Analytical model of incremental oil recovery as a function of WAG ratio and tapered WAG ratio benefits over uniform WAG ratio for heterogeneous reservoir

2021 ◽  
pp. 109955
Author(s):  
Mohammad YunusKhan ◽  
Ajay Mandal
Keyword(s):  
Analytical Model ◽  
Oil Recovery ◽  
Heterogeneous Reservoir ◽  
Incremental Oil Recovery

scholarly journals Manipulation of surface charges of oil droplets and carbonate rocks to improve oil recovery

2021 ◽  
Vol 11 (1) ◽  
Author(s):  
Jian Hou ◽  
Ming Han ◽  
Jinxun Wang
Keyword(s):  
Zeta Potential ◽  
Oil Recovery ◽  
Carbonate Rocks ◽  
Zwitterionic Surfactant ◽  
Surface Charges ◽  
Oil Droplets ◽  
Zeta Potentials ◽  
Potential Value ◽  
Oil Water ◽  
Incremental Oil Recovery

AbstractThis work investigates the effect of the surface charges of oil droplets and carbonate rocks in brine and in surfactant solutions on oil production. The influences of the cations in brine and the surfactant types on the zeta-potentials of both oil droplets and carbonate rock particles are studied. It is found that the addition of anionic and cationic surfactants in brine result in both negative or positive zeta-potentials of rock particles and oil droplets respectively, while the zwitterionic surfactant induces a positive charge on rock particles and a negative charge on oil droplets. Micromodels with a CaCO3 nanocrystal layer coated on the flow channels were used in the oil displacement tests. The results show that when the oil-water interfacial tension (IFT) was at 10−1 mN/m, the injection of an anionic surfactant (SDS-R1) solution achieved 21.0% incremental oil recovery, higher than the 12.6% increment by the injection of a zwitterionic surfactant (SB-A2) solution. When the IFT was lowered to 10−3 mM/m, the injection of anionic/non-ionic surfactant SMAN-l1 solution with higher absolute zeta potential value (ζoil + ζrock) of 34 mV has achieved higher incremental oil recovery (39.4%) than the application of an anionic/cationic surfactant SMAC-l1 solution with a lower absolute zeta-potential value of 22 mV (30.6%). This indicates that the same charge of rocks and oil droplets improves the transportation of charged oil/water emulsion in the porous media. This work reveals that the surface charge in surfactant flooding plays an important role in addition to the oil/water interfacial tension reduction and the rock wettability alteration.

scholarly journals The Analysis for the Effect of Effective Compressibility on Oil Recovery in Polymer Flooded Heterogeneous Reservoir

2014 ◽  
Vol 47 (3) ◽  
pp. 247-254
Author(s):  
Soohyun Baek ◽  
Woodong Jung ◽  
Wonmo Sung ◽  
Junwoo Seo
Keyword(s):  
Oil Recovery ◽  
Heterogeneous Reservoir

scholarly journals Development of an analytical model to predict oil reservoirs performance using mechanical waves propagation

2021 ◽  
Author(s):  
Hesham A. Abu Zaid ◽  
◽  
Sherif A. Akl ◽  
Mahmoud Abu El Ela ◽  
Ahmed El-Banbi ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Field Measurements ◽  
Field Trials ◽  
Oil Field ◽  
Reservoir Properties ◽  
Actual Performance ◽  
Reservoir Performance ◽  
Mechanical Waves ◽  
Incremental Oil Recovery ◽  
Wave Induced

