Evaluation of the wave effect effectiveness in carbonate reservoirs with high viscosity oil

Development of fracture-porous reservoirs can be followed by breakthroughs of water injected into reservoirs through the system of cracks to production wells. This process can reduce the coverage of reservoir by sweeping, which will ultimately lead to a decrease in oil recovery factor. In order to perform a more effective fractured-porous reservoir flooding it is possible to use various methods associated with the injection of gel and sediment-forming agents, the use of wave technologies etc. The paper considers the formation with high-viscosity oil and fractured-porous reservoir. It is observed that water cut increase faster than oil recovery. The authors of the paper propose to use the wave effect associated with the stops of both injection and production wells. Shut-off and shut-in time of each well should be selected based on the parameters of the bottomhole zone. The specific value of the end time of the interaction of blocks and fractures when the pressure changes at the points of the reservoir can be roughly estimated from the beginning of the straight section of the pressure build-up curve in the fracture-porous reservoir. For the selected formation reservoir time of the end of the interaction between fractures and blocks with pressure changes was determined. Various options for implementation were proposed. Process impact modelling was performed using the Tempest More software package. According to the results of the simulation, it can be noted that the wave phenomenon is effective in terms of water cut reduction. Neverthelles, there are losses in oil production with long periods of shut-off of the wells. It should be noted that the time of interaction between fractures and blocks substantially depends on the permeability of the bottomhole zone; the higher the permeability the lower the time. It was also found that a variable frequency wave results in a greater effect

Evaluation of reservoir energy consumption during oil well operation on the north Perm region

In the article an account of extensive investigations of a well with carbonate deposits operating over a period of 44 months in Perm Region is given. Two well production enhancement techniques were used, namely abrasive jet perforation and acid treatment. A detailed analysis of abrasive jet perforation and acid treatment results was carried out, where changes of productivity index depending on reservoir and bottomhole pressures after operations were evaluated. It was shown, that an incremental oil production can significantly decrease with decreasing reservoir and bottomhole pressures. It was found that during the abrasive jet perforation with acid treatment, an incremental oil production has increased for abrasive jet perforation and acid treatment to about 65 % and 35 % respectively. It was also shown, that the abrasive jet perforation helps to slightly increase a well rate and decrease a reservoir energy consumption for fluid communications in bottomhole formation zone. After the acid treatment taking place two years later, oil production was increased and it is understood that 15 % of this increase is due to acid attack, and on 85 % due to growth in bottomhole pressure and fracture permeability. There was revealed a complete exclusion of reservoir energy consumptions to overcome the additional filtration resistance immediately after conducting operations. The reservoir has an excellent intrinsic fracturing property, so bottomhole formation permeability and energy consumption significantly depend on the reservoir and bottomhole pressures. It is recommended to maintain reservoir and bottomhole pressures higher than lateral rock pressure to increase effectiveness of well operations in reservoirs with advanced natural fracturing

Predicting the permeability of the near-bottomhole zone during wave impact

The research reveals that during selection of a method to increase oil recovery it is necessary to take into account rheological features of fluid movement through the formation, effect of capillary forces and heterogeneity of reservoir properties of the productive formation in thickness and along the bedding. Low-frequency wave impact, which is used to increase production in oil fields, is considered. At low-frequency impact new fractures appear and existing fractures in rocks increase in size. The greatest increase in porosity and permeability of rocks occurs at an impact frequency up to 10 Hz. Dynamics of oscillation amplitude during wave's movement in saturated porous medium is studied in the paper: essential attenuation of amplitude occurs at distance up to 1 m from borehole axis. With increase of frequency from 1 to 10 Hz the intensity of amplitude's attenuation decreases. The technology was tested on a well in Perm region (Russia). The actual permeability value was 50 % higher than the predicted value. According to the results of hydrodynamic investigations processing, it was noted that the greatest increase of permeability took place near the wellbore, while away from the wellbore axis permeability remained almost unchanged. In order to refine the mathematical model for prediction of wave impact on rock permeability it is necessary to take into account interconnection of pore space structure, change of adhesion layer, as well as to study transfer of particles during vibration

