Over the last 4 years, two distinct influences have raised-end user concerns over the hydrocarbon content of natural gas in the US.
Sharp increases in the price of natural gas have created a difficult environment for the economical extraction of NGL. At times, producers and processors have found it to be more profitable to leave NGLs in the gas and sometimes very costly to extract them.
Some processing plants have shut down because of these unfavorable economic conditions, and some unprocessed natural gas has flowed through the transmission pipelines. Because of this, some pipelines have experienced unacceptable accumulations of heavier NGLs.
Meanwhile, development of large gas projects outside the US has gained momentum and prompted plans for more US LNG import terminals. The absence of natural gas hydrocarbon specifications is hampering some project developers and leading many to install costly blending equipment or restrict the sources of LNG supply because the thermal content of many sources of LNG is not considered equivalent to US-sourced natural gas.
This article examines the issues surrounding natural gas quality specifications; these issues are made more urgent by the expected increase in LNG imports through current and planned US terminals.
OFOs
Events surrounding the issue of natural gas quality, which began in late 2000, were the driving force behind transmission pipelines issuing operational flow orders (OFOs) to compel the processing plants to begin processing again and to "improve" the hydrocarbon quality of the natural gas or to restrict the injection of high-thermal-content LNG supplies into the US transportation system.
Unfortunately, given the history and nature of the US natural gas industry, attempts to establish hydrocarbon specifications led to conflicting or incompatible specifications, causing unnecessary disruptions in natural gas supply.
Because of their arbitrary natures, many of the OFOs were challenged before the US Federal Energy Regulatory Commission. A FERC conference on Feb. 18, 2004, sought to investigate the issues surrounding natural gas quality.
Panelists representing several trade associations presented gas-quality issues that their constituents found troublesome. At the end of the day, most participants generally agreed on the need for hydrocarbon specifications and that common ground revolved around two facets of natural gas quality:
1. Hydrocarbon liquids fallout from natural gas.
2. Whether gases of differing compositions were interchangeable.
The Natural Gas Council formed two task forces, consisting of industry representatives, to investigate these two quality issues and to report back to the NGC's executive council and the FERC on new protocols to establish hydrocarbon quality specifications.
US natural gas production sources are the primary concern of the first quality issue, liquids fallout. Due to the temperature involved in liquefying LNG (–260° F.), the heavy hydrocarbons that are associated with liquids fallout are absent from LNG. The second facet of gas quality, interchangeability, is primarily the focus of LNG.
Midstream evolutions
This article will only address the issue of hydrocarbon content in natural gas since there are established specifications for the nonhydrocarbon constituents—nitrogen, CO2, helium, H2S, and water—and there has been no change in the level of treating to meet these specifications.
The gas processing function has come to be referred to as the midstream industry, a term used to describe the activities between upstream—exploration and production, and downstream—gas transportation and marketing.
In the early gas industry, a producer sold his gas production as a by-product of oil production to a gas pipeline company, normally through long-term, fixed low-price contracts. The produced gas was processed in "gasoline plants" which simply compressed the gas, cooled it to condense any heavy hydrocarbon gases, i.e., natural gasoline (C5+).
Producers found value in extracting the natural gasoline because it was more valuable as a blend stock in motor gasoline than it was to sell as gas. Increased gas production prompted construction of more pipelines to move gas to regions farther from the producing region.
During this period of growth, the industry became more sophisticated in engineering and materials technology. Gas processing plants began to evolve, driven by the increasing demand for NGLs to supply the needs as a motor gasoline blend stock, rural heating fuel, and as a feedstock for the huge petrochemical industry growth since the 1960s.
Plants were designed to chill the gas even colder to increase the extraction of NGLs from the gas. This evolution continued through the years and was influenced by the prices of natural gas, NGLs, and crude oil, and by many government actions.
As the US industry developed, pipeline transmission companies established quality specifications to address corrosion issues involving the integrity of the steel pipeline itself. These specifications do not address the hydrocarbon content portion of the gas.
Examining several pipeline tariffs for hydrocarbon-content specifications, each pipeline has established its own minimum thermal content unique to its own pipeline, but most pipelines do not limit the maximum thermal content.
That the industry has developed and prospered over the years without hydrocarbon gas specifications is amazing, yet the history of gas regulation was the driver behind the economics of processing. This is due to the historic price of natural gas being so low that producers were driven to extract as much value out of the produced gas in the form of NGL.
Before 1980, pipeline companies purchased gas on a volumetric basis and were not compelled to establish hydrocarbon specifications other than for a minimum thermal content to ensure there was a sufficient hydrocarbon content in the delivered gas to sustain a flame.
