Effect of Initial Water Saturation on Bypassed Oil Recovery during CO2 Injection at Different Miscibility Conditions

2015 ◽  
Vol 29 (7) ◽  
pp. 4114-4121 ◽  
Author(s):  
Keyvan Kazemi ◽  
Behzad Rostami ◽  
Maryam Khosravi ◽  
Danial Zeinabady Bejestani
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Co2 Injection ◽  
Initial Water ◽  
Bypassed Oil

Role of molecular diffusion in the recovery of water flood residual oil

2019 ◽  
Author(s):  
Chem Int
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Gravity Drainage ◽  
Co2 Injection ◽  
Initial Water ◽  
Water Imbibition ◽  
Naturally Fractured ◽  
Carbon Dioxide Co2

Traditionally, carbon dioxide (CO2) injection has been considered an inefficient method for enhancing oil recovery from naturally fractured reservoirs. Obviously, it would be useful to experimentally investigate the efficiency of waterflooding naturally fractured reservoirs followed by carbon dioxide (CO2) injection. This issue was investigated by performing water imbibition followed by CO2 gravity drainage experiments on artificially fractured cores at reservoir conditions. The experiments were designed to illustrate the actual process of waterflooding and CO2 gravity drainage in a naturally fractured reservoir in the Brass Area, Bayelsa. The results demonstrate that CO2 gravity drainage could significantly increase oil recovery after a waterflood. During the experiments, the effects of different parameters such as permeability, initial water saturation and injection scheme was also examined. It was found that the efficiency of the CO2 gravity drainage decrease as the rock permeability decreases and the initial water saturation increases. Cyclic CO2 injection helped to improve oil recovery during the CO2 gravity drainage process which alters the water imbibition. Oil samples produced in the experiment were analyzed using gas chromatography to determine the mechanism of CO2-improved oil production from tight matrix blocks. The results show that lighter components are extracted and produced early in the test. The results of these experiments validate the premises that CO2 could be used to recover oil from a tight and unconfined matrix efficiently.

Mechanistic investigation of bypassed-oil recovery during CO2 injection in matrix and fracture

Fuel ◽  
2014 ◽  
Vol 117 ◽  
pp. 43-49 ◽  
Author(s):  
Maryam Khosravi ◽  
Alireza Bahramian ◽  
Mohammadali Emadi ◽  
Behzad Rostami ◽  
Emad Roayaie
Keyword(s):  
Oil Recovery ◽  
Co2 Injection ◽  
Mechanistic Investigation ◽  
Bypassed Oil

Effective Prediction and Management of a CO2 Flooding Process for Enhancing Oil Recovery Using Artificial Neural Networks

2017 ◽  
Vol 140 (3) ◽  
Author(s):  
Si Le Van ◽  
Bo Hyun Chon
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Environmental Benefits ◽  
Co2 Production ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Injection Process ◽  
Artificial Neural

The injection of CO2 has been in global use for enhanced oil recovery (EOR) as it can improve oil production in mature fields. It also has environmental benefits for reducing greenhouse carbon by permanently sequestrating CO2 (carbon capture and storage (CCS)) in reservoirs. As a part of numerical studies, this work proposed a novel application of an artificial neural network (ANN) to forecast the performance of a water-alternating-CO2 process and effectively manage the injected CO2 in a combined CCS–EOR project. Three targets including oil recovery, net CO2 storage, and cumulative gaseous CO2 production were quantitatively simulated by three separate ANN models for a series of injection frames of 5, 15, 25, and 35 cycles. The concurrent estimations of a sequence of outputs have shown a relevant application in scheduling the injection process based on the progressive profile of the targets. For a specific surface design, an increment of 5.8% oil recovery and 4% net CO2 storage was achieved from 25 cycles to 35 cycles, suggesting ending the injection at 25 cycles. Using the models, distinct optimizations were also computed for oil recovery and net CO2 sequestration in various reservoir conditions. The results expressed a maximum oil recovery from 22% to 30% oil in place (OIP) and around 21,000–29,000 tons of CO2 trapped underground after 35 cycles if the injection began at 60% water saturation. The new approach presented in this study of applying an ANN is obviously effective in forecasting and managing the entire CO2 injection process instead of a single output as presented in previous studies.

