Evaluating the Impact of Reservoir Cooling on the Surfactant Flood Efficiency

2021 ◽  
Author(s):  
Amir Soltani ◽  
Benoit Decroux ◽  
Andres Negre ◽  
Thierry Le Maux ◽  
Maâmar Djarir ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Thermal Model ◽  
Water Injection ◽  
Hole Injection ◽  
Reservoir Temperature ◽  
Temperature Variations ◽  
Temperature Range ◽  
Bottom Hole ◽  
Injection Temperature ◽  
The Impact

Abstract EOR surfactants are usually formulated at the initial reservoir temperature. Is this a correct approach? Field data from three Single-Well Chemical Tracer pilots in North Africa are used to answer this question. The objectives are, first, to provide a realistic image of the temperature variations inside the water-flooded reservoir; second, to demonstrate the impact of such temperature variations on the surfactant performances; and last, to introduce a new methodology for estimating the target temperature window for surfactant formulations. During pre-SWCTT pilot tests, water injection, shut-in and back-production were performed. The bottom-hole temperature was monitored to evaluate the reservoir temperature changes (initially at 120°C) and to calibrate a thermal model. The thermal parameters were applied to the reservoir model to simulate 30 years of water injection (with its surface temperature varying between 20°C and 60°C) and to obtain a full picture of the temperature variations inside the reservoir. Multi-well surfactant injection was modelled assuming that the surfactant is only efficient within ±10°C around the design temperature. The impact of this assumption on the additional oil recovery was analyzed for several scenarios. The rock thermal transmissivity was found to be the key parameter for properly reproducing the observed data gathered in the North African pre-SWCTT tests. The measured temperature during the back-production phase demonstrated the accuracy of the thermal model parametrization. It proved that the heat exchange between the reservoir and the injected fluid is considerably less than what industry expects: the injected water temperature inside the reservoir remains far below the initial reservoir temperature even after 11 days of shut-in. When simulating various historical bottom-hole injection temperatures and pre-flush durations, the thermal model showed an average cooling radius of 275m, larger than the industry recommended well-spacing for the EOR 5-spot patterns. This was mainly due to the significant temperature difference between the historical injected water and the initial reservoir temperature. Several simulations were performed for 3 representative bottom-hole injection temperatures of 20°C, 40°C and 60°C, varying the surfactant design temperature range between the injection temperature and the initial reservoir temperature. The results showed that regardless of the injection temperature, the simulated additional oil recovery is highest when the design temperature range is close to the injection bottom-hole temperature. This is an important subject since in the EOR industry, the surfactants are usually formulated at the initial reservoir temperature and thus, the impact of the reservoir cooling on the surfactant efficiency is seldom considered. In a water flooded reservoir, the injected chemicals are unlikely to encounter the initial reservoir temperature. This results in a dramatic loss of surfactant performance especially when there is a considerable difference between the initial reservoir and the injected fluid temperatures.

A Parametric Study of Reservoir Cooling for Enhanced Recovery by Carbon Dioxide Flooding

SPE Journal ◽  
2016 ◽  
Vol 21 (03) ◽  
pp. 0839-0852 ◽  
Author(s):  
Zhenzhen Wang ◽  
Amey Khanzode ◽  
Russell T. Johns
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Enhanced Recovery ◽  
Co2 Injection ◽  
Reservoir Pressure ◽  
Co2 Flooding ◽  
Reservoir Temperature ◽  
Temperature Variations ◽  
Flow Dimension ◽  
Injection Temperature

Summary Slimtube experiments and analytical calculations show that minimum miscibility pressure (MMP) can significantly decrease with a relatively modest reduction in temperature. Compositional simulation, however, is often made under isothermal conditions even though a prior waterflood may have reduced reservoir temperature in the swept zones of the reservoir. This study uses computer simulation to examine how cooling by a prior waterflood can affect recovery during a carbon dioxide (CO2) flood by lowering the MMP in the swept zones. The results show that for the cases considered, injection of cooler water can increase incremental oil recovery (IOR) significantly because of MMP reduction in the zones swept by the solvent. A parametric simulation study demonstrates how injection temperature, initial reservoir pressure, formation heterogeneity, formation thickness, heat transfer with the overburden/underburden formations, and water-alternating-gas (WAG) ratio may affect the IOR. The simulations are conducted by a long waterflood of up to 2.0 pore volumes injected before CO2 injection. The water during the secondary recovery is injected at several temperatures for selected 1D, 2D, and 3D flow models. CO2 solvent is then injected continuously, or in WAG mode, at the same waterflood-injection temperature. The increase in IORs (greater than what would have been obtained by a standard CO2 flood at original reservoir temperature) varied greatly depending on the flow dimension, initial reservoir pressure, level of heterogeneity, formation thickness, degree of energy gain from the surroundings, and injection temperature. Increases in recovery by CO2 flooding varied from a few percent to nearly 30% of original oil in place, with the highest recoveries occurring in 1D flow. For the same flow dimension, the largest increase in recoveries is achieved when the MMP is sufficiently reduced by temperature so that an otherwise immiscible or near-miscible flood becomes a multicontact miscible flood. The results demonstrate that including temperature variations in the simulations is important for floods that are nearly miscible because recoveries are most affected in that region. Further, including temperature variations could be very important to improve the quality of history matches used to understand the reservoir.

