FR2585404A1 - Method for determining the parameters of formations having several layers producing hydrocarbons - Google Patents

Abstract

The invention relates to a method for determining the parameters of an underground formation producing hydrocarbons comprising several layers through which a well is drilled, which consists in drawing curves representing the relative variations with time of the yields of layers DELTA qj or of groups of layers of the formation from obtained yield measurement points, while a variation of the total yield DELTA q has been set for the well at a given instant between two determined constant values, then in comparing these experimental curves to the curves G, H of a theoretical model which have been established for various values of the characteristic parameters of an underground formation, and in deducing the values of the parameters of the formation in question from those associated with the theoretical curves which best fit the experimental curves.

Description

METHOD FOR DETERMINING PARAMETERS OF FORMATIONS A
MULTIPLE LAYERS PRODUCING HYDROCARBONS
The present invention relates to a method for determining the parameters of a subterranean formation producing hydrocarbons comprising several layers through which a well is drilled.

 It has long been known to perform pressure measurements over time on oil wells to determine the characteristics of the subterranean production formations in which they are drilled. If these measurements make it possible to determine a large number of parameters characterizing the underground formations in general, they prove to be insufficient in the case of complex reservoirs such as formations with several layers. A single pressure curve can not provide the information needed to determine the specific characteristics of the different layers, such as their permeability and their coefficient characterizing the parietal effect (more commonly called "skin").

A test method for multilayer systems has been proposed by Gao ("The Crossflow Behavior and the Determination of
Reservoir Parameters by Draudoun Tests in Multilayer Reservoirs, "
SPE paper No. 12580, submitted for publication on 29 September 1983).

Using the semi-permeable wall model published by Deans and
Gao in SPE paper No. 11966 presented at the 5th Annual Conference and Exhibition in San Francisco, 5-8 October 1983, this process consists in testing each layer individually by taking a series of pressure curves. Such a method has at least three disadvantages. First, it takes a long time to implement. Then, in case of transfer flow between layers of the formation, the interpretation of the curves is tricky. Finally, during the tests, the well is never in a mode of activity similar to that which corresponds to a real production regime.

Another way of investigating multi-layer systems is to use the variations of flow and pressure as a function of depth in a stabilized well, that is to say, whose production is carried out at pressure and flow rate. constant surface. This type of measurement leads to an "instantaneous snapshot" of flow and pressure at each layer for a given flow and pressure at the soil surface. The data obtained can be presented, for different successive surface flow rates, in the form of a series of pressure versus flow curves for each layer. Here, two disadvantages appear. First, the wells do not all reach a stabilized flow regime. In addition, it has been shown (Lefkovits, HC, Hazebroek, P., Allen, EE, and Matthews, CS: "A Study of the Behavior of Bounded Reservoirs Composed of
Stratified Layers, S.Pet.Tac., March 1961) that the respective flow rates of the layers vary over time.Thus, this method is applicable only to wells that actually reach a steady state.

 From the state of the art thus recalled, the object of the invention is an original process for determining the characteristic parameters of a multi-layer underground formation. This method essentially consists in determining the relative variations over time of the flow rates of layers or groups of layers of the formation from flow measurement points obtained while a variation of total flow rate AQ has been imposed on the well at a given moment. t1 between a first determined constant value and a second determined constant value, then comparing said flow rate variations with the behavior of a theoretical model established for different values of the characteristic parameters of a subterranean formation, and deducing the values of the parameters of the of those associated with the behavior of the theoretical model which best coincide with the experimental variations of flow.

 Such a method makes it possible to determine the essential parameters of a multilayer underground formation, relying in particular on the fact that the variations of the respective flow rates of the layers of the formation are, in an initial period immediately following the instant of change of the well rate, sensitive to the effects of wall nature and permeability of the layers, and, in a subsequent period, to inter-layer fluid transfer effects.

 Other features and advantages of the invention will emerge more clearly from the description which follows, with reference to the accompanying drawings, of an example of non-limiting implementation.

 Figure 1 shows schematically, in vertical section, an oil well drilled in a multi-layer formation, where was lowered a flow meter.

 Figure 2 shows a curve obtained using the flowmeter moved in the well.

 Figures 3 and 4 show two networks of flow curves drawn from curves such as that of Figure 2.

 Figure 5 shows an experimental curve of pressure in the well as a function of time, and the derived curve.

