flow assurance as well.
The sand monitoring devices onIndependence Hub are able to provide an ‘early warning’ system - an immediate response when sand is present - and can check the integrity of sand screens used to keep sand out of the production tubing.
The acoustics and monitoring technology used can accurately detect sand in the well stream. Accurate data on the amount of sand in the pipeline allow engineers on theIndependence Hub to minimize erosion damage, optimize production flow rates, and prevent equipment clogging. The data indicate if remedial actions such as sand cleanouts or a sand bailer are needed.
Ormen Lange
The Ormen Lange field, the largest natural gas field under development on the Norwegian continental shelf, is 100 km (62 mi) northwest of the Norwegian coast in water depths of 800-1,100 m (2,600-3,610 ft). It is another example of a wet gas field where effective flow assurance is in place.
Roxar has worked with Hydro, FMC, and Shell to qualify the Roxar subsea wetgas meter and has supplied eight meters to the field.
Ormen Lange is operated remotely, having no offshore platforms. Roxar is working with Hydro and Shell to implement remote management systems to optimize production and to introduce new operation and maintenance concepts. Because the field does not use offshore platforms, but connects wellheads on the ocean floor directly to an onshore processing facility, scaling and corrosion in the pipelines is a major concern.
Today, the desired water detection sensitivity for the Ormen Lange field is 0.005% by volume - a detection accuracy of 34 liters (9 gal) of water an hour in a 100 MMcf/d gas well. Roxar’s wet gas meters are achieving these levels.
“When you are mixing production into the pipeline to shore, you need to know how much gas, water, and condensate is coming from each well,” says Thomas Bernt, Hydro’s subsea manager. “Without this meter, we would have had difficulty with the whole development concept.”
Multiphase metering
Multiphase metering has been at the heart of many advances over the past few years. Putting the multiphase meter on the wellhead, jumper, or manifold can provide critical, reliable, and easy-to-use real-time information on water saturation and possible breakthrough, gas coning, permeability, and flow characteristics.
This information can help achieve optimal production of each well over the lifetime of the field by increasing recovery and by avoiding the risk of overproduction.
Multiphase metering at the wellhead is an insurance policy that can save the well. In a multi-well cluster, for example, the traditional way of investigating a rising water cut is either to shut in wells one by one for observation or to use a dedicated test line with a test separator.
Multiphase meters, however, can immediately detect a change in multiphase flow composition at the subsea wellhead. A multiphase meter in conjunction with permanent downhole pressure and temperature instrumentation tools to measure reservoir pressure and temperature, flow rate, fluid fraction, sand detection, and chemical properties, allow the operator to quickly locate the problem area and implement remedial action.
Well testing is quicker and more efficient with an integrated subsea system, and information for the diagnosis and optimization of a well’s performance is provided.
Wet gas metering
For all the benefits, however, traditional multiphase meters are not capable of detecting water to the accuracy and sensitivity rates required today. Performance gradually erodes when gas rates exceed 98% GVF.
With the increase in deepwater wet gas fields and subsea tiebacks, the ability to measure the water production profile in a wet-gas well is critical for optimizing production, preventing hydrate, scale, and corrosion in the pipelines, and ensuring supply reliability.
Unchecked water can lead to scaling in the production system and catastrophic water breakthrough with water coning and blockage of the well causing a significant reduction in well production. The worst-case scenario in these situations can shorten the well’s lifespan or require the well to be shut in.
Today’s wet gas meters use microwave-based dielectric measurements. Gas and condensate flow rates are based on standard delta pressure devices. The meter detects the resonant frequency in a microwave resonance cavity. The resonant frequency depends on the dielectric properties of the fluid mixture in the cavity. Robustness and resilience at such depths also is essential. The Roxar subsea wet gas meter is qualified to operate at 3,048 m (10,000 ft) and within a process temperature range of -40 to 150 °C (-40 to 302 °F), a process pressure range of 0-700 bars ( 0-70 mPa), and maximum line pressure of 4.83 mPa (10,000 psi).
Wet gas meter design meets requirements
The Roxar wet gas meter was designed for subsea completed gas/condensate wells with gas void fractions greater than 95% and is qualified for high-pressure/high-temperature wells in water depths to 3,048 m (10,000 ft). It can be used with pipes from 51 mm to 305 mm (2-12 in.).
The meter body is installed directly onto the pipeline or manifold with either flanges (SPO compact or API) or direct welding. The body is UNS S31803 Duplex. The Duplex stainless steel’s austenitic-ferritic microstructure offers a combination of mechanical and corrosion resistance. The meter body can operate at 4,572 m (15,000 ft) water depth.
Roxar’s wet gas meter is designed for high gas void fractions with high temperatures and pressures in ultra deepwater.
The top and base of the electronic canister also is UNS S31803. The canister top protects the electronics and has the system control module interface. Two power and communication connections can mount on the canister top. The base is used to mount the electronic canister to the meter body and forms the electronics platform. When the canister is assembled, the electronics are surrounded by 1 atm of nitrogen, and the connectors are pressure compensated to 3,048 m (10,000 ft).
The pressure transmitter mounts to the meter body and measures process flow temperature and pressure. Its housing also is Duplex stainless steel with a depth rating of 3,048 m (10,000 ft), a process temperature range of -40 to 150 °C (-40 to 305 °F), a process pressure range of 0 to 700 bars (0 to 70 mPa), and a maximum line pressure of 4.83 mPa (10,000 psi).
The delta pressure transmitter also is mounted on the meter body. It measures the delta pressure over the V-cone. Those measurements are carried through impulse lines between the process and the membranes in the delta pressure cell. Measurements are used to calculate process flow.
