Determining the pvt properties of a hydrocarbon reservoir fluid

The present invention relates to determining the PVT properties of a hydrocarbon reservoir fluid, where PVT is an acronym used to refer to pressure, volume and temperature. PVT properties are gas-oil ratio, API gravity, viscosity, saturation pressure, formation volume factor, molecular weight, density and oil compressibility.

In order to measure the PVT properties of a hydrocarbon reservoir fluid, a sample of the reservoir fluid is taken and analysed under reservoir pressure and temperature. A brief description of the way in which a PVT analysis is carried out is given in section 3 of the book Contributions in Petroleum Geology and Engineering, Volume 5, Properties of Oils and Natural Gases, K.S. Pederson et al, 1989. Such an analysis can be very accurate, however it takes a long time to be completed.

See also SPE paper 56850 : Neural Network Model for Estimating the PVT Properties of Middle East Crude Oil, Ridha B.C. Garbi et al. for a model for the prediction of PVT properties.

It is of great importance to know the PVT properties of the reservoir fluid as soon as possible, preferably directly after a well has been drilled. Because, then there is still a possibility to adjust the design of the production and surface equipment to take into account the actual PVT properties.

Applicant has found that there are empirical relations between the PVT properties and the pressure gradient (dp/dz) in the reservoir, wherein p is the fluid pressure in the reservoir and z the true vertical depth. Because the pressure gradient can be determined directly after completing drilling, the PVT properties can be obtained as early as possible.

Thereto the method of determining at least one of the in situ PVT properties of a hydrocarbon reservoir fluid that is present in a hydrocarbon-bearing formation layer traversed by a borehole according to the present invention comprises the steps of: <ul id="ul0001" list-style="none" compact="compact"><li>a) calculating along the hydrocarbon-bearing formation layer the pressure gradient; and</li><li>b) determining the in situ PVT property from the pressure gradient using an empirical relation that had been obtained by fitting a curve through previously obtained data points comprising the measured PVT property as a function of the pressure gradient.</li></ul>

The method will now be described by way of example in more detail with reference to the accompanying drawings, wherein <ul id="ul0002" list-style="none" compact="compact"><li>Figure 1 shows the gas-oil ratio in standard cubic feet per standard barrel on the y-axis as a function of the pressure gradient in psi per foot (at in situ pressure and temperature) on the x-axis;</li><li>Figure 2 shows the API gravity in °API on the y-axis as a function of the pressure gradient in psi per foot (at in situ pressure and temperature) on the x-axis;</li><li>Figure 3 shows the viscosity in centipoise (at in situ pressure and temperature) on the y-axis as a function of the pressure gradient in psi per foot (at in situ pressure and temperature) on the x-axis;</li><li>Figure 4 shows the saturation pressure in psi absolute on the y-axis as a function of the pressure gradient psi per foot (at in situ pressure and temperature) on the x-axis;</li><li>Figure 5 shows the formation volume factor, oil on the y-axis as a function of the pressure gradient in psi per foot (at in situ pressure and temperature) on the x-axis; and</li><li>Figure 6 shows the molecular weight on the y-axis as a function of the pressure gradient psi per foot (at in situ pressure and temperature) on the x-axis.</li></ul>

With reference to the Figures, we will now discuss the method of determining at least one of the in situ PVT properties according to the present invention in reverse order, wherein we start with discussing how the empirical relation is obtained.

The curves shown in Figures 1-6 show the empirical relation, line i1, that fits the data points i2, i3 and i4, where i is the number of the Figure (i=1-6) obtained from samples taken from reservoirs in the same geological area. For the sake of clarity not all data points have been referred to by a reference numeral.

A data point was obtained as follows. At first a well was drilled to the formation layer containing a hydrocarbon reservoir fluid. Then a tool was lowered to the first of a set of locations in that formation layer by means of for example a wireline. The tool comprises a central conduit having an inlet and being provided with a pressure sensor, and a fluid receptacle having an inlet opening into the central conduit. At the location an exclusive fluid communication was made between the formation and the inlet of the central conduit by extending into the formation a probe having an outlet that is in direct fluid communication with the inlet of the central conduit. Then formation fluid was allowed to enter into the fluid receptacle and the pressure build-up was measured. The required fluid pressure is the pressure at the end of the pressure build-up for that location.

Then the tool was moved to the next location where the pressure-build up was again measured to obtain the fluid pressure for that location, and so on until all the fluid pressures at all locations had been determined. With this the pressure gradient was determined.

Then a sample of the hydrocarbon reservoir fluid was taken, and the PVT properties of the sample were measured in a laboratory under reservoir conditions. And the measurements gave a data point in Figures 1-6.

To get all data points these data were collected and analysed for more wells in the same geological area.

Then for each PVT property a curve was fitted through the data, and surprisingly, the data could be fitted with a considerable accuracy, with a goodness of fit R² of greater than 0.9, wherein<maths id="math0001" num=""><img file="EP1352154B1_D0001.tif" /></maths> wherein n is the number of data points, (x₁,...,x_n) is the set of pressure gradients, x is the mean pressure gradient, (y₁,...,y_n) is the set of measurements of the PVT property and y is the mean PVT property. R² is the squared value of the correlation coefficient.