 FIGS. 6 to 8 show relative variation curves of flow, respectively of layers with respect to the total flow of the well, of distinct groups of layers or zones with respect to the total flow of the well, and of layers with respect to the total flow rate of the well. area to which these layers belong.

 FIG. 1 shows a petroleum well 10 drilled in a formation which comprises several oil layers, namely five layers 1, 2, 3, 4 and 5. The intermediate layers 12, 34, 45 respectively separating the layers 1 and 2, 3 and 4, 4 and 5 have a certain vertical permeability, so that there can be oil flow through these intermediate layers. On the other hand, the layer 23 separating the layers 2 and 3 is impermeable, and no oil flow occurs between these last layers. Each group of layers between which vertical oil flow can occur and which is isolated by impermeable layers is referred to as the "zone".

In the present example, the formation comprises two zones Z1 and ZZ, the zone Z1 being composed of the layers 1 and 2 and the zone Z2 of the layers 3, 4 and 5. By definition, there can not be vertical transfer of oil between two areas. This sharing of the underground formation in layers and in distinct zones has proved to be very advantageous for the interpretation of the results obtained and constitutes one of the characteristics of the present invention. The different layers and zones can be identified by making a flow recording with respect to the formation as a function of depth. We can also use logging records previously made in this well.

 When the well is put into production, it delivers on the surface a total flow of oil, via its production column 11. The annular space between the casing 10 and the production column It is closed by gaskets or " Packer "9. At total flow contribute layers 1 to 5 by respective partial flow rates q1 to q5. The total flow rate O measured above the formation is the sum of the flow rates q1 to q5. It should be noted that the flow rate measured at the surface may be different, because of the well storage effect. These flows are identical if this effect is zero.

 The method according to the invention implements the variations in time of the pressure p in the well and partial flow rates q1 to q5 of the different layers resulting from a modification imposed on the overall flow rate Q of the well.

The flow measurements are made using a flow meter 13 (for example as described in the French patent
No. 74 / 22,391) lowered into the well at the end of a cable 14, then moved vertically several times in a sweeping motion over the total height of the formation. When it is just above a layer, the flow meter measures the cumulative flow of that layer and lower layers. At each pass is recorded a curve such as that of Figure 2, which indicates the measured flow as a function of the depth and from which we can deduce the cumulative flow rates of the different layers 1 to 5, namely flows q5, q5 + q4 , q5 + q4 + q3w taken to the right of intermediate layers 45, 34, 23 ... .The moments at which these flow measurements are made are also recorded. This makes it possible to plot the curves representing the variations as a function of time of the cumulated flows. FIG. 3 gives a semi-logarithmic representation of such a network of curves, the flow rates being evaluated in barrels per day (1 barrel = 158.98 liters). From these curves, it is possible to draw, by simple subtraction operations, the network of curves of FIG. 4, which represents the variations, as a function of time, of the eigenvalue of each layer 1 to 5.

 In FIGS. 3 and 4, the measurement times appear to be the same for all the layers. In fact, because of the sweeping movement printed at the flowmeter 13, these points are shifted from one curve to another. This obviously does not affect the line drawing operations.

 The cable used may be electric or not. In the first case, the information from the flowmeter is transmitted by the cable to the surface where it is recorded and processed. When the cable used is a simple "piano string", the information is recorded thanks to a recorder including memories. Such a recorder is for example described in British Patent Application No. 82 31560.

 It may be advantageous to use several detectors connected at the end of the other, so as to record respective flow rates of several layers at the same time or for the same layer, at moments not far apart.

 The pressure measurements are carried out by means of a manometer (for example as described in French Patent No. 2,496,884) which can be placed in a fixed position either at the wellhead or (as shown in FIG. 16) at the top of the formation, or be linked to the flow meter 13 (at 16 '). In the latter case, it must be taken into account that the manometer is subjected to the pressure of a column of oil of variable height. Thus, measurements of the pressure p in the well as a function of time are obtained. As for flow measurements, the pressure measurements are either transmitted by an electrical cable to the surface where they are recorded, or recorded in the well using a recorder.

 In its measuring phase, the method according to the invention essentially consists in varying the flow rate Q of the well by an amount 4 'at a time t1, and in measuring the pressure and the flow rates of the respective layers of the formation just before the moment t1 then for a while after this moment.

