Method for Determining the Content of A Plurality of Compounds Contained In A Drilling Fluid

Abstract

A method for the extraction of a gas fraction of each compound, the measurement of information representative of the gas fraction of each compound and the calculation, for each first compound of a first group of compounds, of the content of said first compound in the drilling fluid on the basis of information measured for the gas fraction of the first compound and on the basis of a first correction factor (ρi).

Description

FIELD OF THE DISCLOSURE

The present disclosure relates to a method for determining the content of a plurality of compounds contained in a drilling fluid.

BACKGROUND

During the drilling of a petroleum or gas well, it is known how to perform an analysis of the gas compounds contained in the drilling fluid emerging from the well, this fluid being commonly designated as “drilling mud”. This analysis gives the possibility of reconstructing the geological succession of the crossed formations during the drilling and is involved in the determination of the possibilities of exploiting encountered fluid deposits. This analysis performed continuously comprises two main phases. A first phase consists of continuously sampling the drilling mud in circulation, and then of bringing it into an extraction enclosure where a certain number of compounds carried by the mud (for example hydrocarbon compounds, carbon dioxide, hydrogen sulfide, helium and nitrogen) are extracted from the mud as a gas.

A second phase consists of transporting the extracted gases towards an analyzer where these gases are described and in certain cases quantified. For extracting the gases from the mud, a degasser with mechanical stirring of the type described in FR 2 799 790 is frequently used. The gases extracted from the mud, mixed with a carrier gas introduced into the degasser are conveyed by suction through a gas extraction conduit up to an analyzer which allows quantification of the extracted gases. With such a device it is possible to significantly and specifically extract the very volatile gases present in the mud, for example C₁-C₅ hydrocarbons, notably when it is used with a device for heating the drilling mud, placed upstream from the degasser or in the latter.

However the extraction, in the degasser, of the compounds contained in the mud is not total and the extraction efficiency, defined as the amount of an extracted compound referred to the total amount of this same compound initially contained in the mud, depends on the nature of the compound. It is therefore known how to empirically correct the measurement carried on the gas fraction extracted for each compound with a correction factor depending on the compound in order to provide an estimate of the actual content of the compound in the drilling mud. This is notably the case in muds based on oils or synthetic products, in which the hydrocarbons are relatively soluble. However, the empirical coefficients used do not give entire satisfaction and limit the accuracy of the measurement. In order to improve this accuracy, EP-A-1 710 575 describes a method of the aforementioned type wherein a same calibration sample of the drilling fluid, containing the different compounds to be extracted, successively undergoes several extraction stages in the degasser, the amount of extracted gas being measured at each extraction stage. On the basis of the gas fractions measured at each extraction stage for each compound, a correction factor relating the content of a given compound to the measured fraction during a first extraction stage in the degasser may be determined experimentally for each compound. With such a method the accuracy of the measurement may be considerably improved. However, in order to apply it, it is necessary to have the calibration sample pass at least twice in the degasser and to analyze the gas composition of the extracted gases of each compound to be analyzed, which requires having available an initial mud sample containing a large amount of compounds, the intention being to evaluate the extraction efficiency thereof. Accordingly, the results in certain cases may not be very accurate, notably for heavy compounds which are difficult to extract from the drilling mud.

An object of the disclosure is therefore to further improve and in a simple way, the accuracy of the determination of the content of a plurality of compounds contained in a drilling fluid.

SUMMARY

One object of the disclosure is a method of the aforementioned type, characterized in that the method comprises the following step:

• • calculating, for at least each second compound of a second group of compounds, the content of said second compound in the drilling fluid on the basis of the representative information measured for the second compound under second given extraction conditions, advantageously identical with the first given extraction conditions, and a second correction factor calculated from a calculation equation relating the second correction factor to a plurality of parameters independent of the second compound and of the given extraction conditions and to a thermodynamic factor characteristic of the second compound which depends on at least one thermodynamic parameter representative of the second compound, the independent parameters being determined from each first correction factor and from the calculation equation.

The method according to the disclosure may comprise one or more of the following features, taken individually or according to any technically possible combination(s):

• • the characteristic thermodynamic factor (Fi) is calculated from at least one thermodynamic parameter selected from the boiling temperature of the second compound under atmospheric pressure, the critical temperature of the second compound and the critical pressure of the second compound;
  • the characteristic thermodynamic factor (Fi) is calculated from the temperature of the drilling fluid under given extraction conditions;
  • the characteristic thermodynamic factor (Fi) is calculated by the equation:

$F_i=\frac{\left[\frac{1}{{\theta }_b\left(i\right)}-\frac{1}{\theta }\right]}{\left[\frac{1}{{\theta }_b\left(i\right)}-\frac{1}{{\theta }_c\left(i\right)}\right]}·\log \left(\frac{P_c\left(i\right)}{P_{\mathrm{atm}}}\right)$

wherein θ is the temperature of the drilling fluid under the given extraction conditions, θ_b(i) is the boiling temperature of the second compound at atmospheric pressure, θ_c(i) is the critical temperature of the second compound, P_c(i) is the critical pressure of the second compound and P_atm is the atmospheric pressure;

