Inspired innovation

As the drive towards energy independence in the US continues at full speed, oil and gas companies are turning to hydraulic fracturing to increase production. Increasingly stringent state and national regulations for flare gas in particular now require the installation of mass flow measurement instruments to measure waste and excess gases burned off as a result of the hydraulic fracturing process. For gas wells alone, the EPA estimates that the cost of compliance will rise to US$754 million/y by 2015.

Given the immense number of flares that are to be regulated, there is a need for more cost effective mass flow measurement technologies. Multi path ultrasonic flow meters have been widely used for flare gas measurement, but they are extremely expensive and have marked limitations. To comply with regulations, oil and gas companies need new flow meter alternatives that are accurate, durable, reliable and economical

This article reviews flare gas flow measurement challenges and describes how several recent innovations in thermal mass flow sensor technology give end users an alternative metering choice to consider. Of particular interest is four sensor thermal technology, coupled with an advanced math model algorithm that works in tandem with the American Gas Association’s (AGA) compliant gas property database. In combination, these technologies allow the user to adjust the instrument and retain accuracy as flare gas compositions change in the field over time. The ability of this new breed of four sensor thermal meter to adjust for changing gas compositions gives end users a significantly lower cost alternative to four path ultrasonic meters

Hydraulic fracturing

Hydraulic fracturing is used to release oil and natural gas from wells drilled into reservoir shale rock formations called ‘shale plays’. While fracturing itself is not new (first carried out in 1947), it is the perfecting of horizontal drilling techniques that have made it economical to exploit these shale plays. The oil produced using these techniques and other new exploration technologies is poised to make the USA the world’s largest producer of oil by 2020.

The process of hydraulic fracturing releases large amounts of natural gas. While this is the objective in fracturing a natural gas well, some natural gas is inevitably released during the well completion (flow back). Oil wells almost always produce natural gas (associated gas) along with the petroleum. In many cases, it is uneconomical to process due to heavy contamination. Many of the newer fracturing discoveries do not have the pipelines, compressors and gas plant infrastructure to collect this gas. As a consequence, this gas is combusted, flared off or simply vented as is. When all sources are considered, over 150 billion m3 are flared or vented globally every year. This is equal to 25% of the US’ natural gas consumption in 2012.3 Methane itself is a very potent greenhouse gas, while the carbon dioxide, soot and other contaminants in flared gas are also significant pollutants.

Flare gas measurement challenges

In order to comply with state and federal regulations, oil and gas companies need to invest in mass flow measurement equipment to measure flare gas flowing to: the combustor, vented gas from storage tanks, gas used as fuel, and/or gas sent to the grid for sale. Each well has its unique and constantly changing characteristics that include depth, temperature, pressure, flow rate, soot content and changing gas composition. This makes accurate flare gas measurement very challenging. To comply with stringent state and federal regulations, engineers at oil and gas companies must assess which flow measurement technology yields the highest accuracy with the lowest installation and cost of ownership over the lifetime of the well.

The choice of flow measurement technology for flare gas measurement needs to perform under the following application challenges:

• Wide flow rate variations: Turndowns of up to 1000:1 may be required.
• Non-uniform flow profile: Flare stacks generally have asymmetric and swirling flow.
• Very low pressure with variable temperatures: Most flare headers operate at near atmospheric conditions. Gas temperature varies with well depth and reservoir characteristics.
• Dirty flares versus clean flares: Many flares have significant amounts of dirt, hydrogen sulfide, wax, tar, and other paraffins that make for a dirty, sooty flame.
• Maintenance is difficult and costly: Roaring flames, difficult access and regulatory requirements make flares difficult to service.
• Wide gas density variations: Flare gas composition, and thus the density of flare gas varies over the lifetime of the flare. Traditional flow meters cannot successfully manage the changes in flare gas composition.

As seen in Table 1 (Flare 1), the molecular percentage of hydrogen changes from 86.18% to 48.77%, and methane changes from 5.93% to 3.52% over a year of operation. Faced with such changing flare gas composition, a typical total flow measurement error can be in the 5% to 10% range and could be as high as 20% in applications with widely varying compositions. Correcting measured linear velocities to actual mass flow rates can be problematic if the molecular weight of the waste gas varies by more than 20% from the molecular weight of the meter’s calibration gas.