EP0176410B1 - Verfahren zur Einzelbestimmung der Durchlässigkeit und des Wandfaktors von wenigstens zwei Schichten eines Untertagespeichers - Google Patents

Verfahren zur Einzelbestimmung der Durchlässigkeit und des Wandfaktors von wenigstens zwei Schichten eines Untertagespeichers Download PDF

Info

Publication number
EP0176410B1
EP0176410B1 EP85401719A EP85401719A EP0176410B1 EP 0176410 B1 EP0176410 B1 EP 0176410B1 EP 85401719 A EP85401719 A EP 85401719A EP 85401719 A EP85401719 A EP 85401719A EP 0176410 B1 EP0176410 B1 EP 0176410B1
Authority
EP
European Patent Office
Prior art keywords
flow rate
layer
time
reservoir
wellbore
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Expired
Application number
EP85401719A
Other languages
English (en)
French (fr)
Other versions
EP0176410A1 (de
Inventor
Fikri Kucuk
Luis C. Ayestaran
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Services Petroliers Schlumberger SA
Schlumberger NV
Schlumberger Ltd USA
Original Assignee
Societe de Prospection Electrique Schlumberger SA
Schlumberger NV
Schlumberger Ltd USA
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Societe de Prospection Electrique Schlumberger SA, Schlumberger NV, Schlumberger Ltd USA filed Critical Societe de Prospection Electrique Schlumberger SA
Priority to AT85401719T priority Critical patent/ATE39159T1/de
Publication of EP0176410A1 publication Critical patent/EP0176410A1/de
Application granted granted Critical
Publication of EP0176410B1 publication Critical patent/EP0176410B1/de
Expired legal-status Critical Current

Links

Images

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • E21B49/008—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells by injection test; by analysing pressure variations in an injection or production test, e.g. for estimating the skin factor