The change to a thermal basis did not change the need to establish hydrocarbon quality specification either because the only change to the market place was that transactions were occurring on a thermal quantity (btu) instead of on a volumetric quantity (Mcf).
After decontrol of wellhead gas pricing in 1989, producers found that the maximum extraction of NGL did not always lead to the maximum value for the produced gas. Producers and processors soon realized that there could be financial loss extracting NGL from the gas due to the cost of "shrinkage."
Shrinkage refers to the gas decrease, volumetrically and thermally, from the extraction of NGLs and carries a cost for the lost gas volume. Plant operations were adjusted to reduce the recovery of NGLs, increasing natural gas supply and increasing value to the wellhead.
To complicate matters, gas processing contracts are structured for the economics of extracting NGLs to increase the value of production and are normally devoid of gas-quality specifications because receiving pipelines have had no such specifications.
The changes in processing economics and in the degree of processing have caused many pipelines, distribution companies, and end users to question the composition of the natural gas. Many argue for a return to the "old" nominal composition, but doing so would reduce supply and possibly elevate prices as consumers compete for the remaining supply.
Before establishment of specifications that may reduce supply, a more prudent path to follow would be to understand the issues that are causing concern for downstream customers.
Liquids fallout
The first facet of natural gas quality is hydrocarbon liquids fallout, which occurs in the transmission pipeline or in the market area's distribution pipeline grid and poses operational and safety concerns.
Liquids fallout occurs when the gas is chilled below the hydrocarbon dewpoint (HCDP) of the gas. This can be exemplified by observing the effects of humid air cooling overnight to below its dewpoint and our awaking to find a coating of dew on the grass or the windshield of the automobile parked outside.
Since natural gas consists of many hydrocarbon constituents such as methane, ethane, propane, butane, pentanes and heavier, some of these higher molecular-weight constituents will condense when the gas temperature is reduced or when the concentration gets too high.
Simulations of many gas compositions and calculations of the HCDP over a range of pressures reveal that the constituents having the greatest impact on HCDP are hexane and heavier constituents. Once these constituents condense, they are unlikely to revaporize when the pressure is reduced because the gas chills upon the reduction of pressure and the expansion of the gas (Joule-Thomson effect), such as the pressure drop experienced at a pressure regulator or pressure control valve.
The safety issue free liquids pose in a gas pipelines is that pipelines are not designed for two-phase (liquid-gas) flow, except in certain instances, and liquids can damage pipeline equipment. Another concern is that if liquids are not removed from the delivering pipeline before reaching the burner tip, they can cause sudden flare-ups in the combustion chamber or cause a flameout of the burner.
Avoiding liquid fallout requires two events: First, the natural gas must be processed to reduce the concentration of hexane and heavier constituents to minimal amounts; the second is that the natural gas must be prevented from being chilled below the cricondentherm (CT) of the gas. (Cricondentherm is the highest temperature at any pressure at which a gas will begin to condense and liquids form.)
The dewpoint curve tends to be parabolic in shape; the CT will be at the apex of the curve and at pressures above or below the CT, the dewpoint temperature will be less (Fig. 1). In most traditional natural gas compositions, the CT occurs between 300 and 600 psig. The dewpoints at pressures less than 300 psig can be as much as 50° F. less than the CT temperature.
In a recent OFO posting, ANR Pipeline Co.'s notice uses an example of a gas containing only 0.2 vol % hexane and heaviers that has a corresponding HCDP CT of 59.1° F. and 1.079 btu/cu ft. The C6+ liquefiable content of that amount of gas equals about 88 gal/ MMcf of gas delivered. Therefore, processing the gas to remove the heavy hydrocarbons will be required.
The second event, the temperature of the gas, can be affected by two external factors: the ground temperature of the regional marketplace to which the gas flows and the amount of pressure drop that occurs at each pressure-reduction step from the transmission pipeline to the burner tip.
The ground temperature surrounding the pipeline being below the HCDP of the gas can chill the gas during transmission to a marketplace. In this case, the heavy hydrocarbons can condense on the walls of the pipeline and be swept along through the pipe by the velocity of the gas.
These liquids will aggregate at the low points in the pipeline and can cause pressure pulses in the pipeline when gas is trapped behind a slug of liquids, resulting in a pressure build up that forces the slug to move to the next low point or into a separator at a compressor station.
