Fluid identification and saturation estimation using CSEM and seismic data

Abstract

A method for fluid identification and saturation estimation in subsurface rock formations using the Controlled Source Electromagnetic (CSEM) data and Seismic Data by calculating the fluid saturation (S.sub.fl) in a reservoir given the resistivity obtained from CSEM data, and acoustic impedance obtained from the seismic data, comprising the following steps: a) obtaining wireline data within a zone of interest in a nearby well and determining the resistivity of water by calibrating the background resistivity trend with a reference S.sub.fl curve, b) obtaining inverted CSEM survey data from a subsurface zone of interest, c) obtaining inverted seismic data in the form of Acoustic Impedance (AI), d) bringing both the inverted CSEM and acoustic impedance data to a same domain; time or depth, f) calculating fluid saturation using a rock physics model inputting the resistivity of water along with inverted CSEM and acoustic impedance data, resulting in a S.sub.fl profile.

Claims

1. A method for the estimation of fluid saturation in a subsurface reservoir comprising the following steps: using data provided by inverted CSEM (112), acoustic impedance inverted from seismic (113), and at least one nearest well providing at least three well-logging probes measuring three different parameters (111), selected so that a) the product of the velocity of sound obtained from one logging-tool (115) with the density data obtained from the second logging-tool, hereby called acoustic impedance (116) develop in the same direction in response to a volumetric change of the water, and target fluid in the said sedimentary rocks, characterized by b) the third probe produces measurement signals hereby modified to a resistivity ratio function (117) developing in opposite directions to each other due to the target fluid variation, on the one hand, and the water content, on the other, in the same sedimentary rocks, and c) the three well-logging probes being further selected so that the resulting pairs within the acoustic impedance-resistivity ratio plane correspond to an equal fluid saturation, associated respectively with the said rocks comprising a given percentage of rock matrix or water, are equal represented by one pair of values of the representative parameters of the 100% fluid saturation, creating a system of sets of pairs of values of the acquired parameters, to obtain a continuous representation of the fluid saturation of the formations penetrated by the well, d) estimating the resistivity background within the formation of interest (120), simultaneously obtaining the resistivity of water (121) to further use in calculations, e) obtaining inverted CSEM survey data (112) from a subsurface zone of interest, f) obtaining inverted seismic data (113) in the form of acoustic impedance, g) bring the inverted CSEM and acoustic impedance data into same domain (122) either in depth, or time, h) estimating a fluid saturation S.sub.fl (124) using an equation by inputting the said data (123), whereby S.sub.fl=1S.sub.w.

2. The method of claim 1, wherein the measurements made by at least three well probes are employed, adapted for measuring the electric resistivity of the formation penetrated, the transit time of sound through the same ground, and the density of the said ground.

3. The method of claim 2, wherein the measurements made by the acoustic tool are converted to sound velocity (115), the product of the sound velocity values with the density readings obtained by the density tool is used, calling which as acoustic impedance (116) values.

4. The method as claimed in claim 2, a resistivity ratio function is defined as the square root of the ratio between the resistivity of water and the resistivity values obtained from the resistivity probe (117).

5. The method of claim 2, wherein measurements made by a well probe measuring the electric resistivity of the zone in the sub-surface and two other well probes measuring the transit time of sound and the density through this same zone, a representation diagram is chosen as a function of the resistivity ratio function and of the acoustic impedance where said system of sets of pairs of values of the parameters acquired, each associated with the same saturation, may be likened to a set of parallel iso-fluid saturation curves, the fluid saturation associated with each pair of values of the acoustic impedance and of the resistivity ratio measured in the well then being determined by identifying the saturation curve passing through the point representative of said pair in the chosen representation diagram (118).

6. The method of claim 2, wherein the slope of iso-volumetric content curves is controlled by the tortuosity factor a that is selected for a formation zone considering the pore structure, grain size and level of compaction.

7. The method of claim 2, wherein the resistivity of water (121) is determined by iterating the resistivity of water while aligning the 100% water-saturated borehole data onto the acoustic impedance-resistivity ratio plane with the 0% fluid saturation reference curved line (120).

