Reservoir Conditions Laboratory Experiments of CO2 Injection Into Fractured Cores

2006 ◽  
Author(s):  
Gholam Reza Darvish ◽  
Erik G.B. Lindeberg ◽  
Torleif Holt ◽  
Jon Kleppe ◽  
Svein Arild Utne
Keyword(s):  
Laboratory Experiments ◽  
Co2 Injection ◽  
Reservoir Conditions

Reservoir Conditions Laboratory Experiments of CO2 Injection into Fractured Cores

2006 ◽  
Author(s):  
Gholam Reza Darvish ◽  
Erik G.B. Lindeberg ◽  
Torleif Holt ◽  
Jon Kleppe ◽  
Svein Arild Utne
Keyword(s):  
Laboratory Experiments ◽  
Co2 Injection ◽  
Reservoir Conditions

Machine Learning Predictive Models to Estimate the Minimum Miscibility Pressure of CO2-Oil System

2021 ◽  
Author(s):  
Abderraouf Chemmakh ◽  
Ahmed Merzoug ◽  
Habib Ouadi ◽  
Abdelhak Ladmia ◽  
Vamegh Rasouli
Keyword(s):  
Machine Learning ◽  
Predictive Models ◽  
Critical Parameters ◽  
Co2 Injection ◽  
Learning Models ◽  
Minimum Miscibility Pressure ◽  
Reservoir Conditions ◽  
Important Amount ◽  
Machine Learning Models

Abstract One of the most critical parameters of the CO2 injection (for EOR purposes) is the Minimum Miscibility Pressure MMP. The determination of this parameter is crucial for the success of the operation. Different experimental, analytical, and statistical technics are used to predict the MMP. Nevertheless, experimental technics are costly and tedious, while correlations are used for specific reservoir conditions. Based on that, the purpose of this paper is to build machine learning models aiming to predict the MMP efficiently and in broad-based reservoir conditions. Two ML models are proposed for both pure CO2 and non-pure CO2 injection. An important amount of data collected from literature is used in this work. The ANN and SVR-GA models have shown enhanced performance comparing to existing correlations in literature for both the pure and non-pure models, with a coefficient of R2 0.98, 0.93 and 0.96, 0.93 respectively, which confirms that the proposed models are reliable and ready to use.

Enhanced Recovery of Nanoconfined Oil in Tight Rocks Using Lean Gas (C2H6 and CO2) Injection

SPE Journal ◽  
2021 ◽  
pp. 1-20
Author(s):  
Seunghwan Baek ◽  
I. Yucel Akkutlu
Keyword(s):  
Free Energy ◽  
Oil Recovery ◽  
Enhanced Recovery ◽  
Source Rocks ◽  
Superior Performance ◽  
Co2 Injection ◽  
Molecular Configuration ◽  
Pressure Depletion ◽  
Reservoir Conditions ◽  
Recovery Mechanisms

Summary Organic matters in source rocks store oil in significantly larger volume than that based on its pore volume (PV) due to so-called nanoconfinement effects. With pressure depletion and production, however, oil recovery is characteristically low because of the low compressibility of the fluid and amplified interaction with pore surface in the nanoporous material. For the additional recovery, CO2 injection has been widely adopted in shale gas and tight oil recovery over the last decades. But its supply and corrosion are often pointed out as drawbacks. In this study, we propose ethane injection as an alternative enhanced oil recovery (EOR) strategy for more productive oil production from tight unconventional reservoirs. Monte Carlo (MC) molecular simulation is used to reconstruct molecular configuration in pores under reservoir conditions. Further, molecular dynamics (MD) simulation provides the basis for understanding the recovery mechanism of in-situ fluids. These enable us to estimate thermodynamic recovery and the free energy associated with dissolution of injected gas. Primary oil recovery is typically below 15%, indicating that pressure depletion and fluid expansion are no longer effective recovery mechanisms. Ethane injection shows 5 to 20% higher recovery enhancement than CO2 injection. The superior performance is more pronounced, especially in nanopores, because oil in the smaller pores is richer in heavy components compared to the bulk fluids, and ethane molecules are more effective in displacing the heavy hydrocarbons. Analysis of the dissolution free energy confirms that introducing ethane into reservoirs is more favored and requires less energy for the enhanced recovery.

scholarly journals Chemistry of Reservoir Fluids in the Aspect of CO2 Injection for Selected Oil Reservoirs in Poland

Energies ◽  
2020 ◽  
Vol 13 (23) ◽  
pp. 6456
Author(s):  
Ewa Knapik ◽  
Katarzyna Chruszcz-Lipska
Keyword(s):  
Oil Recovery ◽  
Carbon Capture ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Oil Reservoirs ◽  
Co2 Injection ◽  
Oil Composition ◽  
Co2 Solubility ◽  
Geological Co2 Storage ◽  
Reservoir Conditions

