scholarly journals An Experimental Investigation the Optimum of Salinity and Ph of Sea-Water to Improve Oil Recovery from Sandstone Reservoir as A Secondary Recovery Process

2020 ◽  
Vol 1 (2) ◽  
pp. 83
Author(s):  
Madi Abdullah Naser ◽  
Mohammed A Samba ◽  
Yiqiang Li
Keyword(s):  
Oil Recovery ◽  
Sea Water ◽  
Recovery Process ◽  
Water Flooding ◽  
Core Flooding ◽  
Low Salinity ◽  
Seawater Salinity ◽  
Secondary Recovery ◽  
Two Parameters ◽  
The Impact

Laboratory tests and field applications shows that the salinity of water flooding could lead to significant reduction of residual oil saturation. There has been a growing interest with an increasing number of low-salinity water flooding studies. However, there are few quantitative studies on seawater composition change and it impact on increasing or improving oil recovery.  This study was conducted to investigate only two parameters of the seawater (Salinity and pH) to check their impact on oil recovery, and what is the optimum amount of salinity and ph that we can use to get the maximum oil recovery.  Several core flooding experiments were conducted using sandstone by inject seawater (high, low salinity and different pH). The results of this study has been shown that the oil recovery increases as the injected water salinity down to 6500 ppm and when the pH is around 7. This increase has been found to be supported by an increase in the permeability. We also noticed that the impact of ph on oil recovery is low when the pH is less than 7.

scholarly journals Impact of Brine Composition and Concentration on Capillary Pressure and Residual Oil Saturation in Limestone Core Samples

2019 ◽  
Vol 89 ◽  
pp. 02006
Author(s):  
F. Feldmann ◽  
A. M. AlSumaiti ◽  
S. K. Masalmeh ◽  
W. S. AlAmeri ◽  
S. Oedai
Keyword(s):  
Oil Recovery ◽  
Sea Water ◽  
Spontaneous Imbibition ◽  
Oil Saturation ◽  
Salinity Effect ◽  
Connate Water ◽  
Low Salinity ◽  
Remaining Oil ◽  
The Impact ◽  
Secondary Mode

Low salinity water flooding (LSF) is a relatively simple and cheap EOR technique in which the salinit y of the injected water is optimized (by desalination and/or modification) to improve oil recovery over conventional waterflooding. Extensive laboratory experiments investigating the effect of LSF are available in the literature. Sulfate-rich as well as diluted brines have shown promising potential to increase oil production in limestone core samples. To quantify the low salinity effect, spontaneous imbibition and/or tertiary waterflooding experiments have been reported. For the first time in literature, this paper presents a comprehensive study of the centrifuge technique to investigate low salinity effect in carbonate samples. The study is divided into three parts. At first, a comprehensive screening was performed on the impact of different connate water and imbibition brine compositions/combinations on the spontaneous imbibition behavior. Second, the subsequent forced imbibition of the samples using the centrifuge method to investigate the impact of brine compositions on residual saturations and capillary pressure. Finally, three unsteady-state (USS) core floodings were conducted in order to examine the potential of the different brines to increase oil recovery in secondary mode (brine injection at connate water saturation) and tertiary mode (exchange of injection brine at mature recovery stage). The experiments were performed using Indiana limestone outcrops. The main conclusions of the study are spontaneous imbibition experiments only showed oil recovery in case the salinity of the imbibing water (IW) is lower than the salinity of the connate water (CW). No oil production was observed when the imbibing water had a higher salinity than the connate water or the salinity of the connate water and imbibing brine were identical. Moreover, the spontaneous imbibition experiments indicated that diluting the salinity of the imbibing water has a larger potential to spontaneously recover oil than the introduction of sulfate-rich sea water. The centrifuge experiments confirmed a connection between the overall salinity and oil recovery. As the salinity of the imbibing brines decreases, the capillary imbibition pressure curves showed an increasing water-wetting tendency and simultaneous reduction of the remaining oil saturation. The lowest remaining oil saturation was obtained for diluted sea water as CW and IW. The core flooding experiments reflected the results of the spontaneous imbibition and centrifuge experiments. Injecting brine at a rate of 0.05 cc/min, sea water and especially diluted sea water resulted in a significant higher oil recovery compared to formation brine. Moreover, when comparing secondary mode experiments, the remaining oil saturation after flooding by diluted sea water, sea water and formation water was 30.6 %, 35.5 % and 37.4 %, respectively. In tertiary injection mode, sea water did not lead to extra oil recovery while diluted sea water led to an additional oil recovery of 5.6 % in one out of two tertiary injection applications.

