A Case For and an Update to Research and Testing on the Issue of Hydrocarbon Wet Gas Sampling

In the last 25 years, the natural gas pipeline industry has transitioned from the supplier of clean, dry gas to the mover of billable gas energy; clean and dry or dirty and wet.  The amount of hydrocarbon product that is transported between producer, processor, distributor and user is significant.  To be able to verify the exact composition of the product is important from an economic and product treatment standpoint.  In addition, if the best sampling procedures are followed, the potential for disputes between supplier and customer will be greatly reduced.  The importance of properly determining hydrocarbon gas composition benefits all parties involved.

The level of interest in effective and accurate gas sampling techniques is currently at a very high priority within the natural gas industry.  With current natural gas prices, exploration interests, profitability, deregulation and consolidation of the work force, recoverable revenue must be found and reported.  At large volume delivery points, a 3-5 BTU error in energy determination can cost companies tens of thousands of dollars within a very short time period.  Accurate sampling techniques must be implemented with equal interest as that which is given to accurate volume measurement. And, it bears repeating over and over again.  Most flow equations receive the specific gravity portion of the formula from the analysis of the gas sample.  If the analysis is deprived of the total picture, how can the volumetric answers be relied upon as representative of the total system?  The error is compounded and the integrity of the system is compromised. 

Natural Gas sampling has been performed for years with techniques handed down from generation to generation.  Most of the early methods were not sufficient to meet   today’s requirements of accuracy and repeatability; however, standards have been developed to reach toward these demands.  The most widely known standards are GPA-2166-05 and ISO-10715 and API 14.1 of 2006. These have already generated significant interest in proper sampling techniques, due to a large volume of data produced during the revision work.

In the past 35 years, sampling systems have been refined to meet more exacting requirements of the industry and sampling standards have been revised to reflect the latest reliable knowledge and techniques.  The equipment available today is truly “state of the art.”  Samplers, cylinders, probe regulators, protective filtration systems, separators, membranes, protective shut in devices for analyzers, insulated and heated enclosures and the like are available from a number of known manufacturers. 

Historically, natural gas was sampled as natural gas. Our natural gas pipelines are seeing changes within the pipeline, relative to quality.  Liquids are present for a number of reasons.  One dramatic reason is simply the cost of natural gas.  Producers are trying to meet the demand and sell their product.  In so doing, gas processing is being streamlined or reduced.  Liquids are being passed along in the interest of providing energy.  Another reason for the increased presence of liquids is a change in system operations.  Today, we pull from our storage domes harder and faster than ever before.  This tends to increase the presence of liquids in the system.  Deeper wells, shale plays and colder pipelines in deep-water production are yet other sources of liquids.  Reduced maintenance, more flexible contracts and a host of operational considerations are in play. Hydrocarbon liquids that are present in a natural gas pipeline have monetary value and must be accounted for.  The liquids are not being recognized in the analysis, but they are being measured as mass (density or specific gravity) by the meter. Those liquids must be measured and analyzed in a fashion that is representative of the manner in which they were measured as volume. MMBTU is the total of volume and energy.  Sampling is the energy determination delivery system for this equation, and the results have a dramatic influence on the volume measurement totals and the bottom line profitability for the company.

Most equipment used in the gas industry is not designed to account for and handle liquids.  Liquids have typically been removed and handled as a liquid product.  Today however, that is not always the case in a new multiphase world.  The quality of the pipeline product cannot be represented as accurate if the method of taking a sample incorporates a technology or procedure that is designed to reject or isolate liquids that are present.  Using a separator, coalescing filter or a membrane designed to reject the intrusion of liquids, is not providing the complete answer for the pipeline measurement department.  If liquids never show up in the sample, but continue to be found in headers, river crossings and drips, then something in the procedure or technology is not allowing for a truly representative analysis to be attained.  All of our sampling standards – ISO 10715, API 14.1, GPA 2166, etc. – call for a representative sample of the flowing stream.  From the Gas Processors Association publication GPA 2166-05, “The objective of the listed sampling procedures is to obtain a representative sample of the gas phase portion of the flowing stream under investigation.  Any subsequent analysis of the sample regardless of the test, is inaccurate unless a representative sample is obtained.”  And, from ISO-10715, a representative sample is, “A sample having the same composition as the material sampled, when the latter is considered as a homogeneous whole.”  API 14.1 offers a similar statement in the latest revision, “a representative sample is compositionally identical or as near to identical as possible, to the sample source stream”.  We must capture a representative sample regardless of the effort.  Then, a technology or procedure for correctly and accurately handling the combined sample must be developed.  That is the challenge. 