Definitions

  • the invention relates to well testing in general and in particular to a method for downhole measurements and recording of data from a multiple layered formation of an oil and gas well and for estimating individual permeabilities and skin factors of the layers using the recorded data.
  • One of the major problems for layered reservoirs is the definition of the layers. It has been found that it is essential to integrate all logs and pressure transient and flowmeter data in order to determine flow capacities, skin factors, and the pressure of individual layers.
  • This invention relates primarily to two-layer reservoirs with a flow barrier between the layers (without crossflow). The production is commingled at the wellbore only.
  • This invention relates to the behavior of a well in an infinite two-layered reservoir. If the well has a well-defined drainage boundary (symmetrics about the well axis for both layers), and if a well test is run long enough, the prior art has shown that it is possible to estimate the individual layer permeabilities and an average skin. However, cost or operational restrictions can make it impractical to carry out a test of sufficient duration to attain a pseudo steady-state period. Moreover, even if the test is run long enough, an analyzable pseudo steady-state period may not result because of non-symmetric or irregular drainage boundaries for each layer. It is also difficult to maintain a constant production rate long enough to reach a pseudo steady-state period.
  • a major problem for layered systems not addressed by the prior art is how to estimate layer permeabilities, skins, and pressures from conventioal well testing.
  • the conventional tests drawdown and/or buildup
  • the conventional tests only reveal the behavior of a two-layer formation which cannot be distinguished from the behavior of a single-layer formation even though a two-layer reservoir has a distinct behavior without wellbore storage effect.
  • a well test method for uniquly estimating permeability and skin factor for each of at least two layers of a reservoir includes the positioning of a logging tool of a logging system at the top of the upper layer of a wellbore which traverses the two layers.
  • the logging system has means for measuring downhole fluid flow rate and pressure as a function of time.
  • the surface flow rate of the well is changed from an initial flow rate at an initial time, t 1 , during a first time interval.
  • the downhole fluid flow rate, q i (t), and downhole pressure, p l (t) are measured and recorded during the first interval, t, to 2 , at the top of the upper layer.
  • the logging tool is then positioned to the top of the lower layer where the downhole flow rate, q 12 , from the top of the lower layer is measured and recorded if possible at a stabilized flow.
  • the surface flow rate is then changed at time t 3 , to another flow rate.
  • the downhole fluid flow rate, q 22 (t), and downhole pressure, p 2 (t) are measured and recorded during the second interval, t 3 to t 4 , at the top of the lower layer.
  • the parameters k 1 and s 1 for the first layer are determined from estimates of k 2 , s 2 and k and s.
  • Testing regimes are defined for non-flowing wells and for flowing wells. Estimation methods are presented for matching measured values of pressure and flow rate with calculated values, where the calculated value changes as a result of changes in the parameters to be estimated, k and s.
  • Figures 1 and 2 illustrates a two layered reservoir, the parameters of permeability, k, and skin factor s, of each layer of which are to be determined according to the method of this invention. Although a two-layered reservoir is illustrated and considered, the invention may be used equally advantageously for reservoirs of three or more layers. A description of a mathematical model of the reservoir is presented which is used in the method according to the invention.
  • the reservoir model of Figures 1 and 2 consists of two layers that communicate only through the wellbore. Each layer is considered to be infinite in extent with the same initial pressure.
  • each layer is homogeneous, isotropic, and horizontal, and that it contains a slightly compressible fluid with a constant compressibility and viscosity.
  • the Laplace transform of the production rate for each layer can be written as:
  • Eqs. 1 and 2 give the unsteady-state pressure distribution and individual production rate, respectively, for a well producing at a constant rate in an infinite two-layered reservoir.
  • the basic problem of prior art methods for estimating layer parameters is that the pressure data are not sufficient to estimate the properties of layered reservoirs.
