A New Method to Determine Critical Gas Saturation and Relative Permeability During Depressurization in the Near-wellbore Region
Patrick Egermann and Olga Vizika
ABSTRACT
Depressurization of a virgin or waterflooded oil reservoir results in the appearance of a solution gas saturation. Above a saturation threshold, this gas becomes mobile and can be produced. Knowledge of the critical gas saturation (Sgc) and the subsequent relative permeabilities (kr) in the far field and the near-wellbore region has a tremendous impact on gas and oil production forecasts.
Our paper presents a new methodology to obtain representative kr and Sgc values for a depressurization process. Specific experiments are presented in which under-saturated oil was injected upstream at a fixed rate whereas downstream the pressure was controlled in order to reproduce a drawdown. Evolution of pressure was recorded and in-situ gas saturations measured by CT-scanning. Two initial conditions were considered: fully oil saturated and at irreducible water saturation. Influence of the drawdown scheme was also explored. Transient evolution of the gas saturation profile in the core is clearly shown. kr values are deduced from history matching. They are finally compared to the kr derived from gas injection experiments.
It is demonstrated that gas/oil kr shape is strongly affected by the way the gas phase forms and its distribution in the porous medium. For solution gas drive, oil relative permeability is higher and gas relative permeability smaller than for gas injection.
Concerning critical gas saturation, the experiments show two types of gas mobility depending on the operational conditions: mobility threshold attained from connection of bubbles or from mobilization of a population of separate bubbles. For the first type, Sgc can be linked to the values obtained through static experiments at a fixed depletion rate.
Marc Fleury, Gabriel Ringot, and Philippe Poulain
ABSTRACT
We present a new experimental set-up designed to measure, in addition to the standard drainage and forced imbibition (negative) capillary pressure curves, the positive imbibition capillary pressure curves for oil-water systems. Hence, the full cycle of capillary pressure curves can now be determined using the centrifuge technique. The principle of the method is to keep the fluid produced during drainage in contact with the sample while decreasing the speed of rotation, to allow that fluid to imbibe spontaneously step-by-step (positive imbibition). During the experiment, an oil-water interface is constantly detected and maintained at the outlet face of the sample using an external (non-rotating) pump connected to the core holder through a rotating fitting. The saturation of the sample is deduced from the volume pumped in and out of the core holder.
Two tests are described to demonstrate the potential of the new device: leak rates and stability of the level position, accuracy of production measurements using a feed-back controller. A drainage-imbibition experiment performed on a sandstone plug is also shown. Average saturation data obtained during the positive imbibition cycle are interpreted using existing software in a way similar to drainage. Although technologically challenging, our device is simple to operate and has several practical advantages, two among them being: (1) samples of length up to 8 cm can be analyzed and therefore low speed/large radius centrifuges (200-3000 rpm) are appropriate in most cases and (2) the sample is not removed from the core holder during any capillary pressure cycle (from first to second drainage).
Development of In-Situ Measurements to Determine Reservoir Condition Critical Gas Saturations During Depressurization
Peter Naylor, David Mogford, and Robert Smith
ABSTRACT
This paper describes the development of experimental methods to determine critical gas saturations and relative permeabilities relevant to the depressurization of volatile oils. A series of reservoir condition coreflood experiments at pressures up to 415 bara and 123°C is described. The experiments were conducted with aged core and fluids and comprised a waterflood followed by depressurization at different rates. A key part of the laboratory data was the measurement of extensive three-phase in-situ saturations. These measurements were conducted at full reservoir conditions by adding discrete gamma-emitting radioactive tracers to the brine and oil phases.
The experiments were complicated by the following features: high CO2 content of the oil; radioactive tracer adsorption on the rock; and ultra-low flow rates. Successful solutions have been implemented.
The oil contained up to 22 mole% CO2 and compatibility trials were conducted with gamma-emitting radioactive tracers. The oil phase tracer was ferrocene (C10H10Fe) containing iron-59 (Fe59), and the initial brine phase tracer was potassium cobalticyanide (K3Co[CN]6) containing cobalt-58 (Co58). The C10H10Fe was demonstrated to be compatible with the oil, but the initial brine phase tracer was replaced with cesium chloride (CsCl) containing cesium-137 (Cs137).