8. The method of claim 1, wherein the reference set is established by selecting, from all the pairs of values acquired from the inverted CSEM data and AI data, at least one specific pair of quantities for which a given fluid saturation in fraction or equivalent percentage may be associated.

9. The method of claim 1, wherein quantities from each pair of the parameters acquired in the CSEM and AI is demonstrated in a diagram as a function of coordinates, one measuring acoustic impedance in the rock and the other the square root of the ratio between the resistivity of water and the resistivity of rock, hereby called the resistivity ratio function, where the collection of pairs of values equivalent to a corresponding content are manifested by a system of curved lines parallel to a reference curved line representing a zero fluid saturation in fraction or equivalent percentage, to which a given fluid saturation may be allocated, the position of the latter being ascertained by at least two representative points, one being associated with a rock which contains only the matrix and said given fluid saturation, the other with a pair of values acquired by the input data with which this same fluid saturation may be associated.

10. The method of claim 9, wherein the positions of the iso-fluid saturation curved lines are determined between an axis with the 100% rock matrix member on one end and the 100% fluid saturation on the other end, both represented by the values taken by the two parameters.

11. The method of claim 1, wherein the pairs of values typical of the target fluids and of the matrix are obtained from the existing literature.

12. The method of claim 1, wherein using an organic-rich shale data the increase in values of fluid saturation may indicate increase in maturation.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0022] Other features and advantages of the invention will be better understood from the following detailed description and the attached drawings in which:

[0023] FIG. 1 illustrates typical wireline log data acquisition for subsurface sonic interval time, rock bulk density and resistivity determination;

[0024] FIG. 2 shows an example of typical CSEM acquisition in a marine set up in this case;

[0025] FIG. 3 is an illustration for seismic data acquisition in a marine set up in this case;

[0026] FIG. 4 shows a set of iso-saturation of target fluid curved lines in a three-pole diagram onto AI-Resistivity ratio plane;

[0027] FIG. 5 A-B illustrates the plotting of the set of pairs on the same diagram of values of the parameters acquired in a well by three well-logging probes before the R.sub.w calibration (A), and after R.sub.w calibration (B);

[0028] FIG. 6 is a resistivity profile in depth plotted against spatial distance, inverted from the CSEM data. The darker the grey shade, higher is the resistivity;

[0029] FIG. 7 is an Acoustic impedance (AI) profile inverted from the seismic data. The profile is in depth plotted against spatial distance. The darker the grey shade, higher is AI;

[0030] FIG. 8 is the output obtained after using equation 2 showing the S.sub.fl;

[0031] FIG. 9 shows the resistivity ratio function computed from CSEM resistivity plotted against the AI obtained from the inverted seismic. The fluid saturation (S.sub.fl) calculated using the present method of invention is represented by grey shade. The darker the grey color, higher is the target fluid saturation;

[0032] FIG. 10 is a flowchart showing elementary steps in one embodiment of the present inventive method.

DETAILED EXAMPLE

[0033] The method of the invention comprises the use of data acquired by CSEM, seismic, calibrated by well-logging tools making it possible to separate the influence of fluids other than in-situ saline water and, thus, to estimate the fluid saturation within sedimentary rocks. Subsurface reservoirs may generally consist of two components: (1) the rock matrix, and (2) the fluid(s) within the pore space (water, oil/gas or CO2).

[0034] Data obtained from the wellbore may include so-called well log data. Such data are typically recorded and presented against depth in the subsurface of various physical parameters measured by probes lowered into the wellbore. Such probes may include, for example, electrical resistivity, acoustic interval time, bulk density, neutron slowing down length, neutron capture cross-section, natural gamma radiation, and nuclear magnetic resonance relaxation time distribution, among others. The well logging procedure comprises recording of magnitudes of various above mentioned physical properties within a bore-hole using an array of logging probes (FIG. 1, 11), attached with a logging cable (12) connected on the other end to a data recording cabin (13).