  • the invention described here is for a two-step drawdown test with the simultaneously measured wellbore pressure and flow rate data which provides a better estimate for layer parameters than prior art drawdown or buildup tests. Eqs. 1 and 2 will be used to describe the behavior of two-layered reservoirs.
  • the convolution integral (Duhamel's theorem) is used to derive solutions from Eq. 1 for time-dependent wellbore (inner boundary) conditions.
  • the constant wellbore storage case is a special time-dependent boundary condition.
  • the wellbore pressure drop is given by
  • Wellbore storage effects for layered reservoirs may be expressed as: where a is dependent on reservoir and wellbore fluid properties.
  • the problem of identifiability has received considerable attention in history matching by the prior art.
  • the purpose here is to give an identifiability criterion to nonlinear estimation of layer parameters, Dogru, A. H., Dixon, T. N., and Edgar, T. F: "Confidence Limits on the Parameters and Prediction of Slightly Compressible, Single-Phase Reservoirs", Soc. Pet. Eng. J. (Feb. 1977) 42-56.
  • the identifiability principles given here are very general, and are also applied to other similar reservoir parameter estimations.
  • the main objective of this section is to estimate layer parameters using the model presented by Eq. 1 and measured wellbore pressure data. For convenience, it is assumed that the measured pressure is free of errors.
  • the positive definiteness of the Hessian matrix requires that all of the eigenvalues corresponding to the system be positive and greater than zero. If an eigenvalue of the Hessian matrix is zero, the functional defined by Eq. 8 does not change along the corresponding eigenvector, and the solution vector ⁇ * is not unique. Therefore, the number of observable parameters from m measurements can be determined theoretically by examining the rank of the Hessian matrix H, which is equal to the number of nonzero eigenvalues.
  • a non-zero cutoff value must be used in estimating the rank of the.Hessian.
  • a normalization of the sensitivity coefficient matrix can be carried out by multiplying every column of the sensitivity coefficient matrix by the corresponding nonzero parameter value. That is, Furthermore, the largest sensitivity of the functional two parameters is along the eigenvector corresponding to the largest eigenvalue. Each element of the eigenvector v j corresponds to a parameter in the n dimensional parameter space. The magnitude indicates the relative strength of that parameter along the eigenvector v j .
  • the pressure data for each case are generated by using Eq. 1 and Eq. 3 with the corresponding q D solution. Reservoir and fluid data are given in Table 1 for all these cases.
  • the nonlinear least squares Marquardt method with simple constraints is used for the minimization of Eq. 8 with respect to k 1 , k 2 , s, and s 2 .
  • Table 2 shows the eigenvalues of the Hessian matrix for each test.
  • transient pressure data does not give enough information to determine uniquely flow capacity and skin factor for each individual layer.
  • a drawdown test is best suited for two-layered reservoirs without crossflow.
  • a reservoir to be tested should be in complete pressure equilibrium (uniform pressure distribution) before a drawdown test.
  • the complete pressure equilibrium condition cannot be satisfied throughout the reservoir if wells have been producing for some time from the same formation. Nevertheless, the pressure equilibrium condition can easily be obtained in new and exploratory reservoirs.
  • Figures 1 and 2 illustrate a two zone reservoir with a wellbore 10 extending through both layers and to the earth's surface 11.
  • a well logging tool 14 having means for measuring downhole pressure and fluid flow rate communicates via logging cable 16 to a computerized instrumentation and recording unit 18.
  • the parameters k i , s, of layer 1 and k 2 , s 2 of layer 2 are desired to be uniquely estimated.
  • One layer, such as layer 2 may have a damaged zone which would result in a high value of s 2, skin factor of layer 2, which if known by measurement by the well operator, could aid in decisions relating to curing low flow or pressure from the well.
  • FIG. 3A shows the test procedure.
  • time t i the well should be started to produce at a constant rate at the surface, if possible.
  • production rate does not affect the analysis, a rapid rate increase can cause problems. A few of these are:
  • the third problem which is the most important one, can be avoided by monitoring the flowing wellbore pressure and adjusting the rate accordingly. These three complicating factors should be avoided for all the transient tests, if possible.
