Inorganic salt deposition under in situ conditions in Eastern Siberian reservoirs

UDK: 622.276:031:532.5.072.8
DOI: 10.24887/0028-2448-2020-9-44-49
Key words: Eastern Siberia, evaporites, salt deposition, gypsum, halite, digital core, multiphase flow, hydrodynamic simulator, numerical calculations
Authors: S.V. Zimin (Irkutsk Oil Company LLC, RF, Irkutsk), I.V. Sabanchin (Irkutsk Oil Company LLC, RF, Irkutsk), I.A. Krasnov (Irkutsk Oil Company LLC, RF, Irkutsk), O.O. Butorin (Irkutsk Oil Company LLC, RF, Irkutsk), M.R. Stukan (Schlumberger, RF, Moscow), E.N. Ivanov (Schlumberger, RF, Moscow), A.T. Rebrikova (Schlumberger, RF, Moscow), A.S. Denisenko (Schlumberger, RF, Moscow), V.I. Piskarev (Schlumberger, RF, Moscow), V.D. Laptev (Schlumberger, RF, Moscow)

Deposition of inorganic salt sediments is a sufficient challenge for successive exploration of oil and gas reservoirs in Eastern Siberia. The deposition process is known to be dependent on multiple parameters, which causes additional complications for its description. The observed sediments have a fairly diverse chemical composition. However, gypsum and halite are dominant. To predict the amount and composition of the sediment, as well as its distribution in the reservoir, it is necessary to know in detail the chemical compositions of the available aqueous solutions and their physical properties over the entire range of thermobaric conditions in the reservoir. The required information is not always readily available. However, the current level of development of digital chemistry and numerical methods for simulating a multiphase flow in porous media (a digital core approach) allows one to obtain the necessary information using numerical calculations.

This paper presents an integral approach to the problem. It includes numerical simulations of the miscibility of aqueous solutions using the OLI Studio package, confirmed by laboratory tests, and calculations of matrix porosity and permeability at reservoir conditions for different levels of salt deposition using a pore-scale hydrodynamic simulator DHD (CoreFlowTM) developed in Schlumberger Moscow Research center. Based on the simulation results, a method for construction of a composite hydrodynamic model in a reservoir simulator (ECLIPSE) is proposed. The model takes into account both precipitation and dissolution of inorganic salts. As the result of the study it was possible to make a conclusion about the root causes of salt deposition in the inter-well zone at one of the fields in Eastern Siberian: the mixing of injection waters with formation brine and changes of thermobaric conditions near injection and production wells, which characterize these zones as the most at risk of sediment formation.

The problem of salt deposition is relevant for many fields in Eastern Siberia, and, therefore, the proposed approach has good prospects to be widely used.

References

1. Chertovskikh E.O., Alekseev S.V., Problems of oil and gas production associated with gypsum depositing in the verkhnechonskoye oil and gas condensate field (In Russ.), SPE-171311-RU, 2014.

2. Vinogradov I.A., Zagorovskiy A.A., Bogachev K.Yu. et al., Laboratory and numerical study of the dissolution process of salinization clastic reservoirs (In Russ.), SPE-176630-RU, 2015.

3. Kashchavtsev V.E., Mishchenko I.T., Soleobrazovanie pri dobyche nefti (Salt formation in oil production), Moscow: Orbita-M Publ., 2004, 432 p.

4. Dinariev O.Yu., On the hydrodynamic description of a multicomponent multiphase mixture in narrow pores and thin layers (In Russ.), Prikladnaya matematika i mekhanika (PMM), 1995, V. 59, no. 5, pp. 776–783.

5. Dem'yanov A.Yu., Dinariev O.Yu., Evseev N.V., Osnovy metoda funktsionala plotnosti v gidrodinamike (Fundamentals of the density functional method in hydrodynamics), Moscow: Fizmatlit Publ., 2009, 312 p.

6. Koroteev D., Dinariev O., Evseev N. et al., Direct hydrodynamic simulation of multiphase flow in porous rock, Petrophysics, 2014, V. 55 (4), pp. 294-303

7. Andersen M.A., Digital core flow simulations accelerate evaluation of multiple recovery scenarios, World Oil, 2014, V. 98, pp. 50–56.

8. Shandrygin A., Shelepov V., Ramazanov R. et al., Mechanism of oil displacement during polymer flooding in porous media with micro-inhomogeneities (In Russ.), SPE-182037-RU, 2016.

9. Beletskaya A., Ivanov E., Stukan M. et al., Reactive flow modeling at pore scale, SPE-187805-MS, 2017.

10. MacDonald R.M., Geetan S.I., Klemin D., Hill B., Flow behavior from organic and mineral-hosted porosity systems — From pores to production, URTeC: 2902911, 2018.

11. Yakimchuk I., Evseev N., Korobkov D. et al., Permeability and porosity study of Achimov formation using digital core analysis, SPE-196928-MS, 2019.

12. Dinariev O., Evseev N., Klemin D., Density functional hydrodynamics in multiscale pore systems: chemical potential drive, Proceedings of E3S Web of Conferences, 2020, V.146, Article no. 01001, 10 p., https://doi.org/10.1051/e3sconf/202014601001.

