The remote monitoring of wells has grown significantly over the years and—like a doctor tending to a patient—operators use a variety of tools to gauge the health of their wells. By deciphering the data provided by various gauges, operators gain critical insights into the life expectancy of the well and its downhole equipment. While wells are typically tested on a monthly basis, there is an option that offers real-time analysis of production flow rates from wells equipped with electric submersible pumps (ESPs).

“The Schlumberger Lift IQ real-time production flow-rate analysis service was developed because our customers—operators—need to know how much they are producing every day, not just on the day of the test,” said Leila Hamza, product champion for Schlumberger Artificial Lift. “Most, if not all, test their wells every month. Some need to test their wells more often, and others are unable to check them that often because they just don’t have access to the well for a variety of reasons.

“If you have an ESP in a specific well, you will be able to say, ‘I know how much that well is producing because I have the model that can tell me that at this point in time my ESP is producing this much,’” she said. “It is not a correlation or an artificial intelligence method. It is purely based on physics, and because we use that, we know that it is valid across the whole range of the ESP, going from zero flow to the maximum flow. It works on all brands and types of ESPs in the industry.”

How it works
The service interprets data and provides operators with a continuous and clear picture of how changes in frequency and choke can affect production as well as the oil and water content calculation to use for loss management and back allocation. There is no need to retrofit additional equipment in the field, and the service works with all wells equipped with ESPs and downhole gauges, according to the company.

“It’s an analytical solution; there is nothing additional needed in the field other than the ESP and pressure gauges,” Hamza said. “The values are read and used in an algorithm to calculate flow rates going through the pump.” The algorithm has two pieces, she added. One is the flow rate calculation through the pump, and the other is the water cut. These algorithms are independent, and knowledge of water cut is not required to calculate the flow rate.

Like multiphase meters or test separators, calibration is necessary to ensure accuracy, Hamza explained. Once calibrated, the proprietary flow-rate calculation algorithm is valid for any point on the pump curve. This ensures that the liquid rate can be calculated even during transient conditions such as startup with phase segregation and slugging, according to a product fact sheet.

“We calibrate the model against a physical test. The idea is to calculate rates frequently, and this can be done as often as once per minute,” she said. “The service starts with the model calibration using the physical tests. We’ve proven that the service can go—depending on the application—without recalibration for up to 54 months [as demonstrated in SPE-145542].”

The virtual flowmeter service works well with commingled wells requiring back allocation, when determining zonal back allocation for multilayered reservoirs, with lowmobility wells requiring reservoir pressure monitoring, in unconventional wells with changing flow regimes and with wells with intermittent production.

“Our dedicated service team sets up the model based on the completion information and delivers the rate and water cut to the customer,” she said. “It’s not a black box generating points that one assumes are correct and improve with time. It’s actually an analytical model that has proven to be valid in various well conditions. We have decades of experience on ESPs to create that model, and every customer receives their own model based on their own ESPs.”

Field-tested
Since deployment in 2011, the service has seen success in remote and not-so-remote locations.

“An operator in the jungles of West Africa experienced difficulty accessing their remote well site, creating challenges during testing,” she said. “Over a period of 16 months, the well had less than 10 test datapoints. After reviewing the data, we established that out of the 10, only seven tests were valid because the well was tested at the wrong time for the remaining three. You do not see that on the surface, but you can see it when you look at the ESP data.

“We ran our service technique, picked up the right calibration point and were able to provide the operator with a one-minute flow rate for the entire 16 months,” she continued. “Based on those data, we also were a ble to provide the depletion profile on the well for the 16 months. This is valuable information that they may not have been able to access because of difficulties associated with testing their wells.”

The service also is useful for ESP systems deployed in unconventional plays.

“The challenge with an unconventional well is the rapid depletion,” Hamza said. “For example, an operator may have an initial production at 5,000 bbl/d, but then production could shrink down to 500 bbl/d in less than a year. That in itself is a big challenge. Operators seeking to maximize their production throughout the life of the well need a tool to tell them where they are in the decline curve and where they are in terms of production.” With this knowledge, they can adapt their well operation to maximize recovery.

“We deployed the service on a well equipped with an individual test separator,” she said. “The operator tested the well every day. For the entire period—which was seven months—we not only managed to match the test data but also provided the operator with the relationship between the flow rate and flowing pressure using only one month of data. These tests allowed
the operator to predict how a change in ESP operating would impact the reservoir pressure support. With this new knowledge, the customer was able to make key decisions in lowering its operating cost and maximizing its production.”

View images here: schlumberger_artificial_lift_imagery.pdf

FIGURE 1. An ESP installed in an unconventional well in Colorado where the liquid rate dropped from 2,600 bbl/d to 400 bbl/d in seven months is shown. The Lift IQ service model captures the transient effect due to the decline in reservoir pressure and the high-frequency liquid rate oscillations (due to gas breakthrough). The Lift IQ service was used to predict flowing pressure for various production scenarios, helping the customer maximize recovery on the well. (Source: Schlumberger)

FIGURE 2. An ESP installed in a remote well in West Africa suffered logistical difficulties, and as a result only 10 tests have been performed during the 16 months of production with the test separator located 3 km (1.9 miles) from the wellhead. The Lift IQ service provided a continuous high-frequency flow rate during this period and was used to perform drawdown analysis, deriving reservoir performance and identifying a potential incremental production of 160 bbl/d of oil. (Source: Schlumberger)

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