Industries emitting emissions include oil & gas production, crude oil transportation and refining, and natural gas processing, transportation, and distribution. Emissions must be monitored and assessed, in order to be tracked, and reduced. Some issues exist with assessing emissions, such as excessive errors in use of simple production-based methodology, non-experienced personnel, rigorous bottom-up approaches, costly data analysis, and time consuming, costly emissions management programs, with excessive documentation requirements.
The sources of fugitive emissions from oil & gas activities include process evaporation losses, equipment leaks, venting, flaring, and accidents or equipment failures. Additional sources of fugitive emissions exist:
• Benzene waste management.
• Leakage of CFC gases from refrigeration systems and electrical components.
• Land disposal of solid waste.
• Methane emissions from wastewater handling.
• Methane from industrial wastewater and sludge.
• Nitrous oxide from human sewage.
However, the oil & gas sector is a primary source of methane emissions, followed by carbon dioxide from untreated process streams, raw carbon dioxide stripped from produced gas, waste gas flaring and incineration activities, carbon monoxide, sulphur dioxide, and many other gases causing emissions.
While the industry is advancing with various new technological tools on a regular basis on monitoring, and finding and fixing emissions, best practices, quality data, and technical knowhow is useful. Assessment of emissions from oil & gas can be reviewed as a three-tier approach:
Tier 1 – Use of statistics and production-based factors. In this method average production-based emission factors are applied and reported from production volumes.
Tier 2 – Each piece of equipment can have different data source and techniques of evaluation. Where associated and solution gas is assessed, control factors are used to account for utilization, reinjection, and conservation volumes. This can be assessed from available production accounting data and engineered estimates.
Tier 3 – Emissions measurement and monitoring. Emissions from individual equipment using process infrastructure data and production accounting data including actual measurement work. All are aggregated to determine the total emissions.
There are factors affecting emissions in every plant:
• Design and operating practices.
• Frequency of maintenance and inspection activities.
• Type, age, and quality of equipment.
• Type of hydrocarbons being produced or handled and their composition.
• Operating conditions.
• Pumping or compression requirements.
• Metering requirements.
• Treatment and processing requirements.
• Frequency and duration of process upsets.
• Sweet, sour, or odourized service.
• Population density near the facility.
• Off-shore or on-shore operation.
• Distance to market or the next down-stream segment of the industry.
• Market value of waste hydrocarbons.
• Applicable environmental and conservation regulations.
• Pricing/economic incentives.
The quality of equipment, inspection, testing maintenance dictates emissions from equipment leaks. For example, in most critical applications the fugitive emission leaks are minimal or none. We can see fugitive emissions or methane losses from production activities, natural gas processing, transportation, and distribution.
The Fugitive Emissions Inventory Methodologies (Tier 3)
Conventional technologies used in leak detection and repair programmes i.e., estimation of leak rates based on leak screening data collected in accordance with U.S. EPA’s Method 21, provide only a very crude indication of actual changes in emissions. Since nearly all emissions come from the small percentage of components that leak the most, a good approach might be to conduct a simplified screening programme to identify these few leaks and then use direct measurement techniques such as flow-through flow meters, and bagging techniques to accurately measure their actual leak rates.
For instance, specific fugitive emission rates and uncertainty levels tend to increase upstream in oil & gas systems, while the value of the gas, and to a certain extent, the cost effectiveness of implementing emission reduction measures, tends to increase in the opposite direction.
However, in general, the value of avoided hydrocarbon losses is very site-specific and depends on many factors which include the following:
(i) Value of the hydrocarbons in terms of invested costs up to the point of control.
(ii) Capital and operating costs to achieve the proposed emission reductions compared to the costs to find and develop new gas supplies.
(iii) Supply and demand constraints. Often the conserved gas becomes reserve production that is not sold until reservoir and market conditions change to the point where demand exceeds supply. Thus, the economic benefit of avoided losses may not be realized until near the end of the project life when the avoided gas losses are finally sold, and
(iv) Applicable government taxes, royalties, subsidies, and incentives.
There have been numerous and substantial advancements in recent years in the available methods for conducting Tier-3 source-specific emission assessments:
(i) Activity-based Emission and Control Factors.
(ii) Empirical Correlations.
(iii) Computer Models and Simulators.
(iv) Direct Measurement Techniques.
(v) Indirect Measurement Techniques.