scholarly journals Numerical modeling and experimental investigation on the effect of low-salinity water flooding for enhanced oil recovery in carbonate reservoirs

2021 ◽  
Vol 11 (2) ◽  
pp. 925-947
Author(s):  
Erfan Hosseini ◽  
Mohammad Sarmadivaleh ◽  
Dana Mohammadnazar
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Experimental Investigations ◽  
Core Flooding ◽  
Reservoir Temperature ◽  
Sulfate Ion ◽  
Ionic Content ◽  
Low Salinity

AbstractNumerous studies concluded that water injection with modified ionic content/salinity in sandstones would enhance the oil recovery factor due to some mechanisms. However, the effects of smart water on carbonated formations are still indeterminate due to a lack of experimental investigations and researches. This study investigates the effects of low-salinity (Low Sal) solutions and its ionic content on interfacial tension (IFT) reduction in one of the southwestern Iranian carbonated reservoirs. A set of organized tests are designed and performed to find each ion’s effects and total dissolved solids (TDS) on the candidate carbonated reservoir. A sequence of wettability and IFT (at reservoir temperature) tests are performed to observe the effects of controlling ions (sulfate, magnesium, calcium, and sodium) and different salinities on the main mechanisms (i.e., wettability alteration and IFT reduction). All IFT tests are performed at reservoir temperature (198 °F) to minimize the difference between reservoir and laboratory-observed alterations. In this paper, the effects of four different ions (SO42-, Ca2+, Mg2+, Na+) and total salinity TDS (40,000, 20,000, 5000 ppm) are investigated. From all obtained results, the best two conditions are applied in core flooding tests to obtain the relative permeability alterations using unsteady-state methods and Cydarex software. The final part is the simulation of the whole process using the Schlumberger Eclipse black oil simulator (E100, Ver. 2010) on the candidate reservoir sector. To conclude, at Low Sal (i.e., 5000 ppm), the sulfate ion increases sulfate concentration lower IFT, while in higher salinities, increasing sulfate ion increases IFT. Also, increasing calcium concentration at high TDS (i.e., 40,000 ppm) decreases the amount of wettability alteration. In comparison, in lower TDS values (20,000 and 5000 ppm), calcium shows a positive effect, and its concentration enhanced the alteration process. Using Low Sal solutions at water cut equal or below 10% lowers recovery rate during simulations while lowering the ultimate recovery of less than 5%.

Experimental Investigation of Near-Miscible Water-Alternating-Gas Injection Performance in Water-Wet and Mixed-Wet Systems

SPE Journal ◽  
2013 ◽  
Vol 18 (01) ◽  
pp. 114-123 ◽  
Author(s):  
S. Mobeen Fatemi ◽  
Mehran Sohrabi
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Laboratory Data ◽  
Co2 Injection ◽  
Water Alternating Gas ◽  
Three Phase ◽  
The Impact ◽  
Wag Injection

Summary Laboratory data on water-alternating-gas (WAG) injection for non-water-wet systems are very limited, especially for near-miscible (very low IFT) gas/oil systems, which represent injection scenarios involving high-pressure hydrocarbon gas or CO2 injection. Simulation of these processes requires three-phase relative permeability (kr) data. Most of the existing three-phase relative permeability correlations have been developed for water-wet conditions. However, a majority of oil reservoirs are believed to be mixed-wet and, hence, prediction of the performance of WAG injection in these reservoirs is associated with significant uncertainties. Reliable simulation of WAG injection, therefore, requires improved relative permeability and hysteresis models validated by reliable measured data. In this paper, we report the results of a comprehensive series of coreflood experiments carried out in a core under natural water-wet conditions. These included water injection, gas injection, and also WAG injection. Then, to investigate the impact of wettability on the performance of these injection strategies, the wettability of the same core was changed to mixed-wet (by aging the core in an appropriate crude oil) and a similar set of experiments were performed in the mixed-wet core. WAG experiments under both wettability conditions started with water injection (I) followed by gas injection (D), and this cyclic injection of water and gas was repeated (IDIDID). The results show that in both the water-wet and mixed-wet cores, WAG injection performs better than water injection or gas injection alone. Changing the rock wettability from water-wet to mixed-wet significantly improves the performance of water injection. Under both wettability conditions (water-wet and mixed-wet), the breakthrough (BT) of the gas during gas injection happens sooner than the BT of water in water injection. Ultimate oil recovery by gas injection is considerably higher than that obtained by water injection in the water-wet system, while in the mixed-wet system, gas injection recovers considerably less oil.