• • the equation for calculating the second correction factor (ρ₂(i)) comprises at least a term of the type a×exp(b·F_i) wherein a and b are parameters independent of the second compound determined on the basis of each first correction factor, and F_i is the thermodynamic factor characteristic of the second compound;
  • the extraction step is applied in an enclosure comprising means for stirring the drilling fluid, the second correction factor (ρ₂(i)) being calculated as a function of at least one parameter selected from the flow rate of drilling fluid injected into the enclosure, the average volume of drilling fluid present in the enclosure, the volume of gas head space present in the enclosure, and the total flow rate of gas fraction extracted out of the enclosure;
  • the second correction factor (ρ₂(i)) is calculated by the following equation:

${\rho }_2\left(i\right)=1+\frac{Q_m}{V_g}·\frac{1}{a·c\times \exp \left[\left(b+d\right)·F_i\right]}+\frac{Q_m}{V_m}·\frac{1}{c\times \exp \left(d·F_i\right)}+\frac{Q_m}{Q_g}·\frac{1}{a\times \exp \left(b·F_i\right)}$

wherein Q_m is the volume flow rate of drilling fluid injected into the enclosure, V_m is the average volume of drilling fluid present in the enclosure, V_g is the volume of the gas head space present in the enclosure, Q_g is the volume flow rate of gas fraction extracted out of the enclosure, a, b, c, d are the parameters independent of the second compound determined on the basis of each first correction factor (ρ₁(i)), and Fi is the thermodynamic factor characteristic of the second compound;

• • the method comprises a step for determining each first correction factor (ρ₁(i)),

the determination step comprising the following steps:

• • providing the calibration sample of drilling fluid comprising at least each first compound;
  • at least two successive stages for extracting the same calibration sample under the first given extraction conditions, each extraction stage comprising the extraction out of the drilling fluid of a gas fraction of each first compound and the measurement of a representative piece of information (y_n(i)) of the gas fraction of each first compound;
  • calculating for each first compound the first correction factor on the basis of the representative pieces of information (y_n(i)) measured at each extraction stage;
  • the number of successive extraction stages is equal to 2:
  • providing the calibration sample comprises the mixing of a given amount of drilling fluid and of a measured amount of each first liquid compound;
  • each compound of the first group of compounds has a boiling temperature at atmospheric pressure below the boiling temperature at atmospheric pressure of each compound of the second group of compounds;
  • each compound of the first group of compounds has a boiling temperature at atmospheric pressure above the boiling temperature at atmospheric pressure of each compound of the second group of compounds;
  • the method comprises a step for correcting the value of the first correction factor (ρ₁(i)) of at least one first compound, the correction step comprising the calculation for said first compound of a first correction factor corrected on the basis of the calculation equation connecting the plurality of parameters (a, b, c, d) independent of the second compound and on the basis of the thermodynamic factor (Fi) characteristic of the first compound, and the calculation of the content of said first compound in the drilling fluid on the basis of the measured information (y₁(i)) for the gas fraction of the first compound and on the basis of the corrected correction factor;
  • the method comprises, for at least one first compound of the first group of compounds, the calculation of the content of said first compound in the drilling fluid on the basis of the measured information (y₁(i)) for the gas fraction of the first compound and on the basis of the first correction factor (ρ₁(i)); and
  • the first given extraction conditions are distinct from the second given extraction conditions, the calculation equation comprising at least one parameter representative of the given extraction conditions have a first value under the first extraction conditions and a second significantly different value from the first value under the second extraction conditions, the independent parameters (a, b, c, d) being determined on the basis of the calculation equation in which the representative parameter is equal to its first value, the second correction factor being calculated on the basis of the calculation equation in which the representative parameter is equal to its second value.

BRIEF DESCRIPTION OF THE DRAWINGS

The disclosure will be better understood upon reading the description which follows, given only as an example, and made with reference to the appended drawings, wherein:

FIG. 1 is a schematic vertical sectional view of a drilling installation in which a first determination method according to the disclosure is applied;

FIG. 2 is a schematic vertical sectional view analogous to FIG. 1 of a calibration assembly intended to apply the method according to the disclosure;

FIG. 3 is a curve illustrating the contents of different gas fractions extracted from a calibration sample of the drilling fluid during successive passages of the sample in the calibration stage of FIG. 2;

FIG. 4 is a curve illustrating the different correction factors calculated by the method according to the disclosure versus the thermodynamic factor characteristic of each compound in a first exemplary application of the method according to the disclosure; and

FIG. 5 is a view analogous to FIG. 4 illustrating a second exemplary application of the method according to the disclosure.

DETAILED DESCRIPTION

In all the following, the terms of “upstream” and “downstream” are understood relatively to the normal direction of circulation of a fluid in a conduit.

A first determination method according to the disclosure is intended to be applied in a drilling installation 11 of a well for producing fluid, notably hydrocarbons, such as an oil well. Such an installation 11 is illustrated by FIGS. 1 and 2. This installation 11 comprises a drilling conduit 13 positioned in a cavity 14 pierced by a rotary drilling tool 15, a surface installation 17, and an assembly 19 for analyzing the gases contained in the drilling fluid. The installation 11 further comprises a calibration assembly 20 illustrated in FIG. 2.

