Preview

Science. Innovations. Technologies

Advanced search

Results of Determining the Porosity Coefficient in Oil-Saturated Clay Rocks

https://doi.org/10.37493/2308-4758.2024.1.8

Abstract

The article studies the wells that opened clayey reservoirs of Paleogene age. When predicting the trajectory of a crack during hydraulic fracturing (HF), it is necessary to take into account the percentage of minerals in the rock, since cracks during hydraulic fracturing are formed at the contacts between mineral grains. This conclusion is indisputable, but obtaining complete information about the percentage of minerals in a rock is an expensive and not always feasible task. At the same time, the physical and mechanical characteristics of clayey rocks are no less significantly influenced by their porosity. Therefore, it is important to note that a reliable determination of the porosity coefficient from the exposed geological section will undoubtedly have a primary positive impact on the reliability of hydraulic fracturing modeling. Based on this, in wells that opened clayey reservoirs, the values of porosity coefficients determined by various methods were analyzed, including the direct one – analysis of core, cuttings and the indirect one – geophysical methods. During the work, a coincidence of the porosity coefficient in the core, cuttings and electrical logging was discovered. Based on the results of the study, it can be concluded that the porosity coefficient determined from acoustic logging (AL) significantly exceeds the values of the porosity coefficient determined from core, cuttings and induction logging. This is due both to the influence of clay content on the acoustic logging readings, and due to the low quality of AC materials induced by erosion of the wellbore. It should be noted that the calculations of porosity coefficients in the above-reference part – in the Batalpashinsky formation based on core and induction logging – coincide almost completely. However, in the sub-reference part of the formation the readings differ slightly. The porosity coefficient calculated is a maximum of 2% lower than the porosity coefficient determined from the core, which is quite acceptable.

About the Authors

A.-G. G. Kerimov
North-Caucasus Federal University
Russian Federation

 Abdul-Gapur G. Kerimov – Dr. Sci. (Tech.), Associate Professor, Head of the Department of Oil and Gas Geophysics

1, Pushkin St., 355017, Stavropol

Scopus ID: 56872657000



E. G. Kerimova
North-Caucasus Federal University
Russian Federation

 Elizaveta G. Kerimova – Assistant of the Department of Petroleum Geophysics 

1, Pushkin St., 355017, Stavropol

Scopus ID: 57220025188



T. A. Gunkina
North-Caucasus Federal University
Russian Federation

 Tatiana A. Gunkina – Cand. Sci. (Tech.), Associate Professor, Head of the Department of Development and Operation of Oil and Gas Fields

1, Pushkin St., 355017, Stavropol

Scopus ID: 57474914000



L. S. Mkrtchian
North-Caucasus Federal University
Russian Federation

Levon S. Mkrtchian – Cand. Sci. (Phys.-Math.), Associate Professor of the Department of Petroleum Geophysics

1, Pushkin St., 355017, Stavropol



E. S. Kliupa
North-Caucasus Federal University
Russian Federation

 Elena S. Kliupa – Senior Lecturer of the Department of Oil and Gas Geophysics

1, Pushkin St., 355017, Stavropol



References

1. Basarygin YuM, Makarenko PP, Mavromati VD. Repair of gas wells. Moscow: Nedra; 1998. 271 p. (In Russ.).

2. Basniev KS, Nikolaevsky VN, Gorbunov AT, Zotov GL. Mechanics of saturated porous media. Moscow: Nedra; 1976. 335 p. (In Russ.).

3. Zeigman YuV Operation of systems for maintaining reservoir pressure during the development of oil fields: textbook. Ufa: USNTU; 2007. 232 p. (In Russ.).

4. Zinchenko IA, Kirsanov SA, Marshaev OA et al The use of hydraulic fracturing for inflow stimulation at gas condensate wells of the Yamburg field and the prospects for using the method in the process of further development of deposits. Moscow: IRC Gazprom; 2007. 120 p. (In Russ.).

5. Gritsenko AI, Aliev ZS, Ermilov OM, Remizov VV, Zotov GA. Well Study Guide. Moscow: Nauka; 1995. 523 p. (In Russ.).

6. Dudayev SA, Dudayev RS Hadumites of Ciscaucasia: new in geological and geophysical study, secondary discovery and development. Moscow: Publishing house. Geoinformmark; 2015. 204 p. (In Russ.).

7. Tan X, Konietzky H, Chen W. Numerical simulation of heterogeneous rock using discrete element model based on digital image processing. Rock Mechanics and Rock Engineering. 2016;(12):4957–4964. https://doi.org/10.1007/s00603-016-1030-0.

8. Sova V, Kerimov A-G. Large undiscovered oil resources are predicted south of Russia. Journal of Petroleum Exploration and Production Technology. 2019;(3):1659–1676. https://doi.org/10.1007/s13202-019-0611-3

9. Zheltov YuP. et al Collection of problems for the development of oil fields: Educational manual for universities. Moscow: Nedra; 1985. 296 p. (In Russ.).

10. Shelepov VV State of the raw material base of Russia. Enhanced oil recovery: Moscow; 2003. 240 p. (In Russ.).

11. Shchurov VI. Equipment and technology of oil production: textbook. Moscow: Alliance TID; 2009. 510 p. (In Russ.).

12. Roodhart LP. Frac-and-Pack Stimulation: Application, Design, and Field Experience. Journ. Petr. Technol. 1994;230–238.

13. Strubhar MK. Multiple, Vertical Fractures From an Inclined Wellbore –AField Experiment. Journ. Petr. Technol. 1975;641-647.

14. Alexandrov BL. Abnormally high reservoir pressures in oil and gas basins. Moscow: Nedra; 1987. 216 p. (In Russ.).

15. Bogdanovich NN. Determination of effective porosity by the adsorption method (using the example of complex clayey reservoirs of the Lower Maikop deposits of the Eastern Ciscaucasia). Porody-kollektory i migraciya nefti = Reservoir Rocks and Oil Migration. Moscow: IGIRGI; 1988;89–93. (In Russ.).

16. Golf-Rakht TD. Fundamentals of oilfield geology and development of fractured reservoirs. M.: Nedra; 1986. P. 193. (In Russ.).


Review

For citations:


Kerimov A.G., Kerimova E.G., Gunkina T.A., Mkrtchian L.S., Kliupa E.S. Results of Determining the Porosity Coefficient in Oil-Saturated Clay Rocks. Science. Innovations. Technologies. 2024;(1):159–171. (In Russ.) https://doi.org/10.37493/2308-4758.2024.1.8

Views: 176


Creative Commons License
This work is licensed under a Creative Commons Attribution 4.0 License.


ISSN 2308-4758 (Print)