The Effect of Water-Induced Stress To Enhance Hydrocarbon Recovery in Shale Reservoirs

SPE Journal ◽  
2013 ◽  
Vol 18 (05) ◽  
pp. 897-909 ◽  
Author(s):  
Perapon Fakcharoenphol ◽  
Sarinya Charoenwongsa ◽  
Hossein Kazemi ◽  
Yu-Shu Wu
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Reservoir Pressure ◽  
Reservoir Temperature ◽  
Hydrocarbon Recovery ◽  
Induced Stress ◽  
Stress Changes ◽  
Matrix Blocks ◽  
The Matrix ◽  
Shale Reservoirs

Summary Waterflooding has been an effective improved-oil-recovery (IOR) process for several decades. However, stress induced by waterflooding has not been well studied or documented. Water injection typically increases reservoir pressure and decreases reservoir temperature. The increase in reservoir pressure and decrease in reservoir temperature synergistically reduce the effective stress. Because of such decrease in stress, existing healed natural fractures can be reactivated and/or new fractures can be created. Similar effects can enhance hydrocarbon recovery in shale reservoirs. In this paper, we calculated the magnitude of water-injection-induced stress with a coupled flow/geomechanics model. To evaluate the effect of water injection in the Bakken, a numerical-simulation study for a sector model was carried out. Stress changes caused by the volume created by the hydraulic fracture, water injection, and oil production were calculated. The Hoek-Brown failure criterion was used to compute rock-failure potential. Our numerical results for a waterflooding example show that during water injection, the synergistic effects of reservoir cooling and pore-pressure increase significantly promote rock failure, potentially reactivating healed natural macrofractures and/or creating new macrofractures, especially near an injector. The rock cooling can create small microfractures on the surface of the matrix blocks. In shale oil reservoirs, the numerical experiments indicate that stress changes during water injection can improve oil recovery by opening some of the old macrofractures and creating new small microfractures on the surface of the matrix blocks to promote shallow water invasion into the rock matrix. Furthermore, the new microfractures provide additional interface area between macrofractures and matrix to improve oil drainage when using surfactant and CO2 enhanced-oil-recovery techniques. These positive effects are particularly important farther away from the immediate vicinity of the hydraulic fracture, which is where much of the undrained oil resides.

scholarly journals Effect of Salts on Interfacial Tension and CO2 Mass Transfer in Carbonated Water Injection

Energies ◽  
2019 ◽  
Vol 12 (4) ◽  
pp. 748 ◽  
Author(s):  
Aly Hamouda ◽  
Nikhil Bagalkot
Keyword(s):  
Mass Transfer ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Hydration Shell ◽  
Water Injection ◽  
Oh Groups ◽  
Carbonated Water Injection ◽  
Carbonated Water ◽  
Co2 Mass Transfer ◽  
The Impact

Carbonated water injection (CWI) is a promising enhanced oil recovery (EOR) and CO2 sequestration method, which overcomes the problems associated with CO2 EOR. CO2 mass transfer and interfacial tension (IFT) are important parameters that influence oil recovery efficiency. This study addresses the impact of MgCl2 and Na2SO4 in carbonated water (CW) on CW/hydrocarbon IFT and CO2 mass transfer. An axisymmetric drop shape analysis was used to estimate the IFT and the CO2 diffusion coefficient. It was found that CW+MgCl2 reduced both the CW/n-decane IFT (36.5%) and CO2 mass transfer, while CW+Na2SO4 increased both the IFT and CO2 mass transfer (57%). It is suggested that reduction in IFT for CW+MgCl2 brine is mainly due to the higher hydration energy of Mg2+. The Mg2+ ion forms a tight bond to the first hydration shell [Mg(H2O)6]2+, this increases the effective size at the interface, hence reduce IFT. Meanwhile, the SO42− outer hydration shell has free OH groups, which may locally promote CO2 mass transfer. The study illustrates the potential of combining salts and CW in enhancing CO2 mass transfer that can be the base for further investigations. Furthermore, the contribution and proposed mechanisms of the different ions (SO42− and Mg2+) to the physical process in carbonated water/hydrocarbon have been addressed, which forms one of primary bases of EOR.