If we state that we have taken a representative sample from a flowing stream, then it must represent ALL of the components present in that stream; not simply all the gas phase components of the stream.  In the quest for full knowledge of our system, we must know all of the components of the gas stream.  Not all of the components act the same, flow at the same speed or stay equally dispersed across the inside diameter of the pipeline.  It is not as simple as sampling a dry gas stream.  It is noteworthy that the current and updated gas sampling standards all make the clear statement that they are to be used in gas streams that are clean, dry, non-saturated and above the hydrocarbon dew point of the flowing gas stream.  Therefore, lessons learned in the programs need to be presented accurately and honestly.  While there are indeed few issues with taking a sample of 1012 BTU gas at 80° F, it is not likely a good practice to infer from that data that there are few issues to be seen with 1348 BTU gas at 58° F.  While it is true that a probe is not required in a laboratory test of nearly pure methane, it might be considered questionable to extrapolate that to a 10 year old 8 inch meter run installation in North Dakota with1246 BTU gas and only a bottom tapping and a valve for a sample point. While we continue as an industry to find new answers, we must not forget the lessons learned over the last 45 years. 

Most current Gas Chromatographs boast an accuracy level of ½ of a BTU, but that should not be the comfort zone for the measurement department.  A faulty sampling method or improperly installed and maintained equipment may alter the BTU content of the flowing stream by 25+ BTU.  While the accuracy of the GC may be considered as a given, the properly executed technique for taking the sample is certainly not a given.

On some meters we know what the possible error can be, if we know what the liquid content is.  So knowing the liquid content is becoming critical with the higher gas prices, which look like they are here to stay.  Determining the accurate dew point (leading to a liquid content answer) has been impossible with the current method of sampling.  Repelling liquids that are present in the pipeline at the sample point, is taking care of the liquids issue for the GC….. but it is avoiding the accounting issue for the pipeline profitability and safety issue for pipeline integrity. 

Spot sampling was the primary method of acquiring a sample for analysis until the early 1970’s.  This method is still widely used today.  In today’s world of growing trends toward therm-measurement and therm-billing, this method is increasingly expensive in analytical cost and man-hours, as well as a very questionable method of assessing an accurate heating value to volume sales.  It is at best a “spot” sample of what was present at the moment the sample was taken.  Minutes before and minutes after become unknown guesses.  While this may be a reasonable risk if the gas source is known by a long historical data base, most gas being consumed today is a combined gas from several origins, or is switched from source to source by contractual updates; in some cases by daily or even hourly arrangements.   This author has been on location and witnessed a 62 BTU increase at a single sample point, within a one-hour time frame.  It was mainly attributed to both a substantial increase and decrease in flow rate as well as well selection changes within the gathering grid.  Also, we find typically, that the older the well and the longer it stays in production, the higher the BTU value will become.  Natural gas is an extremely fragile product and almost every step in the production, transportation and distribution of natural gas, will have an adverse effect on its quality.   Switching wells, pressure changes, temperature changes and storage vessels are only a few of the items that can add or subtract BTU values on the gas moving through measurement stations.  Thus, our sampling methods may not even represent the correct source in question.

The issue of sampling “wet gas” from a flowing pipeline is one that has elevated itself in importance over the past 20 years.  Historically, natural gas was sampled from a natural gas pipeline that had been processed and was relatively free of liquids.  The water, condensate, or heavy hydrocarbons that could create unwanted liquids had been basically removed by processing, separation, or filtration of some type.  When a technician went to take a sample of “dry” natural gas, he was reasonably assured that he would be able to extract a representative sample of natural gas and return that to the laboratory for analysis.  Due to the costs of production and processing and the increased demands on the supply and numerous other considerations, that old, simple process of taking a gas sample is no longer that simple.

This paper is presented with the desire to focus on the considerations and challenges that lie ahead.  It is the author’s desire to stimulate dialogue about the ultimate goal of measurement quality equipment for the industry as it operates in the real world today.  In order to promote discussions, there has to be an awareness of the issues that impact the pursuit of new procedures or technology.  The concerns of the natural gas measurement industry are real and legitimate concerns.  However, in the race to find answers, we should not fail to keep in mind the lessons that we have learned and have documented to be true in the past.  If we are mindful of those lessons, it will allow us to appreciate the current advancements and accept how we arrived at them.  As we look for answers in the new world of gas pipeline measurement, we should not purge the data base of knowledge just to solve one aspect of the problem.  We must incorporate that knowledge into the pursuit of future advancements. 

