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The Case for Density Compensation in Water Cut Monitoring

The Case for Density Compensation in Water Cut Monitoring
Continuous density compensation for water cut monitoring provides the necessary accuracy that is demanded for today’s tight oil extraction processes. The value of produced oil depends in part on its percentage of water, or water cut. Water cut also largely determines the processing necessary to prepare the oil for sale and transport. Operators need to determine whether the oil is ready to run through a Lease Automated Custody Transfer (LACT) unit typically used to measure the flow rate and composition of the crude as it changes hands (Figure 1), or if it must be diverted for further preparation to remove water.

The LACT “cash register” system measures multiple variables (flow, density, temperature, water) to determine if the oil is of specified quality for a pipeline. Oil with water content higher than 0.5% to 1.0% is corrosive, and typically not suitable for sale.

Water cut measurements also are part of automatic well testing (AWT) systems used to assess and manage the productivity of individual wells in a production field by sequentially testing their productivity and output. When water cut is negligible or constant, it can be assayed by sampling at intervals, and the results of this sampling can be used to set the value of a well’s output until the next test.

Where water cut varies, as it does, using today’s tight oil extraction technologies such as hydraulic fracturing (fracking), the composition of oil-and-water mixtures must often be frequently measured or continuously monitored. In addition, continuous monitoring reduces the labor to sample the oil and allows increased automation of production at the wellheads.

Figure 1: A Lease Automated Custody Transfer (LACT) unit, which measures flow, density, temperature and water, is often equipped with a Coriolis mass flowmeter as well as a capacitance water cut analyzer.

Water cut measurements are performed with instrumentation, including microwave analyzers, infrared spectrometers, Coriolis densitometers and capacitance
analyzers. Coriolis densitometry and capacitance analysis, in particular, each offer a combination of low initial cost, high accuracy, ruggedness and reliability that make them ideally suited for continuous measurements in wellhead applications. 

A capacitance-based water cut analyzer in effect, is a concentric inline capacitor that leverages the relatively large difference in dielectric constant between oil (k ≈ 2.3) and water (k ≈ 80) to infe stream composition. The system electronics transmit a radio-frequency (RF) voltage to a sensing probe and measures the capacitance between the probe and the surrounding pipe. The more water in the intervening fluid, the higher its capacitance.

The water cut can be calculated from the measured capacitance based on a predictable relationship in the properties of the materials. 

Many wellheads routinely use Coriolis flowmeters to measure the amount of oil produced. Along with measuring mass flow, Coriolis technology can be used to measure average fluid density. If the oil density is known and remains constant, the average fluid density measurement can be used to calculate the water cut.

But used alone, neither capacitance nor Coriolis technology is able to distinguish shifts due to changes in water cut from shifts due to changes in oil density, or API gravity. As a result, conventional water cut measurement shows density variation as water change. Constant temperature and density changes at the LACT looks like a change in water content. Lower density looks like lower water, but the water might actually be going up. Water translates into cost, and the customer or buyer might not be getting what they’re paying for.

More Density Variation
Many factors affect the API gravity of crude oil, including temperature and composition changes, as well as the region and formation where it has been extracted. If not properly compensated, those changes will cause standard water cut monitors to mistakenly attribute changes in density to changes in water content.

That shortcoming is of little consequence in applications where API gravity varies over a tight range, such as conventional vertical oil wells that draw from a localized, well-defined area with consistent properties. But higher oil prices have led to increased use of horizontal drilling and fracking. Instead of vertical wells
dotting the landscape, horizontal drilling may be used to attack a 600-1,000-acre unit. From a single location, six or eight wells typically go down to the formation (perhaps 7,000 to 8,000 feet), then horizontally for a mile or more to cover the entire area.

API gravity values for most petroleum liquids fall between 10 and 70 degrees. The variation within any given formation can easily be +/- 5 API, and the changes across different formations, even in the same region, can be much greater. Without compensating for this variation, water content inaccuracies can be as high as 0.15% per API degree change. Even a small change of 3 API may cause errors in water measurement of 0.45%, which is close to the divert threshold for most LACT systems.

Once a well is fracked and completed it is common for the oil from the extraction point to be laden with as much as 50% water, so it must be processed through separation equipment such as a heater treater (Figure 2) to separate gas, oil and water. Monitoring the water cut of the oil output from the separation unit helps monitor and control how well the equipment is working, and whether the oil is dry enough to present to the LACT. Once the oil is at the LACT, a determination
needs to be made whether it is dry enough to present to the pipeline, that threshold is typically at 0.5% to 1.0% water content.

In un-automated fields, the tanks are emptied by trucks rather than a pipeline. 

Oil from an area of 25-30 square miles is typically trucked to an unloading station equipped with a LACT and connected to a local tank farm and pipeline. Here, density compensation is an absolute requirement because oil from an area of this size will typically have a higher density variation than oil from a leasehold unit of 1,000 acres.

Density Compensation
Water cut measurements can be cost-effectively compensated for density by correcting them using the density measurement from an existing Coriolis mass flowmeter. Connecting a capacitance water cut analyzer to a Coriolis meter using an available density compensation module (DCM) allows the analyzer
to automatically compensate for density changes that may occur in the composition of oil products, and it reduces the calibration requirements due to those changes.

This approach can allow the capacitance analyzer to maintain its stated accuracy with high variations in density, ensuring measurement accuracy from load to load regardless of changes in product composition. The modules also use the Coriolis meter’s existing temperature measurement to perform temperature compensation at temperatures as high as 450°F and at pressures as high as 1500 psi.

Applications for this approach include basic sediment and water (BS&W), separation vessels, pipeline slug detection, truck unloading, pipe protection, dielectric analysis and machinery lube oil monitoring, as well as the aforementioned AWT, LACT, and separator applications.

Figure 2: Along with monitoring equipment performance and product quality, adding density compensation may reduce the amount of oil that must be diverted back to oil/water separation equipment such as this thermal reactor.

Improvements in oil drilling along with the need to automate oil fields that are experiencing productivity gains due to those advances, have created a demand for more accurate measurement technologies. The availability of new, innovative and more accurate products, such as water cut monitoring that minimizes the errors associated with temperature and density changes, meets the latest challenge of these demanding oil measurement applications.

Learn more about Drexelbrook water cut monitors here.