A heavy burden

More and more heavy oil is coming into production pipelines. Measuring it, in a multiphase flow, is a challenge, says NEL’s David Millington.

Heavy Oil. Photos from NEL.

Cost-efficient heavy oil production is an important feature within the oil and gas industry’s near- and long-term objectives.

Over two-thirds of remaining global oil reserves are estimated to be heavy oil, where the more financially attractive, conventional reserves have been progressively depleted. Extraction and processing of high viscosity oils generally comes at the price of a much greater production cost, where refining of additional by-products also becomes a factor.

Onshore regions comprising extra heavy resources, e.g. Canada and Venezuela, often resort to enhanced recovery techniques, such as steam-assisted gravity drainage (SAGD), to boost production rates and therefore maximize recovery factors.

Thermal recovery methods are less common offshore due to financial restraints. However, artificial lifting solutions, such as electric submersible pumps (ESPs), are readily coupled with viscosity-reducing diluent to economically increase hydrocarbon production offshore.

Multiphase flow

The multiphase flow meter is another technology that could support the production of heavy oil fields. Multiphase flow meters have been in use for over 20 years on new and existing oilfield installations.

They can be employed onshore, topside and subsea (often directly at the wellhead) to deliver a full three-phase measurement of the components within the production stream (gas/oil/water) and their respective flow rates.

Multiphase meters offer a number of advantages: real-time production monitoring; improved well testing capacity; and they can also act as a full replacement to the conventional test separator setup, reducing capex and opex costs. However, very few multiphase flow meters have been designed specifically for use with high viscosity oil.

Using the traditional test separator setup for heavy oil is often regarded as an impractical approach. This typically results in long oil-water residence times and contamination issues in the separator outlet streams. Multiphase flow meters not only eliminate these limitations, but also act as a monitoring tool to allow optimization of critical enhanced recovery techniques – an advantage that can directly benefit the productivity of the oil field.

The definition of heavy oil may vary depending on the source, but it generally ranges from API gravity 10 to 22 – any less than 10 and the oil is considered “extra heavy,” where challenging low reservoir pressures are common and thermal recovery (e.g. SAGD) and artificial lifting techniques would be considered essential.

Flow metering is commonly used to dictate custody and fiscal asset allocation alongside providing well monitoring data. Heavy oil measurement is more complicated. First, the effect of fluid viscosity on flow meter performance, either single phase or multiphase, is widely unknown. Second, heavier oils are often forced out of the reservoir using water flooding techniques. This tends to increase the likelihood of oil-water emulsification which presents new measurement challenges in itself.

Effective measurement

Over the past 10 years, the effects of heavy oil on flow metering technologies have been the focus of several research projects at NEL’s flow measurement facility. This research has revealed that high fluid viscosity introduces significant measurement uncertainties, when no correction factor from a baseline low viscosity calibration is applied.

Dynamic qualification is used to identify the optimum performance of the device in controlled conditions and assess the various measurement processes within the device. This includes analysis of the direct measurement, typically performed using dual-energy gamma-ray densitometry to determine component fractions and a Venturi section to approximate the bulk velocity of the flow.

This is preceded by a mathematical model, calculating the difference in velocity between each phase. It is likely the gas phase will be travelling faster than the liquid phase; this phenomenon is known as phase slip. For a heavy oil, the phase slip is generally less than a light oil, where the viscous effects of the liquid begin to overcome the buoyancy effects of the gas. Therefore, the mathematical slip model used within a multiphase flow meter should vary with respect to changes in liquid viscosity.

Testing

NEL recently conducted an experimental program investigating flows of high viscosity multiphase mixtures. The nature of the developed flow patterns and performance of a simulated multiphase flow meter was assessed. The testing was performed in NEL’s multiphase flow facility using high viscosity oil (1500cP).

The pipeline equipment included a vertical perspex Venturi tube and additional straight length perspex pipe spools to allow for flow visualization. A high-speed tomography system was installed upstream of the perspex Venturi tube to enable cross-sectional imaging of the flow pattern.

This test, alongside previous heavy oil multiphase trials, has proven substantial fluid viscosity effects, where the conditions prevent gas coalescence, as well as eradicating high frequency slugging and other flow dynamics that would typically be encountered in lower viscosity conditions. Consequently, the variation in flow pattern at the meter inlet, Reynolds number effects, and phase slip influence the performance and uncertainty characteristics of the simulated meter. Further high viscosity trials with a commercial multiphase flow meter have also been conducted. These trials have provided valuable data enabling the manufacturer to establish critical correction data to adapt the multiphase meter to heavy oil multiphase flows.

Future direction

In order to move forward and progress the functionality of multiphase flow meters for use in high viscosity flows, we should expect to see more qualification testing in heavier oils.

As found by NEL’s research, the flow dynamics will change for lighter and heavier oils, adversely impacting the device measurement uncertainty if unaccounted for. Further guidance on qualification testing requirements should be proposed to ensure the multiphase flow meter will be tested in suitable conditions that better reflect its baseline performance.