Admittedly, much of the basis for this paper and its content is the result of the fact that we now see gas pipelines with more liquid content than before.  Many are in fact, nearing multiphase pipelines.  At times, we are led to believe that our leaders of the past never faced or thought of this issue.  This is why the author reflects in this paper about not forgetting the lessons of the past.  Here is an interesting paragraph from a paper presented at the University of Oklahoma, to the International School of Hydrocarbon Measurement in 1982 — 30+ years ago.

The ability to “tame” liquids when they appear in the gas sample streams or cylinders is now at hand with the availability of high quality new equipment.  The capability of determining the heating value of the gas at any pressure and temperature condition can be determined with reasonable accuracy by conditioning the sample as it is directed to the measuring instrument.  However, there is a need to more precisely define a “liquid” in our contracts and state how to account for the heating value of the fluid when liquid is present as an aerosol or otherwise.  Should the BTU be determined on the gas at flowing conditions, or should it be determined at a greatly reduced pressure and elevated temperature?  Should a pressure and temperature be selected for determining the BTU that would correspond with the average annual ground temperature and average annual pipeline pressure?  These and other points must be resolved before any determined effort can be instituted to standardize BTU determination procedure on aerosol gasses.

The Wet Gas Sampling matter clearly came to the forefront during the API 14.1 work.  The Scope of API 14.1 was not inclusive of Hydrocarbon Wet Gas as we know and understand it to be today.  Due to the impact of this phenomenon and reality in our operating systems today, this is an area that we must address as an industry, and in the very near future. 

Perhaps the single major issue that has created an interest in ascertaining the total picture of the natural gas pipeline system is “wet gas.”  The definition of “wet gas” as gas with more than 7 lbs. water per million cubic feet is almost history.  Wet gas metering is redefining how we talk about wet gas.  There is a white paper written by Dr. Parviz Mehdizadeh that describes wet gas.  Wet gas, in that multiphase white paper, is defined as “gas, which contains some liquid.  The amount of liquid can vary from a small amount of water or hydrocarbon to a substantial amount of water or hydrocarbon.”  Today’s measurement issues are different from the past, but they are here to stay.  We must either return to the insistence and requirement of a clean, dry gas pipeline system (separators, processing plants, dehydration systems, etc) or acknowledge the realities of the present.  One of the biggest challenges is the transportation or Mid-stream system operating below the HCDP.  Liquids cause corrosion, pulsation, freezing problems and basic maintenance issues that create concerns for a natural gas pipeline system.  Their presence must be addressed with an awareness of what that means to our industry.

One thing is for sure.  The industry wants to push everything down the pipeline at once.  It wants to sample the entire contents at once.  It wants a correct answer of total content from that single sample.  Keeping some things out of the sample is not the answer.

There was a solid attempt to work on this matter within the ISO system in TC 193 SC 3 and in 2011 WG 5 was established and met in Nanjing, China.  Then, due to United States policy with sanctioned countries and the ISO position, that work became idle of US involvement for the present.

At the October 2012 API COPM meeting in New Orleans, the interest of Wet Gas Sampling was brought up in the API 14.1 Working Group of COGFM.  It was suggested to move this interest to CPMA.  In that meeting, there was clear interest in the matter and an Ad Hoc committee was established to present a white paper for this subject.

The people of this Ad Hoc committee are clearly aware of the need and the differences between upstream and downstream interests in the matter.  In this current interest we are not talking about water wet, but rather, hydrocarbon wet – very rich streams that have the potential for causing real issues with current sampling techniques and how to get a qualified representative sample from a wet gas system. These include issues of ambient conditions and phase envelope knowledge, undefined variability or uncertainty of the sampled hydrocarbon gas composition, BTU content and a host of similar matters.   

We do not suggest that the points raised hereafter are the sole focus of the task, the answer, the correct way, or even the appropriate wording to go forward. Nor will they alone provide the answers that we seek.  What we do feel is that these points can prompt some thoughts and ideas as we move forward.

While these issues listed below are not finalized answers or solutions, they are none the less a listing of the issues and thoughts that will impact the pursuit of an answer to wet gas sampling.