[0035] The controlled-source electromagnetic (CSEM) methods had been used in hydrocarbon exploration since early in the 20th century. Recent advances in the technique make it possible to remotely measure the total horizontal and vertical electrical resistivity of subsurface formations with considerable accuracy but with moderate vertical resolution. CSEM surveying has become an essential geophysical tool for evaluating the presence of hydrocarbon-bearing reservoirs within the subsurface formations. In this method a controlled electromagnetic transmitter is towed above or positioned between electromagnetic receivers on the seafloor. FIG. 2 illustrates the controlled-source electromagnetic data acquisition method in a body of water above a potential hydrocarbon accumulation (21). The vessel is shown towing an electromagnetic source such as a horizontal electrical dipole (22). Receivers (24) are placed on the seafloor. The source emits a low-frequency current signal that penetrates below the water bottom as indicated in the drawing, A signal path (23) is shown traversing a hydrocarbon-bearing layer (21), which will be characterised by high electrical resistivity, and then being detected by the receivers. Data from receivers may be transmitted using telemetry devices (not shown separately) to the ship (25) that is recorded and processed.

[0036] Seismic data acquisition is routinely performed both on land and at sea. At sea, seismic vessels deploy one or more cables (streamers) behind the vessel as the vessel moves forward. Each streamer includes multiple receivers in a configuration generally as shown in FIG. 3. Streamer (34) trails behind a vessel (35), which moves forward as the survey progresses. As shown in FIG. 3, source (32) is also towed behind vessel (35). Source (32) and receivers (34) typically deploy below the surface of the ocean. Data is transmitted to the ship (35) through the cables that is recorded and processed. Source (32) emits seismic waves which reflect from boundaries (such as, e.g., formation boundary 31). The reflected waves are detected by receivers (34) and recorded as a function of time by determining the time it takes for seismic waves to propagate from source, reflected at a boundary (31) and back to receivers (34). The recorded signal may yield the information of the position, topography of boundary (31), rock, and in-situ fluid properties. The receivers used in marine seismology are commonly referred to as hydrophones, or marine pressure phones. Inversion of seismic data, depending on the procedure, may yield acoustic impedance, shear impedance, P-wave velocity, S-wave velocity, P- to S-wave ratio, and bulk density.

[0037] One embodiment of a method according to the invention will be explained with reference to the flow chart in FIG. 10. The method of the invention makes use, in some embodiments, of data acquired from at least one wellbore (Well A in this case, FIG. 6, 7&8) drilled through subsurface rock formations in an area of interest. The method of the invention contains first of all the Rw calibration of model using three well-logging probes data appropriate for predicting the magnitude of pore fluid. The response of well-logging tools is dependent on the properties related to the components as well as their respective percentage in the rocks investigated. The tool measuring the sonic transit time through the formations is sensitive to the rock porosity and the fluids it contains. We converted the sonic interval time to sonic velocity (115). The probe measuring the density is sensitive to water, other fluids and the void spaces/porosity between the matrix grains. The tool that measures the electric resistivity of the rock makes slight discrimination between the wet clay and the saline water as both are conducting agents, and no discrimination for variations in composition of the matrix if the conducting minerals are not in a continuous phase. The resistivity tool, however, records high resistivity values in case of hydrocarbon, freshwater or CO2 contained in the pore spaces. The product of density with sonic derived velocity is called acoustic impedance. We used acoustic impedance values as a combined augmented response of the sonic and density probes within the method of invention (116). Acoustic impedance is a standard outcome of inversion of seismic data, whereas resistivity (vertical and horizontal) is obtained from CSEM, both the procedures yield independent measurements within a wide areal extent. A function namely resistivity ratio function ({square root over (R.sub.w/R.sub.t)}) was introduced within the method of invention. The resistivity ratio function was defined as the square root of the ratio between the resistivity of formation water and the resistivity measured by the resistivity tool (117).

