The Rangely Weber Sands Unit in northwest Colorado is the state’s oldest and largest oil field. Since large-scale development began in the 1940s, it has produced nearly 1 billion barrels. Chevron began water-flooding in 1958, then injecting carbon dioxide (CO2) in 1981 to increase the total volume of recoverable crude oil, putting the field into the tertiary recovery phase.
The field has more than 900 wells in a sparsely populated, 40-square-mile valley near the small town of Rangely. “We go to Utah for groceries, Wyoming for fireworks, and you can guess what they come to Colorado for,” said Harry Stafford, senior automation analyst, Chevron.
Stafford co-presented the session, “Produced oil and water pump skids” with Mark Head, flow sales account manager, Emerson Automation Solutions, and Rich Hogan, flow account manager, Emerson Automation Solutions, this week at the Emerson Global Users Exchange in San Antonio.
“The pump infrastructure was built in the 1940s and refurbished every 20 to 30 years,” Stafford said. “It has a fairly archaic SCADA system, with high level, high pressure, and a callout—that’s it. There was no data on flow, level or pressure for the engineers.”
Along with getting more data, Chevron sought to reduce OPEX by reducing the equipment and the cost to operate it. The wells each had separation facilities gathered to one collection point, with a tariff on it. “This was also a Chevron facility but not ours, so the tariff was an incentive to do something else,” Stafford said.
The resulting project objectives were to reduce the counts of vessels, pumps and tanks in the field, simplify the controls and instrumentation, ease operation and maintenance, and reduce the gathering system pipelines.
“We eliminated the separation equipment at the pumps and replaced it with separation at the central facility,” Stafford said. “We cut the pump count in half, got rid of all the vessels except the new ones at the central facility, and reduced the custody transfer flowmeters from 75 turbines to two Coriolis meters.”
Chevron also worked with Emerson to decide if turbine meters were still the best choice for measuring the unseparated flows from the individual wells, which are now mainly a combination of oil, water and CO2.
Looking at the typical flowmeter selection chart and focusing on accuracy, low maintenance, pressure drop, capital expenditures (CAPEX) and total cost of ownership, Chevron and Emerson decided to compare turbine flowmeters with magnetic, Coriolis and vortex flowmeters. The water cut is typically 95%, which, with entrained gas, was a problem for Coriolis mass flow measurement. “So, we decided to measure only volume flow,” Head said. “Since the varying amount of oil was a problem for the magmeters, a detailed comparison was made only between turbine and vortex meters.”
With varying CO2 content, the update rates on the turbine flowmeters was too slow, even when they were reconfigured to increase the interval from the standard four seconds to one second. Other drawbacks of turbine meters include reliability. “Almost everything is wetted, with much opportunity for damage,” said Head. “The internals are available for $500-600, but you have to come out and replace them. Meanwhile, the accuracy is reduced and you don’t know about it.”
Issues with vortex meters include abrupt cut-off at low flow, susceptibility to vibration and possible clogging or fouling around the shedder bar. Proper selection can eliminate the cut-off problem, filtering can negate vibration effects, and clocking the meter properly on installation—with the shedder bar across 3:00 and 9:00 positions—can minimize clogging or fouling of the shedder bar.
Vortex meter installations are also easy to engineer thanks to two-wire loop power, and flow rates that change over time can be readily accommodated by replacing the meter with a larger or smaller one, because the meter bodies with adapters have the same pipe flanges and face-to-face dimension.
“So, vortex meters won the business case,” Head said.
The well flow measurement applications range from 2,500 to 40,000 barrels per day with 3-in., 4-in. or 6-in. piping. A specific application’s range was matched by using a 2-in., 3-in., 4-in. or 6-in. meter body with suitable adapters.
Piping straight run requirements are nominally 35 diameters upstream, five diameters downstream. “Extensive lab test results have provided published K-factor adjustments, but we didn’t have any problems with 10 diameters upstream and five downstream,” Hogan said.
CAPEX for 54 vortex meters totaled $190,877, about $25,000 less than turbine meters. “No one expected that,” Hogan said.
Five-year operational expenditure (OPEX) projections for turbines, assuming three replacements per year at $2,600 each (no electronics) and eight rebuilds per year at $660 each (no labor), came to $65,400. Vortex, assuming one replacement every five years and no rebuilds, was $3,535.
Hogan added, “We’ve never replaced a meter but showed one every five years, just in case.”
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