13. Amaefule J.O. et al., Enhanced reservoir description: using core and log data to identify hydraulic (flow) units and predict permeability in un-cored intervals/wells, SPE-26436-MS, 1993, http://doi:10.2118/26436-MS.

14. Stolz A.-K., Graves R.M., Sensitivity study of flow unit definition by use of reservoir simulation, SPE-84277-MS, 2003.

15. Khormali A., Petrakov D.G., Farmanzade A.R., Prediction and inhibition of inorganic salt formation under static and dynamic conditions–Effect of pressure, temperature, and mixing ratio, Int. J. Technol., 2016, V. 7, no. 6, pp. 943–951.

Deposition of inorganic salt sediments is a sufficient challenge for successive exploration of oil and gas reservoirs in Eastern Siberia. The deposition process is known to be dependent on multiple parameters, which causes additional complications for its description. The observed sediments have a fairly diverse chemical composition. However, gypsum and halite are dominant. To predict the amount and composition of the sediment, as well as its distribution in the reservoir, it is necessary to know in detail the chemical compositions of the available aqueous solutions and their physical properties over the entire range of thermobaric conditions in the reservoir. The required information is not always readily available. However, the current level of development of digital chemistry and numerical methods for simulating a multiphase flow in porous media (a digital core approach) allows one to obtain the necessary information using numerical calculations.

This paper presents an integral approach to the problem. It includes numerical simulations of the miscibility of aqueous solutions using the OLI Studio package, confirmed by laboratory tests, and calculations of matrix porosity and permeability at reservoir conditions for different levels of salt deposition using a pore-scale hydrodynamic simulator DHD (CoreFlowTM) developed in Schlumberger Moscow Research center. Based on the simulation results, a method for construction of a composite hydrodynamic model in a reservoir simulator (ECLIPSE) is proposed. The model takes into account both precipitation and dissolution of inorganic salts. As the result of the study it was possible to make a conclusion about the root causes of salt deposition in the inter-well zone at one of the fields in Eastern Siberian: the mixing of injection waters with formation brine and changes of thermobaric conditions near injection and production wells, which characterize these zones as the most at risk of sediment formation.

The problem of salt deposition is relevant for many fields in Eastern Siberia, and, therefore, the proposed approach has good prospects to be widely used.

References

1. Chertovskikh E.O., Alekseev S.V., Problems of oil and gas production associated with gypsum depositing in the verkhnechonskoye oil and gas condensate field (In Russ.), SPE-171311-RU, 2014.

2. Vinogradov I.A., Zagorovskiy A.A., Bogachev K.Yu. et al., Laboratory and numerical study of the dissolution process of salinization clastic reservoirs (In Russ.), SPE-176630-RU, 2015.

3. Kashchavtsev V.E., Mishchenko I.T., Soleobrazovanie pri dobyche nefti (Salt formation in oil production), Moscow: Orbita-M Publ., 2004, 432 p.

4. Dinariev O.Yu., On the hydrodynamic description of a multicomponent multiphase mixture in narrow pores and thin layers (In Russ.), Prikladnaya matematika i mekhanika (PMM), 1995, V. 59, no. 5, pp. 776–783.

5. Dem'yanov A.Yu., Dinariev O.Yu., Evseev N.V., Osnovy metoda funktsionala plotnosti v gidrodinamike (Fundamentals of the density functional method in hydrodynamics), Moscow: Fizmatlit Publ., 2009, 312 p.

6. Koroteev D., Dinariev O., Evseev N. et al., Direct hydrodynamic simulation of multiphase flow in porous rock, Petrophysics, 2014, V. 55 (4), pp. 294-303

7. Andersen M.A., Digital core flow simulations accelerate evaluation of multiple recovery scenarios, World Oil, 2014, V. 98, pp. 50–56.

8. Shandrygin A., Shelepov V., Ramazanov R. et al., Mechanism of oil displacement during polymer flooding in porous media with micro-inhomogeneities (In Russ.), SPE-182037-RU, 2016.

9. Beletskaya A., Ivanov E., Stukan M. et al., Reactive flow modeling at pore scale, SPE-187805-MS, 2017.

10. MacDonald R.M., Geetan S.I., Klemin D., Hill B., Flow behavior from organic and mineral-hosted porosity systems — From pores to production, URTeC: 2902911, 2018.

11. Yakimchuk I., Evseev N., Korobkov D. et al., Permeability and porosity study of Achimov formation using digital core analysis, SPE-196928-MS, 2019.

12. Dinariev O., Evseev N., Klemin D., Density functional hydrodynamics in multiscale pore systems: chemical potential drive, Proceedings of E3S Web of Conferences, 2020, V.146, Article no. 01001, 10 p., https://doi.org/10.1051/e3sconf/202014601001.

13. Amaefule J.O. et al., Enhanced reservoir description: using core and log data to identify hydraulic (flow) units and predict permeability in un-cored intervals/wells, SPE-26436-MS, 1993, http://doi:10.2118/26436-MS.

14. Stolz A.-K., Graves R.M., Sensitivity study of flow unit definition by use of reservoir simulation, SPE-84277-MS, 2003.

15. Khormali A., Petrakov D.G., Farmanzade A.R., Prediction and inhibition of inorganic salt formation under static and dynamic conditions–Effect of pressure, temperature, and mixing ratio, Int. J. Technol., 2016, V. 7, no. 6, pp. 943–951.


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