The below Table gives the results of the curve fitting. <tables id="tabl0001" num="0001"><table frame="all"><tgroup cols="3" colsep="1" rowsep="1"><colspec colnum="1" colname="col1" colwidth="52.50mm" /><colspec colnum="2" colname="col2" colwidth="52.50mm" /><colspec colnum="3" colname="col3" colwidth="52.50mm" /><thead valign="top"><row><entry namest="col1" nameend="col1" align="left">PVT property</entry><entry namest="col2" nameend="col2" align="center">Curve</entry><entry namest="col3" nameend="col3" align="center">R²</entry></row></thead><tbody valign="top"><row><entry namest="col1" nameend="col1" align="left">Gas oil ratio</entry><entry namest="col2" nameend="col2" align="left">(8.6)(dp/dz)^-4·2</entry><entry namest="col3" nameend="col3" align="char" char=".">0.98</entry></row><row><entry namest="col1" nameend="col1" align="left">API gravity</entry><entry namest="col2" nameend="col2" align="left">65-(117)(dp/dz)</entry><entry namest="col3" nameend="col3" align="char" char=".">0.91</entry></row><row><entry namest="col1" nameend="col1" align="left">Viscosity</entry><entry namest="col2" nameend="col2" align="left">(0.0005)exp(24dp/dz)</entry><entry namest="col3" nameend="col3" align="char" char=".">0.96</entry></row><row><entry namest="col1" nameend="col1" align="left">Saturation pressure</entry><entry namest="col2" nameend="col2" align="left">(16980)exp(-3.6dp/dz)</entry><entry namest="col3" nameend="col3" align="char" char=".">0.72</entry></row><row><entry namest="col1" nameend="col1" align="left">Formation volume factor</entry><entry namest="col2" nameend="col2" align="left">(0.10)(dp/dz)^-2·3</entry><entry namest="col3" nameend="col3" align="char" char=".">0.97</entry></row><row rowsep="1"><entry namest="col1" nameend="col1" align="left">Molecular weight</entry><entry namest="col2" nameend="col2" align="left">(5.2)exp(8.9dp/dz)</entry><entry namest="col3" nameend="col3" align="char" char=".">0.98</entry></row></tbody></tgroup></table></tables>

The correlation can as well be obtained for other PVT properties, such as density and oil compressibility.

We now discuss how a PVT property of an unknown hydrocarbon reservoir fluid that is present in a hydrocarbon-bearing formation layer traversed by a borehole is determined in situ. Suitably, the hydrocarbon-bearing formation layer is in the same geological area.

At first a tool is lowered to the first of a set of locations in that formation layer. The tool comprises a central conduit having an inlet and being provided with a pressure sensor, and a fluid receptacle having an inlet opening into the central conduit. At the location an exclusive fluid communication is made between the formation and the inlet of the central conduit by extending into the formation a probe having an outlet that is in direct fluid communication with the inlet of the central conduit. Then formation fluid is allowed to enter into the fluid receptacle and the pressure build-up was measured. The required fluid pressure is the pressure at the end of the pressure build-up for that location.

Then the tool is moved to the next location where the pressure-build up is again measured to obtain the fluid pressure for that location, and so on until all the fluid pressures at all locations have been determined. With this the pressure gradient is calculated.

Then the pressure gradient is used with the empirical relation to get the PVT property that is required.

This shows that with the method according to the present invention a good accuracy can be achieved.

In case the hydrocarbon reservoir fluid is a so-called heavy oil that is relatively viscous, it will be difficult to acquire a representative sample of the reservoir fluid. In order to obtain a representative sample, the step of making an exclusive fluid communication further includes activating a heating device arranged near the probe to heat the formation fluid.

Suitably, the probe is associated with a packer pad in an assembly, and the heating device is placed in the packer pad. Alternatively the heating device is arranged on the tool. The heating device may be a device generating microwaves, light waves or infrared waves. The heating device may also be an electrical heater, a chemical heater or a nuclear heater.

So far the present invention has been discussed with reference to an open hole, however, the present invention can as well be applied in a cased hole. In that case, calculating the pressure gradient along the hydrocarbon-bearing formation layer starts with making a plurality of perforation sets through the casing wall into the formation layer. Then the tool is lowered in the cased borehole to the first perforation set. The tool is further provided with an upper and a lower packer arranged at either side of the inlet of the central conduit, wherein the distance between the upper and the lower packer is larger than the height of a perforation set, and wherein the spacing between adjacent perforation sets is at least equal to the length of the longest packer. The packers are set so that the perforation set is straddled between the packers. Then formation fluid is allowed to enter into the fluid receptacle, the pressure build-up is measured, and the fluid pressure is determined. Then the tool is positioned near the next perforation set, and the fluid pressure is measured and so on, until the fluid pressures of a predetermined number of locations have been measured. From these fluid pressures and the true vertical depths of the casing sets, the pressure gradient is calculated.