Papers

The measurement of natural gas liquids (NGL) is similar in many respects to that of other hydrocarbon liquids but is
markedly different in other aspects. The main difference in NGL measurement is the need to properly address the effects of solution mixing. Measuring NGL by mass measurement techniques will properly address solution mixing effects because the mass measurement process is not sensitive to the effect that pressure, temperature and solution mixing have on the fluid measured.
Another difference is the effect of higher vapor pressures on the measurement of natural gas liquids. In static measurement methods, the liquid equivalent of the vapor space must be determined. In dynamic measurement methods, the equilibrium vapor pressure, or that pressure at which a liquid and its vapor phase is in equilibrium at a given operating temperature, must be deducted from the operating pressure when determining the compressibility effects on measured volumes. This paper will describe the basic concepts used to measure and report the quantities of NGL streams.

This paper will verify the history, requirements and operation of all Provers accepted for liquid pipeline meter uncertainty verification in the Liquid Oil/Gas Industry. It will continue with an explanation and the industries wide acceptance of the Uni-directional Captive Displacement Prover (UDCDP). This document will supply the reader with information regarding meter types and the flow volumes that can be used with the UDCDP and will look at the opportunities for the use of a UDCDP as a mass prover. It will also provide the information for field verification of provers known as a water draw.

The first flow meter utilizing the Coriolis force to measure mass flow was patented in 1978. Today, hundreds of
thousands of Coriolis meters are in service in the hydrocarbon industry to measure mass, volume, and density of a wide variety of fluids. The American Petroleum Institute published Chapter 5.6 entitled “Measurement of Liquid Hydrocarbons by Coriolis Meters” in October 2002 and reaffirmed the standard in 2013. The standard describes methods to achieve custody transfer levels of accuracy when a Coriolis meter is used to measure liquid hydrocarbons.

This paper will discuss the use of pycnometers for densitometer provings. The primary objective will be to provide guidance in the operation and maintenance of a densitometer and pycnometer (pyc), as well as common issues found during normal operation.

With the proliferation of horizontal drilling allowing access to tight oil formations, liquid production in the U.S. has significantly increased over recent years. Consequently, there is renewed interest in accurate measurements for both custody transfer and allocation purposes. Advances in measurement automation have yielded operators’ savings in the millions of dollars annually. Over the last several years, the increase of shale play drilling has created a problem within the industry. Most of the shale plays have been developed in primarily natural gas production areas, where a lack of liquids measurement knowledge may exist.
While there certainly are knowledgeable people in these areas, measurement personnel can be spread thin due to the many
active drill sites. Both allocation measurement and custody transfer measurement occur in these areas, so measurement
personnel must be well versed on both. Typical questions that come up are: What is the right technology to use in each of the areas of measurement? Should I use turbine meters, Coriolis meters, or maybe just orifice meters? What data do I need to get back to my host system? Should I just count barrels or do I want to get some real insight into the process?

The word “Auditing” is often used to imply that activities related to a review of general business practices, and procedures for an asset or business unit, are under way.
The objective of those activities is to assure compliance with corporate policies and procedures, industry and government standards, and sound management principles. Additional objectives may include review of accounting and financial transactions for accuracy, completeness and timeliness. The Institute of Internal Auditing defines the process as:
“Internal auditing is an independent, objective assurance and consulting activity designed to add value and improve an
organization’s operations. It helps an organization accomplish its objectives by bringing a systematic, disciplined approach to evaluate and improve the effectiveness of risk management, control, and governance processes.”

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.