scholarly journals Investigation on Coal Skeleton Deformation in CO2 Injection Enhanced CH4 Drainage From Underground Coal Seam

2021 ◽  
Vol 9 ◽  
Author(s):  
Chaojun Fan ◽  
Lei Yang ◽  
Gang Wang ◽  
Qiming Huang ◽  
Xiang Fu ◽  
...  
Keyword(s):  
Mathematical Model ◽  
Coal Seam ◽  
Initial Temperature ◽  
Water Saturation ◽  
Early Stage ◽  
Gas Injection ◽  
Strain Curve ◽  
Co2 Injection ◽  
Initial Water ◽  
Gas Drainage

To reveal the evolution law of coal skeleton deformation during the process of CO2 flooding and displacing CH4 in coal seam, a fluid-solid coupling mathematical model of CO2 injection enhanced CH4 drainage was established based on Fick’s law, Darcy’s law, ideal gas state equation, and Langmuir equation. Meanwhile, numerical simulations were carried out by implementing the mathematical model in the COMSOL Multiphysics. Results show that the CH4 content of both regular gas drainage and CO2 enhanced gas drainage gradually decreases with time, and the decreasing rate is high between 10 and 60 days. Compared with regular gas drainage, the efficiency of CO2 enhanced gas drainage is more obvious with greater amount of CH4 extracted out. When coal seam gas is extracted for 10, 60, 120, and 180 days, CH4 content in coal seam is reduced by 5.2, 17.2, 23.6, and 26.7%, respectively. For regular gas drainage, the deformation of coal skeleton is dominated by the shrink of coal matrix induced by gas desorption, and the strain curve shows a continuous downward trend. For CO2 enhanced gas drainage, the strain curve of coal skeleton showed a decrease—rapid increase—slow increase trend. The evolution of permeability is opposite to the evolution of coal skeleton strain. Higher gas injection pressure will lead to a greater coal skeleton strain. The pumping pressure affects the deformation of coal skeleton slightly compared with that of initial water saturation and initial temperature. Greater initial water saturation leads to larger deformation of coal skeleton in the early stage. The strain value of coal skeleton gradually tends to be consistent as gas injection prolongs. Higher initial temperature leads to greater reduction in coal skeleton strain when the gas injection continues. Research achievements provide a basis for the field application of CO2 injection enhanced CH4 drainage in underground coal mines.

Pore-Scale Modeling of Wettability Effects and Their Influence on Oil Recovery

1999 ◽  
Vol 2 (01) ◽  
pp. 25-36 ◽  
Author(s):  
A.B. Dixit ◽  
S.R. McDougall ◽  
K.S. Sorbie ◽  
J.S. Buckley
Keyword(s):  
Crude Oil ◽  
Capillary Pressure ◽  
Oil Recovery ◽  
Aging Process ◽  
Water Saturation ◽  
Contact Angles ◽  
Initial Water ◽  
Water Imbibition ◽  
Pore Level ◽  
Capillary Pressure Curves

