LTX — Reapplication of Proven Technology
This paper resurrects a proven technology which saw its zenith in the 1960s, but which, due to changes in gas contract terms, became less common. It is now virtually unknown to engineers new to the field. This is unfortunate because circumstances have changed again, allowing this field-proven process to improve economics in some areas of gas production.
Engineers familiar with modern gas plant operation, particularly cryogenic plants, are acutely aware of the need for gas dehydration. This concern for hydrate prevention carries over into low temperature separation in the field. Although thousands of low temperature wellhead gas processing units have been placed in operation, processing units have been placed in operation, most gas engineers have not experienced the sound of intentionally formed hydrates as they ricochet around the LTX spinner chamber, nor have they seen performance data which demonstrate the significant performance data which demonstrate the significant cost effectiveness of LTX processing in the field.
The purpose of this paper is to present such data and to reintroduce this proven technology to a new generation of gas engineers. The theory and practical application of LTX processing will be practical application of LTX processing will be explained, along with the conjunctive effects of condensate stabilization and overhead vapor recompression. In summary, the paper will demonstrate that the road to increased profits is not paved solely by new technology.
Low temperature separation of natural gas liquids is as old as the gas processing industry itself. Over forty years ago, the Joule Thompson cooling effect of expanding gas across a choke was utilized to "auto-refrigerate" gas and to condense hydrocarbon liquid. Soon thereafter, National Tank Company (now, NATCO) introduced the LTX (Low Temperature Extraction) unit. This design purposely forms hydrates as part of the process, purposely forms hydrates as part of the process, whereas the conventional approach is to inhibit hydrate formation by injecting alcohol or glycol. As a result of the LTX process, the water and hydrocarbon dewpoints of natural gas are suppressed while recovering enhanced value condensate.
During the 1950's and 60's, over 1500 LTX wellhead units were placed into operation. In the late 60's and early 70's, these were coupled with condensate stabilizers, gas recompressors and vapor recovery units as conservation became the watchword. Soon thereafter, field recovery of natural gas liquids was replaced by processing in large downstream facilities. As pipeline companies became both purchasers and sellers of gas, they also became gas processors, and the economics of scale heavily favored comingling of gas sources to supply downstream processing. As a result, some companies began to specialize as gas plant operators. plant operators
The table has now turned, as two new factors change the market. First, natural gas liquid prices have fallen even as gas prices have edged prices have fallen even as gas prices have edged upward. The most valuable liquids are those which can be sold as crude oil or condensate. Even with depressed crude oil prices, condensate still commands more as a liquid than does its gas Btu equivalent; thus the incentive is to maximize condensate recovery. Furthermore, where rate of production is limited by gas sales contract, production is limited by gas sales contract, increasing liquid recovery makes room for more flow at the wellhead. The bottom line: more total revenue from wellhead low temperature extraction.