Measurements after time t1 make it possible to draw up the flow curve networks of FIGS. 3 and 4 and the pressure curve of FIG. 5 as a function of time # elapsed from that moment. More precisely, in FIG. 5 the variations of the quantity # p x (Q # Q) are represented, Ap denoting the pressure difference measured between the instants t1 and t1 +. The pressure scale is expressed in psi (1 psi = - 6.9 kPa). Also shown are the variations of the derivative of the preceding amountAp. The abscissa and ordinate scales are logarithmic.

The table at the end of the description gives an example of simulated values of pressure variation measurements.
bp (in psi) as a function of time At (At being expressed in days and counted from time t1). Also shown are the values of the variations of the derivative (#p) ', calculated as explained below, as well as the flow measurements q1 to q5 (expressed in barrels / day and represented in FIG. 4) of the five layers of the training.

The derivative (#p) 'is computed according to the logarithm of #t, that is (#p)' = d (Ap)
d (log At)
The manner of making this calculation, as well as the interpretation of the data of the derivative, is described in the published French patent application No. 83 07075 of April 22, 1983.

 The negative values obtained for dp and (#p) 'can be explained by the superposition principle well known to the specialists. Briefly, for the measurements to be exploitable and meaningful, the flow time of the well before the change of flow must be very long compared to the period of time during which the measurements are made after the flow change.

 To draw the curves of FIG. 5, the values of Ap and (cl) 'of the array, multiplied by the ratio Q / EQ of the flow O before the change at the time t1 to the flow variation AQ before and after the time, are used. t1. In the example of the figure, O = 500 and AO = 500 - 200 = 300, the value of the flow after the time t1 having been reduced from 500 to 200 barrels / day.

This amounts to normalizing the pressure values after time t1 with the values that would have been obtained before time t1. The standardization of the curves, both with regard to pressure measurements and flow measurements, is important because it allows the measured values to be used just before the time t1 as asymptotic values for the very long times.

 This characteristic of the invention, important in practice, will be explained with reference to FIG. 7 (points P1 and P2).

 For the interpretation of the experimental pressure data, a conventional analysis, well known to those skilled in the art, is carried out, which consists in plotting different graphs in logarithmic and semi-logarithmic scales to diagnose the well storage effect (" wellbore storage "), the flow rate of oil in the reservoir, this regime can be radial and considered infinite at the well scale, the presence of several layers and the presence of any reservoir limits. Thus, in logarithmic scales, the well storage effect results in a slope equal to 1 for the pressure and pressure derivative curves corresponding to the short times (start of the curves), and the presence of a limit. or reservoir boundary results in a rise in pressure and pressure derivative values for long times (end of curves). These diagnostic methods are commonly used in the petroleum industry and are described, for example, in US Pat. No. 4,328,705 and published French Patent Application No. 83,070,75.

It is also possible to use the convolution of the total flow rate measured at the bottom of the well with the pressure so as to eliminate the well storage effect of the pressure measurements (in this case, the pressure is called "rate convolved pressure"). This technique is published in "Interpretation of Pressure Build-up
Test using In-Situ Measurement of Afterflou "Journal of Petroleum
Technology, January 1985.

In its phase of interpretation of the measurements, the method according to the invention comprises the operations of determination of the following parameters
A) kh (average product permeability kx thickness h
training for all training
considered globally);
B) k. and s. (horizontal permeability and
not a word
parietal coefficient of layer j,
j varying from 1 to 5 in the present
example);
C) type and position of the boundary or boundary
external training (which
determines the extent and type of
training);
D) vertical permeability between layers.

 A.-Determination of the parameter kh.

This is done from pressure measurements, using the following formula
141.2 QQ BV
kh =
2 (Ap) 'M in which
QQ is the variation imposed on the flow (expressed in barrels / day) of the well at time t1;
B is the relative oil volume factor in formation and surface (it is equal to the ratio of oil volumes in formation and surface);
ii is the viscosity of oil, expressed in centipoises;
(tp) 'is the value of the derivative of the pressure p as a function of the logarithm of time, in the flat part of the derived curve (Figure 5). This flat part corresponds to a radial flow with infinite action.

In this example, we find in Figure 5 that (Q. (Q / QQ) = #Q) = 5
As a result, (#p ') M = 3.

 On the other hand, by other measurements, it has been found that O = 1,2 and # = 1.

As a result, kh = 8,472 md.ft
= 25.42. 102 um2.m.