  • the well tool 14 is lowered to the top of the lower zone as illustrated in Figure 2 while monitoring measured flow rate and pressure. If there is a recordable rate from this layer, at time t 2 , the production rate should be changed to another rate. The rate can be increased or decreased according to the threshold value of the flowmeter and the bubble point pressure of the reservoir fluid. As can be seen in Figure 3A, the flow rate is increased. If the rate is not recordable the test is terminated. A buildup test for further interpretation as a single-layered reservoir could be performed.
  • the test should be continued from t 3 to t 4 for another few hours until another storage-free infinite acting period is reached. The test can be terminated at time t 4 .
  • the interpretation of measured rate and pressure data is discussed below after the test for a producing or short shut-in well is described.
  • a short flow profile (production logging) test should be conducted to check if the bottom layer is producing. If there is enough production from the bottom layer to be detected, then as in Figure 1, the production logging tool 14 is returned to the top of the whole producing reservoir and the test is started by decreasing the flow rate, q 1 (t 1 as in Figure 4A to another rate, q 1 (t 2 ). The well is allowed to continue flowing until time t 2 , when the well reaches the storage-free infinite acting period. At the end of this period, the tool string should be lowered just to the top of the bottom layer as in Figure 2. At the time t 3 , the flow rate is increased back to approximately q 1 (t 1 During the test, the rates should be kept above the threshold value of the flowmeter, and well bore pressure should be kept above the bubble point pressure of the reservoir fluid.
  • test procedure described above is applicable for a layer system in which the lower zone permeability in less than the upper zone. If the upper zone is less permeable, then the testing sequence should be changed accordingly.
  • the method according to the invention is described to estimate individual layer parameters from measured wellbore pressure and sandface rate data.
  • the automatic type-curve (history) matching techniques are used to estimate k 1 , k 2 , sy, and s 2 . In other words, Eq. 8 is minimized with respect to parameters k 1 , k 2 , S1 and s 2 .
  • An automatic type-curve matching method is described in Appendix B to this description of the invention. Unlike the semilog method, the automatic type curve matching usually fits early time data as well as the storage-free infinite acting period if it exists to a given model.
  • Figure 5 presents the wellbore pressure data for synthetic sequential drawdown tests
  • Figure 6 presents sandface flow rate data for the same test using the reservoir and fluid data given in Table 1.
  • the test is started from the initial conditions and the well continues to produce 238 m 3 /day (1,500 bbl/day) for 12 hours.
  • the rate is increased from 238 m 3 /day (1,500 bbl/day) to 476 m 3 /day (3,000 bbl/day).
  • Figure 6 shows the total and individual flow rates from each zone.
  • q l (t) only total flow rate, q l (t) will be measured.
  • the rate from the bottom zone will be measured. It is also important to record the flow rate from the lower layer for a few minutes just before the second drawdown test.
  • the automatic type-curve matching approach is suitable for this purpose. If it is applicable, the semilog portion of the pressure data should also be analyzed. In general, type-curve matching with the wellbore pressure and sandface rate is rather straightforward. A brief mathematical description of the automatic type-curve matching procedure is given in Appendix B. In any case, the automatic type-curve method that is used fits the first drawdown data to a single layered, homogeneous model. The estimated values of and 5 are where
  • the rate from the bottom layer, q 12 should also be measured before starting the second drawdown test.
  • k 1 , k 2 , s 1, and s 2 can be calculated by using deconvolution methods.
  • the deconvolution process is very sensitive to measurement errors, particularly errors in flow rate measurements.
  • the convolution process, Eq. 3 is a smoothing operation, and it is less sensitive to measurement errors.
  • the second drawdown test described below almost assures an accurate estimation of the layer parameters.
  • the second transient creates enough sensitivity to the parameters of the less permeable layer.
  • Figures 5 and 6 present wellbore pressure and rate data respectively for the second as well as the first drawdown. These data are analyzed using the automatic type-curve matching method described above.
  • the computed sandface rate of the bottom layer-for a variable total rate can be expressed as:
  • ⁇ p wf is the measured well bore pressure during the second drawdown.
  • the Laplace transform of f(t) function in Eq. 16 can be expressed as (from Eq. 2):
  • the function f(z) in Eq. 17 is only a function of the lower layer parameters, k 2 and s 2 .
  • ⁇ ( ⁇ ,t) can be obtained by automatic type-curve matching.