The mechanical waves have been used as an unconventional enhanced oil recovery technique. It has been tested in many laboratory experiments as well as several field trials. This paper presents a robust forecasting model that can be used as an effective tool to predict the reservoir performance while applying seismic EOR technique. This model is developed by extending the wave induced fluid flow theory to account for the change in the reservoir characteristics as a result of wave application. A MATLAB program was developed based on the modified theory. The wave’s intensity, pressure, and energy dissipation spatial distributions are calculated. The portion of energy converted into thermal energy in the reservoir is assessed. The changes in reservoir properties due to temperature and pressure changes are considered. The incremental oil recovery and reduction in water production as a result of wave application are then calculated. The developed model was validated against actual performance of Liaohe oil field. The model results show that the wave application increases oil production from 33 to 47 ton/day and decreases water-oil ratio from 68 to 48%, which is close to the field measurements. A parametric analysis is performed to identify the important parameters that affect reservoir performance under seismic EOR. In addition, the study determines the optimum ranges of reservoir properties where this technique is most beneficial.

An In-Depth Review of the Recovery Mechanisms for the Cyclic Gas Injection Process in Shale Oil Reservoirs

2021 ◽  
Author(s):  
Hilario Martin Rodriguez ◽  
Yalda Barzin ◽  
Gregory James Walker ◽  
Markus Gruenwalder ◽  
Matias Fernandez-Badessich ◽  
...  
Keyword(s):  
Simulation Model ◽  
Oil Recovery ◽  
Hydraulic Fracture ◽  
Gas Injection ◽  
Pressure Profile ◽  
Shale Oil ◽  
Gas Composition ◽  
Pure Methane ◽  
Recovery Mechanisms ◽  
Incremental Oil Recovery

Abstract This study has double objectives: investigation of the main recovery mechanisms affecting the performance of the gas huff-n-puff (GHnP) process in a shale oil reservoir, and application of optimization techniques to modelling of the cyclic gas injection. A dual-permeability reservoir simulation model has been built to reproduce the performance of a single hydraulic fracture. The hydraulic fracture has the average geometry and properties of the well under analysis. A history match workflow has been run to obtain a simulation model fully representative of the studied well. An optimization workflow has been run to maximize the cumulative oil obtained during the GHnP process. The operational variables optimized are: duration of gas injection, soaking, and production, onset time of GHnP, injection gas flow rate, and number of cycles. This optimization workflow is launched twice using two different compositions for the injection gas: rich gas and pure methane. Additionally, the optimum case obtained previously with rich gas is simulated with a higher minimum bottom hole pressure (BHP) for both primary production and GHnP process. Moreover, some properties that could potentially explain the different recovery mechanisms were tracked and analyzed. Three different porosity systems have been considered in the model: fractures, matrix in the stimulated reservoir volume (SRV), and matrix in the non-SRV zone (virgin matrix). Each one with a different pressure profile, and thus with its corresponding recovery mechanisms, identified as below: Vaporization/Condensation (two-phase system) in the fractures.Miscibility (liquid single-phase) in the non-SRV matrix.Miscibility and/or Vaporization/Condensation in the SRV matrix: depending on the injection gas composition and the pressure profile along the SRV the mechanism may be clearly one of them or even both. Results of this simulation study suggest that for the optimized cases, incremental oil recovery is 24% when the gas injected is a rich gas, but it is only 2.4% when the gas injected is pure methane. A higher incremental oil recovery of 49% is obtained, when injecting rich gas and increasing the minimum BHP of the puff cycle above the saturation pressure. Injection of gas results in reduction of oil molecular weight, oil density and oil viscosity in the matrix, i.e., the oil gets lighter. This net decrease is more pronounced in the SRV than in the non-SRV region. The incremental oil recovery observed in the GHnP process is due to the mobilization of heavy components (not present in the injection gas composition) that otherwise would remain inside the reservoir. Due to the main characteristic of the shale reservoirs (nano-Darcy permeability), GHnP is not a displacement process. A key factor in success of the GHnP process is to improve the contact of the injected gas and the reservoir oil to increase the mixing and mass transfer. This study includes a review of different mechanisms, and specifically tracks the evolution of the properties that explain and justify the different identified mechanisms.

