By leveraging a robust mitigation strategy of optimized maintenance and process control—enabled by instrumentation insight—the industry is able to reduce greenhouse gas emissions, while simultaneously increasing production.
BRANDON BROMBEREK, Emerson
The oil and gas industry makes up 40% of all anthropogenic methane emissions, and 78% of these happen at upstream production sites. Fortunately, the well pad is often where methane emissions are easiest to address through a mitigation strategy of optimized maintenance and process control—all enabled by instrumentation insights.
With the right strategy, producers can not only reduce emissions, they can also reduce operating costs and increase output. Many have already taken significant steps to reduce methane emissions, and all are looking to improve further in this area to address this significant issue.
Here are a few thought-provoking statistics reported by the Environmental Defense Fund about oil and natural gas production in the U.S., with similar trends worldwide:
Methane emissions are a pollutant, but they also represent lost product, reducing output and revenue. Therefore, producers need to think differently, and the information in this article provides a roadmap to address both these issues.
COST EFFECTIVE EMISSION REDUCTION
Operating in oil and gas fields can be regarded as an opportunity to practice stewardship over a finite natural resource. The objective for any company should be delivering the most production while causing the least environmental impact. The challenge arises when a cost/benefit analysis indicates that the cost of reducing emissions is significantly more than the added revenue from any extra gas captured, Fig. 1.
Such discussions have major sustainability implications. Companies wanting to increase production—while also improving their environmental, social and governance (ESG) programs—must consider how operational realities affect ESG objectives. These efforts end up being visible to outside stakeholders and the public in general, so they indicate how serious a company is about sustainability overall.
In addition to more local stakeholders, regulatory directives are emerging globally, each with practical goals for reducing emissions and energy consumption (Fig. 2), but these often approach the challenge from different directions.
For a company wanting to reduce unintended methane releases, leading questions include:
Let’s unpack these serious questions with some practical answers.
WHERE ARE THE LEAKS?
In the upstream sector, Emerson’s engineers, working with a variety of producers, have identified common causes of methane emissions:
Regardless of the cause, all these issues—and more—can be addressed at a reasonable cost with intelligent equipment and other upgrades. Let’s focus on these leaks, examining three process areas at the wellsite: wellhead management, separation solutions and tank and water management.
WELLHEAD MANAGEMENT
Individual wellheads are often the first source of emissions, and they are also a place where emissions can be quickly and effectively addressed. Fortunately, there are a range of available technologies (Fig. 3) to help improve well production, reduce operating costs and reduce emissions, providing wins on all fronts.
At the wellhead, leaks or containment breaches often go unidentified because the only way to detect them is via manual operator rounds, leaving detection dependent on human factors, such as experience and time availability. By outfitting a wellhead with strategically placed instrumentation, manual rounds can be turned into automated health checks. For example, a basic pressure transmitter (Fig. 4) continuously delivers reliable data to identify leaks or integrity issues, allowing for timelier remediation—even in remote locations. This is in contrast to an isolated, fluid-filled gauge, which requires a technician to access it onsite, record the data and relay the results to operations personnel.
Sand coming out of a reservoir can cause rapid erosion of piping, fittings and valves. Acoustic monitors (Fig. 5) “hear” particles and can quantify sand content in real time, flagging the risk of erosion before damage occurs. Strategic high-wear points in piping should be equipped with ultrasonic metal thickness monitors to measure the effects of sand erosion and corrosion and to identify when wall thickness is approaching critical points, long before loss of containment. This improves operational safety, while avoiding emissions and shutdowns. A software application interprets these measurements to provide clear direction for operators and maintenance planning.
Where gas and oil are particularly corrosive, chemical additives may be needed to neutralize harmful components. Dosing must be controlled to deliver only the required amount, since overdosing can harm downstream equipment and result in environmental incidents, while requiring excessive spend on wasted chemicals. Coriolis mass flowmeters provide very accurate measurements of additive dosing, ensuring optimal injection rates at the wellhead for ideal treatment effect.
Gas sent to the flare, if properly combusted, eliminates methane from being released into the atmosphere. However, unlit or inefficient flares result in raw methane releases. If that methane can be captured, it provides a practical and valuable resource at the wellsite, such as fueling gas-fired generators for site power—or better yet, being transported off-site and sold. A DP flowmeter equipped with a multi-variable transmitter provides an accurate and economical differential pressure flowmeter, capable of monitoring a site’s gas consumption.
SEPARATION SOLUTIONS
The mixture of gases, liquids and solids coming out of a well must be separated into respective streams. When a separator is outfitted with a range of diagnostic instruments (Fig. 6), it can provide information on the production rate or each stream, and then inform operators when upset conditions—which can quickly create emissions events if not handled properly—are developing.