  • Eq. 15 is used to estimate k 2 and s 2 .
  • the direct solution of Eq. 16 gives correct values of the sandface flow rate for the constant wellbore storage case.
  • the f(z) function is the Laplace transform of the dimensionless rate, q o , for a well producing a constant pressure in an infinite radial reservoir.
  • the flow rate q D changes very slowly with time.
  • f(t) is not very sensitive to change in k 2 and s 2 . This ill-posedness becomes worse if the sandface rate is not accurately measured at very early times.
  • an alternate approach for the estimation of k 2 and s 2 is used to produce a more accurate estimate.
  • n( ⁇ ,t) the total rate, q o , must be measured.
  • the total rate cannot be measured unless two flowmeters are used simultaneously. This is not practical using currently available logging tools. Thus, q o must be determined independently. This is not difficult since during the first drawdown, the behavior of the wellbore storage is known.
  • the sandface flow rate can either be approximated by Eq. 5 or 6 or any other form. It is also important to measure total flow rate just at the end of the second drawdown test. If the wellbore storage is constant, the problem becomes easier.
  • the Laplace transform of ⁇ ( ⁇ ,t) can be written from Eq. 18 as,
  • k 2 and s 2 can be estimated by minimizing Eq. 15 with respect to measured rate, q 22 (t), and calculated rate, ⁇ ( ⁇ ,t), from Eq. 19.
  • the estimated k 2 and s 2 are: and These values are very close to the actual values.
  • the first method can be used to estimate the lower limit of k 2 and s 2 in order to check the values calculated from the second method.
  • a method for testing a well to estimate individual permeabilities and skin factors of layered reservoirs has been provided.
  • the invention provides unique estimates of layer parameters from simultaneously measured wellbore and sandface flow rate data which are sequentially acquired from both layers.
  • the invention provides unique estimates of the parameters distinguished from prior art drawdown or buildup tests using only wellbore pressure data.
  • the invention uses in its estimation steps the nonlinear least-squares (Marquardt) method to estimate layer parameters from simultaneously measured wellbore pressure and sandface flow rate data.
  • a general criterion is used for the quantitative analysis of the uniqueness of estimated parameters.
  • the criterion can be applied to automatic type-curve matching techniques.
  • the new testing and estimation techniques according to the invention can be extended to multilayered reservoirs.
  • one drawdown test per layer should be done for multilayered reservoirs.
  • the wellbore pressure and the sandface rate should be measured simultaneously.
  • the new testing technique can be generalized straightforwardly to layered reservoirs with crossflow.
  • the testing method according to the invention also can be used to estimate skin factors for each perforated interval of a well in a single layer reservoir.
  • the analysis technique has to be slightly modified.
  • the initial pressure of each layer can be obtained easily from wireline formation testers.
  • Nonlinear parameter estimation methods used in the testing method according to the invention provides a means to determine the degree of uncertainty of the estimated parameters as a function of the number of measurements as well as the number of parameters to be estimated for a given model.
  • Prior art graphical type-curve methods cannot provide quantitative measures to the "matching" with respect to the quality of the measured data and the uniqueness of the number of parameters estimated.
  • Eq. A-2 The right-hand side of Eq. A-2 can be integrated directly. Substitution of the integration results in Eq. 3 yields where and the first term in Eq. A-4 is given by In Eqs. A-3 to A-5,q d is normalized measured sandface rate defined as
  • ⁇ p sf For type-curve matching the ⁇ p sf is model dependent. For a homogeneous single-layer system, ⁇ p sf is given by
  • the cylindrical source solution can also be used instead of the line source solution that is given by Eq. A-7.
  • the difference between the two solutions is very small.
  • many function evaluations may be needed.
  • Eq. A-7 will be used. If the Laplace transform solution is used, the minimization becomes very costly because for a given time, at least 8 function evaluations have to be made in order to obtain ⁇ psf (t).
  • the time step is fixed by the sampling rate of the measured data. It is preferred for the integration that the data sampling rate be less than 0.1 hours; i.e., t 1 -t 1-1 ⁇ 0.1 hours.
  • Eq. 8 In order to estimate k and s from measured wellbore pressure and sandface flow rate data, Eq. 8 is minimized. Eq. 8 can be written as where
  • Eq. 1 should be used for ⁇ p sf (t) instead of Eq. A-7.