An ANN model to predict oil recovery from a 5-spot waterflood of a heterogeneous reservoir

2021 ◽  
pp. 110012
Author(s):  
Shams Kalam ◽  
Usama Yousuf ◽  
Sidqi A. Abu-Khamsin ◽  
Umair Bin Waheed ◽  
Rizwan Ahmed Khan
Keyword(s):  
Oil Recovery ◽  
Ann Model ◽  
Heterogeneous Reservoir

AN ANALYTICAL MODEL OF A NON-STATIONARY TEMPERATURE FIELD IN A RESERVOIR WITH A HYDRAULIC FRACTURING

2021 ◽  
Vol 7 (2) ◽  
pp. 75-94
Author(s):  
Ramil F. SHARAFUTDINOV ◽  
Filyus F. Davletshin
Keyword(s):  
Temperature Field ◽  
Hydraulic Fracturing ◽  
Analytical Model ◽  
Oil Recovery ◽  
Temperature Anomaly ◽  
Nonstationary Temperature ◽  
Initial Moment ◽  
Positive Temperature ◽  
Fluid Filtration ◽  
Stage Of Development

At the present stage of development of the oil and gas industry, considerable attention is paid to methods of increasing oil recovery of productive reservoirs. One of the most popular methods of intensifying oil production today is hydraulic fracturing. The efficiency and success of hydraulic fracturing largely depends on the parameters of the formed fracture; in this regard, the development of methods for evaluating the parameters of hydraulic fracturing fractures is an urgent task. Non-stationary thermometry is a promising area for monitoring the quality of hydraulic fracturing. To date, thermometry is used to localize the locations of multiple fractures in horizontal wells. In this paper, we study the application of non-stationary thermometry for estimating the parameters of a vertical hydraulic fracturing fracture. An analytical model of non-isothermal single-phase fluid filtration in a reservoir with a vertical fracture is developed. To calculate the temperature field in the formation and the fracture, the convective heat transfer equation is used, taking into account the thermodynamic effects (Joule — Thomson and adibatic), for the fracture, the heat and mass transfer between the fracture and the formation area is also taken into account. To assess the correctness of the model, the analytical solution is compared with the results of numerical modeling in the Ansys Fluent software package. The nonstationary temperature field is calculated for the constant sampling mode. It is established that at the initial moment of time after the well start-up, a negative temperature anomaly is formed due to the adiabatic effect, the value of which increases with a decrease in the fracture width. Over time, the temperature of the fluid flowing into the well increases due to the Joule — Thomson effect, and the value of the positive temperature anomaly increases as the width and permeability of the fracture decreases due to an increase in the pressure gradient in it. The developed analytical model can be used to solve inverse problems for estimating hydraulic fracturing parameters based on non-stationary temperature measurements in the wellbore of producing wells.

Exploring Low-IFT Foam EOR in Fractured Carbonates: Success and Particular Challenges of Sub-10-md Limestone

SPE Journal ◽  
1900 ◽  
Vol 25 (02) ◽  
pp. 867-882
Author(s):  
Pengfei Dong ◽  
Maura Puerto ◽  
Guoqing Jian ◽  
Kun Ma ◽  
Khalid Mateen ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Surfactant Solution ◽  
Mineral Dissolution ◽  
Mobility Control ◽  
Matrix Permeability ◽  
Geochemical Properties ◽  
Remaining Oil ◽  
The Matrix ◽  
Incremental Oil Recovery ◽  
Foam Flooding

