Testing of gas condensate reservoirs requires careful coordination of all parameters in the analytical process. Therefore, the sampling procedure, the laboratory analysis of the collected samples, the design of the testing equipment, and the design and analysis of the test itself are all critical to the accuracy of the analysis. This paper will outline the methodology and procedures used in testing gas condensate reservoirs. Obtaining a representative formation fluid sample that may be used for compositional and pressure-volume-temperature (PVT) analysis is crucial in testing gas condensate reservoirs. In most cases, this means maintaining a monophasic sample as close as possible to actual reservoir conditions. New sampling technologies have been introduced that improve the quality of the initial sample and can maintain the sample integrity. Additionally, new downhole sensor technologies show promise of improving sample contamination estimates and making in-situ fluid property measurements. The various sampling techniques are discussed, and comparisons of processes that include wireline formation testing and bottomhole sampling, isokinetic sampling used in drillstem and production testing, and surface sampling are made. Laboratory testing procedures including sample quality validation, error propagation, and sample contamination are also discussed. The flow of gas condensate in a reservoir is a complicated mathematical problem involving phase changes, condensate loss into the small pores of the rock, multi-phase-flow of the wet gas oil and possibly water, phase redistribution in and around the wellbore, and finally, liquid vaporization back into the condensate gas. A well test can provide identification of the absolute reservoir and relative permeabilities, the source of declining gas permeability, near wellbore damage, and the reservoir pressure. It can also distinguish the extent of the liquid-condensate bank that forms a composite reservoir, as well as the location of the nearby boundaries. The analysis procedure and techniques will be illustrated through presentation of two field cases. In the first case, the flowing pressure is above the dewpoint pressure. Thus, the fluid inside the reservoir is a single-phase gas, and liquid dropout causes phase segregation in the wellbore. In the second case, the well is producing below the dewpoint pressure while the original reservoir pressure is above the dewpoint pressure. This caused the well test to resemble that of a composite reservoir with earlier phase-segregation effects. Introduction PVT analysis is the study of hydrocarbons and the effects of pressure and temperature on the volume of hydrocarbons. As hydrocarbon flows inside the reservoir wellbore and into production facilities, it undergoes several changes. The changes that take place in the physical qualities not only relate to temperature, pressure and volume of the fluid but also can concern phase changes. A hydrocarbon is a multi-system component that has a complex phase behavior. This phase behavior will be dictated by its composition. Based on this composition, a hydrocarbon may be classified as black oil, volatile oil, retrograde condensate gas, wet gas, or even dry gas.1 In this paper, attention will be directed toward gas condensate reservoirs.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe giant Statoil-operated North Sea oil field Statfjord is currently far down its production decline curve. During 23 years of production 60% of the STOOIP has been recovered, and the remaining reserves are characterized by complex distributions of oil, water and gas.In order to obtain a cost-effective production of the remaining oil, an aggressive drilling and intervention programme is necessary. Future developments might also include a pressure blow down phase of the reservoir. Then large volumes of water will be produced to surface. So far the Statfjord Field has exhibited a fairly mild scale potential. Sulphate scale has been detected in several wells down hole, whereas carbonate scale when found is mainly above the down hole safety valve. Carbonate scale precipitation will be more severe in any future blow down phase with a lowering of the reservoir pressure. To improve carbonate scale prediction a "correct" down hole pH value is necessary. The prediction program will then be capable of performing a better tuning sequence and give more accurate predictions, refer references.Petrotech has developed a pH sensor system for downhole use. In 2002 Statfjord performed a field test of this system by running it in a well with a "single phase" fluid sampling chamber. The water sample captured down hole was used to get a lab measurement of the pH in the formation water at reservoir temperature and pressure. This sample was then flashed to standard conditions and a full water and gas analysis was performed. The results were used in the MultiScale software program to calculate a pH value. The results indicated good correspondence between the pH values obtained from the down hole sensor, the water sample and the pH value calculated with the scale prediction program.