• What definition will we use for Wet Gas?
  • Parviz Mehdizadeh – “gas, which contains some liquid. The amount of liquid can vary from a small amount of water or hydrocarbon to a substantial amount of water or hydrocarbon.” 
  • Lockhart-Martinelli
  • API Chapter 1 Definition
  • ASME MFC – 19G-2008 Definition

• Is Wet Gas – Multiphase? Is Multiphase- Wet Gas?
  
  • For the measurement arena that downstream interests are familiar with, we are interested in natural gas streams with entrained liquid similar to Type I and Type II as defined by Lockhart-Martinelli, not a stream with 30 to 90% liquid. Initially, many of us are looking at a system that the industry would typically consider being a natural gas stream with an unusually high content of hydrocarbon liquids, when one expects (by past standards) a clean, dry supply of natural gas.
  • Understanding that one could say yes to both, our first focus is the saturated stream we are trying to measure and sample with conventional methods and not a multiphase production stream, with the entire wellhead production coming by.
  • After we tackle the Wet Gas issue, then we can move toward a Multiphase sampling program for upstream applications.

• Attempt to define upstream vs. downstream keeping in mind the mid-stream folks.  Is the break at the Gas Plant?
  
  • We have upstream, midstream and downstream interests in our industry.  Perhaps our first work will likely not focus on the production or upstream side.  With the work done and the knowledge gained in 14.1, GPA-2166 and ISO-10715, we are best positioned to work on the midstream concerns and certainly the downstream applications.  Liquids are an issue that cause measurement errors, once you get away from production allocation.  Our sampling standards are focused on very accurate detection of BTU values, not just acknowledging the presence of components at any level. 
  • Perhaps for the initial work, the plant outlet should be considered the beginning of the downstream side, and primary area of initial attention.  We fully recognize the push to move accurate measurement closer and closer to the well head, but we need to document the impact that such a move has on conventional sampling programs, and how to accommodate the challenges we face when seeking a REPRESENTATIVE SAMPLE of what is in the pipeline at flowing conditions — all of it!!  The custody transfer point has moved into the environment that we have yet to address the physical realities for.
  • Once we grasp the challenges at this level, we should have discovered useful tools and knowledge to venture further upstream. 

• What are the concerns at the well head that are different for the LDC and everyone in-between?
  
  • The main concern at the wellhead centers on the ability to properly sample representative phase fractions at the wellhead conditions, such that this information (phase densities and PVT information) can be directly attributed to flow measurement (e.g. a wet gas meter) or the application of phase behavior.  Wellhead sampling becomes a necessity when representative downhole samples are not available (or no longer applicable), or single-phase sampling and recombination is not feasible (e.g. commingled separation facilities downstream of well).
  • Are we sampling for Energy Content (heating value and Mass component % determination) or simply for Component Identification – (it is there, but we don’t care how much is present, simply that we know it is part of the stream).  These are two distinct interests that will impact the scope and goal of the work.  Both ultimately need to be addressed.
  • Operations downstream of production do not expect to deal with the potential for different types of liquids (i.e.  water, oil, emulsion, chemicals, drilling mud and lots more) you find close to the wellhead and these fluids will create headaches for the sampling techniques and labs doing typical natural gas analysis.

What is the economic impact from poor measurement in sampling practices?  While it may be initially difficult to quantify, it can be substantial.  It will depend on the application of the sample results and how they are used in the operations of a company.  Studies that have already been conducted have seen 50+ BTU swings at a single measurement location within one hour, due to liquids, volumetric flow changes and well-head switching.  That impact is impressive when it relates to an attempt to provide accurate measurement, both component and flow related.  The impact of improper techniques today on a clean, dry system with known practices is well documented and significant.   Poor practices on a wet gas system is at least as significant, if not much greater.  Proper sampling techniques will also lead to improved allocation for production and pipeline operations.