With reference to FIG. 1, the drilling conduit 13 is positioned in the cavity 14 pierced in the subsoil 21 by the rotary drilling tool 15. It extends in an upper portion of the height of the cavity 14 which it delimits. The cavity 14 further has a lower portion directly delimited by the subsoil. The drilling conduit 13 includes at the surface 22 a well head 23 provided with a conduit 25 for circulation of the fluid. The drilling tool 15 comprises, from bottom to top in FIG. 1, a drilling head 27, a drill string 29, and a head 31 for injecting drilling fluid. The drilling tool 15, is driven into rotation by the surface installation 17.

The drilling head 27 comprises means 33 for piercing the rocks of the subsoil 21. It is mounted on the lower portion of the drill string 29 and is positioned in the bottom of the cavity 14. The string 29 comprises a set of hollow drilling tubes. These tubes delimit an inner space 35 which allows the drilling fluid injected through the head 31 from the surface 22 to be brought as far as the drilling head 27. For this purpose, the injection head 31 is screwed onto the upper portion of the drill string 29. This drilling fluid, commonly designated with the term of <<drilling mud>>, is essentially liquid. The surface installation 17 comprises means 41 for supporting and driving into rotation the drilling tool 15, means 43 for injecting the drilling fluid and a vibrating sieve 45. The injection means 43 are hydraulically connected to the injection head 31 for introducing and circulating the drilling fluid in the internal space 35 of the drill string 29.

The drilling fluid is introduced into the inner space 35 of the drill string 29 through the injection means 43. This fluid flows downwards down to the drilling head 27 and passes into the drilling conduit 13 through the drilling head 27. This fluid cools and lubricates the piercing means 33. The fluid collects the solid debris resulting from the drilling and flows upwards through the annular space defined between the drill string 29 and the walls of the drilling conduit 13, and is then discharged through the circulation conduit 25. The inner space 35 opens out facing the drilling head 27 so that the drilling fluid lubricates the piercing means 33 and flows upwards in the cavity 14 along the conduit 13 up to the well head 23, while discharging the collected solid drilling debris, in the annular space 45 defined between the string 29 and the conduit 13. The drilling fluid present in the cavity 14 maintains hydrostatic pressure in the cavity, which prevents breakage of the walls delimiting the cavity 14 not covered by the conduit 13 and which further avoids eruptive release of hydrocarbons in the cavity 14.

The circulation conduit 25 is hydraulically connected to the cavity 14, through the well head 23 in order to collect the drilling fluid from the cavity 14. It is for example formed by an open return line or by a closed tubular conduit. In the example illustrated in FIG. 1, the conduit 25 is a closed tubular conduit. The vibrating sieve 45 collects the fluid loaded with drilling residues which flow out of the circulation conduit 25, and separates the liquid from the solid drilling residues. The analysis assembly 19 comprises a device 51 for sampling drilling fluid in the conduit 25, a device 53 for extracting a gas fraction of the compounds contained in the drilling fluid, a device 55 for transporting gas fractions and an analysis device 57.

The sampling device 51 comprises a sampling head 61 immersed in the circulation conduit 25, a sampling conduit 63 connected upstream to the sampling head 61, a pump 65 connected downstream to the sampling conduit 63, and a conduit 67 for bringing the drilling fluid into the extraction device 53, connected to an outlet of the pump 65. The sampling device 51 is further advantageously provided with an assembly for heating the sampled fluid (not shown). This heating assembly is for example positioned between the pump 65 and the extraction means 53 on the supply conduit 67. The pump 65 is for example a peristaltic pump capable of conveying the drilling fluid sampled by the head 61 towards the extraction means 53 with a determined fluid volume flow rate Q_m. The extraction device 53 comprises an enclosure 71 into which the supply conduit 67 opens out, a rotary stirrer 73 mounted in the enclosure 71, a mud discharge conduit 75, an inlet 77 for injecting a carrier gas and an outlet 79 for sampling the extracted gas fractions in the enclosure 71.

The enclosure 71 has an inner volume for example comprised between 0.04 L and 3 L. It defines a lower portion 81 of average volume V_m, kept constant, in which circulates the drilling fluid stemming from the supply conduit 67 and an upper portion 83 of average volume V_g kept constant and defining a gas head space above the drilling fluid. The mud supply conduit 67 opens out into the lower portion 81. The stirrer 73 is immersed into the drilling fluid present in the lower portion 81. It is capable of vigorously stirring the drilling fluid in order to extract the extracted gases therefrom.

The discharge conduit 75 extends between an overflow passage 85 made in the upper portion 83 of the enclosure 71 and a retention tank 87 intended to receive the drilling fluid discharged out of the extraction device 53. The discharge conduit 75 is advantageously bent in order to form a siphon 89 opening out facing the retention tank 87 above the level of liquid contained in this tank 87. Alternatively, the drilling fluid from the conduit 75 is discharged into the circulation conduit 25.

