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.

The Caballos formation is thick laminated sandstone with less than 10% of total clays and permeability ranging from 20 mD to as high as one Darcy. However, the production from this formation is often limited due to the low critical flow rate in the matrix (less than 1 mL/min) and associated fines migration as shown in several tests. Historically matrix acidizing and hydraulic fracturing treatments in this formation have only been partially successful due to destabilization of the clays and inadequate fines stabilization, along with the incompatibility of the crude oil with many conventional acid systems. In order to overcome the limitations associated with the use of conventional acid systems an extensive laboratory study was conducted using a non-acid based stimulation fluid. The base fluid selected was a newly developed chelating agent that is very tolerant to high concentrations of both carbonate and aluminosilicates, and iron and zeolite bearing minerals. By including acid salts in the fluid it proved possible to develop a fluid system with the equivalent dissolving power of a conventional 6:1.5 (HCl: HF) mud acid, even at temperatures as low as 180°F. Testing also showed that the fluid was capable of controlling fines migration and that a scale inhibitor could be included in the formulation, while the fluid system exhibited excellent compatibility with the formation fluids throughout the field. The newly developed non-acid fluid system provides some unique advantages for matrix acidizing applications and in particular for stimulating the Caballos formation 1) Minimizes the risk of secondary and tertiary precipitation due to the nature of the chelating agent 2) A single treating fluid instead of the multiple fluids/stages used in a conventional treatment 3) Greatly reduced sludging and emulsion tendencies compared to conventional acid systems (without the addition of surfactants or demulsifiers) and much lower corrosion rates 4) The ability to stabilize fines present in the matrix 5) Allows for a scale inhibitor to be included in the treating fluid 6) Reduces the logistics and HSE risks during the execution of the treatment. This paper reviews the laboratory testing including an extensive core flow testing performed to develop a new nonacid treating fluid for both matrix acidizing and dual stimulation applications in the Caballos formation and its implementation in the field, illustrated with case studies and production data. Introduction In the Orito field in the south of Colombia the most prolific reservoir is the Caballos Formation, 250-ft thick interbedded fluvial/deltaic and marginal marine sands that originally contained more than 700 million bbl of oil in place. Due to distinct changes in the vertical lithology the reservoir is divided into four distinct flow units or layers A, B, C and D in ascending order shown in Fig 1. Furthermore, the production of the wells along with a petrographic and petrophysical study has shown that there are two distinct zones of markedly different reservoir quality. The lower zone - layer A, is a much better quality reservoir than the upper zone. Layer A is a well sorted sand with kaolinite present in the pore spaces. The porosity and klinkenberg permeability varies from 12 to 14 % and from 100 to 300 mD, respectively. While, the upper zone - layers B, C and D - is a much poorer quality reservoir. A single facies of poorly sorted and loosely packed quartz with kaolinite in the inter-granular spaces. The porosity in this upper zone is predominantly intergranular ranging from 11 to 12 % and the klinkenberg permeability from 5 to 150 mD, (Fig. 2). In addition, due to the presence of a number of major and minor faults the reservoir is compartmentalized. The complexity of the stratigraphy reflected in the marked changes in the quality of the reservoir and the properties of the oil in place, across the field. Due to the fractional composition of the oil, the properties of the crude oil also vary between the different layers, independently of the location of the wells on the structure.

The Orito field in the south of Colombia was initially put on production in 1969 and has produced continuously since then. The most prolific reservoir, is the Caballos Formation, a thick (250 ft avg.) laminated sandstone located at a depth of 6100 to 7500 ft that has produced (30 to 45 °API crude) for over 35 years, with production peaking at 66,000 BOPD. The permeability varies from 20 to 200 mD with streaks exceeding one Darcy. At different times in the past, attempts were made to hydraulically fracture one or more of the sands, using a variety of different (water- and oil-based) fluids. However, many of the wells indicated positive skin factors following the fracture treatments, irrespective of the fluid system used. In at least one case, a well stopped producing after being treated. A core study revealed that despite the relatively low clay content in the formation the critical velocity was less than one cc/min. Moreover, the retained matrix permeability after performing a static leakoff test (500-psi differential for 30 minutes) was less than 5%, regardless of the fluid used. From this testing it was concluded that the reduction in the permeability was due to the mechanical plugging of the kaolinite or disrupted mica in the pore throats. This reduction in the matrix permeability creating a very high fracture face skin that would account for the higher skin factors following fracture treatments. To eliminate the fracture face skin created during the fracture treatment a new treatment incorporating a pre-pad of acid viscosified with a solids free visco-elastic surfactant was developed. By incorporating this stage into the fracturing treatments, the retained matrix permeability was increased to +/- 30%, resulting in a negligible fracture face skin. The productivity of fracturing treatments performed using this technique resulted in negative skin factors and production ratios that exceeded expectations. Introduction The Caballos formation and reservoir is an asymmetric anticline with an orientation of N-NE to S-SW with two domes separated by a fault as shown in Fig 1. The field has an active aquifer that has maintained the reservoir pressure at around 1,500 psi during the last 20 years. The main production mechanisms being water and solution gas drive. Figure 1: Schematic of Orito Anticline The 250 ft thick reservoir is a massive sand with interbedded shale and carbonates, deposited in a marine environment. The variation in the vertical lithology subdivides the reservoir into four distinct flow units or layers A, B, C and D in ascending order Fig. 2.

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.

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