B.-Determination of k. and s ..
NOT A WORD
For each layer, the curve representing, as a function of time, the fraction of the variation of the total flow rate attributable to the layer under consideration, that is to say the quantity # qj / # Q, from the values of the table and The curves of FIG. 4 thus give five series of points, in semi-logarithmic representation (FIG. 6), respectively relating to the five layers 1 to 5 of the formation, as a function of the time Qt elapsed after time t1.

 Each series of points is then compared with the curves of a theoretical model in order to determine which of these curves coincides appropriately with the series of points considered, at least in the initial period following the instant t1 of change of the flow rate. It has been recognized that, in this period, the model used may correspond to the conditions of absence of inter-layer flow in the formation, with infinite outer boundary. After the initial period, discrepancies between measurement points and the theoretical curve may occur, due to inter-layer and outer boundary effects, or overlay effects.

dans laquelle
qjD est la transformée de Laplace du débit sans dimension de la couche j;

The theoretical model is established from the formula

in which
qjD is the Laplace transform of the dimensionless flow of layer j;

(#h)j désignant le produit porosité . hauteur de la couche j,
J n le nombre de couches de la formation, et z la variable d'espace de Laplace.sj is the parietal coefficient of layer j; k0 and k1 are modified Bessel functions of the first and second kind; PwD is the Laplace transform of the dimensionless pressure in the well;
while #j is given by:
#j = (wj z / kj) 1/2 in which with

(#h) j denoting the product porosity. height of layer j,
J n the number of layers of the formation, and z the Laplace space variable.

 Equation (1) does not give the flow as a function of time.

To obtain it, we apply to it the inverse transform of Laplace given by the Stehfest algorithm (cf "Numerical inversion of
Laplace transforms, "D-5, Communications of the ACM, January 1970, 13, No. 1, pages 47-49).

 When the coincidence is made with a given curve of the theoretical model, we can deduce the parietal coefficient sj of the layer j considered, which appears in the formula (1), as well as its permeability, which is also included in the form of the product. (kh) the permeability and the height of said layer, the latter parameter being known by prior logging measurements, while the product kh was determined using the pressure measurements explained above.

 To illustrate cases that may be encountered in practice, Figure 6 (in dashed lines) has two theoretical curves G and H which do not coincide correctly with the series of measurement points relating to layers 1 and 2 of the formation in the left side of the figure, while there is coincidence in the right part (large differences appear however (on the extreme right, due to border effects and inter-layer flow). the position of the curve G shows for example that the parietal coefficient chosen for this one is too weak and must be increased.In the case of the curve H, the opposite occurs: the parietal effect must be decreased, although the change in the value of the parietal effect of curve G has an influence on the other curves.

These operations make it possible to determine the horizontal permeability k. and the parietal coefficient s. of each
JJ layers of training.

p5f (T) étant la valeur de la variation de pression mesurée dans le puits au temps T.These parameters may, according to a second operating mode of the present invention, be determined in the following manner:
It is known by the specialists that the result of the mathematical operation of convolution of the derivative of the variations of flow q by the dimensionless pressure PD (this pressure is none other than the pressure that one would obtain if other parameters did not intervene in the formation and the well to influence the value of the pressure and if the flow rate was constant) is none other than the variations of the pressure P5f actually measured in the well opposite the formation. This results in the following equation

p5f (T) being the value of the pressure variation measured in the well at time T.

 To obtain PD, which is the value of the desired pressure, the mathematical deconvolution operation is carried out between the actual measured pressure p5f and the flow rate.

However, the results obtained by the deconvolution can be tainted with important errors if the experimental data are noisy. It is then preferred to use the convolution operation.

Thus, in the context of the present invention, the flow variations for each layer and the pressure variations in the well have been measured. It was then demonstrated that the operation of convolution of the flow variations of each layer by the pressure variations in the well provides the pressure response of the layer as if this layer were alone to produce a fluid, provided, however, that there is no flow between layers. Thus, knowing the pressure response of each layer, we can use for each of them the classical methods of interpretation, in particular the pressure versus time curves plotted in semilogarithmic scales which make it possible to determine the permeability and the parietal effect. .

C.-Determination of the external border of each zone
This is to determine the type of border of each zone:
- border appearing infinite;
- boundary without flow, behaving like a watertight wall, all the liquid flowing in the well thus coming from the formation zone situated within this boundary;
- constant pressure boundary.

 In the first case, everything happens as if there was no frontier. In the other two cases, the radius of the frontier must also be specified.