Summary The wettability of a crude oil/brine/rock system influences both the form of petrophysical parameters (e.g., Pc and krw/kro) and the structure and distribution of remaining oil after secondary recovery. This latter issue is of central importance for improved oil recovery since it represents the "target" oil for any IOR process. In the present study, we have developed a three-dimensional network model to derive capillary pressure curves from nonuniformly wetted (mixed and fractionally wet) systems. The model initially considers primary drainage and the aging process leading to wettability alterations. This is then followed by simulations of spontaneous water imbibition, forced water drive, spontaneous oil imbibition and forced oil drive—i.e., we consider a complete flooding sequence characteristic of wettability experiments. The model takes into account many pore level flow phenomena such as film flow along wetting phase clusters, trapping of wetting and nonwetting phases by snapoff and bypassing. We also consider realistic variations in advancing and receding contact angles. There is a discussion of the effects of additional parameters such as the fraction of oil-wet pores, mean coordination number and pore size distribution upon fractionally and mixed wet capillary pressure curves. Moreover, we calculate Amott oil and water indices using the simulated curves. Results indicate that oil recovery via water imbibition in weakly water-wet cores can often exceed that obtained from strongly water-wet samples. Such an effect has been observed experimentally in the past. The basic physics governing this enhancement in spontaneous water imbibition can be explained using the concept of a capillarity surface. Based on these theoretical calculations, we propose a general "regime based" theory of wettability classification and analysis. We classify a range of experimentally observed and apparently inconsistent waterflood recovery trends into various regimes, depending upon the structure of the underlying oil- and water-wet pore clusters and the distribution of contact angles. Using this approach, numerous published experimental Amott indices and waterflood data from a variety of core/crude oil/brine systems are analyzed. Introduction In crude oil/brine/rock (COBR) systems, pore level displacements of oil and brine and hence the corresponding petrophysical flow parameters (e.g., Pc and krw/kro) describing these displacements are governed by the pore geometry, topology and wettability of the system. A number of excellent review papers are available that describe experimental investigations of the effect of wettability on capillary pressure and oil-water relative permeability curves.1–5 In COBR systems, wettability alterations depend upon the mineralogical composition of the rock, pH and/or composition of the brine, crude oil composition, initial water saturation, reservoir temperature, etc.6–12 Therefore, in recent years, interest in restoring the wettability of reservoir core using crude oil and formation brine has greatly increased.3,4,13,14 In this approach, cleaned reservoir core is first saturated with brine and then oil flooded to initial water saturation using crude oil. The core containing crude oil and brine is then aged to alter its wettability state. Wettability measurements, such as Amott and USBM tests, and waterflood experiments are then typically conducted on the aged core. This entire process broadly mimics the actual flow sequences in the reservoir; consequently, the wettability alterations are more realistic than those achieved using chemical treatment methods. During the aging process, wettability may be altered to vastly different degrees depending upon many factors, including those mentioned above. In addition, aging time, thickness of existing water films and wetting film disjoining pressure isotherms also play important roles. Hence, the final wettability state of a re-conditioned core will generally be case specific.

Influence of Initial Water Saturation on Recovery by Spontaneous Imbibition in Gas/Water/Rock Systems and the Calculation of Relative Permeability

2006 ◽  
Vol 9 (04) ◽  
pp. 295-301 ◽  
Author(s):  
Kewen Li ◽  
Kevin Chow ◽  
Roland N. Horne
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Water Saturation ◽  
Water Injection ◽  
Spontaneous Imbibition ◽  
Rock Properties ◽  
Initial Water ◽  
Gas Recovery ◽  
Water Imbibition ◽  
Theoretical Predictions