Summary The high formation heterogeneity in naturally fractured limestone reservoirs requires mobility control agents to improve sweep efficiency and boost oil recovery. However, typical mobility control agents, such as polymers and gels, are impractical in tight sub-10-md formations due to potential plugging issues. The objective of this study is to demonstrate the feasibility of a low-interfacial-tension (low-IFT) foam process in fractured low-permeability limestone reservoirs and to investigate relevant geochemical interactions. The low-IFT foam process was investigated through coreflood experiments in homogeneous and fractured oil-wet cores with sub-10-md matrix permeability. The performance of a low-IFT foaming formulation and a well-known standard foamer [alpha olefin sulfonate (AOS) C14-16] were compared in terms of the efficiency of oil recovery. The effluent ionic concentrations were measured to understand how the geochemical properties of limestone influenced the low-IFT foam process. Aqueous stability and phase behavior tests with crushed core materials and brines containing various divalent ion concentrations were conducted to interpret the observations in the coreflood experiments. Low-IFT foam process can achieve significant incremental oil recovery in fractured oil-wet limestone reservoirs with sub-10-md matrix permeability. Low-IFT foam flooding in a fractured oil-wet limestone core with 5-md matrix permeability achieved 64% incremental oil recovery compared to waterflooding. In this process, because of the significantly lower capillary entry pressure for surfactant solution compared to gas, the foam primarily diverted surfactant solution from the fracture into the matrix. This selective diversion effect resulted in surfactant or weak foam flooding in the tight matrix and hence improved the invading fluid flow in the matrix. Meanwhile, the low-IFT property of the foaming formulation mobilized the remaining oil in the matrix. This oil mobilization effect of the low-IFT formulation achieved lower remaining oil saturation in the swept zones compared with the formulation lacking low-IFT property with oil. The limestone geochemical instability caused additional challenges for the low-IFT foam process in limestone reservoirs compared to dolomite reservoirs. The reactions of calcite with injected fluids—such as mineral dissolution and the exchange of calcium and magnesium—were found to increase the Ca2+ concentration in the produced fluids. Because the low-IFT foam process is sensitive to brine salinity, the additional Ca2+ may cause potential surfactant precipitation and unfavorable over-optimum conditions. It, therefore, may cause injectivity and phase-trapping issues especially in the homogeneous limestone. Results in this work demonstrated that despite the challenges associated with limestone dissolution, the low-IFT foam process can remarkably extend chemical enhanced oil recovery (EOR) in fractured oil-wet tight reservoirs with matrix permeability as low as 5 md.

scholarly journals Polymer-functionalized silica nanoparticles for improving water flood sweep efficiency in Berea sandstones

2020 ◽  
Vol 146 ◽  
pp. 02001 ◽  
Author(s):  
Alberto Bila ◽  
Jan Åge Stensen ◽  
Ole Torsæter
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Functionalized Silica ◽  
Sweep Efficiency ◽  
Rock System ◽  
Injection Water ◽  
Improved Stability ◽  
Production Stages ◽  
Incremental Oil Recovery ◽  
Original Oil In Place

Extraction of oil trapped after primary and secondary oil production stages still poses many challenges in the oil industry. Therefore, innovative enhanced oil recovery (EOR) technologies are required to run the production more economically. Recent advances suggest renewed application of surface-functionalized nanoparticles (NPs) for oil recovery due to improved stability and solubility, stabilization of emulsions, and low retention on porous media. The improved surface properties make the NPs more appropriate to improve microscopic sweep efficiency of water flood compared to bare nanoparticles, especially in challenging reservoirs. However, the EOR mechanisms of NPs are not well understood. This work evaluates the effect of four types of polymer-functionalized silica NPs as additives to the injection water for EOR. The NPs were examined as tertiary recovery agents in water-wet Berea sandstone rocks at 60 °C. The NPs were diluted to 0.1 wt. % in seawater before injection. Crude oil was obtained from North Sea field. The transport of NPs though porous media, as well as nanoparticles interactions with the rock system, were investigated to reveal possible EOR mechanisms. The experimental results showed that functionalized-silica NPs can effectively increase oil recovery in water-flooded reservoirs. The incremental oil recovery was up to 14% of original oil in place (OOIP). Displacement studies suggested that oil recovery was affected by both interfacial tension reduction and wettability modification, however, the microscopic flow diversion due to pore plugging (log-jamming) and the formation of nanoparticle-stabilized emulsions were likely the relevant explanations for the mobilization of residual oil.

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