Method for determining porosity associated with organic matter in a well or formation

1. A method for estimating porosity associated with organic matter (PAOM) in a well or formation, comprising:

(a) using a scanning electron microscope (SEM) or a focused ion beam (FIB)-SEM to obtain SEM or FIB-SEM images for a plurality of first rock samples obtained from the well or formation;

(b) determining PAOM, total porosity (PHIT), and organic matter (OM) content (TOC), from the SEM or FIB-SEM images;

(c) determining maximum apparent transformation ratio (ATR) for the plurality of rock samples using equation (1): ATR=PAOM/ (PAOM+OM), wherein the PAOM and OM are determined in (b);

(d) curve-fitting a ratio of the PAOM to the PHIT and the TOC for at least three data points obtained in (b) to generate at least one of a mathematical function equation or cross-plot (2) thereof;

(e) determining total porosity (PHIT) and organic matter (OM) content (TOC) for a second sample of a location along a length of a logged wellbore or core sample of the well or formation;

(f) computing a first estimated PAOM for the sample of the logged wellbore or core sample using the mathematical function equation or cross-plot (2) generated using the total porosity (PHIT) and the organic matter (OM) content (TOC) determined in (e);

(g) computing a second estimated PAOM for the sample of the logged wellbore or core sample using equation (3): PAOM=ATR×OM/(1−ATR), wherein the ATR is determined in (c) and the OM is determined in (e);

(h) comparing the first estimated PAOM calculated from (f) with the second estimated PAOM calculated in (g); and

(i) selecting the first estimated PAOM unless the first estimated PAOM is greater than the second estimated PAOM wherein the second PAOM is selected.

2. The method of claim 1 , wherein the well or formation comprises shale.

3. The method of claim 1 , wherein the plurality of rock samples in (a) are whole cores, sidewall cores, drill cuttings, or outcrop quarrying samples.

4. The method of claim 1 , wherein the determining of porosity associated with organic matter (PAOM), total porosity (PHIT), and organic matter (OM) content (TOC) in (b) comprises segmenting the SEM images into organic matter and porosity, and determining quantity of porosity that is bounded by organic material as compared to that bounded by solid grains.

5. The method of claim 1 , wherein the determining of total porosity (PHIT) and organic matter (OM) content (TOC) in (e) comprises interpreting PHIT and TOC from well logging data.

6. The method of claim 1 , wherein the determining of total porosity (PHIT) and organic matter (OM) content (TOC) in (e) comprises computing PHIT and TOC from x-ray CT scan and spectral gamma log data.

7. A method for evaluating the production potential of a well or formation, comprising:

(a) using a scanning electron microscope (SEM) or focused ion beam (FIB)-SEM to obtain SEM or FIB-SEM images for a plurality of first rock samples obtained from a well or formation;

(b) determining porosity associated with organic matter (PAOM), total porosity (PHIT), and organic matter (OM) content (TOC), from the SEM or FIB-SEM images;

(c) determining maximum apparent transformation ratio (ATR) for the plurality of rock samples using equation (1): ATR=PAOM/(PAOM+OM), wherein the PAOM and OM are determined in (b);

(d) curve-fitting a ratio of the PAOM to the PHIT and the TOC for at least three data points obtained in (b) to generate at least one of a mathematical function equation or cross-plot (2) thereof;

(e) determining total porosity (PHIT) and organic matter (OM) content (TOC) for a second sample of a location along a length of a logged wellbore or core sample of the well or formation;

(f) computing a first PAOM for the sample of the logged wellbore or core sample using the mathematical function equation or cross-plot (2) generated using the total porosity (PHIT) and the organic matter (OM) content (TOC) determined in (e);

(g) computing a second PAOM for the sample of the logged wellbore or core sample using equation (3): PAOM=ATR×OM/(1−ATR), wherein the ATR is determined in (c) and the OM is determined in (e);

(h) comparing the first PAOM calculated from (f) with the second PAOM calculated in (g); and

(i) selecting the first PAOM calculated unless the first PAOM is greater than the second PAOM wherein the second PAOM is selected; and

(j) evaluating the production potential of the well or formation based at least in part on the selected first or second PAOM in (i).

8. The method of claim 7 , further comprising (k) producing at least one of petroleum and natural gas from the well or formation.

9. The method of claim 7 , wherein the well or formation comprises shale.

10. The method of claim 7 , wherein the plurality of rock samples in (a) are whole cores, sidewall cores, drill cuttings, or outcrop quarrying samples.

11. The method of claim 7 , wherein the determining of porosity associated with organic matter (PAOM), total porosity (PHIT), and organic matter (OM) content (TOC) in (b) comprises segmenting the SEM images into organic matter and porosity, and determining quantity of porosity that is bounded by organic material as compared to that bounded by solid grains.

12. The method of claim 7 , wherein the determining of total porosity (PHIT) and organic matter (OM) content (TOC) in (e) comprises interpreting PHIT and TOC from well logging data.

13. The method of claim 7 , wherein the determining of total porosity (PHIT) and organic matter (OM) content (TOC) in (e) comprises computing PHIT and TOC from x-ray CT scan and spectral gamma log data.

14. A system for estimating porosity associated with organic matter in a well or formation, comprising:

(a) an SEM or FIB-SEM operable to scan a plurality of rock samples obtained to obtain digital images thereof;

(b) one or more computer systems operable for (i) determining porosity associated with organic matter (PAOM), total porosity (PHIT), and organic matter (OM) content (TOC), from the digital images, (ii) determining maximum apparent transformation ratio (ATR) for the plurality of rock samples using equation (1): ATR=PAOM/(PAOM+OM), wherein the PAOM and OM are determined in (i), (iii) curve-fitting a ratio of the PAOM to the PHIT and the TOC for at least three data points obtained in (i) to generate at least one of a mathematical function equation or cross-plot (2) thereof, (iv) determining total porosity (PHIT) and organic matter (OM) content (TOC) for a sample of a location along a length of a logged wellbore or core sample of the well or formation, (v) computing a first PAOM for the sample of the logged wellbore or core sample using the mathematical function equation or cross-plot (2) generated using the total porosity (PHIT) and the organic matter (OM) content (TOC) determined in (iv), (vi) computing a second PAOM for the sample of the logged wellbore or core sample using equation (3):

PAOM=ATR×OM/(1−ATR), wherein the ATR is determined in (ii) and the OM is determined in (iv), (vii) comparing the first PAOM calculated from (v) with the second PAOM calculated in (vi), (viii) selecting the first PAOM calculated unless the first PAOM is greater than the second PAOM wherein the second PAOM is selected, and optionally further (ix) evaluating the production potential of the well or formation based at least in part on the selected first or second PAOM in (viii); and

(c) at least one device to display, print, or store results of the computations.

15. A non-transitory computer readable medium with a computer program product embodied thereon that, when performed on a processor in a computerized device provides a method for performing computations of one or more or all of the indicated steps of the method of claim 1 .

16. A non-transitory computer readable medium with a computer program product embodied thereon that, when performed on a processor in a computerized device provides a method for performing computations of one or more or all of the indicated steps of the method of claim 7 .