TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractNatural gas hydrate formation is a costly and challenging problem for the oil and gas industry. In recent years, two new families of chemical additives have been commercially developed to prevent hydrate plugging problems in production lines. This approach is commonly known as low-dose inhibition, and the two families are kinetic inhibitors and antiagglomerants. Evolution of these new products is proceeding at a rapid pace, in order to meet goals of covering a greater range of operating conditions and finding an economically and environmentally attractive alternative to thermodynamic inhibition. Successful deployment of low-dose inhibitors depends on an appropriate selection of inhibitors and a complete understanding of the system. Based on a synthesis of available literature on application of low-dose inhibitors to hydrocarbon processing equipment and handling facilities, this paper describes a methodology for designing a deployment strategy. This guide provides a systematic approach to aid production engineers in deploying low-dose inhibitors in existing facilities and new developments. An easy-to-follow flow chart is given. The information provided in this article was compiled from published data, and experience provided by several companies in the oil and gas industry.

Unrestricted fluid flow of oil and gas streams is crucial to the petroleum industry. Unless preventative action is taken, gas hydrate plugs form under the high pressure, low temperature conditions inherent to offshore production. The oil and gas industry is facing increasing costs in inhibiting gas hydrate formation due to the development of offshore gas reservoirs. Recent international estimates of the cost of the conventional inhibitor, methanol, alone are in excess of $150 million/year. Gas hydrates are likely to form in subsea flowlines unless the water is removed down to the lowest dew point encountered, highly effective insulation is in place, or inhibitors are used. Since complete stripping of water from condensates and/or natural gas is prohibitively expensive, and effective insulation is beyond current economic limits, the most effective solution includes the use of hydrate inhibitors. This paper describes the state of the art of hydrate prevention, detailing hydrate structure, conditions and mechanisms of formation, and developing approaches - from the conventional to the cutting-edge - to hydrate inhibition. Its focus on low-dosage inhibitors, including a review of kinetic inhibitors and anti-agglomerants form, function, development, selection, modeling and applications, highlights gaps in current knowledge. Finally, a research agenda addressing both mitigation and deployment strategies is proposed. Introduction Since the 1930's when Hammerschmidt1 determined that the material plugging pipelines was gas hydrates, interest in gas hydrates has continued to increase. Hammerschmidt's discovery led to the regulation of the water content in natural gas pipelines2. In 1934, Hammerschmidt published a correlation summary of over one hundred hydrate formation data points. Unrestricted and problem-free flow of petroleum products during extraction, processing, and transportation is essential to the oil and gas industry. Whether heavy hydrocarbons such as crude oil, or low molecular weight hydrocarbons such as natural gas and natural gas liquids are the target end product, natural gas is almost always present in the fluid extracted during production. To varying degrees (most often low early in the life of a reservoir and high toward the end), the extracted oil and gas mixture also contains water. In the presence of water, and under a fixed range of pressure and temperature conditions, specific to each hydrocarbon mixture, hydrates of the light gases can form. Gas hydrates, which have a crystalline structure analogous to that of ice, form solid plugs and block the flow. Clearly, inhibition of hydrate formation is of utmost interest to industry. Hydrate formation is a substantial problem in deepwater production and underwater pipelines, which transport condensed phase hydrocarbons such as gas condensate or crude oil. In these situations, once plugs have formed, there are limited possibilities for removal2. Since the 1970's, the oil and gas industry has faced increasing costs associated with inhibition of gas hydrate formation, due to the development of offshore gas reservoirs. Recent international estimates of the cost of the conventional inhibitor, methanol, alone, are in excess of $150 million/year3. Gas hydrates are likely to form in subsea flowlines unless the water is removed down to the lowest dew point encountered, highly effective insulation is in place, or inhibitors are used. The first option is difficult when supersaturated condensates exist in the flowline even after the gas phase is stripped to saturation levels. Stripping condensate completely of water is prohibitively expensive and effective insulation is beyond current economic limits. Therefore, the most effective solution appears to be the use of inhibitors. Generically, there are two kinds of hydrate inhibitors: thermodynamic inhibitors, and the more recently identified low-dosage inhibitors. Thermodynamic inhibitors have been in use for a long time, and continue to be the industry standard. This kind of inhibitor works as an antifreeze by involving the water in a thermodynamically favourable relationship, so that it is not available for reaction with the gas.

Through the application of horizontal well technology in a giant shallow, un-consolidated oil-rim reservoir, Shell Gabon significantly increased field output and recovery at reduced cost, while minimising the environmental impact of field development. Systematic well design changes were implemented particularly in completion hardware and mud- and completion fluids and latest coiled tubing-technology was introduced in efforts to improve completion efficiency. The paper summarises the observations and practices resulting in the improved completion technology and gives examples of the production logging tool selection and interpretation techniques developed. An outline is given of techniques which require further development to control over the inflow distribution in un-consolidated oil-rim reservoirs such that the recovery of the field can be achieved with the minimum number of wells. Introduction The Rabi field, discovered in 1985 with a current estimated STOIIP of some 1.5 109 stb and key characteristics as given in Table 1, was initially planned to be developed with vertical wells. These wells, however, experienced a significant decline, which is typical for an oil-rim situation where bean-back is the primary method used to prevent excessive gas production and limited oil recovery. Where possible, gassed-out zones were shut-off with production continuing from lower completion intervals but oil recovery per well remained low. Measures to maximise the distance to the gas-oil and oil-water contacts in the vertical wells included the successful use of sand consolidation allowing for limited completion heights as opposed to the use of gravel-packs with a normal completion height of some 10–20m in the (initially) 46m oil column, Ref. 1. Nevertheless, with the limited recovery of vertical wells (which have an average ultimate recovery of some 4.5 106 bbl per well), drainage of the remaining reserves would require some 180 additional (vertical and deviated) wells. Production history with the first horizontal wells drilled in Rabi in the period 1990-91, showed that these wells could be drilled successfully in the shallow un-consolidated reservoir sands. These wells also, although imperfect as far as completion efficiency is concerned, proved to have a significantly higher oil recovery. P. 279^