Additional thoughts

• Is it better to try to separate the liquids in the pipeline and keep them from the sample apparatus, or is it better to take a representative sample of the contents of the pipeline and then develop a methodology of extracting the products from the cylinder? Return to gas plant separation and measurement of liquids as liquids and gas as gas.   You cannot separate the gas and liquid that easily as it comes from the line.  Some of the gas will remain with the liquid and some of the liquid will remain with the gas.  Retention time is needed to properly separate the gas from the liquid.  The constant pressure cylinder is the best way to give the gas and liquids the retention time needed to do good separation.  Doing this at the line temperature should tell you what was in the line.  Naturally this will take some testing.
• If you take a representative sample of the properly mixed stream (much as we do with crude and refined product systems), can we then (after capture) heat the contents of the cylinder until it is all vaporized, in a controlled environment, and get a true picture of the contents of the pipeline?  Or, must it be returned to the same temperature and pressure at which it was taken.
• Of course, the fluid, liquid and gas in the pipeline must be completely mixed before the sample is taken in order to take a representative sample. We know that we can extract a representative sample from a flowing stream.  That has been done for years.  If the stream is mixed and uniform, then we can extract a representative sample.  But, can we analyze that sample correctly?  What does it represent in regards to the volume of gas and the volume of liquid to be measured?  That is the question.  This is where some testing needs to be done.

Looking at two major regions in the USA and the current production volumes from those regions, we can present these two financial inputs to consider for the importance of studying this sampling issue.  In a hydrocarbon wet gas system, a 20 BTU error is conservative and completely within the realm of reality.  Using 20 BTU as the potential bias, these numbers show the potential financial impact of not having an appropriate sampling method for hydrocarbon wet gas.

Based on the late December 2013 prices of $4.43 MMBTU and the production rate of 3 bcf/d at the Eagle Ford Shale region, a 20 BTU error (or less than 2% error) would be a financial impact swing of $315,000 per day or over $100,000,000 a year.

Based on the same numbers, Marcellus Shale at 5.5 bcf/d would be a swing of $405,000 per day or over $145,000,000 a year

This issue has been driven by several concerns.  Value determination has been moving closer and closer to the well head due to allocation, royalty (land owners, State and Federal Government), joint ventures (more partners with commercial interests), streamlining of operations, etc.  Sampling has also been done at the field meter.  Sampling used to be done after the gas plant, as clean, dry pipeline quality gas – and often by the same company or no more than two parties involved.  Liquids were stripped and sampled as liquids.  Now, people are concerned with custody transfer earlier in the process.  Offshore production, deeper wells, colder temperatures, richer gas streams, shale gas formations and other considerations, all lead to higher BTU gas production and Hydrocarbon Wet Gas streams.  Our current gas sampling standards do not address gas streams that are considered as wet gas streams or below hydrocarbon dew point (inside the phase envelope).  Finally, it is agreed that the issue has been there all along, but we did not sample at those points in the past.  It was not ignored, but simply did not come into play.  Wet Gas has always been there – we just sampled after separation and processing.  No need to do it sooner, until now.

Due to the breadth of this matter, there should be participation from multiple reliable sources, including industry companies, suppliers, government interests that have participated and followed earlier work (they understand that this is not a 6 month project) and one or two research facilities.  API 14.1 successfully utilized more than one of the leading research bodies and it enhanced the work of the program, as well as added to the validity of the work.  There should be one leader with strong guidance, direction and input from the sampling committee, but as many participants as are willing to work openly.   The Natural Gas Industry needs to drive this due to the knowledge present in the industry.  No outside interest is knowledgeable enough to guide this project.  All viable and reasonably, potentially sound solutions should be examined and addressed in this project.  Is there a better way?  Is it mechanically possible?  Is it technically possible?  Is it analytically possible? 

The project will need a recognized facility with a wet gas loop.  There should be at least three or four…….. or preferably a number of field locations with a variety of gas flows, to validate and field test the standard.  There will be a need for several gas labs that will participate in potential round robin testing of the samples and specialty gas standard manufacturers for necessary standards during testing.  It will also need locations that allow us the broad range of dry to wet gas delivery points and begin to simply take samples with different technologies, and see how they affect the integrity of the sample? 

As of the writing of this paper, there is working being conducted within Pipeline Research Council International (PRCI) on wet gas sampling.  Due to limited funding they are concentrating on separating the liquids from the gas and focusing on getting an accurate gas sample.  Also, within API at this time, there is a proposed scope of work for the solicitation of funds.  This was presented by the Ad Hoc Committee on Wet Gas Sampling in API CPMA.   COPM approved the project for solicitation of funds in late 2014.  The proposed scope and support for the work were presented as follows:

• Proposed Project Scope:
  The scope of API 14.1 and the resulting data produced from the revision of that standard, was limited to natural gases that “are at or above their hydrocarbon dew point.”  The current initial intent, while understandably not the final scope of potential research, is to pursue the next step beyond the scope of 14.1.
  
