By John Kemp

LONDON (Reuters) - “A rose by any other name would smell as sweet,” William Shakespeare wrote in “Romeo and Juliet”. But he was not working for the U.S. government and trying to define what constitutes condensate and natural gas liquids.

A simple and workable definition might have baffled even the undisputed master of the English language.

In the world of condensates and natural gas liquids, a rose is never just a rose, and producing simple and consistent definitions has eluded federal regulators.

OPEC, which includes crude but not condensate in its production quotes, has also struggled and failed to agree on common definitions.

In the past, the inconsistent treatment of condensates in the United States did not matter because they were a relatively small proportion of total petroleum production. But thanks to the shale revolution, condensate production is rising faster than the output of either crude oil or natural gas.

Output of natural gas liquids from gas processing plants and oil refineries has risen by more than 1 million barrels per day (50 percent) since 2010 to over 3 million barrels per day in July 2014.

Production of condensate directly from oil and gas fields is not recorded separately. But it probably accounts for a significant proportion of the 3 million barrels per day increase in crude production reported over the last four years.

Because of the current record-keeping system, however, there is no way to accurately estimate condensate production.

Intelligently regulating and managing a resource is obviously impossible if neither industry nor government knows how much is actually being produced.

On Oct. 3, the U.S. Energy Information Administration, the statistical and analysis arm of the Department of Energy, held a closed-door “Condensate Workshop” for officials from several government agencies and experts from the industry in an effort to come up with a new and more consistent definition.

“We hope to have this sorted out so that policymakers will know what the numbers are,” EIA Administrator Adam Sieminski had told a conference in September. (“U.S. oil industry’s billion-dollar question: what is condensate?” Oct 8)

This was the first step in what is likely to be a long, drawn-out process.

NOT CRUDE, NOT GAS

Condensates and natural gas liquids (NGLs) occupy an intermediate position in the spectrum of hydrocarbons, which ranges from natural gas at one end to heavy crude oils at the other.

Some of the lighter NGLs are gases at standard atmospheric pressure and temperature but become liquid easily with only moderate compression and cooling. Ethane, propane and butane are gases at room temperature but condense at minus 88 degrees, minus 42 degrees and minus 1 degree Celsius, respectively. But methane condenses only at minus 164 degrees.

Heavier NGLs and condensates are already liquid at standard pressure and temperature but are volatile and vaporise readily. Pentane, hexane and heptane become gases at just 36 degrees, 68 and 98 degrees Celsius.

In the real world, the distinction between natural gas, condensate and crude oil production is blurred. Most oil and gas wells produce some of all three, mixed together.

Some crude and condensates are suspended in the methane produced from gas wells. These liquids are removed from the gas flow by field separation facilities (in which case they are called “lease condensate”) or more complex natural gas processing plants (where they are termed “plant condensate” or “natural gas plant liquids” depending on the degree of processing).

Oil wells usually produce some dissolved gas, which is separated at the well head. It contains condensates that can be recovered either at field separators or natural gas plants.

In addition, some proportion of the crude will consist of light hydrocarbons such as propane, butane, pentane and hexane, which are recovered at refineries (where they are termed “liquefied refinery gases”).

The point is that there are many names and ways of producing the light hydrocarbons that occupy an intermediate position between natural gas and crude.

PRODUCTION METHOD

From the industry’s point of view, what matters is chemistry and the uses of different hydrocarbons, each of which is marketed and traded as a commodity, either separately or in blends.

But from a regulatory perspective, what matters is how hydrocarbons are produced. Broadly speaking any light liquid hydrocarbons recovered from natural gas processing plants (NGPLs) and oil refineries (LRGs) are treated as refined products, while those reclaimed from simple field separators (lease condensate) are treated as crude oil.

This focus on production stems from historical differences in the way the oil and gas industries were regulated by federal and state governments (usually with separate statutes, taxes and record-keeping systems for oil and gas production).

Differences in treatment based on production have become enshrined in federal regulations. For example, the regulations controlling crude oil exports count lease condensate as crude, which cannot normally be exported except to Canada, but liquefied refinery gases are refined products that can be sent abroad without restriction.

The production approach is also enshrined in the way the U.S. Energy Information Administration (EIA) collects and presents statistics on the production and consumption of natural gas liquids. It was still central to a set of revised definitions that the agency introduced in 2013.

Under the EIA’s definitions, lease condensate is aggregated together with crude oil, while the products from natural gas processing plants and refineries are reported separately. This made sense at one time, when natural gas liquids and condensates were relatively minor byproducts of natural gas production and the refining industry.

But as they become increasingly important, the inconsistent and confusing definition of natural gas liquids reduces transparency and makes sensible policymaking impossible.

New and more consistent definitions are needed that harmonize the classification of natural gas liquids and other condensates, whether they come from an oil field, a gas field, a gas processing plant or a refinery.

API GRAVITY DEFINITION?

The obvious approach is to define condensate by its physical characteristics or chemical composition.

Condensates and natural gas liquids are typically lighter than most crudes, so one option would be to base a new definition on the API measure of specific gravity, where lighter hydrocarbons have higher numbers.

Much of the oil industry already employs this approach. “The API gravity of condensate is typically 50 degrees to 120 degrees,” according to Schlumberger’s online Oilfield Glossary.

Some experts have suggested that the federal government define condensates as any hydrocarbons that are liquid at standard pressure and temperature and have an API gravity of more than 50 degrees.

Hexane has an API gravity over 80, pentane over 90 and butane over 110, which are all well above the suggested 50-degree threshold.

But some other light crudes would also be caught by this definition. The challenge will be setting the cut-off point to minimize the incentive for oil producers to claim that their light crude is actually condensate or natural gasoline to secure more favorable regulatory treatment.

Once a definition of condensate based on API gravity is agreed, the data collection system, export controls and other parts of the U.S. Code of Federal Regulations will all then need to be revamped to use the new definition.

Then and only then will policymakers, regulators and the industry be able to get a clear sense of how much is being produced and what controls, if any, should be maintained on exports.

(editing by Jane Baird)