To make gas fungible, the regional market aspects need to be considered. Pipelines transporting gas to northern-tier US states will require a lower HCDP due to ground temperature than gas remaining in southern-tier states. Therefore the consideration of HCDP should be set at a temperature below that of the wintertime ground temperature at the buried depth of the pipeline, less a safety margin of 10° F. (i.e., an HCDP = (30° F. –10° F.) = 20° F.). This would imply that all pipelines serving northern-tier states would have the same HCDP and therefore any gas interchanged from one pipeline to another be fungible.
The second cause of liquids fallout is the pressure reduction that occurs after gas is delivered off of a high-pressure pipeline. The delivery-point customer usually reduces the pressure of the gas into its own system. The expansion of the gas during pressure reduction creates cooling (Joule-Thomson effect).
A rule of thumb used for natural gas is to expect cooling of 7° F. /100 psi of pressure reduction. The first pressure-reduction step is the most critical because this is the most common point at which the gas passes through the temperature-pressure apex of the HCDP curve.
Therefore, entities that receive gas from high-pressure pipelines must handle the gas so as to avoid chilling it below its HCDP CT. Because very few transmission pipelines have HCDP specifications in their tariffs, end users have been unable to build pressure-reduction stations to a consistent HCDP temperature design.
Depending on how each end user handles his gas prior to pressure reduction, the temperature may drop below the HCDP CT, thereby causing liquids fallout. El Paso Corp., parent of ANR Pipeline, recommends designing pressure-reduction stations with a maximum of 250-psi reduction or an equivalent 18° F. decrease in gas temperature.
This would imply that during winter, the example cited would require a minimum 8° F. of heating to keep the gas from forming liquids below 20° F. Since every end user has its own uniquely designed reduction station, some end users would need to make modifications to ensure the safe handling of the gas.
Figs. 1 and 2 present two examples of a large pressure reduction and the effects of liquids fallout.
Fig. 1 shows a pressure-reduction station not following the recommended design criteria referred to previously and operates at a 700-psig reduction without preheating the gas. The gas temperature passes through the dewpoint curve and liquids begin to form.
Fig. 2 shows that preheating the gas sufficiently to ensure the temperature after pressure reduction is above the HCDP temperature will ensure no liquid fallout occurs.
Another option suggested is that the HCDP be used only seasonally. During the warmer seasons, the ground temperature would be sufficiently high to allow the operation of the pressure-reduction station without preheating the gas and still stay above the HCDP of the gas.
The unfortunate drawback to this option is that high-HCDP gas would be injected into storage fields, mainly downstream of gas processing plants. When this gas is drawn upon during the wintertime, this high-HCDP gas would enter the marketplace, causing liquids fallout that the HCDP specification was instituted to avoid.
This reinforces the need to process the gas year round to a level that will comply with an established HCDP specification on a pipeline and for pipelines supplying a specific geographic region with an interchangeable, fungible supply.
Therefore, a hydrocarbon dewpoint specification is the best control measure for liquids fallout. This will allow for a wide range of gas compositions to be made available to end-users without compromising the safety or the integrity of the natural gas supply infrastructure.
The use of a hydrocarbon dewpoint specification will provide the information necessary for end-users to design, install, and operate pressure-reduction stations that will keep the flowing gas from entering into a two-phase region and causing liquids fallout.
Interchangeability
The second facet of the natural gas quality issue is interchangeability.
The principle of interchangeability is the ability to substitute a gas supply source for the traditional system supply without interfering with the safe and efficient operation of end-use facilities and appliances.
Because of the variety of appliances in the market place, finding a range of gas compositions that are interchangeable is very complex.
The objective would be to include as broad a range of compositions without compromising the safety of the natural gas supply. Some measures used to establish interchangeability are thermal content (gross heating value, GHV), specific gravity, Wobbe Index, and some of the Weaver indices, such as flame stability, flame flashback, and incomplete combustion.
Finding agreement on interchangeability specifications will be difficult. Each piece of equipment in use, such as industrial turbines, furnaces, residential heaters, ranges, and unvented space heaters, has unique performance characteristics. Changing the quality of gas may not affect one type of equipment but have a large and possibly detrimental effect on another.
Unfortunately, for many industrial applications, different types of equipment have been designed that use the current flowing gas quality, instead of a consistent standard. This practice has created a situation in which large investments have been made based on an assumed gas quality.
If the gas quality changes, the operation of the equipment may cause it to fail the performance guarantees of the manufacturer or to exceed the environmental compliance levels unless further investment is made to allow for more flexible supply. In other instances, depending on the design configuration of the burner, some appliances can accommodate a wider range of gas compositions than others.