scholarly journals Experimental Studies of Immiscible High-Nitrogen Natural Gas WAG Injection Efficiency in Mixed-Wet Carbonate Reservoir

Energies ◽  
2020 ◽  
Vol 13 (9) ◽  
pp. 2346
Author(s):  
Mirosław Wojnicki ◽  
Jan Lubaś ◽  
Marcin Warnecki ◽  
Jerzy Kuśnierczyk ◽  
Sławomir Szuflita
Keyword(s):  
Natural Gas ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Experimental Studies ◽  
Carbonate Reservoir ◽  
High Nitrogen ◽  
The Impact ◽  
Wag Injection

Crucial oil reservoirs are located in naturally fractured carbonate formations and are currently reaching a mature phase of production. Hence, a cost-effective enhanced oil recovery (EOR) method is needed to achieve a satisfactory recovery factor. The paper focuses on an experimental investigation of the efficiency of water alternating sour and high-nitrogen (~85% N2) natural gas injection (WAG) in mixed-wetted carbonates that are crucial reservoir rocks for Polish oil fields. The foam-assisted water alternating gas method (FAWAG) was also tested. Both were compared with continuous water injection (CWI) and continuous gas injection (CGI). A series of coreflooding experiments were conducted within reservoir conditions (T = 126 ℃, P = 270 bar) on composite cores, and each consisted of four reservoir dolomite core plugs and was saturated with the original reservoir fluids. In turn, some of the experiments were conducted on artificially fractured cores to evaluate the impact of fractures on recovery efficiency. The performance evaluation of the tested methods was carried out by comparing oil recoveries from non-fractured composite cores, as well as fractured. In the case of non-fractured cores, the WAG injection outperformed continuous gas injection (CGI) and continuous water injection (CWI). As expected, the presence of fractures significantly reduced performance of WAG, CGI and CWI injection modes. In contrast, with regard to FAWAG, deployment of foam flow in the presence of fractures remarkably enhanced oil recovery, which confirms the possibility of using the FAWAG method in situations of premature gas breakthrough. The positive results encourage us to continue the research of the potential uses of this high-nitrogen natural gas in EOR, especially in the view of the utilization of gas reservoirs with advantageous location, high reserves and reservoir energy.

Investigation on the Impact of an Enhanced Oil Recovery Polymer towards Microbial Growth and Microbial Induced Corrosion Rates

2019 ◽  
Vol 797 ◽  
pp. 385-392
Author(s):  
Abd Rahman Hasrizal ◽  
Najmiddin Yaakob
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Volatile Fatty Acids ◽  
Sea Water ◽  
Bacterial Species ◽  
Water Injection ◽  
Bacterial Consortium ◽  
Pipeline System ◽  
Sweep Efficiency ◽  
The Impact

Some of the enhanced oil recovery (EOR) techniques involve injection of polymer brine in the formation. Addition of polymer increases the viscosity causing improved sweep efficiency owing to favorable mobility factor. Microbial induced corrosion (MIC) is caused by growth of certain bacterial species in the pipeline system and the reservoir. There is possibility of MIC to occur along the water injection schemes. Sea water is considered bereft of nutrients not allowing much bacterial activity but some sessile consortia may grow on internal line surface and cause corrosion. When the sea water is injected into the formation some anaerobic consortia dominated by sulfate reducing bacteria (SRB) grow in the formation. These bacteria use oxygen present in sulfate for respiration and volatile fatty acids (VFAs) as carbon source. But after some time of water injection the formation may get depleted of VFAs thwarting bacterial growth. This study was taken up to understand impact of EOR polymer on growth of bacterial consortium. A bacterial consortia labelled as consortia II from ATCC which is tough oilfield bacteria consortia was allowed to grow with VFA (lactate or acetate), in absence of VFA and in presence of 1000 ppm of HPAM polymer. Planktonic and sessile counts were monitored over 40 days period. Results from this study showed, microbes utilized the polymer as their secondary nutrient, whenever their preferred nutrient was depleted or insufficient. SRB sessile count which was 102 cells/cm2 in nutrient depleted medium picked up a value of 106 cells/cm2 in presence of polymer. It was observed that the bacteria first utilize the available VFA source, after that a period of lull for about 5 days followed before the growth being picked up.