Worldwide experiences related to geological CO2 storage show that the process of the injection of carbon dioxide into depleted oil reservoirs (CCS-EOR, Carbon Capture and Storage—Enhanced Oil Recovery) is highly profitable. The injection of CO2 will allow an increasing recovery factor (thus increasing CCS process profitability) and revitalize mature reservoirs, which may lead to oil spills due to pressure buildups. In Poland, such a solution has not yet been implemented in the industry. This work provides additional data for analysis of the possibility of the CCS-EOR method’s implementation for three potential clusters of Polish oil reservoirs located at a short distance one from another. The aim of the work was to examine the properties of reservoir fluids for these selected oil reservoirs in order to assure a better understanding of the physicochemical phenomena that accompany the gas injection process. The chemical composition of oils was determined by gas chromatography. All tested oils represent a medium black oil type with the density ranging from 795 to 843 g/L and the viscosity at 313 K, varying from 1.95 to 5.04 mm/s. The content of heavier components C25+ is up to 17 wt. %. CO2–oil MMP (Minimum Miscibility Pressure) was calculated in a CHEMCAD simulator using the Soave–Redlich–Kwong equation of state (SRK EoS). The oil composition was defined as a mixture of n-alkanes. Relatively low MMP values (ca. 8.3 MPa for all tested oils at 313 K) indicate a high potential of the EOR method, and make this geological CO2 storage form more attractive to the industry. For reservoir brines, the content of the main ions was experimentally measured and CO2 solubility under reservoir conditions was calculated. The reservoir brines showed a significant variation in properties with total dissolved solids contents varying from 17.5 to 378 g/L. CO2 solubility in brines depends on reservoir conditions and brine chemistry. The highest calculated CO2 solubility is 1.79 mol/kg, which suggest possible CO2 storage in aquifers.

scholarly journals An Experimental and Numerical Study of CO2–Brine-Synthetic Sandstone Interactions under High-Pressure (P)–Temperature (T) Reservoir Conditions

2019 ◽  
Vol 9 (16) ◽  
pp. 3354
Author(s):  
Zhichao Yu ◽  
Siyu Yang ◽  
Keyu Liu ◽  
Qingong Zhuo ◽  
Leilei Yang
Keyword(s):  
High Pressure ◽  
Numerical Modelling ◽  
Numerical Study ◽  
Mineral Dissolution ◽  
Co2 Injection ◽  
High Pressure And Temperature ◽  
Reservoir Conditions ◽  
Stainless Steel Reactor ◽  
Geochemical Reactions ◽  
And Storage

The interaction between CO2 and rock during the process of CO2 capture and storage was investigated via reactions of CO2, formation water, and synthetic sandstone cores in a stainless-steel reactor under high pressure and temperature. Numerical modelling was also undertaken, with results consistent with experimental outcomes. Both methods indicate that carbonates such as calcite and dolomite readily dissolve, whereas silicates such as quartz, K-feldspar, and albite do not. Core porosity did not change significantly after CO2 injection. No new minerals associated with CO2 injection were observed experimentally, although some quartz and kaolinite precipitated in the numerical modelling. Mineral dissolution is the dominant reaction at the beginning of CO2 injection. Results of experiments have verified the numerical outcomes, with experimentally derived kinetic parameters making the numerical modelling more reliable. The combination of experimental simulations and numerical modelling provides new insights into CO2 dissolution mechanisms in high-pressure/temperature reservoirs and improves understanding of geochemical reactions in CO2-brine-rock systems, with particular relevance to CO2 entry of the reservoir.

scholarly journals Laboratory Results of the Influence of Carbon Dioxide on the Development of the Permo-Carboniferous Reservoir of the Usinskoe Deposit

2021 ◽  
Vol 21 (1) ◽  
pp. 28-35
Author(s):  
Stanislav A. Stanislav A. ◽  
◽  
Oleg A. Morozyuk ◽  
Konstantin S. Kosterin ◽  
Semyon P. Podoinitsyn ◽  
...  
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Co2 Concentration ◽  
High Viscosity ◽  
Co2 Injection ◽  
Oil Displacement ◽  
Displacement Mode ◽  
Use Of Technology ◽  
Reservoir Conditions ◽  
High Viscosity Oil

As an option for enhancing oil recovery of a high-viscosity Permo-Carboniferous reservoir associated with the Usinskoye field, the use of technology based on technogenic carbon dioxide as an injection agent is considered. In the world practice, several fields are known as close in their parameters to the parameters of the Permo-Carboniferous reservoir, and in which CO2 injection was accepted as successful. Based on this, CO2 injection can potentially be applicable in the conditions of a Permo-Carboniferous reservoir. At present, as a result of the various development technologies implementation, reservoir zones are distinguished, characterized by different thermobaric properties. Depending on reservoir conditions, when displacing oil with gases, various modes of oil displacement can be realized. This article describes the results of studies carried out to study the effect of the concentration of carbon dioxide on the properties of high-viscosity oil in the Permo-Carboniferous Reservoir of the Usinskoye field, as well as the results of filtration experiments on slim models performed to assess the oil displacement regime under various temperature and pressure conditions of the Permo-Carboniferous Reservoir. The study of the influence of CO2 concentration on oil properties was carried out using the standard PVT research technique. The displacement mode was assessed using the slim-tube technique. Based on the performed experiments, it was established that an increase in the concentration of CO2 in high-viscosity oil led to a noticeable change in its properties; for the conditions of a Permo-Carboniferous Reservoir, the most probable mode of oil displacement by carbon dioxide was established. Difficulties associated with the preparation of the CO2-heavy oil system were described separately. Based on a literature review, it was shown that the rate of mixing of oil with carbon dioxide depended on certain conditions.