Summary It has been a challenge to understand why recovery by spontaneous imbibition could both increase and decrease with initial water saturation. To this end, mathematical models were developed with porosity, permeability, viscosity, relative permeability, capillary pressure, and initial water saturation included. These equations foresee that recovery and imbibition rate can increase, remain unchanged, or decrease with an increase in initial water saturation, depending on rock properties, the quantity of residual gas saturation, the range of initial water saturation, and the units used in the definitions of gas recovery and imbibition rate. The theoretical predictions were verified experimentally by conducting spontaneous water imbibition at five different initial water saturations, ranging from 0 to approximately 50%. The effects of initial water saturation on residual saturation, relative permeability, capillary pressure, imbibition rate, and recovery in gas/water/rock systems by cocurrent spontaneous imbibition were investigated both theoretically and experimentally. Water-phase relative permeabilities and capillary pressures were calculated with the experimental data of spontaneous imbibition. Experimental results in different rocks were compared. Introduction Spontaneous water imbibition is an important mechanism during water injection. Prediction of recovery and imbibition rate by spontaneous water imbibition is essential to evaluate the feasibility and the performance of water injection. For example, is water injection effective in the case of high initial water saturation in reservoirs? Answers to such a question may be found by investigating the effect of initial water saturation on spontaneous water imbibition. It has been observed experimentally that initial water saturation affects recovery and production rate significantly (Blair 1964; Zhou et al. 2000; Viksund et al. 1998; Cil et al. 1998; Tong et al. 2001; Li and Firoozabadi 2000; Akin et al. 2000). However, the experimental observations from different authors (Zhou et al. 2000; Cil et al. 1998; Li and Firoozabadi 2000; Akin et al. 2000) are not consistent. On the other hand, few studies have investigated the effect of initial water saturation on recovery and imbibition rate theoretically, especially in gas reservoirs. Using numerical-simulation techniques, Blair (1964) found that the quantity and the rate of oil produced after a given period of imbibition increased with a decrease in initial water saturation for countercurrent spontaneous imbibition. Zhou et al. (2000) found that both imbibition rate and final oil recovery in terms of oil originally in place (OOIP) increased with an increase in initial water saturation, whereas oil recovery by waterflooding decreased. Viksund et al. (1998) found that the final oil recovery (OOIP) by spontaneous water imbibition in Berea sandstone showed little variation with a change in initial water saturation from 0 to approximately 30%. For the chalk samples tested by Viksund et al. (1998), the imbibition rate first increased with an increase in initial water saturation and then decreased slightly as initial water saturation increased above 34%.Cil et al. (1998) reported that the oil recovery (in terms of recoverable oil reserves) for zero and 20% initial water saturation showed insignificant differences in behavior. However, the oil recovery for initial water saturation above 20% increased with an increase in initial water saturation. Li and Firoozabadi (2000) found that the final gas recovery in the units of gas originally in place (GOIP) by spontaneous imbibition decreased with an increase in initial water saturation in both gas/oil/rock and gas/water/rock systems. The imbibition rate (GOIP/min) increased with an increase in initial water saturation at early time but decreased at later time. Akin et al. (2000) found that the residual oil saturation was unaffected significantly by initial water saturation. In this study, equations, derived theoretically, were used to study the effect of initial water saturation on gas recovery and imbibition rate. The equations correlate recovery, imbibition rate, initial water saturation, rock/fluid properties, and other parameters. Experiments of spontaneous water imbibition in gas-saturated rocks were conducted to confirm the theoretical predictions. The effect of rock properties on gas recovery and imbibition rate was also studied. An X-ray CT scanner was used to monitor the distribution of the initial water saturation to confirm that the initial distribution of the water saturation was uniform. In this study, we only focused on cocurrent spontaneous imbibition. It was assumed that there were no chemical reactions or mass transfer between gas and liquid.

Water Mixing During Waterflood Oil Recovery: The Effect of Initial Water Saturation

SPE Journal ◽  
2011 ◽  
Vol 17 (01) ◽  
pp. 43-52 ◽  
Author(s):  
Arne Graue ◽  
Martin A. Fernø ◽  
Robert W. Moe ◽  
Bernard A. Baldwin ◽  
Riley Needham
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Core Sample ◽  
Initial Water ◽  
Connate Water ◽  
Fluid Saturation ◽  
Secondary Recovery ◽  
Tracer Imaging ◽  
Displacement Processes

Summary This work studies the mixing of injected water and in-situ water during waterfloods and demonstrates that the mixing process is sensitive to the initial water saturation. The results illustrate differences between a waterflooded zone and a preflooded zone during, for example, water-based EOR displacement processes. The mixing of in-situ, or connate, water and injected water during laboratory waterfloods in a strongly water-wet chalk core sample was determined at different initial water saturations. Dynamic 1D fluid-saturation profiles were determined with nuclear-tracer imaging (NTI) during waterfloods, distinguishing between the oil phase, connate water, and injected water. The mixing of connate and injected water during waterfloods, with the presence of an oil phase, resulted in a displacement of all connate water from the core plug. During displacement, connate water banked in front of the injecting water, separating (or partially separating) the injected water from the mobile oil phase. This may impact the ability of chemicals dissolved in the injected water to contact the oil during secondary recovery and EOR processes. The effect of the connate-water-bank separation was sensitive to the initial water saturation (Swi). The time difference between breakthrough of connate water and breakthrough of injected water at the outlet showed a linear correlation to the initial water saturation Swi. The results obtained in chalk confirmed earlier findings in sandpacks (Brown 1957) and thus demonstrated the generality in the results.

Sign in / Sign up

Export Citation Format

Share Document