In this example, the inlet for injecting a carrier gas 77 opens out into the discharge conduit 75 upstream from the siphon 89 in the vicinity of the overflow passage 85. Alternatively, the inlet 77 opens out into the upper portion 83 of the enclosure 71. The sampling outlet 79 opens out into an upper wall delimiting the upper portion 83 of the enclosure 71. The drilling fluid introduced into the enclosure 71 via the supply conduit 67 is discharged by overflow into the discharge conduit 75 through the overflow passage 85. A portion of the discharged fluid temporarily lies in the siphon 89 which prevents gases from entering the upper portion 83 of the enclosure 71 through the discharge conduit 75. The introduction of gas into the enclosure 71 is therefore exclusively carried out through the inlet for injecting a carrier gas 77.

In the example illustrated by FIG. 1, the carrier gas introduced through the introduction inlet 77 is formed by the surrounding air around the installation, at atmospheric pressure. Alternatively, this carrier gas is another gas such as nitrogen or helium. The transport device 55 comprises a line 91 for transporting the extracted gases towards the analysis device 57 and suction means 93 for conveying the gases extracted out of the enclosure 71 through the transport line 91. The transport line 91 extends between the sampling outlet 79 and the analysis device 57. It advantageously has a length comprised between 10 m and 500 m, in order to move the analysis device 57 away from the well head 23 into a non-explosive area. The transport line 91 is advantageously made on the basis of a metal or polymer material, notably polyethylene and/or polytetrafluoroethylene (PTFE).

The analysis device 57 comprises a sampling conduit 97 tapped on the transport line 91 upstream from the suction means 93, an instrumentation 99, and a computing unit 101. The instrumentation 99 is capable of detecting and quantifying the gas fractions extracted out of the drilling fluid in the enclosure 71 which have been transported through the transport line 91. This instrumentation for example comprises infrared detection apparatuses for the amount of carbon dioxide, chromatographs with flame ionisation detectors (FID) for detecting hydrocarbons or further with thermal conductivity detectors (TCD) depending on the gases to be analyzed. It may also comprise a chromatography system coupled with a mass spectrometer, this system being designated by the acronym “GC-MS”. It may comprise an isotope analysis apparatus as described in Application EP-A-1 887 343 of the Applicant. Online simultaneous detection and quantification of a plurality of compounds contained in the fluid, without any manual sampling by an operator, is therefore possible within time intervals of less than 1 minute.

As this will be seen below, the computing unit 101 is capable of calculating the content of a plurality of compounds to be analyzed present in the drilling fluid on the basis of the value of the extracted gas fractions in the enclosure 71, as determined by the instrumentation 99, and on the basis of correction factors ρ(i) specific to each compound to be analyzed. The calibration assembly 10 illustrated in FIG. 2 is in this example formed by the sampling device 51, the extraction device 53, the transport device 55 and the analysis device 57 of the analysis assembly 19. However, this calibration assembly 20 further comprises an upstream tank 111 intended to receive a calibration sample of the drilling fluid with view to having this sample pass several successive times in the extraction device 53 in order to be subject to several extraction stages therein. In one alternative, at least the extraction device of the calibration assembly 20 is distinct from the extraction device 53 of the analysis assembly 19. In this case, the extraction devices of the analysis assembly 19 and of the calibration assembly 20 are substantially identical and for example have an enclosure geometry 71 which is identical (notably in size or in volume), and an identical stirrer 73. Thus, the extraction of the gas fractions from the calibration sample contained in the upstream tank 111 may be carried out under the same extraction conditions as the extraction of the gas fractions in a drilling fluid sample continuously taken in the drilling conduit 25 during the analysis of this fluid.

This notably implies that the temperature of the drilling fluid in the enclosure 71, the pressure P of the gas head space located above the fluid present in the enclosure 71, the drilling fluid flow rate Q_m admitted into the enclosure 71, and the sampled gas flow rate Q_g, the volume V_m of drilling fluid in the enclosure 71, and the gas volume Vg present in the enclosure 71, the nature of the stirring as well as the stirring rate, are substantially identical in the extraction devices of the calibration assembly 20 and of the analysis assembly 19. The drilling fluid for example is formed by mud with water or mud with oil. The compounds to be analyzed contained in the drilling fluid are notably aliphatic or aromatic C₁-C₁₀ hydrocarbons.

The application of a first determination method according to the disclosure will now be described. This method comprises an initial step for evaluating the correction factors ρ₁(i) of a first group of compounds i to be analyzed, a step for adjusting a model linking the correction coefficients of each compound according to one of their thermodynamic characteristics, a step for calculating from the thereby determined model, correction factors ρ₂(i) of a second group of constituents to be analyzed, and then an online analysis step of the gas content of the drilling fluid circulating in the circulation conduit 25. The first step for evaluating the correction factors is advantageously carried out by a calibration method as described in patent application EP-A-1 710 575 of the Applicant, notably in the calibration assembly 20 described in FIG. 2. For this purpose, a calibration drilling fluid sample is introduced into the upstream tank 111. This sample contains a plurality of first compounds among those intended to be analyzed in the drilling fluid circulating in the drilling conduit 25.

