Papers

Liquids measurement in the oil patch is suddenly getting a lotof attention. Some are dismayed at the low level of technology used to measure liquids. Today, custody transfer of 80 to 85% of onshore crude and condensate production is still documented by a hauler climbing to the top of the tank and strapping it. “That would be a fair estimate,” concurs Mark Davis Staff Engineer Shell Exploration and Production. The hauler straps the tank before loading his truck and again when he finishes. The producer is paid on whatever that hauler writes on the ticket.

Differential Pressure (DP) Flow meters are popular for being relatively simple, reliable and inexpensive. Their
principles of operation are relatively easily understood. However, traditionally there has been a misconception that no
DP meter self-diagnostic capabilities exist and as such only upgrading to newer ultrasonic or Coriolis technology can
help bridge this gap. In 2008 & 2009 a generic Differential Pressure (DP) meter self-diagnostic methodology [1,2]
was proposed to the industry. In this paper these advanced diagnostic principles were applied towards helping provide
end user a newer yet effective, methodology for DP flow meters diagnostics, field proven with experimental test
results. These results form the basis of a comprehensive validation methodology designed to help meter operators
achieve improved confidence on their DP measurement and thereby help lower their operational risks associated with
large measurement uncertainties due to non-compliance. The paper also aims to demonstrate how such new advanced
tools/methodologies can help reduce operating costs (OPEX) by moving towards a risk based predictive maintenance
plan.

Over the past 30 years, gas ultrasonic meters have transitioned from the engineering lab to wide commercial use as the primary device of choice to measure gas volume for fiscal accounting. Wide acceptance and use by gas
pipeline companies has occurred during this time due to the device’s
 Reliability
 Accuracy
 Repeatability
 Capacity (rangeability)
 Commercial availability that translates into product support, and
 Adoption of industry standards for fiscal measurement applications

Pipeline Operators have used Ultrasonic meters commercially for gas custody transfer applications since the late
‘90’s. These meters’ combination of operating features, including superior rangeability and on-board diagnostics
have made this the technology of choice for most high volume gas metering applications. As user comfort with, and
capabilities of, the technology has increased and the size and cost of ultrasonic meters has decreased, Operators
and Manufacturers continue to stretch the envelope of application possibilities. This includes use in upstream,
corrosive and high CO2 applications, where the technology previously couldn’t work or didn’t make economic sense.

Part 1 of this paper provided basic information on the theory, application, and installation of ultrasonic flow meters to natural gas measurement. This paper covers additional information related to the interface and operation of ultrasonic meters.

This paper is the first of a two-part series that provides an introduction to flow measurement using transit-time ultrasonic flow meters. This paper covers the essential knowledge that users should have regarding the basic operation of ultrasonic flow meters. The second paper will provide more detail on diagnostics and operational effects on ultrasonic flow meters.

Since their introduction to the natural gas industry in the mid-1990s, multipath ultrasonic flow meters have developed a large installed base and have become the meters of choice for a variety of reasons. While one of the initial goals of the
manufacturers was to develop a meter that did not require flow calibration, the accuracy requirements of most measurement applications dictate that ultrasonic flow meters need to be flow calibrated. This paper provides an overview of the calibration process and elements that should be considered by those responsible for the calibration.

We have all heard of or seen the devastating effects of a direct lightning burst. Communication equipment destroyed.
Transmitters and EFM devices vaporized into slag metal. Complete process and measurement systems down with extended
recovery times. These effects are the most dramatic and the easiest to trace. However, these kinds of events are rare. The
more prominent events are those that occur on a day-to-day basis without we, the user, even knowing. With the advent of the transistor and today when surface mount electronics is the norm and not the exception, transient suppression has become a science of necessity. Tight tolerances of voltage requirements and limited current carrying capabilities makes the new compact integrated circuits much more susceptible to many types of transients.

The purpose of this paper is to explain the measurement of natural gas for custody transfer applications through the
use of ultrasonic meters. Specifically, this paper explains the operation of ultrasonic meters, issues surrounding their
performance in natural gas, calibration procedures, and proper installation considerations. Additionally, the electronics making the measurements generate calculated values relating to the operation of the meter and as a result a database is available to provide analysis of the meter’s ongoing performance. Meter health parameters can be evaluated to verify the meter’s operation and these principles are explained.

The measurement of oil & gas production has progressed considerably since the days of paper charts and manual integration. Technology has moved increasingly to microprocessor based flow computers allowing for greater measurement accuracy, increased control functionality, and ready integration into a company’s enterprise computer networks.