Landscapes

  • Mining & Mineral Resources (AREA)
  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Physics & Mathematics (AREA)
  • Fluid Mechanics (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Chemical & Material Sciences (AREA)
  • Analytical Chemistry (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Environmental & Geological Engineering (AREA)
  • Sampling And Sample Adjustment (AREA)
  • Measuring Volume Flow (AREA)
  • Management, Administration, Business Operations System, And Electronic Commerce (AREA)
  • Cosmetics (AREA)
  • Measuring And Recording Apparatus For Diagnosis (AREA)
  • Investigating Or Analysing Biological Materials (AREA)
  • Investigating Or Analyzing Non-Biological Materials By The Use Of Chemical Means (AREA)

Claims (7)

1. Bohrlochuntersuchungsverfahren zum eindeutigen Abschätzen der entsprechenden Durchlässigkeiten k1, k2 und des Wandfaktors s1, s2 von wenigstens zwei Schichten (layer-1, layer-2) entsprechender Mächtigkeit h1, h2 eines Untertagespeichers, wobei ein Logwerkzeug (14), das mit Mitteln zum Messen von bohrlochseitigen Fluiddurchflußleistungen und Drücken als Funktion der Zeit, in das Bohrloch abgesenkt wird, wobei das Untersuchungsverfahren folgende Schritte umfaßt:-
Positionieren des besagten Logwerkzeugs (14) an der Oberseite der oberen Schicht (layer-1);
Ändern der Oberflächendurchflußleistung von einer anfänglichen Durchflußleistung zu einer Anfangszeit t1;
Messen und Aufzeichnen der bohrlochseitigen Fluiddurchflußleistung q1(t) und des bohrlochseitigen Drucks p1(t) während eines ersten Zeitintervals t, bis t2;
Positionieren des besagten Logwerkzeugs (14) an der Oberseite der unteren Schicht (layer-2);
Messen und Aufzeichnen der bohrlochseitigen Fluiddurchflußleistung q12(t3) zur Zeit t3;
Ändern der Oberflächendurchflußleistung zur Zeit t34 auf eine andere Durchflußleistung;
Messen und Aufzeichnen der bohrlochseitigen Fluiddurchflußleistung q22(t) und des bohrlochseitigen Drucks p2(t) während eines zweiten Zeitintervals t3 bis t4;
Abschätzen von Werten k bzw. s, die für die Durchlässigkeit und den Wandfaktor des Untertagespeichers repräsentativ sind, und zwar entsprechend einem Modell für einen einschichtigen, homogenen Untertagespeicher, wobei
Figure imgb0055
und
Figure imgb0056
ist, indem die gemessene Änderung im bohrlochseitigen Druck
Figure imgb0057
mit der Faltung der gemessenen Fluiddurchflußleistung q1(t) und einer Einflußfunktion Δpsf(t), die eine Funktion der Durchlässigkeit k und des Wandfaktors 5 ist, angepaßt wird;
Bestimmen der Durchlässigkeit k2 und des Wandfaktors s2 der unteren Schicht (layer-2) durch Anpassen der gemessenen Fluiddurchflußleistung q22(t) mit der Flatung der gemessenen Änderung im bohrlochseitigen Druck
Figure imgb0058
und einer Einflußfunktion f(t), die eine Funktion der Durchlässigkeit k2 und des Wandfaktors s2 der unteren Schicht (layer-2) ist; und
Bestimmen der Durchlässigkeit k, und des Wandfaktors s, aus Abschätzungen der Durchlässigkeiten k, k2 und der Wandfaktoren s, s2.
2. Verfahren nach Anspruch 1, wobei die Einflußfunktion Δpsf(t)
Figure imgb0059
ist, wobei
µ=Fluidviskosität des Untertagespeichers in cP,
φ=Untertagespeicherporosität, Bruchteil,
rw=Bohrlochradius und
Ei=Exponentialintegral ist.
3. Verfahren nach Anspruch 2, wobei die gemessen Änderung im bohrlochseitigen Druck Δp1(t) an den berechneten bohrlochseitigen Druck Δpwf(t) angepaßt wird, wobei
Figure imgb0060
ist, durch Minimieren der Funktion
Figure imgb0061
wobei
β=[k, s] ist.
4. Verfahren nach Anspruch 1, wobei für die untere Schicht die gemessene Fluiddurchflußleistung q22(t) mit einer berechneten Fluiddurchflußleistung η(ß,t) gemäß folgender Relation
Figure imgb0062
angepaßt wird, wobei q'D die gesamte normierte Leistung und die Laplace-Transformation der Relation
Figure imgb0063
Figure imgb0064
ist, wobei
β2=k2h2/µ,
C=Bohrlochspeicherkonstante,
z=Laplacesche Bildraumvariable,
rw=Bohrlochradius,
Ko=modifizierte Besselfunktion zweiter Art und nullter Ordnung,
K1=modifizierte Besselfunktion zweiter Art und erster Ordnung und
µ=Fluidviskosität des Untertagespeichers ist.
5. Verfahren nach Anspruch 4, wobei die gemessen Fluiddurchflußleistung q22(t) an die berechnete Fluiddurchflußleistung η)(ß,t) durch Minimieren der Funktion
Figure imgb0065
angepaßt wird, wobei β=[k2,s2] ist.
6. Verfahren nach Anspruch 1, wobei die Bohrlochuntersuchung für ein strömungsfreies Bohrloch ist und die Oberflächendurchflußleistung von einem Wert q1(t1) einer Null-Durchflußleistung zu einer Anfangszeit t1 auf eine stabilisierte Durchflußleistung q1(t2) zu einer Zeit t2 erhöht sowie von der Oberflächendurchflußleistung q2(t3) zu einer Zeit t3 auf eine stabilisierte Durchflußleistung q2(t4) zu einer späteren Zeit t4 erhöht wird.
7. Verfahren nach Anspruch 1, wobei die Bohrlochuntersuchung für ein förderndes Bohrloch ist und die Oberflächendurchflußleistung von einer Durchflußleistung q1(t1) ungleich null zu einer Anfangszeit t, auf eine stabilisierte Durchflußleistung q1(t2) abgesenkt und von der Oberflächendurchflußleistung q1(t3) zu einer Zeit t3 auf eine stabilisierte Durchflußleistung q2(t4) zu einer späteren Zeit erhöht wird.
EP85401719A 1984-09-07 1985-09-05 Verfahren zur Einzelbestimmung der Durchlässigkeit und des Wandfaktors von wenigstens zwei Schichten eines Untertagespeichers Expired EP0176410B1 (de)