In a first alternative application of the method, these first compounds are advantageously the most lightweight, such as for example C₁-C₅ hydrocarbons or further C₁-C₄ hydrocarbons. The sampling head 61 is then immersed in the upstream tank 111 in order to pump the calibration sample through the pump 65 and the admission conduit 67 as far as the enclosure 71 at a flow rate Q_m. Next, the stirrer 73 having been activated, a gas fraction y₁(i) of each first compound to be measured contained in the calibration sample is extracted and conveyed via the carrier gas introduced through the inlet 77 across the transport line 91 as far as the instrumentation 99. Each gas fraction y₁(i) is then quantified for each compound, as illustrated by FIG. 3. Next, when the calibration sample has substantially totally passed through the enclosure 71 and been recovered in the tank 87, the tanks 87 and 111 are inverted so that the same calibration sample under the given extraction conditions again passes through the extraction device 53. A gas fraction y₂(i) of each compound to be analyzed present in the calibration sample is then extracted during this extraction phase.

Next, this operation is repeated for n successive extraction stages, with n being a total number of extraction stages of the same calibration sample advantageously comprised between 2 and 10 as illustrated in FIG. 3. The computing unit 101 then determines, for each first compound, the definition of a series illustrated on a logarithmic scale by a linear curve from at least two pairs of values (n, y_n) which correspond to the extraction stage n of the gases of the sample and to the given amount y_n(i) of a gas fraction of a compound during the extraction stage n. This series depends on the gas fraction y₁(i) extracted during a first extraction stage and on a parameter m(i) independent of the extraction stage and characteristic of the compound extracted from the drilling fluid, and of the extraction conditions. Advantageously, the series determined by the computing unit is substantially an exponential geometrical series which is described by the formula:

y_n(i)=y₁(i)×exp[−m(i)×(n−1)]

Next, a first correction factor ρ₁(i) is calculated for linking the content t₀(i) of each first compound in the drilling fluid to the gas fraction y₁(i) extracted at a total volume flow rate of extracted gases Q_g, during a first passage of the fluid in the extraction device 53 and at a volume flow rate Q_m, by the equation:

$\begin{array}{cc}{t}_0\left(i\right)=\frac{Q_g}{Q_m}·\rho \left(i\right)·y_i\left(i\right)& \left(1\right)\end{array}$

This correction factor ρ₁(i) is then determined by the equation (2) below:

$\begin{array}{cc}{\rho }_i\left(i\right)=\sum _1^{\infty }y_n\left(i\right)=\frac{1}{1-\exp \left(-m\left(i\right)\right)}=\frac{1}{1-\lambda }& \left(2\right)\end{array}$

In one alternative, the correction factors ρ₁(i) of the first group of first compounds are determined by other equations, or even empirically. Next, the step for calculating the correction factors ρ₂(i) of a second group of compounds to be analyzed is applied.

In a first alternative embodiment of the method, this second group advantageously comprises the heaviest compounds, for example C₅-C₁₀ hydrocarbons for which the accuracy of the measurement of the extracted gas fractions is lower. For this purpose, each second correction factor ρ₂(i) is advantageously calculated from a calculation equation posed on the basis of a coefficient α(i) representative of the degassing kinetics of each second compound in the extraction device 53 under the given extraction conditions, and of a coefficient K(i) representative of thermodynamic equilibrium between the gas fraction and the liquid fraction of each second compound present in the extractor 71 of the extraction device 53. The equation for calculating each second correction factor ρ₂(i) further depends on the volume flow rate Q_m of mud circulating in the enclosure 71, on the average volume V_g of the upper portion 83 forming the gas head space, on the average volume V_m of the lower portion 81 containing the circulating fluid and on the total gas flow rate Q_g sampled through the outlet 79 under the given extraction conditions. Advantageously, each second correction factor ρ₂(i) is calculated by the equation:

$\begin{array}{cc}{\rho }_2\left(i\right)=1+\frac{Q_m}{V_g}·\frac{1}{\alpha \left(i\right)·K\left(i\right)}+\frac{Q_m}{V_m}·\frac{1}{\alpha \left(i\right)}+\frac{Q_m}{Q_g}·\frac{1}{K\left(i\right)}& \left(3\right)\end{array}$

According to the disclosure, the coefficients K(i) and α(i) are calculated from a characteristic thermodynamic factor Fi specific to each second compound which depends at least on one thermodynamic parameter representative of the second compound, and are also calculated from a plurality of parameters a, b, c, d which are independent of the second compound and of the extraction conditions and which are calculated from each first correction factor ρ₁(i) and from the calculation equation (3) as this will be seen below.