Simulation of Scale Inhibitor Squeeze Treatments in a Polymer Flooded Reservoir

2021 ◽  
Author(s):  
Alan Beteta ◽  
Oscar Vazquez ◽  
Munther Mohammed Al Kalbani ◽  
Faith Eze
Keyword(s):  
Oil Recovery ◽  
Reservoir Simulation ◽  
Water Injection ◽  
High Viscosity ◽  
Polymer Flooding ◽  
Base Case ◽  
Scale Inhibitor ◽  
Polymer Flood ◽  
Water Rate ◽  
The Impact

Abstract This study aims to demonstrate the changes to scale inhibitor squeeze lifetimes in a polymer flooded reservoir versus a water flooded reservoir. A squeeze campaign was designed for the base water flood system, then injection was switched to polymer flooding at early and late field life. The squeeze design strategy was adapted to maintain full scale protection under the new system. During the field life, the production of water is a constant challenge. Both in terms of water handling, but also the associated risk of mineral scale deposition. Squeeze treatment is a common technique, where a scale inhibitor is injected to prevent the formation of scale. The squeeze lifetime is dictated by the adsorption/desorption properties of the inhibitor chemical, along with the water rate at the production well. The impact on the adsorption properties and changes to water rate on squeeze lifetime during polymer flooding are studied using reservoir simulation. A two-dimensional 5-spot model was used in this study, considered a reasonable representation of a field scenario, where it was observed that when applying polymer (HPAM) flooding, with either a constant viscosity or with polymer degradation, the number of squeeze treatments was significantly reduced as compared to the water flood case. This is due to the significant delay in water production induced by the polymer flood. When the polymer flood was initiated later in field life, 0.5PV (reservoir pore volumes) of water injection, water cut approximately 70%, the number of squeeze treatments required was still lower than the water flood base case. However, it was also observed that in all cases, at later stages of field life the positive impacts of polymer flooding on squeeze lifetime begin to diminish, due in part to the high viscosity fluid now present in the production near-wellbore region. This study represents the first coupled reservoir simulation/squeeze treatment design for a polymer flooded reservoir. It has been demonstrated that in over the course of a field lifetime, polymer flooding will in fact reduce the number of squeeze treatments required even with a potential reduction in inhibitor adsorption. This highlights an opportunity for further optimization and a key benefit of polymer flooding in terms of scale management, aside from the enhanced oil recovery.

Numerical Evaluation of the Impact of Steam Quality on Steam Flood Performance in a Kuwait Heavy Oil Reservoir

2021 ◽  
Author(s):  
Yacob Al-Ali ◽  
Abdullah Al-Rubah ◽  
Marco Verlaan
Keyword(s):  
Energy Efficiency ◽  
Heat Loss ◽  
Oil Recovery ◽  
Energy Content ◽  
Recovery Process ◽  
Thermal Recovery ◽  
Steam Quality ◽  
Bottom Hole ◽  
Steam Flood ◽  
The Impact

Abstract The objective of this study is to assess any opportunities to improve field recovery or thermal efficiency by evaluating different steam quality scenarios and their impact on the performance of the cyclic steam stimulation and steam flood in Lower Fars reservoir. In this study, simulation history matching of the dynamic test data from the ongoing thermal pilots was used to validate the static and dynamic description. The process results in an improved dynamic model to be used specifically for the steam quality scenarios evaluation, which was then used in the prediction mode for deciding on an optimum steam quality percentage for the upcoming steam flood operation. Different bottom-hole steam quality scenarios are defined using different steam quality output values at the steam generator and a fixed amount of surface network heat loss. The wellbore heat losses are explicitly modelled to arrive at bottom hole steam quality corresponding to a boiler steam quality. The impact of the steam quality on the cumulative amount of oil produced is significant when an economic steam oil ratio cutoff is applied. There was an overall 40% difference in cumulative oil production between low and high steam quality cases, and a 30% difference when an energy cut off criterion was applied instead of the steam oil ratio cutoff. The highest steam quality resulted in the best performance in terms of oil recovery and energy efficiency. Analysis of the results show that the effect of steam quality is different during different periods of the CSS/SF process and mainly related to the different amount of enthalpy injected. During the CSS period a lower steam quality results in lower oil recovery but at a better efficiency compared to a high steam quality. In the steam flood phase the high steam quality results in both higher recovery and higher energy efficiency. The latter is caused by lower over and underburden heat loss. The bottom hole steam quality is a measure of the energy content of the steam that is delivered to the reservoir. This has a significant impact on the efficiency of the thermal recovery process. The steam quality can vary as function of well location and time for numerous reasons. Thus, it is essential to understand how these variables affect the recovery process.

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