TY - THES

T1 - Multiscale modeling of gas hydrate formation in oil reservoirs

AU - Rathmaier, Daniel

N1 - embargoed until null

PY - 2021

Y1 - 2021

N2 - Oftentimes, undersaturated oil reservoirs are subject to cold water injection to enhance the ultimate oil recovery of a field. During this process, the risk of gas hydrate formation that lowers the intrinsic permeability of a reservoir rock occurs if special thermodynamic conditions are met. Coreflooding experiments performed in previous work verified the possibility of gas hydrate formation in Bentheimer sandstone core samples saturated with live-oil during the injection of cold water. To further assess this process, the objective of this thesis was to numerically reproduce the laboratory experiments and extend the scope to different scales, namely to the pore scale, the laboratory coreflood scale, and the field scale. Numerical models for two different core samples with different physical dimensions were created to simulate the conditions of gas hydrate formation during cold water injection experiments. The first model represented the large diameter core sample with the dimensions of 3 inches in diameter and 10 inches in length, and the second one represented the small diameter core sample with the dimensions of 1.5 inches in diameter and 12 inches in length. The models were fine-tuned to reproduce experimental results for different injection rates, temperatures, and salinities of the injected water. The models that matched the waterfront location and solid saturation were upscaled to a four acres five-spot vertical-well pattern waterflooding operation. The model showed that the permeability reduction due to the formation of gas hydrates affects the waterflooding process performance. All the simulations have been performed with the commercial reservoir simulator STARS by Computer Modelling Group (CMG). The results of this research showed that the waterfront location during the cold-water injection in the laboratory coreflooding experiments could be reproduced by tuning the models. Modifications of reservoir simulation models included: changing capillary pressure relations, adjusting parameters of hydrate formation reactions. Pressure differential measurements that should give indirect information about the hydrate saturation formed in the experiments showed the same trend in the numerical models. Furthermore, the field scale simulations showed a significant permeability reduction due to the formation of hydrates.

AB - Oftentimes, undersaturated oil reservoirs are subject to cold water injection to enhance the ultimate oil recovery of a field. During this process, the risk of gas hydrate formation that lowers the intrinsic permeability of a reservoir rock occurs if special thermodynamic conditions are met. Coreflooding experiments performed in previous work verified the possibility of gas hydrate formation in Bentheimer sandstone core samples saturated with live-oil during the injection of cold water. To further assess this process, the objective of this thesis was to numerically reproduce the laboratory experiments and extend the scope to different scales, namely to the pore scale, the laboratory coreflood scale, and the field scale. Numerical models for two different core samples with different physical dimensions were created to simulate the conditions of gas hydrate formation during cold water injection experiments. The first model represented the large diameter core sample with the dimensions of 3 inches in diameter and 10 inches in length, and the second one represented the small diameter core sample with the dimensions of 1.5 inches in diameter and 12 inches in length. The models were fine-tuned to reproduce experimental results for different injection rates, temperatures, and salinities of the injected water. The models that matched the waterfront location and solid saturation were upscaled to a four acres five-spot vertical-well pattern waterflooding operation. The model showed that the permeability reduction due to the formation of gas hydrates affects the waterflooding process performance. All the simulations have been performed with the commercial reservoir simulator STARS by Computer Modelling Group (CMG). The results of this research showed that the waterfront location during the cold-water injection in the laboratory coreflooding experiments could be reproduced by tuning the models. Modifications of reservoir simulation models included: changing capillary pressure relations, adjusting parameters of hydrate formation reactions. Pressure differential measurements that should give indirect information about the hydrate saturation formed in the experiments showed the same trend in the numerical models. Furthermore, the field scale simulations showed a significant permeability reduction due to the formation of hydrates.

KW - Gashydrat

KW - Numerische Simulation

KW - CMG

KW - STARS

KW - Porenskala

KW - Laborkernflutskala

KW - Feldskala

KW - Wasserinjektion

KW - Hydrates

KW - Reservoir simulation

KW - CMG

KW - STARS

KW - water injection

KW - pore scale

KW - laboratory coreflood scale

KW - field scale

KW - Five-spot pattern

KW - permeability effect

M3 - Master's Thesis

ER -