 For this determination, a graph is drawn (FIG. 7) similar to that of FIG. 6, but on which each series of points corresponds to a zone i of the formation according to the definition given above, and no longer to a particular layer ( of course, an area may comprise only one layer).

In the present example, there are two zones Z1 and Z2 (FIG. 1), and the two series of dots respectively represent the quantities
# q1 + # q2 and # q3 + # q4 + # q5
#Q #Q as a function of time # t. To plot the experimental curves of Figure 7, the values in the table are used.

Moreover, theoretical models corresponding to the formula (1) indicated above and to the formulas

In these formulas, whose formula (2) is already known, the quantities # are defined as follows: # 0k (z) = K0 (#k) I0 (reD # k) - I0 (#k) K0 (reD # k)
# 1k (z) = K1 (#k) I1 (reD # k) - I1 (#k) K1 (reD # 1)
# 01k (z) = K0 (#k) I1 (reD # k) + I @ (# k) K1 (reD # k)
# 10k (z) = K1 (#k) I0 (reD # k) + I1 (#k) K0 (reD # k) where I0, li, Kg and H1 are modified Bessel functions of the first and second kind, and reD is the dimensionless outer radius of the formation.

 The formula (1) relates to the case of a boundary behaving as if it were infinite, the formula (2) to the case of a border without flow and the formula (3) to the case of a boundary at constant pressure.

 Figure 7 shows the coincidence realized (in the initial period) between the series of points corresponding to the zones Z1 and Z2 and curves defined from the formula (2).

It can be concluded that the boundary of the zones studied is of the "no flow" type.

 If the coincidence is obtained with a curve ending in a horizontal, like the curve H corresponding to the formula (3) sketched at the top right of FIG. 7, it is a boundary of the constant pressure type. If the curve ends by bending slightly downward like the curve L resulting from the formula (1), the boundary is of the type of those which appear infinite.

 Naturally, in these operations relating to the zones of formation, it is not necessary to envisage a flow regime with vertical transfers, since such transfers are by definition non-existent between zones.

 In the case represented in FIG. 7, where it is a border without flow, that is to say where the production volume of the formation is limited, the curve corresponding to each zone tends, in its part right, to a value equal to the product fh relative to said zone, that is, in the present example, respectively 0.4 for zone Z1 and 0.6 for zone Z2. These values are also known thanks to the preliminary operations of diography.

 Figure 7 further shows that the curves deviate from the experimental points in the right part. This is due to an overlay effect due to the fact that the well in question was put into production for 200 hours (8.33 days), and then its production rate was lowered (from 500 to 200 barrels / day). ) at time t1 for another 200 hours. However, if a measurement is made at the end of the first 200-hour period, just before the time t1, we obtain results that can be shown on the figure (points P1 and P2) and which can be considered as measurement points obtained after the initial period after time t1, with no superposition effect. As can be seen, the theoretical curves pass very close to these points.

 It follows from the preceding remark that, in practice, it is possible to refrain from making measurements at times remote from the instant t1, since measurements made just before this instant advantageously compensate for them. Thus, the measurements corresponding to the points located between 100 and 101 days after t1 will not be carried out, which considerably shortens the total time to be spent on measurements on the well.

 It is thus possible to determine, by measurements only made before t1, whether the boundary is of the non-flow type (if the measuring points correspond to the known values of fh) or not (if there is not match), because this effect depends only on border conditions.

 In the case where the boundary has been recognized as non-infinite, its radius is determined by finding which radius value leads to the best coincidence of the model curves with the measurement points, in the period after the initial period. Measurement points taken just before the well rate change are also very useful in this phase of determining the parameters of the formation.

 As in the case of the determination of the permeability and parietal effect, it is possible to operate also in a second way, using the convolution operations. It has indeed been demonstrated that the convolution of the flow variations of each zone by the pressure variations in the well provides the pressure response of the zone considered. Thus, as for the individual layers, this is reduced to a conventional well test interpretation, in particular for determining the boundaries of each zone.

D.- Determination of permeability between layers
Having determined the horizontal permeability and the parietal coefficient of each of the layers of the formation, the type of the boundary of the zones and its location, it remains to determine the values of vertical permeability between layers.

This is done by analyzing, in each zone of the formation, the flow rates of the layers of this zone relative to the total flow rate thereof.

