Profitability of U.S. NGL Extraction

Abstract

Summary Natural gas liquids (NGL's) are a significant source of hydrocarbon production in the U.S. NGL's are extracted from produced natural gas, and their volume depends on the levels of oil and gas production. For NGL extraction to be economically viable, however, the sales price of the NGL product must exceed the cost of extraction. This paper reviews factors that affect NGL extraction economics and addresses the effects of petrochemical demand, imports of liquefied petroleum gas (LPG), and vapor-pressure limitations on motor gasoline. Introduction and History The processing business is a significant part of the U.S. hydrocarbon industry. NGL production from gas plants in 1987 was about 1.6x106 B/D [2.54X10.3M3/d], representing more than 15 % of domestic liquid production (crude oil, condensate, and NGL). The market value of NGL products was more than $6 billion in 1987 alone. The gas-processing industry has a long and storied history. The first gas-processing plant was constructed in 1903 in Sistersville, WV, to remove condensable hydrocarbons from a gas stream upstream of a 4-mile [6. 4km) pipeline. The plant's objective was to prevent "drips" from condensing in the line. The cooling medium was water and the heat exchanger an old boiler. The natural gasoline product was transported in wooden barrels to a nearby refinery for blending. Most of the early plants were compression-type. Casinghead gas was collected from oil wells and compressed and cooled. The condensed liquid was weathered, usually in an open tank, and sold as natural gasoline. Early problems included strong competition from refiners who manufactured a more stable gasoline product, market acceptance, and safety. The first absorption plant, built in 1913, used horizontal tanks as the absorber. Charcoal adsorption and refrigeration plants were also developed around this time. By 1920, natural gasoline production from gasprocessing plants was nearly 20,000 B/D [3x103 M3/d]. The gas-processing industry became increasingly important over the next 20 years. Specifications were developed for natural gasoline product. Installation of high-pressure gas transmission lines necessitated processing nonassociated gas. Ambient-temperature lean-oil plants became the most popular type of processing facility. Product stabilization and fractionation were developed and improved. By 1940, NGL production reached 150,000 B/D [23.8 × 103 m 3 /d]. During World War 11, several cycling plants were constructed to recover condensate from retrograde-gas-condensate reserhigh-quality feedstock for gasoline production needed for the war effort. After the war, the demand for natural gas increased dramatically. Gas production increased six-fold between 1940 and 1960. Markets for LPG-propanes and butaneswere developed. Deeper extraction levels were required to satisfy this new demand, and refrigerated lean-oil absorption plants became the industry standard. By 1960, NGL production in the U.S. had risen to nearly 900,000 B/D [143X103 M3/ dl-approximately 60% LPG and 40% natural gasoline. In the early 1960's, the country's rapidly growing demand for plastic products spawned the petrochemical era. The preferred feedstock for these early petrochemical plants was ethade. Existing plants were converted to ethane recovery, and new, lowtemperature, refrigerated lean-oil plants were constructed to extract ethane. Lean-oil plants operating at -40deg.F [-40deg. Cl were able to achieve ethane recovery levels of 50% and better. The 1970's brought the turboexpander process, which could achieve ethane recovery levels in excess of 80% at capital and operating costs considerably lower than the refrigerated lean-oil process. Turboexpander plants now dominate the industry. More than half of the 800 plants installed in the U.S. today use the turboexpander process. Current Issues The gas-processing industry faces many challenges today. Excess Capacity. Declining natural gas production has dramatically reduced gas-plant throughput. Estimated utilization (throughput/capacity) in 1986 was 55%. This adversely affects processing economics in two ways. First, fixed costs, such as operating and maintenance expenses, are allocated to fewer gallons of production, thus increasing unit processing costs. Second, third-party processors must compete more aggressively for gas, offering more favorable terms to the producers. P. 922^