  Therefore, we seek to determine and quantify (in the field and laboratory) the variability of compositional and BTU content analysis associated with gas sampling in upstream production separator outflow conditions and similar pipeline conditions, using existing sampling methods (from API 14.1 and GPA 2166) with the target flow regime for this initial testing program to be a Type I (as defined below) wet gas flow stream.  The Wet Gas Sampling Committee and the director of the funded research will utilize both laboratory research and field research to study this variability issue.
  
  Tests of sampling methods are proposed at a test facility under closely monitored conditions and in field locations where we have a high level of confidence are within the Type I gas flow. These locations are to have well-understood and stable process flow conditions that resemble wet-gas pipeline flows and can be recreated in a controlled test facility.
  
  The impact of water-wet conditions will also be followed in those locations where those conditions are present.  At this point, water-wet is not the primary focus, but is not to be ignored when present and observable.

• Business Need for the Proposed Research:
  

  Variability of sample results in upstream production separator outflow and Type I pipeline (transmission pipelines for example) conditions can be related to the inefficiency of the separation process as well as the reservoir production itself.  Unprocessed gas can exhibit both water-wet and hydrocarbon-wet conditions that will have an impact on the quality of the sample and resulting analysis. The composition and BTU content of separated gas streams have shown wide variability, and testing should be done to determine how much of the variability is associated with sampling and how much is associated with the well reservoir or separation process itself.  If testing shows that changing reservoir conditions or separator efficiency are not responsible for most of the composition and BTU variability, then additional testing (Phase 2) will be warranted to understand how the current sampling practices are rendered unreliable by the unprocessed stream conditions.  At this point, we need to address the most urgent need in our industry and focus on the area that is most likely to bear useable fruit.

  As described in API MPMS Chapter 20.3 and ASME MFC-19G, there are three ranges of interest in wet gas measurement based on the Lockhart-Martinelli number – Type I (XLM <0.02), Type II (XLM = 0.02 to 0.3), and Type III (XLM ³ 0.3).  Type I wet gas flows have low liquid levels, but are most likely to affect mid-stream and upstream gas companies by causing inaccurate and unrepeatable sample compositions and BTU content, and errors in contract payments at the metering and sampling interface.  Type I wet gas flows are also expected at locations where contract amounts are largest.  Type II and Type III flow regimes fall outside of the proposed scope of work, but will be considered for later research if data points to that need.

This is likely to be a 3-5 year project if fully funded and active, and an approximate budget of $500,000 to $2,500,000 is anticipated.  There will be a need for a very strong commitment to see the project through and an understanding of the value of the study, as well as a need to promote this at high levels within the industry, based on the need for such a standard and monetary impact to profitability.

The end game is to have a standard on wet gas sampling techniques with validation criteria and improved measurement and better balances on systems.

Is there likely to be a Phase I, Phase II and Phase III approach, or not?  There might be a need to present a phased approach both from a technical viability standpoint (see what is out there, how it’s used, and limitations first, with further steps improving on the technology) and from a timing standpoint (if our scope is too large, and it takes too long to get something off of the ground, people will lose interest).

Participants in venues like NGSTech 2014 and other measurement forums should find this topic to be of great interest over the next several years.

“Proper Sampling of Light Hydrocarbons”, O. Broussard, Oil and Gas Journal, September 1977

“Selection and Installation of Hydrocarbon Sampling Systems”, D. A. Dobbs & D. J. Fish, Presented at Australian International Oil & Gas Conference, Melbourne, Australia, 1991

“Methods, Equipment & Installation of Composite Hydrocarbon Sampling Systems”, D. J. Fish, Presented at Belgian Institute for Regulation and Automation, Brussels, Belgium, 1993

“The Importance of Discerning the Impact of New Measurement Technology”, D. J. Fish, Presented at 25th Annual North Sea Flow Measurement Workshop, Keynote Address, Olso, Norway, 2007

“Practical Considerations of Gas Sampling Systems for Today’s Changing Natural Gas Environment”, D. J. Fish, Pipeline and Gas Journal, June/August 2012

Various Standards of AGA, GPA, API, ASTM and ISO

The author acknowledges the contributions made to this paper that also came from members of the API CPMA Ad Hoc Committee on Wet Gas Sampling as we prepared a statement to API and in the preparation of the funding request and members of PRCI wet gas sampling efforts.