Advantageously, said or each representative thermodynamic parameter is selected from the boiling temperature θ_b(i) at atmospheric pressure of the second compound I, from its critical temperature θ_c(i) and its critical pressure P_c(i). Said or each characteristic thermodynamic factor is advantageously selected as proposed by Hoffman (Hoffman et al. <<Equilibrium Constants for a Gas Condensate System>> Trans. AIME (1953) 198, 1-10) or in an improved way by Standing (Standing, <<A set of Equations for Computing Equilibrium Ratios of a Crude Oil/Natural Gas System at Pressures below 1,000 psia>> SPE 7903 1979). The characteristic thermodynamic factor Fi is then further calculated according to the temperature θ of the drilling fluid in the enclosure 71 under the given extraction conditions. Advantageously, the parameter Fi is obtained from an equation linking all the aforementioned parameters such as the following equations:

$\begin{array}{cc}{F}_i=\frac{\left[\frac{1}{{\theta }_b\left(i\right)}-\frac{1}{\theta }\right]}{\left[\frac{1}{{\theta }_b\left(i\right)}-\frac{1}{{\theta }_c\left(i\right)}\right]}·\log \left(\frac{P_c\left(i\right)}{P_{\mathrm{atm}}}\right)& \left(4\right)\end{array}$

The coefficients K(i) and α(i) are then given by the following equations:

K(i)=a×exp(b·F_i)  (5)

α(i)=c×exp(d·F_i)  (6)

Thus, the equation (3) above may be re-written for each second compound in the following form:

$\begin{array}{cc}{\rho }_2\left(i\right)=1+\frac{Q_m}{V_g}·\frac{1}{a·c\times \exp \left[\left(b+d\right)·F_i\right]}+\frac{Q_m}{V_m}·\frac{1}{c\times \exp \left(d·F_i\right)}+\frac{Q_m}{Q_g}·\frac{1}{a\times \exp \left(b·F_i\right)},& \left(7\right)\end{array}$

wherein each second correction factor ρ₂(i) depends on the plurality of parameters a, b, c, d independent of the second compound, determined on the basis of each first correction factor ρ₁(i), and also depends on the characteristic thermodynamic factor Fi of each second compound as defined above, as well as on the volume flow rate Qm of drilling fluid passing through the enclosure 71, on the volume V_g of the upper portion 83 of the enclosure comprising a gas head space, on the average volume V_m of drilling fluid present in the enclosure and on the volume flow rate Q_g of gas extracted from the enclosure.

In order to determine the parameters a, b, c, d, a system of equations is laid out by applying the calculation equation (7) above to each first correction factor ρ₁(i) depending on the thermodynamic parameter Fi of each first compound, according to the system:

$\begin{array}{cc}{\rho }_1\left(i\right)=1+\frac{Q_m}{V_g}·\frac{1}{a·c\times \exp \left[\left(b+d\right)·F_i\right]}+\frac{Q_m}{V_m}·\frac{1}{c\times \exp \left(d·F_i\right)}+\frac{Q_m}{Q_g}·\frac{1}{a\times \exp \left(b·F_i\right)}& \left(8\right)\end{array}$

This system is solved by an optimization method for example using the least squares technique for obtaining the parameters a, b, c and d independently of each second compound.

With reference to FIG. 5, once the parameters a, b, c, d are obtained from each first correction factor ρ₁(i) represented in solid symbols in FIG. 5, each second correction factor ρ₂(i) relating to each second compound, represented by hollow symbols in FIG. 5, is calculated by using equation (7) and by calculating for each second compound the coefficient Fi by equation (4). With the method according to the disclosure it is therefore possible to obtain all the correction factors of the compounds to be analyzed by a simple calculation based on a not very large number of correction factors determined experimentally or empirically. This considerably increases the accuracy of the measurement, notably for relatively heavy compounds which are present in a small amount in the calibration sample and which are difficult to extract from the drilling fluid.

In one alternative, the whole of the correction factors for each compound to be analyzed, including the first compound, is recalculated from the calculation equation (7). The analysis step is then applied during the drilling. In order to carry out the drilling, the drilling tool 15 is driven into rotation by the surface installation 41. The drilling fluid is introduced into the inner space 35 of the drilling lining 29 through the injection means 43. This fluid flows down to the drilling head 27 and passes in the drilling conduit 13 through the drilling head 27. This fluid cools and lubricates the piercing means 33. The fluid collects solid debris resulting from the drilling and moves up through the annular space defined between the drill string 29 and the walls of the drilling conduit 13, and is then discharged through the circulation conduit 25.

In this step, the sampling head 61 is positioned in the circulation conduit 25, downstream from the vibrating sieve 45. The pump 65 is then actuated in order to pick up drilling fluid in the conduit 25 with the given volume flow rate Q_m and to introduce it into the enclosure 71 through the admission conduit 67. The drilling fluid then contains the components to be analyzed. The stirrer 73 is actuated for stirring the drilling fluid present in the lower portion 81 and for extracting a gas fraction y₁(i) of each compound i present in the drilling fluid. This gas fraction y₁(i) is conveyed as far as the instrumentation 99 through the transport line 91 in order to determine its value. During the extraction, the temperature of the drilling fluid in the enclosure 71, the pressure P of the gas head space located above the fluid present in the enclosure 71, the flow rate Q_m of drilling fluid admitted into the enclosure 71, and the sampled gas flow rate Q_g, the nature of the stirring as well as the stirring rate are substantially identical as compared with the same parameters used during the calibration step. Next, the computing unit 101 infers therefrom the value of the content of each compound i in the drilling fluid by equation (1), where the correction factors ρ(i) of at least one second group of compounds are calculated with the equation (7) above.