This Cs137 brine phase tracer adsorbed on the core and the magnitude of the adsorption was a function of the experimental conditions. It was necessary to calibrate the tracers at reservoir conditions and this required the development of a new flooding protocol and the measurement of in-situ porosity using a gamma-attenuation technique.
In order to investigate the influence of depressurization rate on critical gas saturation, a range of rates was investigated. The longest duration experiment involved depressurization over a period of 141 days with an average flow rate of just 0.3 mL day-1. This low rate required extremely high standards of leak integrity. It was necessary to develop a new core sleeving arrangement that combined low gamma-attenuation with ultra-high leak tightness. The high CO2 content did not favor the use of elastomer or epoxy resin coated cores during depressurization, and a core sleeve involving polytetrafluoroethylene (PTFE) and aluminum was developed. Produced fluids were collected at reservoir conditions in a visual cell and the very low flow rates could not overcome the static friction of the piston in the visual cell. This problem was solved with the novel use of a fluorinated hydrocarbon which acted as a ‘liquid-piston’.
The development of new experimental procedures has enabled the measurement of three-phase, in-situ saturations during the depressurization of volatile oils. This data has been used to determine critical gas saturations and derive relative permeabilities that can be used in reservoir simulations.
A Practical Approach to Obtain Primary Drainage Capillary Pressure Curves from NMR Core and Log Data
Yakov Volokitin, Wim J. Looyestijn, Walter F.J. Slijkerman, and Jan P. Hofman
ABSTRACT
The purpose of this study was to find a way of constructing primary drainage capillary pressure (Pc) curves from NMR relaxation time T2 distributions with an accuracy which can satisfy most practical applications. The application that initiated the study was to predict initial virgin reservoir saturations from NMR log data. However, an equally important application proved to be a fast, cheap and non-destructive estimation of capillary pressure curves on core samples.
The proposed method of relating NMR distributions to primary drainage capillary pressure curves can be seen as a development that enables better and faster integration of core capillary pressure data and log interpretation. Namely, once a calibration of the T2–Pc conversion against a few core samples has been established, the capillary pressure information can easily be obtained continuously across the whole reservoir section logged with an NMR instrument. The advantage compared to other methods comes from the fact that the NMR T2 distribution is more directly related to the pore structure, and thus to capillary pressure information.
A serious shortcoming of all other conversion methods proposed so far is that they could be applied to NMR measurements only on fully water-bearing rocks. The presence of hydrocarbons strongly dictates the shape of the T2 distributions and thus invalidates the predicted capillary pressure curve. In this paper we present an approach which greatly reduces this problem. The presented technique can be applied to NMR T2 distributions obtained on sandstone rocks at any water saturation.
Xina Xie and Norman R. Morrow
ABSTRACT
Spontaneous imbibition is of special importance to oil recovery from fractured reservoirs. Laboratory measurements of volume of liquid imbibed versus time are often used in the prediction of oil recovery. Imbibition measurements also provide a useful approach to the complex problem of characterizing the wetting properties of porous media. Correlation of a large body of data for imbibition of brine into porous media initially saturated with refined oil was achieved through a semi-empirical scaling group which includes permeability, porosity, interfacial tension, oil and brine viscosity, and the size, shape and boundary conditions of the sample.
The objective of the present study was to test this correlation for samples of different geometry for spontaneous imbibition under weakly water-wet conditions established by adsorption from crude oil with initial water saturation ranging from 14% to 31%. After establishing initial water saturations, the wettability of thirty-two core samples was changed to weakly water-wet by aging in an asphaltic crude oil at elevated temperature. Initial water saturation had a dominant effect on rate of oil recovery. Times for imbibition decreased by about 2 to 4 orders of magnitude with decrease in initial water saturation. Results for cores with the same initial water saturation but of different size and shape (cylindrical, annular, and rectangular) and boundary conditions (given by sealing off part of the rock surface with epoxy resin) were closely correlated. The presence of epoxy resin during aging in crude oil enhanced the decrease in water-wetness attained for cores and crude oil alone. The contribution to oil recovery by gravity segregation at very weakly water-wet conditions can be significant for sufficiently small capillary forces.