Priority Applications (1)

Application Number Priority Date Filing Date Title
AT85401719T ATE39159T1 (de) 1984-09-07 1985-09-05 Verfahren zur einzelbestimmung der durchlaessigkeit und des wandfaktors von wenigstens zwei schichten eines untertagespeichers.

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US64811384A 1984-09-07 1984-09-07
US648113 1984-09-07

Publications (2)

Publication Number Publication Date
EP0176410A1 EP0176410A1 (de) 1986-04-02
EP0176410B1 true EP0176410B1 (de) 1988-12-07

Family

ID=24599492

Family Applications (1)

Application Number Title Priority Date Filing Date
EP85401719A Expired EP0176410B1 (de) 1984-09-07 1985-09-05 Verfahren zur Einzelbestimmung der Durchlässigkeit und des Wandfaktors von wenigstens zwei Schichten eines Untertagespeichers

Country Status (4)

Country Link
EP (1) EP0176410B1 (de)
AT (1) ATE39159T1 (de)
AU (1) AU579182B2 (de)
DE (1) DE3566702D1 (de)

Families Citing this family (16)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
DE3566702D1 (en) * 1984-09-07 1989-01-12 Schlumberger Ltd Method for uniquely estimating permeability and skin factor for at least two layers of a reservoir
CA1277157C (en) * 1985-07-23 1990-12-04 Christine Ehlig-Economides Process for measuring flow and determining the parameters of multilayer hydrocarbon-producing formations
FR2585404B1 (fr) * 1985-07-23 1988-03-18 Flopetrol Procede de determination des parametres de formations a plusieurs couches productrices d'hydrocarbures
EP0429078A1 (de) * 1986-05-15 1991-05-29 Soletanche Verfahren und Vorrichtung zum Messen der Grunddurchlässigkeit
US5247829A (en) * 1990-10-19 1993-09-28 Schlumberger Technology Corporation Method for individually characterizing the layers of a hydrocarbon subsurface reservoir
FR2678679B1 (fr) * 1991-07-05 1993-10-29 Services Projets Procede et dispositif pour evaluer la qualite de production d'un puits, notamment de petrole.
NO305259B1 (no) * 1997-04-23 1999-04-26 Shore Tec As FremgangsmÕte og apparat til bruk ved produksjonstest av en forventet permeabel formasjon
US6347666B1 (en) 1999-04-22 2002-02-19 Schlumberger Technology Corporation Method and apparatus for continuously testing a well
US6357525B1 (en) 1999-04-22 2002-03-19 Schlumberger Technology Corporation Method and apparatus for testing a well
US6382315B1 (en) 1999-04-22 2002-05-07 Schlumberger Technology Corporation Method and apparatus for continuously testing a well
US6330913B1 (en) 1999-04-22 2001-12-18 Schlumberger Technology Corporation Method and apparatus for testing a well
RU2460878C2 (ru) * 2010-09-30 2012-09-10 Шлюмберже Текнолоджи Б.В. Способ определения профиля притока флюидов и параметров околоскважинного пространства
RU2455482C2 (ru) * 2010-09-30 2012-07-10 Шлюмберже Текнолоджи Б.В. Способ определения профиля притока флюидов и параметров околоскважинного пространства
RU2461026C1 (ru) 2011-05-31 2012-09-10 Шлюмберже Текнолоджи Б.В. Способ определения геометрических характеристик трещины гидроразрыва
CN110486009B (zh) * 2019-09-02 2023-10-31 合肥鼎盛锦业科技有限公司 一种无限大地层的参数自动反求方法及系统
CN114165217B (zh) * 2020-09-11 2023-09-26 中国石油天然气股份有限公司 有效渗透率的确定方法、装置、计算机设备及存储介质

Family Cites Families (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3321965A (en) * 1964-10-08 1967-05-30 Exxon Production Research Co Method for testing wells
US3636762A (en) * 1970-05-21 1972-01-25 Shell Oil Co Reservoir test
FR2434923A1 (fr) * 1978-08-30 1980-03-28 Schlumberger Prospection Procede d'essais de puits
US4328705A (en) * 1980-08-11 1982-05-11 Schlumberger Technology Corporation Method of determining characteristics of a fluid producing underground formation
DE3566702D1 (en) * 1984-09-07 1989-01-12 Schlumberger Ltd Method for uniquely estimating permeability and skin factor for at least two layers of a reservoir

Non-Patent Citations (4)

* Cited by examiner, † Cited by third party
Title
Dogru, A.H. and Steinfeld, J.H., "Design of Well Tests to Determine the Properties of Stratified Reservoirs," Proceedings of 5th SPE Symposium on Reservoir Simulation, Denver, CO, February 1-2, 1979. *
Dogru, A.H., Dixon, T.N, and Edgar, T.F: "Confidence Limits on the Parameters and Prediction of Slightly Compressible, Single-Phase Reservoirs," Soc. Pet. Eng. J. (Feb 1977) 42-56. *
Lefkovits, H.C. et al.: "A Study of the Behavior of Bounded Reservoirs Composed of Stratified Layers," Soc. Pet. Eng. J. (March 1961) 43-58; Trans., AIME, 222 (copy enclosed) *
Rosa, A.J. and Horne, U.N.: "Automated Type-Curve Matching in Well Test Analysis Using Laplace space Determination of Parameter Gradients," SPE paper SPE 12131 presented at the SPE-AIME 58th Annual Fall Technical Conference and Exhibition, San Francisco, CA (Oct. 5-8, 1983). *

Also Published As

Publication number Publication date
DE3566702D1 (en) 1989-01-12
EP0176410A1 (de) 1986-04-02
AU4713385A (en) 1986-03-13
AU579182B2 (en) 1988-11-17
ATE39159T1 (de) 1988-12-15