Many of the Tier-3 methods require the use of experienced well-trained personnel or specialists to achieve reliable results. Moreover, they require either very detailed site-specific data or the performance of actual field measurements. The use of these refined approaches allows greater disaggregation of the emissions, and in turn, facilitates better interpretation of the results. It also allows more meaningful comparisons with corresponding specific emission rates in other regions.
Tracking and Measuring Results
It is important to achieve proven, transparent results, account for specific control measures and understand the uncertainties in the developed results. However, the cost of achieving such results should not become a significant burden on resources available to reduce emissions. Focused measurement and monitoring programmes should be conducted to confirm calculated emissions and emission reductions where such values are significant.
Some industry associations have been developing comprehensive handbooks for use by member companies in assessing their emissions. The key objectives for a number of these initiatives have been to provide a flexible framework in which individual companies may assess their emissions, and to establish a base set of terms, source categories and nomenclature to facilitate intercompany comparisons and allow easy aggregation of the results for roll-up into national emission inventories. GRI Canada (1998 and 1999) has recently prepared two such handbooks for application to gas transmission, storage, and distribution systems.
API (1996) has developed a calculation workbook for oil and gas production equipment fugitive emissions. CAPP (2000) has prepared a document for up-stream oil and gas operations. In addition, there are several commercial software packages available for developing and maintaining Tier-3 emission inventories. Updates to the inventory should, at a minimum, match critical baseline and milestone years specified in the agreements by the Parties to the United Nations Framework Convention on Climate Change (UNFCCC).
However, more frequent updates will allow parties to track their progress in achieving targeted reductions, and allow progressive refinement of the results. In general, the frequency of updates should reflect the rate of change in emissions. Additionally, fast-response analyzers (e.g., for methane or hydrogen sulphide) may be used to visualize and verify separation of plumes in real time.
If all the necessary historical data are present for the base year, emission estimates should be made using the best available current technologies (BACT). While establishing baseline emission levels is meaningful and important at a regional or national level, it is often a misleading indicator at the company level due to frequent mergers, divestitures, and acquisitions in many areas. This may be an issue where national inventories are developed based on a roll-up of company-level inventories, and some extrapolations or interpolations are required.
Documenting and Reporting
The current trend by some government agencies and industry associations is to develop detailed methodology manuals, reporting formats for specific segments and subcategories of the industry. This is perhaps the most practical means of maintaining, documenting, and disseminating the subject information.
To promote transparency in the reporting of emission estimates it is important to also include reporting of the estimation methodology, sources of the emission factors and activity data, and the applied QA/QC procedures.
Since emission factors and estimation procedures are continually being improved and refined, it is possible for changes in reported emissions to occur without any real changes in actual emissions. Accordingly, the basis for any changes in results between inventory updates should be clearly discussed and those due strictly to changes in methodologies and factors should be highlighted. A common means to address such issues, where they do arise, is to aggregate the data using a reputable independent third party.
Refineries may have larger LDAR programs and include 10-15 technicians doing method 21, and one or two cameras, to meet the overall appendix K requirements. If this is the case, appendix K should say that cameras are required to be sufficient for leak detection, and one does not require Method 21. Facilities with larger programs will therefore use cameras, and smaller programs will continue with Method 21. Refineries and chemical processing plants may allow optical gas imaging as an alternative. In all types of plants, the proper measuring, and documenting of emissions is essential.
1. Industry experts and colleagues, including David Picard, Art Jaques, Gary Webster, Bob Lott, Marc Darras, Jasmine Urisk and Katarina Mareckova and Thomas Martinsen.
2. Illustrations and details from paper courtesy, David Picard.
ABOUT THE AUTHOR
Gobind N Khiani, a UCalgary alumnus of Masters in Mechanical Engineering is a seasoned change-maker. He has a proven track record in technical and value engineering and holds a Fellowship in Engineering and an MBA. He is the Chairman of the End User Group at API and Vice Chairman of the Standards Council of Canada. He has done peer review on Emissions Management regulatory documents for ECCA and participated in research and development initiatives. Further, his experience is in the energy sector in the improvement of standards, technical compliance, strategy, governance, digital innovation, engineering management, technology, sustainable development, and operations. He is also skilled in Asset Integrity and Maintenance Management. As a volunteer, he is involved in technical standards (energy, tech, public safety) and has been a mentor/judge at First Robotics Canada. He is also the past chair of the CBEC of APEGA.