Permeability Evolution of Porous Sandstone in the Initial Period of Oil Production: Comparison of Well Test and Coreflooding Data

Permeability prediction in hydrocarbon production is an important task. The decrease in permeability due to depletion leads to an increase in the time of oil or gas production. Permeability models usually are obtained by various methods, including coreflooding and the field testing of wells. The results of previous studies have shown that permeability has a power-law or exponential dependence on effective pressure; however, the difficulty in predicting permeability is associated with hysteresis, the causes of which remain not fully understood. To model permeability, as well as explain the causes of hysteresis, some authors have used mechanical reservoir models. Studies have shown that these models cannot be applied with small fluctuations in effective pressures in the initial period of hydrocarbon production. In this work, based on the analysis of well test data, we came to the conclusion that in the initial period of production under constant thermobaric conditions, the permeability of a slightly clayey terrigenous reservoir depends on the amount of fluid produced. A model has been obtained that describes the change in permeability in the initial period of oil production. Core samples were flooded to confirm the model. Coreflooding showed high convergence of the model obtained from well test data. With computed tomography (CT) and scanning electron microscope (SEM), the properties and structure of the core were studied, and it was found that the main reason for the decrease in the permeability of slightly clayey rocks in the initial period of production is the migration of natural colloids

Permeability Evolution of Porous Sandstone in the Initial Period of Oil Production: Comparison of Well Test and Coreflooding Data

Permeability prediction in hydrocarbon production is an important task. The decrease in permeability due to depletion leads to an increase in the time of oil or gas production. Permeability models usually are obtained by various methods, including coreflooding and the field testing of wells. The results of previous studies have shown that permeability has a power-law or exponential dependence on effective pressure; however, the difficulty in predicting permeability is associated with hysteresis, the causes of which remain not fully understood. To model permeability, as well as explain the causes of hysteresis, some authors have used mechanical reservoir models. Studies have shown that these models cannot be applied with small fluctuations in effective pressures in the initial period of hydrocarbon production. In this work, based on the analysis of well test data, we came to the conclusion that in the initial period of production under constant thermobaric conditions, the permeability of a slightly clayey terrigenous reservoir depends on the amount of fluid produced. A model has been obtained that describes the change in permeability in the initial period of oil production. Core samples were flooded to confirm the model. Coreflooding showed high convergence of the model obtained from well test data. With computed tomography (CT) and scanning electron microscope (SEM), the properties and structure of the core were studied, and it was found that the main reason for the decrease in the permeability of slightly clayey rocks in the initial period of production is the migration of natural colloids

Colloid Migration as a Reason for Porous Sandstone Permeability Degradation during Coreflooding

During coreflooding under stationary conditions, permeability is determined by the Darcy formula; thus, the apparent permeability is determined, which characterizes the average hydraulic conductivity of the core, but does not take into account the processes occurring at the microlevel. Transient processes during fluid injection regime change are important for understanding the evolution of permeability and underlie such phenomena as permeability degradation and its hysteresis. Our paper presents the coreflooding methodology and the results showing that during changes in injection conditions, the permeability of samples can significantly decrease due to the migration of colloids. In the developed methodology, coreflooding conditions exclude the influence of other factors on permeability, such as creep, the chemical reactions of rocks and fluids, and chemical mobilization of colloids. It has been established that the decrease in permeability occurs only when fluid is injected through the core, which is indirect evidence of pore blockage by colloids. The article also attempts to evaluate the effect of pore pressure on the sensitivity of the porous medium permeability to the amount of injected fluid. A decrease in pore pressure leads to a more intense decrease in permeability during injection, which most likely indicates additional mobilization of colloids, while the narrowing of pore channels does not affect permeability. Analysis of coreflooding results showed that porous media with lower permeability are more sensitive to colloid migration and pore pressure changes. It has also been found that the sensitivity of porous media to colloid migration is greatly affected by the pore pressure gradient, while media with higher permeability are less sensitive to colloid migration