Similar Documents

Publication Publication Date Title
US4799157A (en) Method for uniquely estimating permeability and skin factor for at least two layers of a reservoir
EP0176410B1 (de) Verfahren zur Einzelbestimmung der Durchlässigkeit und des Wandfaktors von wenigstens zwei Schichten eines Untertagespeichers
EP0520903B1 (de) Verfahren zur Bestimmung der horizontalen und/oder vertikalen Permeabilität einer irdischen Formation
US7032661B2 (en) Method and apparatus for combined NMR and formation testing for assessing relative permeability with formation testing and nuclear magnetic resonance testing
CA2034444C (en) Method and apparatus for the determination of formation fluid flow rates and reservoir deliverability
EP1649140B1 (de) Verbesserte druck/volumen-bohrlochtests für blasenpunktdruck
US4936139A (en) Down hole method for determination of formation properties
US7059179B2 (en) Multi-probe pressure transient analysis for determination of horizontal permeability, anisotropy and skin in an earth formation
US5644076A (en) Wireline formation tester supercharge correction method
US5789669A (en) Method and apparatus for determining formation pressure
US20030213591A1 (en) Well testing using multiple pressure measurements
US7849736B2 (en) Method for calculating the ratio of relative permeabilities of formation fluids and wettability of a formation downhole, and a formation testing tool to implement the same
US11230923B2 (en) Apparatus and method for determining properties of an earth formation with probes of differing shapes
US20090114009A1 (en) Method for analysis of pressure response in underground formations
Kuchuk Interval pressure transient testing with MDT packer-probe module in horizontal wells
WO2019219153A2 (en) Estimation of free water level and water-oil contact
US7021405B2 (en) Determining gradients using a multi-probed formation tester
US9988902B2 (en) Determining the quality of data gathered in a wellbore in a subterranean formation
US20070157719A1 (en) Practical Methods to Estimate Horizontal and Vertical Permeabilities
US8919438B2 (en) Detection and quantification of isolation defects in cement
Kuchuk et al. Estimating permeability distribution from 3D interval pressure transient tests
Badry et al. New wireline formation tester techniques and applications
US20040251021A1 (en) Apparatus and methods for canceling the effects of fluid storage in downhole tools
Partouche et al. A Technology Update in Wireline Formation Testing
Guo et al. Integrated Workflow on Single Well Productivity Estimation in a Laminated Reservoir of South China Sea

Legal Events

Date Code Title Description
PUAI Public reference made under article 153(3) epc to a published international application that has entered the european phase

Free format text: ORIGINAL CODE: 0009012

AK Designated contracting states

Kind code of ref document: A1

Designated state(s): AT DE FR GB IT NL

17P Request for examination filed

Effective date: 19861001

17Q First examination report despatched

Effective date: 19870504

GRAA (expected) grant

Free format text: ORIGINAL CODE: 0009210

AK Designated contracting states

Kind code of ref document: B1

Designated state(s): AT DE FR GB IT NL

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: IT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT;WARNING: LAPSES OF ITALIAN PATENTS WITH EFFECTIVE DATE BEFORE 2007 MAY HAVE OCCURRED AT ANY TIME BEFORE 2007. THE CORRECT EFFECTIVE DATE MAY BE DIFFERENT FROM THE ONE RECORDED.

Effective date: 19881207

Ref country code: FR

Free format text: THE PATENT HAS BEEN ANNULLED BY A DECISION OF A NATIONAL AUTHORITY

Effective date: 19881207

Ref country code: AT

Effective date: 19881207

REF Corresponds to:

Ref document number: 39159

Country of ref document: AT

Date of ref document: 19881215

Kind code of ref document: T

REF Corresponds to:

Ref document number: 3566702

Country of ref document: DE

Date of ref document: 19890112

EN Fr: translation not filed
PLBE No opposition filed within time limit

Free format text: ORIGINAL CODE: 0009261

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: NO OPPOSITION FILED WITHIN TIME LIMIT

26N No opposition filed
PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: DE

Effective date: 19900601

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: NL

Payment date: 19910930

Year of fee payment: 7

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: NL

Effective date: 19930401

NLV4 Nl: lapsed or anulled due to non-payment of the annual fee
REG Reference to a national code

Ref country code: GB

Ref legal event code: IF02

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: GB

Payment date: 20040901

Year of fee payment: 20

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: GB

Free format text: LAPSE BECAUSE OF EXPIRATION OF PROTECTION

Effective date: 20050904

REG Reference to a national code

Ref country code: GB

Ref legal event code: PE20