[0038] In a salt water-wet porous rocks, the two curves i.e. acoustic impedance and resistivity ratio respond to porosity. But in case of rock pores filled with hydrocarbon, freshwater or CO2 both the acoustic impedance and resistivity measurements respond due to two main effects: 1) the acoustic impedance responds to the presence of low-density low-velocity fluids, and 2) the resistivity ratio measurements respond to the porosity and the resistive fluids (gas/oil, freshwater, CO2). In a rock comprised of 100% matrix content with zero porosity (FIG. 4, 41), or a fluid comprised of 100% of hydrocarbon for instance (43), is assumed to yield infinity resistivity resulting in a zero resistivity ratio value. On the other hand at water pole (42) the resistivity of water (Rw) theoretically becomes equal to the total resistivity (Rt) resulting in resistivity ratio value of 1.

[0039] The two properties obtained from the well log data are chosen also so that the collection of pairs of values of acquired parameters (namely the acoustic impedance on the one hand and the resistivity ratio function on the other) at least partly correspond to the equal fluid saturation volume (S.sub.fl) for sedimentary rocks comprising a given proportion of matrix or water are substantially identical.

[0040] This selection of petrophysical parameters substantially simplifies the operation for estimating the fluid saturation. In a cross-plot of the two chosen properties, the collection of pairs of values of the said parameters are spread over iso-fluid-saturation curves. A diagram may be drawn where the iso-saturation curved lines converge at the 100% matrix pole (41). A reference curved line (44) representing 0% (or 0 fraction) S.sub.fl which joins the 100% (or 1 fraction) water pole (42) with the 100% (or 1 fraction) matrix pole (41).

[0041] The baseline (45) represented by the X-axis against the resistivity ratio function ({square root over (R.sub.w/R.sub.t)})=0 was assumed to be having infinity resistivity and zero porosity. If we assume the rock consists of matrix, target fluid (Oil/gas, or CO2 for instance) and water-filled matrix porosity then collection of pairs of values of the parameters serving as reference which is represented by the iso-saturation curved line equivalent to a given fluid percentage within a rock obtained experimentally from values of the two chosen parameters acquired from the data.

[0042] This method of determining the R.sub.w to align the 0% (or 0 fraction) S.sub.fl zone data along the 0% (or 0 fraction) fluid reference line implies that, among the zones crossed by the well, some are water-bearing. This is possible if we assume the data pairs with lowest resistivity ratio function values occasionally showing a trend partly parallel to the 0% (or 0 fraction) S.sub.fl reference line (44). It is possible to verify the existence of such zones by comparison with other fluid saturation calculation techniques within a basin. The pairs of values are represented by the set of iso-saturation curved lines, from the line with 0% fluid saturation to the line representing 100% fluid saturation volume within the rock pores. The fluid saturation which corresponds to that is then obtained by applying the following relation:

[00002]$\begin{array}{cc}\sqrt{\frac{R_w}{R_t}}=\frac{\left({}_{m.Math.a}-\frac{\mathrm{AI}}{V_{P_{m.Math.a}}}\right).Math.\left(1-S_{\mathrm{fl}}\right)}{\sqrt{a}\left[\mathrm{AI}.Math.\left\{S_{\mathrm{fl}}\left(\frac{1}{V_{\mathrm{Pfl}}}-\frac{1}{V_{\mathrm{Pw}}}\right)+\left(\frac{1}{V_{\mathrm{Pw}}}-\frac{1}{V_{\mathrm{Pma}}}\right)\right\}-\left\{S_{\mathrm{fl}}\left({}_{\mathrm{fl}}-{}_w\right)+\left({}_w-{}_{\mathrm{ma}}\right)\right\}\right]}& \left(1\right)\end{array}$

where V.sub.Pma, V.sub.Pfl and V.sub.Pw are the P-wave velocities of the mineral matrix, target fluid and water respectively, .sub.ma is density of mineral grains, .sub.fl is density of target fluid, .sub.w is density of water, R.sub.t is deep resistivity, R.sub.w is the resistivity of water, a is tortuosity factor, AI is acoustic impedance and S.sub.fl is the target fluid saturation (in fraction). The tortuosity factor a controls the slope of the iso-saturation curved lines and may be selected in a formation zone depending on pore structure, grain size and level of compaction. The relevant constants may be taken from Mavko et al (2009) and vendors' logging chart books.