In an alternative application of the method, illustrated in FIG. 6, a plurality of first correction factors ρ₁(i), illustrated in solid symbols in the figure are determined experimentally or empirically. However, at least one first correction factor 201 determined experimentally or empirically is not taken into account for carrying out the determination of the parameters a, b, c, d. This correction factor 201 is then excluded and replaced with a correction factor 203 calculated with equation (7). The method according to the disclosure thereby allows correction of doubtful or erroneous experimental measurements for example because of contaminants present in the calibration sample. In one alternative, the second compounds are identical with the first compounds, all the correction factors ρ₁(i) being replaced with corrected correction factors. In one alternative, the coefficient Fi is equal to the boiling temperature θ_b(i) at atmospheric pressure of the compound.

In an alternative embodiment, it is possible to improve the determination of the correction factors ρ₁(i) by only using two successive stages for extracting the calibration sample. In this case, the correction coefficients ρ₁(i) obtained with equation (2) are indeed very sensitive to measurement errors, the exponential decrease coefficient m(i) of equation (2) is no longer obtained via a linear regression but by directly calculating a straight line passing through two points. The calculation of the parameters a, b, c, and d by solving the system of equations (8) and the calculation of optimized correction coefficients 203 for each first compound, as described above, allows these measurement errors to be reduced by introducing an overdimensioned system of equations.

With the method according to the disclosure it is further possible to improve the application of the calibration method described in Patent Application EP-A-1 710 575 of the Applicant. Indeed for applying this method, a mud sample containing hydrocarbons in a sufficient amount has to be available. This mud sample is generally taken during drilling after having crossed formations containing hydrocarbons. This makes it difficult to obtain the correction coefficients ρ₁(i) during drilling. Sometimes it is even impossible to obtain all the coefficients ρ₁(i) for lack of having crossed formations containing a sufficient amount of hydrocarbons. The method according to the present disclosure then allows determination of these coefficients from artificial mixtures of mud and hydrocarbons forming a calibration sample. These mixtures are made for example by emulsifying at the surface, liquid heavy hydrocarbon compounds under atmospheric conditions (for example C₅-C₈ hydrocarbons such as pentane to octane) in a sufficient amount for providing extracted gas amounts which may be measured with good accuracy. These compounds are then used as the first compounds allowing determination of the parameters a, b, c and d. The correction coefficients for the second compounds either too lightweight and difficult to mix with the mud because of their gas state (for example C₁-C₄ hydrocarbons such as from methane to butane), or difficult to handle because of their toxicity (aromatic compounds) are advantageously determined by applying the method described above.

Another advantage provided by the method according to the disclosure, is to allow calculation of the correction coefficients to be applied for each first or second compound in the case when the second extraction conditions in the analysis step substantially differ from the first extraction conditions during the calibration step. In this case, at least one of the temperature θ, of the introduced fluid flow rate Q_m, of the extracted gas flow rate Q_g, of the fluid volume V_m and of the gas head space volume V_g, is significantly different, for example by at least 5%, under the first extraction conditions and under the second extraction conditions. For this purpose, the parameters a, b, c and d independent of each compound and extraction conditions are determined in the step for fitting the model as described earlier, by using the system of equations (8) in which the representative parameters of the extraction conditions, θ, Q_m, Q_g, V_m and V_g of each calculation equation are those which prevail under the first extraction conditions.

Next, once the coefficients a, b, c, d have been determined, the correction coefficients ρ(i) for each compound are recalculated with equations (4) and (7) from the new values of the parameters representative of the extraction conditions θ, Q_m, Q_g, V_m and V_g under the second extraction conditions. The computing unit 101 may further take into account any change in these representative parameters of extraction conditions during the analysis step by adjusting in real time the correction coefficients for each measured compound from the new values of θ, Q_m, Q_g, V_m and V_g.

Claims

1. A method for determining the content (t0(i)) of a plurality of compounds contained in a drilling fluid, of the type comprising:

extracting a gas fraction of each compound out of the drilling fluid;

measuring representative information (y1(i)) of the gas fraction of each compound;

obtaining for each first compound of a first group of compounds, a first correction factor (ρ1(i)) linking the measured information (y1(i)) for the gas fraction of the first compound under first given extraction conditions to the content of said first compound in the drilling fluid;

wherein the method comprises the following steps:

calculating for at least each second compound of a second group of compounds, the content of said second compound in the drilling fluid on the basis of the representative information measured for the second compound under second given extraction conditions, advantageously identical with the first given extraction conditions, and a second correction factor (ρ2(i)) calculated from a calculation equation relating the second correction factor (ρ2(i)) to a plurality of parameters (a, b, c, d) independent of the second compound and of the given extraction conditions and to a thermodynamic factor characteristic of the second compound (Fi) which depends at least on one thermodynamic parameter representative of the second compound, the independent parameters (a, b, c, d) being determined from each first correction factor (ρ1(i)) and from the calculation equation.