 As shown in Figure 8, we use as a function of t, always in semi-logarithmic representation and from the table data, the quantities #qji / #Qi where #Qi denotes the flow variation of zone i and bq : the variation of flow of the layer j belonging to the zone i. FIG. 8 is limited, by way of example, to the measurements relating to zone Z1, composed of layers 1 and 2, the values of which are indicated in the table (page 19).

où
4jD est le débit sans dimension de la couche j de la zone i, qui comprend couches;
CD est la constante sans dimension d'emmagasinage du puits;
rapport du produit perméabilité . hauteur pour la couche j au produit moyen Th perméabilité . hauteur pour la zone i;
aki représente la quantité ak relative à la zone i;
a K sont les racines de l'équation #n = O où Yj est un polynome défini par récurrence par :: #j = #j-1 aji - #j-2aj,j-1 aj-1,j pour j = 2, ..., n avec Y0 = 1 et Y1 = 11'
ajk désignant des éléments de la matrice [ ajk]:

The theoretical model used, established for the case where there are transfer flows between layers, is derived from the formula

or
4jD is the dimensionless flow of layer j of zone i, which comprises layers;
CD is the dimensionless constant of well storage;
ratio of product permeability. height for layer j to medium product Th permeability. height for zone i;
aki represents the quantity ak relative to zone i;
a K are the roots of the equation #n = O where Yj is a polynomial defined by recurrence by :: #j = # j-1 aji - # j-2aj, j-1 aj-1, j for j = 2 , ..., n with Y0 = 1 and Y1 = 11 '
ajk designating elements of the matrix [ajk]:

<tb><SEP>## j-1,
<tb> ajk <SEP> = <SEP># kj # 2 <SEP> - <SEP>#jz<SEP> - <SEP># j-1 <SEP><SEP> - <SEP>#j,
<tb><SEP>## j,
<tb><SEP> o, <SEP>
<tb> for k = j-1; j> 1, for k = j, for k = j + 1; j <n, for k # j - 1, j, or j + 1,
&alpha; jki is a coefficient relative to the layer j, root k, for zone i, defined by the formula

bki is an outer boundary condition factor defined by the formulas
bki = 0 for an infinite-looking boundary bki = K1 (#kireD) / I1 (#kireD) for a non-flow boundary bki = -K0 (#kireD) / I0 (#kireD) for a constant pressure boundary, while B1ki is connected to A1ki by the relation
A ki1 being determined from well conditions.

The values of parietal effect coefficients obtained in the interpretation phase (0) are used, and the type and location of the outer boundary of the formation determined in phase C) is taken into account. Finally, we search for a set of values of the parameters X. of permeability between the
J layers j and j + 1 of each zone i which gives a good coincidence of the curves for all the fractions
#qj / #What to consider.

 More precisely, it is observed that the shape of the curves in the left part of the figure depends on the permeability and the parietal effect, whereas the right part of FIG. 8 also depends on the type of boundary and the transfer flows. The permeability, the parietal effect and the type of boundary being known, the only parameter that remains is that of transfer flow, for which different values are tested until a good coincidence of the curves is obtained.

 These operations are repeated for each of the zones of the formation, in order to determine the transfer flow parameters of all the layers.

 The set of calculations and curve coincidence operations that have just been described in the context of the method according to the invention can be performed either by hand or, preferably, on a digital computer. In the first case, graphs of standard curves are drawn using the equations given previously. These graphs translate graphically the behavior of the theoretical models. One can also use a numerical calculator by means of which one selects the values of the searched parameters which correspond to a perfect identity between the theoretical and experimental variations of the different functions of the pressure and the flows (variation as a function of time of the pressure, of the derivative of the pressure, of the fraction of the variation of the total flow for a given layer and for a zone considered and of the fraction of the variation of flow of a layer compared at the rate of the zone to which this layer belongs).

TABLE #t # 2 (#p) 'q1 q2 q3 q4 q5 6.67 E - 5 23.93 3.03 9.33 46.37 52.42 34.07 57.82! 2.67 E - 4 28 , 13 3.02 12.90 40.77 53.68 36.66 56.00, 1.02 E - 3 32.16 2.91 15.73 36.20 54.78 38.63 54.66 14, 06 E - 3 36.05 2.68 18.03 32.37 55.74 40.19 53.67, 1.63 E - 2 39.62 2.23 19.98 29.03 56.56 41.51 52.93 16.65 E - 2 42.28 0.99 21; 59 26.19 57.15 42.68 52.38! 10.26 42.41 - 2.16 22.75 25.14 57.44 43.27 51.40 11.05 36.24 -12.29 25.63 27.94 56.32 41.91 48.20 4.19 8.34 -43.72 32.48 35.42 51.41 38.00 42.69 8.33 -29.69 -55.40 35.76 39.00 48.83 36.06 40, 35
In this table, the notation "E - 5" means:
"Exponential - 5".