scholarly journals Characterization of a Reservoir Fluid Based on an Analysis of Intrinsic Properties Using the Adaptive Batzle-Wang Method in Field “M”

2019 ◽  
Vol 17 (2) ◽  
Author(s):  
M. Syamsu Rosid ◽  
Muhammad` Iksan ◽  
Reza Wardhana ◽  
M. Wahdanadi Haidar
Keyword(s):  
Physical Properties ◽  
Laboratory Experiments ◽  
Fluid Model ◽  
Rock Physics ◽  
P Wave ◽  
Fluid Replacement ◽  
Intrinsic Properties ◽  
Temperature Conditions ◽  
Reservoir Conditions ◽  
Fluid Properties

The physical properties and phases of a fluid under reservoir conditions are different from those under surface conditions. The value of a fluid property may change as a result of changes in pressure and temperature. An analysis of the intrinsic properties of fluids is carried out to obtain a fluid model that corresponds to fluid conditions in a reservoir. This study uses the Adaptive Batzle-Wang model, which combines thermodynamic relationships, empirical data trends, and experimental fluid data from the laboratory to estimate the effects of pressure and temperature on fluid properties. The Adaptive Batzle-Wang method is used because the usual Batzle-Wang method is less suitable for describing the physical properties of a fluid under the conditions in the field studied here. The Batzle-Wang fluid model therefore needs to be modified to obtain a fluid model that adjusts to the fluid conditions in each study area. In this paper, the Adaptive Batzle-Wang model is used to model three types of fluid i.e. oil, gas, and water. By making use of data on the intrinsic fluid properties such as the specific gravity of the gases (G), the Gas-Oil Ratio (GOR), the Oil FVF (Bo), the API values, the Salinity, and the Fluid Density obtained from laboratory experiments, the Batzle-Wang fluid model is converted into the Adaptive Batzle-Wang model by adding equations for the intrinsic fluid properties under the pressure and temperature conditions in the field reservoir. The results obtained are the values of the bulk modulus (K), the density (ρ), and the P-wave velocity (Vp) of the fluid under reservoir conditions. The correlation coefficient of the Adaptive Batzle-Wang model with the fluid data from the laboratory experiments is 0.95. The model is well able to calculate the fluid properties corresponding to the conditions in this field reservoir. The model also generates a unique value for the fluid properties in each study area. So, it can adjust to the pressure and temperature conditions of the field reservoir under study. The Adaptive Batzle-Wang method can therefore be applied to fields for which laboratory fluid data is available, especially fields with a high reservoir pressure and temperature. The results of the fluid modeling can then be used for rock physics and Fluid Replacement Model analysis.

A Laboratory Study of Coinjection of Water and CO2 to Improve Oil Recovery and CO2 Storage: Effect of Fraction of CO2 Injected

SPE Journal ◽  
2020 ◽  
pp. 1-9
Author(s):  
Emmanuel Ajoma ◽  
Thanarat Sungkachart ◽  
Saria ◽  
Hang Yin ◽  
Furqan Le-Hussain
Keyword(s):  
Oil Recovery ◽  
Laboratory Experiments ◽  
Water Pressure ◽  
Co2 Storage ◽  
Water Injection ◽  
Molar Fraction ◽  
Co2 Injection ◽  
The Core ◽  
Carbon Dioxide Co2 ◽  
Water Saturated

Summary To determine the effect on oil recovery and carbon dioxide (CO2) storage, laboratory experiments are run with various fractions of CO2 injected (FCI): pure CO2 injection (FCI = 1), water-saturated CO2 (wsCO2) injection (FCI = 0.993), simultaneous water and gas (SWAG) (CO2) injection (FCI = 0.75), carbonated water injection (CWI) (FCI = 0.007), and water injection (FCI = 0). All experiments are performed on Bentheimer sandstone cores at 70°C and 11.7 MPa (1,700 psia). The oil phase is composed of 65% hexane and 35% decane by molar fraction. Before any fluid is injected, the core is filled with oil and irreducible water. Pressure difference across the core and production rate of gas are measured during the experiment. The collected produced fluids are analyzed in a gas chromatograph to determine their composition. Cumulative oil recovery after injection is found to be 78 to 83% for wsCO2, 78% for SWAG, 74% for pure CO2, 53% for CWI, and 35% for water. Net CO2 stored is also found to be the highest for wsCO2 (59 to 65% of the pore volume), followed by that for CO2 injection (56%) and that for SWAG (42%). These results suggest that wsCO2 injection might outperform pure CO2 injection at both oil recovery and net CO2stored.

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