[0043] From this function (equation 1) we are able to define a set of lines representing different fluid saturations converging at the 100% matrix pole onto the Acoustic impedance-resistivity ratio function plane (FIG. 4 & FIG. 10, step 118).

[0044] Rearranging the equation the fluid saturation can be calculated in fraction (that can be converted to a percentage by multiplying with 100) using the following equation:

[00003]$\begin{array}{cc}{S}_{\mathrm{fl}}=\frac{\left[{}_{m.Math.a}-A.Math.I\left(\frac{1}{V_{P.Math.m.Math.a}}\right)+\sqrt{\frac{a.Math.R_w}{R_t}}.Math.\left\{\left({}_w-{}_{m.Math.a}\right)-\mathrm{AI}\left(\frac{1}{V_{\mathrm{Pw}}}-\frac{1}{V_{\mathrm{Pma}}}\right)\right\}\right]}{\left[\sqrt{\frac{a.Math.R_w}{R_t}}.Math.\left\{\mathrm{AI}\left(\frac{1}{V_{\mathrm{Pfl}}}-\frac{1}{V_{\mathrm{Pw}}}\right)-\left({}_{\mathrm{fl}}-{}_w\right)\right\}+\left\{{}_{m.Math.a}-A.Math.I\left(\frac{1}{V_{P.Math.m.Math.a}}\right)\right\}\right]}& \left(2\right)\end{array}$

Until now the Rw is unknown, iterate the value of R.sub.w making the upper right part of the data representing the 100% water-saturated matrix (51 in FIG. 5B) to align with the 0% (or 0 fraction) fluid saturation line. The obtained R.sub.w value (FIG. 10, 121) is employed to insert in the step (123).

[0045] Bring the inverted CSEM data (FIG. 6 & FIG. 10, step 112) and inverted seismic data in the form of AI (FIG. 7 & FIG. 10, step 113) to the same domain (122); time or depth. Putting both the inverted CSEM and AI with the R.sub.w in equation 2 and calculate (123) to obtain the fluid saturation (S.sub.fl) (124). The obtained S.sub.fl profile in this embodiment is shown in FIG. 8, and the computed points from selected data plotted onto an AI vs ({square root over (R.sub.w/R.sub.t)}) plane are illustrated in FIG. 9.

[0046] The technical solution is only one embodiment of the present invention, to those skilled in the art, the present invention discloses a fundamental principle of the method and applications, straightforward to make various types of modifications or variations, the method is not limited to the specific embodiments of the present invention described above, and therefore the manner described above are only preferred and is not in a limiting sense.

References Cited

PATENT DOCUMENTS

[0047]

TABLE-US-00001 0037 US U.S. Pat. No. 8,064,287B2 November 2011 Peter Harris, Lucy Macgregor W O2014000758A1 January 2014 Torgeir Wiik, Per Atle Olsen, Lars Ole Lseth US 20090306899A1 December 2009 Peter Harris, Joel Walls US 20080059075A1 March 2008 Daniele Colombo, Michele De Stefano US 20090204327A1 August 2009 Xinyou Lu, James J. Carazzone US 20140058677A1 February 2014 Leendert Combee WO 2012173718A1 December 2012 Christopher DiCaprio, Jan Schmedes, Charlie Jing, Garrett M. Leahy, Anoop A. Mullur, Rebecca L. Saltzer

OTHER PUBLICATIONS

[0048] Archie, G. E. (1942): The electrical resistivity log as an aid in determining some reservoir characteristics, Trans. AIME, 146, 01, 54-62.

[0049] Carcione, J. M., B. Ursin & J. I. Nordskag (2007): Cross-property relations between electrical conductivity and the seismic velocity of rocks, Geophysics, 72, 5, E193-E204.

[0050] Mavko, G., T. Mukerji & J. Dvorkin (2009): The rock physics handbook: Tools for seismic analysis of porous media, Cambridge university press.