The design of a separator assumes a range of flowrates, with typical proportions of the products. But at an actual well site, those proportions and flows can be anything but fixed. Proper instrumentation provides valuable insight to understand, if the separator is actually operating efficiently. For example, if a separator is over- or under-sized, gas may break through to liquid lines, resulting in methane being forced farther downstream. When operators have accurate awareness of the separator’s performance, it is possible to avoid such downstream emission events.
Natural gas feed pressure to the separator must be stabilized, especially when it tends to surge at the wellhead. If separator back pressure is too high, it reduces well production, and it can even result in a shut-in well. A pressure relief valve (PRV) should open before that happens, but this releases gas. PRV activity should be monitored, using an acoustic transmitter, supported by appropriate software, to record release events and leakage, Fig. 7. Even moderate pressure increases make separation less effective, allowing gas to be released to the atmosphere, so monitoring pressure via a robust transmitter is critical.
Some flowmeters can detect when a separator is operating outside its design range—a condition often leading to excess emissions. If gas is carried into the liquid legs, a Coriolis flow meter (Fig. 8) installed on the oil and water discharge lines can detect two-phase flow. Additionally, the flowmeter’s ability to determine liquid density can also detect oil in the water line, or vice versa.
Since separator upsets can cause emissions farther downstream, it is critical to detect the presence of gas in the oil holding tank, which can create a safety issue and undesired emissions.
TANK AND WATER MANAGEMENT
Maintaining product quality and safety is critical to any production operation. Failure to have appropriate management solutions for produced fluid—including water—results in safety risks, product loss, and environmental release. However, by implementing the proper measurement technologies (Fig. 9), it’s possible to identify potential failures and leak points before a catastrophic event occurs.
For example, when an operator accesses a tank roof and opens a hatch to check fluid levels, any gas or volatile organic compounds accumulated in the tank are released. Additional safety risks, such as hydrogen sulfide overcoming the operator, can deliver potentially fatal consequences. A roof-mounted, non-contacting radar level transmitter provides level measurements without the need to open a hatch, while delivering better accuracy than manual methods, in accordance with API 18.2 requirements.
Pairing level measurement technology with effective inventory management software allows for collection of real-time tank-gauging data, automatically calculating volume and mass for inventory and custody transfer purposes.
Fugitive emissions are difficult to measure and detect, but methane detection technologies are available, with sensitivity able to respond to minute concentrations. Three technologies are often used in combination (Fig.10):
Water coming out of the well contains hydrocarbons, and often in large quantities, in the case of unconventional production. Processing the water begins with the separator and then moves to a storage tank. Typically, this water is removed from the site and processed further elsewhere, which calls for an effective custody transfer process, since various handling and disposal charges are involved. Where truck transfer is the procedure, a magnetic flowmeter (Fig. 11) is a robust solution for monitoring the transfer and determining resulting charges. This sensor type can handle difficult situations, such as high sand content and variable flowrates, without damage or plugging.
The presence of oil in water tanks causes additional concerns, such as cost and environmental problems. As oil continues to rise to the surface in the holding tank, it forms a layer. If the water collection truck picks this oil up, or it is sent away via a water pipeline, additional downstream processing charges may apply, not to mention the loss of salable product. These situations can be detected using a guided wave radar level gauge (Fig. 12), capable of detecting the interface between fluid types, and even measuring the volume of residual hydrocarbons.
Gas entrained in the water or pumped into water lines during a separator upset accumulates in the tank and can escape via venting. These are fugitive emissions, as well as lost product. As described earlier, effective separator control is paramount to avoid these problems, so production must be matched with separator flow capabilities by deploying effective measurement and control technologies.
COMMITMENT TO SUSTAINABILITY
Emerson is committed to doing our part to ensure a sustainable planet for future generations. We are dedicated to helping our customers reach their production and sustainability goals with our application and instrumentation expertise.
For the upstream production sector, this means reducing methane emissions. Emerson has solutions to help reduce these emissions through improved measurement, for more precise real-time control and process optimization, and by supplying technologies capable of monitoring emissions. With these tools, it is possible to establish a baseline for tracking and demonstrating improvements, while reducing costs and increasing overall production, allowing sustainability to support the bottom line. WO
BRANDON BROMBEREK, vice president for oil and gas at Emerson, focuses on empowering end users to help them achieve more sustainable operations, optimize production and decrease costs by utilizing the firm’s automation technology. His expertise centers on helping the industry navigate the energy transition through the coexistence of traditional oil and gas with emerging themes, such as hydrogen and carbon capture, and employing automation to advance developments across these value chains. Mr. Bromberek joined Emerson in 2018 after 13 years in oilfield services. He sits on the board of directors for the Society of Petroleum Engineers’ Flow Measurement Technical Section, and he holds a project management license from the Project Management Institute. Mr. Bromberek holds a bachelor’s degree in mechanical engineering, from Purdue University, and a master’s degree in management for the oil and gas industry, from Heriot Watt University.