Senior Automation Analyst
ARC Advisory Group
As oil companies venture further afield to find oil and gas, the deposits they find are increasingly difficult to develop. Subsea deposits require an investment in highly engineered equipment that can withstand harsh underwater conditions that can reach 30,000 ft (9,144 m) below sea level. Deposits on land tend to hold heavier oil that is difficult to get flowing. But both types can require complex extraction methods such as injecting seawater or high pressure steam into the well to drive oil or gas to the surface. Unfortunately, this compounds one of the most vexing measurement challenges -- multi-phase flow with combinations of water, oil, and gas.
To make matters worse, the output of oil wells can vary significantly over time, impacting the economic justification to continue running them. Older wells with changing conditions require more frequent testing to determine if their output is sufficient. New wells that appear promising may underperform once pumping starts. Operators need real-time well data to optimize production and to ensure accurate measurement of hydrocarbons produced for allocation and custody transfer.
Multi-phase flow measurement has made great advances in recent years, and suppliers have invested heavily in R&D to develop new solutions that offer potential gains in efficiency and profits for users. For example, older technologies such as test separators have been joined by partial separators which separate gas from liquid flows, and multi-phase flowmeters which measure multi-phase flows without fully separating each constituent. Each technology has advantages and disadvantages, and applicability varies based on well condition, location, and output.
Full separation technology
Full separators, also called test separators, are behemoth tanks that hold a large sample of the pumped oil/water/gas mixture. Once the tank is filled, gas vents through the top, water settles to the bottom, and oil rises to the surface of the water. Flowmeters connected to the tank measure the individual volumes of gas, oil, and water.
Full separators offer high accuracy, and enjoy wide acceptance in the industry. However, large footprints limit their use in offshore platforms where space is limited. Also, full separators rely on gravity to separate the various phases, and the process can take several hours or days, depending on how heavy the oil is. As a result, operators can only determine average flow rates for a given period.
Full separators have a high average selling price and carry high operational and maintenance costs since they must be cleaned after every sample is analyzed.
Partial separation technology
Partial separators, also called compact cyclonic degassers or compact cyclone multi-phase meters, get around the problem of multi-phase flow by separating the gas phase from the water and oil phases. When oil is pumped into the device, it enters a cylindrical chamber at an angle, generating a centrifugal force that pushes the oil and water to the outside of the chamber, leaving the gas stage in the center to rise to the top to be measured by a gas flowmeter. The oil and water mixture then passes through a water-cut meter or other multi-phase meter. Coriolis flowmeters commonly are used. Indeed, Coriolis meters are probably the best technology to measure two-phase oil and water flows, making it promising for heavy oil applications.
With partial separators, the process is much quicker than with a full separator, offering near real-time measurements to determine if a well is producing adequately. Partial separators cost less to purchase and have a much smaller footprint than full separators. They can be made small enough to be portable, allowing operators to test older wells that might not have enough output to justify investing in a full separator. Partial separators may not be an ideal choice for measuring heavy oil, which is difficult to separate.
At the cutting edge of multi-phase flow measurement technology are true multi-phase flowmeters that do not require separation to measure the components of three-phase flow. Multi-phase meters use sophisticated technologies and carry a high price tag. The devices can use multiple measurement technologies such as gamma radiation for composition, venturi for flow, and pressure and temperature measurement to determine three-phase flow. One supplier uses three-dimensional tomography (akin to magnetic resonance imaging in medical applications) to identify liquid, gas, and water accurately. While highly accurate, some users are reluctant to embrace meters that use radioactive materials due to permitting costs and environmental considerations. Some end users remain skeptical regarding the general reliability of these units, but this is likely to change as they become more proven in use.
Multi-phase meters are the preferred choice for subsea applications, and are accepted widely in natural gas applications. Because oil wells are uniquely different than gas wells, multi-phase meters are different and are purpose-built for each application. However, only one supplier promises a meter capable of measuring multi-phase oil and wet natural gas streams with the same device. Multi-phase meters are also a good fit for offshore allocation metering applications, where a single platform may be pumping oil from multiple wells for several different customers. Multi-phase meters are also a better technology for heavy oil, because they do not require separation to measure three-phase flow. Due to the price of multi-phase flowmeters, they are suitable only for subsea applications and only then in wells with sufficient output to justify the expense.
No single solution
As described, a number of technologies are available to address the problem of multi-phase flow. However, it may be that no one technology can satisfy all user requirements. Older devices such as full separators offer high accuracy, but by design cannot give users the real-time data they need. Partial separators provide timely data, but may not be the best choice for heavy oil deposits. Multi-phase meters, which carry a high price tag, still strive for widespread acceptance. In oil and gas production, there are no "typical" applications, and operators must carefully evaluate each project to determine which technology to apply.
During the transition to multi-phase meters, ARC expects that many installations will have multiple redundant technologies to validate new multi-phase metering technologies as end users adjust to the paradigm shift.
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