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The single-well chemical tracer (SWCT) test is an in-situ method for measuring fluid saturations in reservoirs. Most often, residual oil saturation (Sor) is measured; less frequently, connate water saturation (Swc) is the objective. Either saturation is measured where one phase effectively is stationary in the pore space (i.e., is at residual saturation) and the other phase can flow to the wellbore. Recently, the SWCT method has been extended to measure oil/water fractional flow at measured fluid saturations in situations in which both oil and water phases are mobile. The SWCT test is used primarily to quantify the target oil saturation before initiating improved oil recovery (IOR) operations, to measure the effectiveness of IOR agents in a single well pilot and to assess a field for bypassed oil targets. Secondarily, it is used to measure Swc accurately for better evaluation of original oil in place (OOIP). Fractional flow measurement provides realistic input for simulator models used to calculate expected waterflood performance. This chapter familiarizes the reader with the SWCT method, and offers guidelines for selecting suitable test wells and for planning and executing the field operations on the target well. Test interpretation is also discussed and illustrated with typical examples. The first SWCT test for Sor was run in the East Texas Field in 1968. Patent rights were issued in 1971. Since then, numerous oil companies have used the SWCT method.
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
A new in-situ procedure has been developed for measuring the residual gas saturation in watered-out zones of gas reservoirs. Gas-free formation brine is injected into a well penetrating the water-invaded zone to dissolve the penetrating the water-invaded zone to dissolve the residual gas from a region around the wellbore. The brine is then produced from the well. The volume of brine containing no dissolved gas is then determined by sampling the brine and analyzing for gas content. The original residual gas saturation can be calculated from these data.
The procedure has been confirmed by computer simulation and by laboratory tests on a long glass-bead pack. Two full-scale field tests have also been conducted; the interpretation of one of these tests is discussed in detail.
Water invasion is a significant drive mechanism in many natural gas reservoirs. The residual gas saturation left behind the water front is an important parameter required for accurate prediction of recoverable reserves, frontal advance velocity, and optimal production scheduling.
The traditional method for determining residual gas saturation is laboratory waterflooding of core plugs. With that method there is usually some uncertainty as to whether the core samples used are truly representative of the entire reservoir zone, or whether the displacement process is representative of that within the reservoir. Pressure coring has been used successfully to measure residual gas saturations, but it is a very expensive procedure which requires that a new well be drilled in an already-depleted portion of the reservoir. In theory, neutron logging methods could be used in existing water-invaded wells to measure the residual saturation. However, cased-hole logging tools sample a relatively small volume of reservoir, and local wellbore effects might produce results that are not typical of general produce results that are not typical of general reservoir conditions.
In the new method described here, a relatively large volume of reservoir around a well is observed. Brine containing no gas is injected into the well, dissolving the residual gas within a circular zone around the wellbore. Brine is then produced from the well, and the concentration of dissolved gas in the brine is measured during production. The original residual gas saturation in the zone can be calculated from the amount of brine produced before dissolved gas appears.
This paper describes the theory of the method, results from laboratory and field tests, and results from test simulations using mathematical models. The test accuracy and range of applicability determined from field experience are reported.
In certain situations, it is necessary to obtain a reliable measurement for connate water saturation (Swc) in an oil reservoir. The single well chemical tracer (SWCT) method has been used successfully for this purpose. The SWCT method has been used successfully for this purpose in six reservoirs. The SWCT test for Swc usually is carried out on wells that are essentially 100% oil producers. The procedure is analogous to the SWCT method for Sor, taking into account that oil is the mobile phase and water is stationary in the pore space.
The paper addresses problems related to application of a single-well surfactant test (SWST) for a North Sea oil reservoir. Waterflooding an oil production well prior to a SWST by injection of seawater will change the oil properties in the wellbore region. Injection of unsaturated water with respect to hydrocarbon gas in a formation containing a volatile oil with GOR in the range of 100-1000, will cause stripping of the oil.
The injection of cold seawater may alter the temperature in the injection zone and this effect combined with the variation of GOR with distance from the wellbore will result in gradients both in temperature and oil properties. The effect of these variations will influence the phase behavior and the performance of the surfactants as well as the tracers.
Static multiple water-oil contact experiments at reservoir conditions have been performed. These experiments were compared to dynamic core displacements in order to quantify the stripping of the oil phase by water. The tracer partitioning and hydrolysis were measured both in static experiments and reservoir cores. The effect of GOR on tracer partitioning was also investigated.
The results reveals that the GOR of the specific oil used was reduced from 110 to 10 and the formation volume factor (BO) from 1.34 to 1.05. The decreasing gas content in the oil changes the phase behavior of the optimized surfactant system towards a lower phase microemulsion.
The surfactant system had to be re-optimized against the stripped oil both by static phase behavior and dynamic core displacements. The effect of stripping leads to a significant change in surfactant and tracer phase behavior. In addition. due to the changes in Bo, the saturation values as determined by the tracer test yields low waterflood residual oil saturations compared to expected results of a large scale waterflood.
In earlier papers, development of a surfactant flooding process for a North Sea oil reservoir have been reported. Preliminary studies have shown that the surfactant system have a potential for improved oil recovery under the restrictions of the high reservoir temperature, moderate high salinity and the logistics of offshore oil production.
The single-well tracer test (SWTT) developed by Deans offers the possibility of measuring the waterflood residual oil saturation of a reservoir which again can be compared to results from core analysis and conventional logging methods. The concept of SWTT have been discussed in several papers, and will not be extensively covered in this paper. The single-well surfactant test involves measurement of the residual oil saturation by tracers (SWTT) prior and after a surfactant injection.
There are however several problems associated with performing a SWST under North Sea reservoir conditions.
Sothcott, J. (Challenger Division for Seafloor Processes, National Oceanography Centre, Southampton, UK) | Khazanehdari, J. (Reservoir Services, WesternGeco, Gatwick, UK) | Best, A.I. (Challenger Division for Seafloor Processes, National Oceanography Centre, Southampton, UK)
In the past, many dry boreholes have been drilled on the basis of false hydrocarbon indicators. In some cases, these have been thought to be related to ‘fizz water’ effects. Unfortunately, the identification of these effects is difficult, mostly due to the lack of reliable seismic methodologies for gas quantification and the subsequent misinterpretation of seismic data.
Understanding the acoustic response of partially gas saturated rock under different pressure and temperature conditions may help to develop better seismic methodologies and help in quantitative hydrocarbon detection and characterization, hence avoiding drilling costly dry wells.
New ultrasonic measurements on a partially gas saturated sandstone show that dissolved gas significantly affects the compressional wave velocity and attenuation of rocks only at low pore fluid pressures. At high pore pressure (above the bubble point) gas bubbles are dissolved in the water and the mixture behaves like a liquid with lower density.