- Establish specifications that will either cause a very narrow range of gas compositions, thus limiting the available supply of gas to the market place; or,
- Establish a broader range of gas compositions and possibly require end users to replace or modify appliances that cannot handle a broader range of supply.
Hence the dilemma:
In either case, the consumer will be affected by the higher cost of a restricted supply or by the need to replace appliances that cannot safely consume the broader range of gas compositions.
Approaches
Thus, there can be two approaches to the issue of natural gas supply:
- The lowest common denominator approach, to transport a low-energy-content gas that is suitable for all appliances.
- The second approach, to employ high-energy-content gas to be transported by the transmission pipelines to secondary users and allow them to adjust the thermal content as needed.
The first approach, establishing hydrocarbon specifications similar to gas compositions in the early 1990s, would be to maintain a low thermal content (~1,025 btu/cu ft) gas supply.
A US produced gas would be stripped of almost all ethane and heavier hydrocarbons, regardless of the economic gain or loss incurred to extract the NGLs.
Depending on the produced gas source, the extraction of NGL from the gas can reduce the thermal content of the gas by 2-30% to reach a low-btu gas content. Processing to extract a very deep cut of NGLs would reduce the available supply of domestic natural gas.
This approach would also affect LNG supplies to the US, requiring the gas to be reduced in thermal content, either by processing to extract propane and any heavier hydrocarbons or by blending with nitrogen to lower the thermal content.
Since ethane markets exist mainly on the US Gulf Coast, importers of LNG to the US East Coast would be unable feasibly to extract the ethane portion of the gas due to the lack of storage and transportation assets, unlike propane and butanes where these assets are available.
Alternatively an inert gas, such as nitrogen, could be used to dilute high-thermal-content gas. A drawback to this alternative is that the gas may be unsuitable for certain applications requiring low levels of inerts in the natural gas.
Both options to lower LNG thermal content will incur higher investment costs and higher operating costs for LNG.
Creating higher costs for LNG, a fuel that competes on the world marketplace, may cause the US to be a less attractive destination for LNG compared to other countries vying for the same supplies.
Therefore, this scenario may have the lowest initial investment cost but will most likely lead to end users paying higher supply costs.
The second approach, resorting to a gas composition more typical of the pre-1960s, would be to process natural gas to a lesser degree, extracting only the heavy hydrocarbon gases (C4+) and allowing for a higher thermal content gas, possibly as high as 1,150 btu/cu ft.
This method would increase available supply and allow transmission pipelines to deliver more thermal content per unit of volume. This would defer the need to expand the existing interstate pipeline grid.
Designing a higher thermal content natural gas supply system would lend itself to greater supply options for LNG and keep the US in a favorable competitive position in the future.
Delivering high thermal-content gas to end users would require each type of user to install equipment and instrumentation necessary to blend down the rich natural gas with air or nitrogen to customize the gas quality for its own needs.
On the other hand, increased supply optionality would most likely lead to lower supply costs to end users—potentially creating savings in the long run—but shift up-front investment to the end users.
The two approaches have both advantages and disadvantages. There are both costs and savings associated with each method, and the current gas distribution system would need to be modified to convert to either methodology.
A shift to either type of supply scenario would most likely require a planned phase-in date years from now in order for equipment manufacturers and end users to standardize designs and install equipment.
Since many of the LNG projects are in the planning phase currently, it is imperative that these specifications be established for the orderly design and construction of LNG facilities, both here and abroad.
The natural gas industry has never established hydrocarbon content specifications on a uniform basis across the US. Implementing hydrocarbon gas-quality specifications in a well developed and functional gas supply and marketing industry will require much thought and compromise by all parties in the industry in order to benefit the US consumers.
Hence, faced with the demands by suppliers and end users, the NGC gas- quality teams and the FERC will have to balance these demands and establish specification protocols that will have far-reaching effects on the US natural gas supply.
The goal is to establish specification levels that will permit the maximum supply of natural gas to be available to end users while ensuring the safe use and suitable quality of natural gas for all parties concerned.
The author
Alfred Fatica is a director of NGL assets for BP America, Houston. He has 24 years of experience in refinery process research, refinery operations, economic analysis, crude oil supply planning and logistics, NGL marketing, and gas gathering and processing. He has worked for Texaco Inc. and Vastar Resources Inc. prior to joining BP in 2000. Fatica holds a BS in chemical engineering from the University of Michigan and is a member of the GPA Legal & Regulatory Affairs committee and is secretary and treasurer of the Houston Chapter of the GPA.