2. The method according to claim 1, characterized in that the characteristic thermodynamic factor (Fi) is calculated from at least one thermodynamic parameter selected from the boiling temperature of the second compound at atmospheric pressure, the critical temperature of the second compound and the critical pressure of the second compound.

3. The method according to claim 1, characterized in that the characteristic thermodynamic factor (Fi) is calculated from the temperature of the drilling fluid under given extraction conditions.

4. The method according to claim 2, characterized in that the characteristic thermodynamic factor (Fi) is calculated by the equation: F i = [ 1 θ b  ( i ) - 1 θ ] [ 1 θ b  ( i ) - 1 θ c  ( i ) ] · log  ( P c  ( i ) P atm ) wherein θ is the temperature of the drilling fluid under given extraction conditions, θb(i) is the boiling temperature of the second compound at atmospheric pressure, θc(i) is the critical temperature of the second compound, Pc(i) is the critical pressure of the second compound and Patm is the atmospheric pressure.

5. The method according to claim 1, characterized in that the equation for calculating the second correction factor (ρ2(i)) comprises at least one term of the type a×exp(b·Fi), wherein a and b are parameters independent of the second compound determined on the basis of each first correction factor, and Fi is the thermodynamic factor characteristic of the second compound.

6. The method according to claim 1, characterized in that the extraction step is applied in an enclosure (71) comprising means (73) for stirring the drilling fluid, the second correction factor (ρ2(i)) being calculated as a function of at least one parameter selected from the flow rate of drilling fluid injected into the enclosure, the average volume of drilling fluid present in the enclosure (71), the volume of the gas head space present in the enclosure (71), and the total flow rate of gas fraction extracted out of the enclosure (71).

7. The method according to claim 6, characterized in that the second correction factor (ρ2(i)) is calculated by the following calculation equation: ρ 2  ( i ) = 1 + Q m V g · 1 a · c × exp  [ ( b + d ) · F i ] + Q m V m · 1 c × exp  ( d · F i ) + Q m Q g · 1 a × exp  ( b · F i ) wherein Qm is the volume flow rate of drilling fluid injected into the enclosure, Vm is the average volume of drilling fluid present in the enclosure, Vg is the volume of the gas head space present in the enclosure, Qg is the volume flow rate of gas fraction extracted out of the enclosure, a, b, c, d are the parameters independent of the second compound determined on the basis of each first correction factor (ρ1(i)) and Fi is the thermodynamic factor characteristic of the second compound.

8. The method according to claim 1, characterized in that it comprises a step for determining each first correction factor (ρ1(i)),

the determination step comprises the following phases: providing a drilling fluid calibration sample containing at least each first compound; at least two successive stages for extracting the same calibration sample under the first given extraction conditions, each extraction stage comprising the extraction out of the drilling fluid of a gas fraction of each first compound and the measurement of a representative piece of information (yn(i)) of the gas fraction of each first compound; calculating, for each first compound, the first correction factor on the basis of representative pieces of information (yn(i)) measured at each extraction stage.

9. The method according to claim 8, characterized in that the number of successive extraction stages is equal to 2.

10. The method according to claim 8, characterized in that providing the calibration sample comprises mixing of a given amount of drilling fluid and of a measured amount of each first liquid compound.

11. The method according to claim 1, characterized in that each compound of the first group of compounds has a boiling temperature at atmospheric pressure below the boiling temperature at atmospheric pressure of each compound of the second group of compounds.

12. The method according to claim 1, characterized in that each compound of the first group of compounds has a boiling temperature at atmospheric pressure above the boiling temperature at atmospheric pressure of each compound of the second group of compounds.

13. The method according to claim 1, characterized in that it comprises a step for correcting the value of the first correction factor (ρ1(i)) of at least one first compound, the correction step comprising the calculation for said first compound of a first correction factor corrected on the basis of the calculation equation linking the plurality of parameters (a, b, c, d) independent of the second compound and on the basis of the thermodynamic factor (Fi) characteristic of the first compound, and the calculation of the content of said first compound in the drilling fluid on the basis of measured information (y1(i)) for the gas fraction of the first compound and on the basis of the corrected correction factor.

14. The method according to claim 1, characterized in that it comprises, for at least one first compound of the first group of compounds, the calculation of the content of said first compound in the drilling fluid on the basis of measured information (y1(i)) for the gas fraction of the first compound and on the basis of the first correction factor (ρ1(i)).

15. The method according to claim 1, characterized in that the first given extraction conditions are distinct from the second given extraction conditions, the calculation equation comprising at least one parameter representative of the given extraction conditions having a first value under the first extraction conditions and a second value significantly different from the first value under the second extraction conditions, the independent parameters (a, b, c, d) being determined on the basis of the calculation equation in which the representative parameter is equal to its first value, the second correction factor being calculated on the basis of the calculation equation in which the representative parameter is equal to its second value.