Claims (13)

 1. A method for determining the characteristic parameters of a hydrocarbon-producing underground formation comprising a plurality of layers through which a well is drilled, characterized in that it essentially consists in determining the relative variations over time of the flow rates of layers or groups of formation layers from flow measurement points obtained while a total flow variation has been imposed on the well at a time t1 between a first constant value determined and a second constant value determined, and then comparing said variations in the flow rate at the behavior of a theoretical model established for different values of the characteristic parameters of a subterranean formation, and in deducing the values of the parameters of the formation considered from those associated with the behavior of the theoretical model which coincide best with the experimental variations of debt.  2. Method according to claim 1, characterized in that one also uses values of the pressure in the well, measured at the same time as the flow values of the different layers, which make it possible to calculate the product kh permeability x thickness of training.  3. Method according to claim 1 or 2, characterized in that for each layer j of the formation is determined the variations, as a function of time Qt, of the fraction  aq. / EQ  J representing the ratio of the variations Aqj of the flow rate of the layer j to the variation aq of the total flow of the well and which is deduced from the comparison of said variations # qj / # Q with the behavior of a theoretical model the parameters kj and sj horizontal permeability and parietal effect coefficient of said layer.  4. Method according to claim 2, characterized by the fact that a convolution operation of the flow rate variations of each layer j is carried out by the pressure variations in the well, which makes it possible to obtain the pressure response of the layer in question. as if it were alone, from which one can deduce, by classical methods of interpretation, the permeability and the coefficient of parietal effect of said layer.  5. Method according to any one of claims 1 to 4, characterized in that it is determined for each zone of the formation, that is to say for each group of producing layers between two impermeable intermediate layers, the variations, as a function of the time ht, of the fraction Zssq / hQ representing the ratio of the flow variations of said zone i to the variation of the total flow Q of the well, and which is deduced from the comparison of said variations of said fraction with the behavior of a theoretical model the type and position of the outer boundary of the zone.  6. Method according to any one of claims 1 to 4, characterized in that it performs an operation of convolution of the flow rate variations of each zone i by the pressure variations in the well, which provides the response in pressure of the zone considered, from which is deduced, by conventional methods of interpretation, the type and the outer boundary position of said zone.  7. Method according to any one of claims 1 to 6, characterized in that for each layer j is determined a zone i of the formation, that is to say a group of producing layers between two impervious intermediate layers, the variations, as a function of the time ht of the fraction #qj / #Qi representing the ratio of the variations of flow of the layer j to the variation of flow of the zone i, and which are deduced by comparing said variations of said fraction with the behavior of a theoretical model, the permeability parameters between layers of the zone considered, these operations being carried out for each of the zones of the formation.  8. Method according to any one of claims 3 to 7, characterized in that one draws curves representing the variations of said fractions and that one deduces from the coincidence of these curves with curves representing said theoretical model the characteristics of the underground formation.  9. A method according to any one of claims 1 to B, characterized in that instead of the flow measurement points corresponding to a time elapsed ht fairly important after the time t1 of flow rate change of the well, uses measurement points recorded just before this moment, the well having previously discharged for a period substantially equivalent to the value of the aforementioned elapsed time.  10. Method according to any one of claims 7 to 9, characterized in that the measurement of the eigenvalue, as a function of time, of the different layers of the formation is carried out down the well (10) at least one flowmeter (13), passing it successively opposite each of the layers (1 to 5) of the formation and by raising the values of flow that it provides when it is immediately above each layer, as well as the corresponding measuring instants, the flow rate specific to each layer (1 to 5) being then deducted from the cumulated flow rates thus recorded.  11. Process according to claim 10, characterized in that the flowmeter (13) is moved up and down over the entire height of the formation.  12. Method according to claim 2 and claim 10 or 11, characterized in that the flowmeter (13) is attached to a manometer (16) providing pressure measurements in the well (10) concomitantly with the debit.  13. The method of claim 12, characterized in that said manometer occupies a fixed position in the well.