The industry is focusing on cost reductions by saving on expensive rig time and on reducing the impact on the environment during well testing. Decisions regarding field development are increasingly taken based on the results of samples and data obtained by wireline formation tester/samplers (WFT/S) and not on data obtained by flow to surface during a drill stem test. The use of oil-based mud to increase the drilling rate is also becoming more common. These measures reduce the likelihood of obtaining quality fluid samples and increase the uncertainty in field development projects related to fluid data. A systematic approach to fluid sampling is presented which discusses the different aspects related to the quality of fluid data obtained depending on the sampling method, type of reservoir fluid system and formation properties. Recommendations for the decision making process are presented. Introduction Managing efficiently the production of natural gas and oil requires accurate data on the characteristics of the reservoir fluid and the phase and property changes as the fluid moves from the reservoir through the transport and production systems. The objective of reservoir fluid sampling is to collect a sample that is representative of the reservoir fluid. These samples are subsequently used for laboratory studies of the physical and chemical property change that occur during production. A non-representative sample will not reflect the true properties of the reservoir fluid and may result in costly errors in design and reservoir management regardless of the accuracy of the laboratory data. One should also keep in mind that the sample may only represent a single point in the reservoir where it was obtained and there is no assurance that the sample is representative of the fluid throughout the reservoir. Planning A successful sampling program in a well requires good planning, the right sampling equipment and the right sampling technique. Also the timing of the sampling operation is important. In most situations the best conditions for taking a representative sample of the reservoir fluid are during the exploration phase before the formation pressure has started to drop. Some specialised fluid studies may be identified later and the required samples taken successfully during the production phase. There will be differences in the challenge depending on whether the reservoir fluid is an oil, a near-critical fluid, a gas condensate or a dry gas. The well will normally be logged prior to the commencement of any reservoir fluid sampling. The logging will give information that is very useful in the planning of the sampling operation. It has become increasingly more common in offshore wells to take open hole samples by use of wireline formation testers in order to save on expensive rig time and to reduce the impact on the environment from standard drill stem testing. The selected sampling intervals will be based on logs. Intervals with good permeability and good hole quality increase the chances for a successful sampling run with a WFT. The height of the hydrocarbon column may indicate whether a compositional change with depth is likely to be encountered and whether it will be important to sample several intervals. One should try to take advantage of the bubble point gradient (typically 0.2–0.4 bar/m) in a situation were the fluid is close to saturation. The pressure gradient in the hydrocarbon column together with the reservoir conditions will identify the type of reservoir fluid, Figure 1. The degree of undersaturation may be evaluated by the use of correlations. Wire line fluid samples should and will in most situations be taken as a part of the well logging operation. These samples will usually not be truly representative due to the difficulties with well conditioning and an effective clean up. There may also be effects on the reservoir fluid from the decreased temperature in the vicinity of the well caused by the mud circulation. Each fluid system presents special challenges, for example a gas condensate can drop below the dew point pressure and high molecular waxes/resins may deposit from oils.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe giant Statoil-operated North Sea oil field Statfjord is currently far down its production decline curve. During 23 years of production 60% of the STOOIP has been recovered, and the remaining reserves are characterized by complex distributions of oil, water and gas.In order to obtain a cost-effective production of the remaining oil, an aggressive drilling and intervention programme is necessary. Future developments might also include a pressure blow down phase of the reservoir. Then large volumes of water will be produced to surface. So far the Statfjord Field has exhibited a fairly mild scale potential. Sulphate scale has been detected in several wells down hole, whereas carbonate scale when found is mainly above the down hole safety valve. Carbonate scale precipitation will be more severe in any future blow down phase with a lowering of the reservoir pressure. To improve carbonate scale prediction a "correct" down hole pH value is necessary. The prediction program will then be capable of performing a better tuning sequence and give more accurate predictions, refer references.Petrotech has developed a pH sensor system for downhole use. In 2002 Statfjord performed a field test of this system by running it in a well with a "single phase" fluid sampling chamber. The water sample captured down hole was used to get a lab measurement of the pH in the formation water at reservoir temperature and pressure. This sample was then flashed to standard conditions and a full water and gas analysis was performed. The results were used in the MultiScale software program to calculate a pH value. The results indicated good correspondence between the pH values obtained from the down hole sensor, the water sample and the pH value calculated with the scale prediction program.