Optimization of Smart Water Chemical Composition for Carbonate Rocks Through Comparison of Active Cations Performance

2017 ◽  
Vol 139 (6) ◽  
Author(s):  
Malek Jalilian ◽  
Peyman Pourafshary ◽  
Behnam Sedaee Sola ◽  
Mosayyeb Kamari
Keyword(s):  
Chemical Composition ◽  
Oil Recovery ◽  
Carbonate Rocks ◽  
Low Cost ◽  
Recovery Phase ◽  
Ion Concentration ◽  
Water Flooding ◽  
Core Flooding ◽  
Smart Water ◽  
The Impact

Designing smart water (SW) by optimizing the chemical composition of injected brine is a promising low-cost technique that has been developed for both sandstone and carbonate reservoirs for several decades. In this study, the impact of SW flooding during tertiary oil recovery phase was investigated by core flooding analysis of pure limestone carbonate rocks. Increasing the sulfate ion concentration by using CaSO4 and MgSO4 of NaCl concentration and finally reducing the total salinity were the main manipulations performed to optimize SW. The main objective of this research is to compare active cations including Ca2+ and Mg2+ in the presence of sulfate ions (SO42−) with regard to their efficiency in the enhancement of oil production during SW flooding of carbonate cores. The results revealed a 14.5% increase in the recovery factor by CaSO4 proving its greater effectiveness compared to MgSO4, which led to an 11.5% production enhancement. It was also realized that low-salinity water flooding (LSWF) did not lead to a significant positive effect as it contributed less than 2% in the tertiary stage.

scholarly journals Comparative Study of Using Sea-Water for Enhanced Oil Recovery in Carbonate and Sandstone Reservoirs: Effects of Temperature and Aging Time on Oil Recovery

2018 ◽  
Vol 7 (2) ◽  
pp. 1-13
Author(s):  
Madi Abdullah Naser ◽  
Mohamed Erhayem ◽  
Ali Hegaig ◽  
Hesham Jaber Abdullah ◽  
Muammer Younis Amer ◽  
...  
Keyword(s):  
Aging Time ◽  
Oil Recovery ◽  
Sea Water ◽  
Essential Element ◽  
Recovery Process ◽  
Spontaneous Imbibition ◽  
Effect Of Temperature ◽  
Injection Process ◽  
Reservoir Conditions ◽  
The Impact

Oil recovery process is an essential element in the oil industry, in this study, a laboratory study to investigate the effect of temperature and aging time on oil recovery and understand some of the mechanisms of seawater in the injection process. In order to do that, the sandstone and carbonate cores were placed in the oven in brine to simulate realistic reservoir conditions. Then, they were aged in crude oil in the oven. After that, they were put in the seawater to recover, and this test is called a spontaneous imbibition test. The spontaneous imbibition test in this study was performed at room temperature to oven temperature 80 oC with different sandstone and carbonate rock with aging time of 1126 hours. The result shows that the impact of seawater on oil recovery in sandstone is higher than carbonate. At higher temperature, the oil recovery is more moderate than low temperature. Likewise, as the aging time increase for both sandstone and carbonate rocks the oil recovery increase. 

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%.

scholarly journals Mechanisms of Microscopic Displacement During Enhanced Oil Recovery in Mixed-Wet Rocks Revealed Using Direct Numerical Simulation

2019 ◽  
Vol 130 (3) ◽  
pp. 731-749 ◽  
Author(s):  
Takashi Akai ◽  
Amer M. Alhammadi ◽  
Martin J. Blunt ◽  
Branko Bijeljic
Keyword(s):  
Numerical Simulation ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Water Flooding ◽  
Surfactant Flooding ◽  
Displacement Efficiency ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
The Impact

Abstract We demonstrate how to use numerical simulation models directly on micro-CT images to understand the impact of several enhanced oil recovery (EOR) methods on microscopic displacement efficiency. To describe the physics with high-fidelity, we calibrate the model to match a water-flooding experiment conducted on the same rock sample (Akai et al. in Transp Porous Media 127(2):393–414, 2019. 10.1007/s11242-018-1198-8). First we show comparisons of water-flooding processes between the experiment and simulation, focusing on the characteristics of remaining oil after water-flooding in a mixed-wet state. In both the experiment and simulation, oil is mainly present as thin oil layers confined to pore walls. Then, taking this calibrated simulation model as a base case, we examine the application of three EOR processes: low salinity water-flooding, surfactant flooding and polymer flooding. In low salinity water-flooding, the increase in oil recovery was caused by displacement of oil from the centers of pores without leaving oil layers behind. Surfactant flooding gave the best improvement in the recovery factor of 16% by reducing the amount of oil trapped by capillary forces. Polymer flooding indicated improvement in microscopic sweep efficiency at a higher capillary number, while it did not show an improvement at a low capillary number. Overall, this work quantifies the impact of different EOR processes on local displacement efficiency and establishes a workflow based on combining experiment and modeling to design optimal recovery processes.

scholarly journals Sequential Injection of Carbonated Water: A Possible Process for Coupling CO2 Enhanced Oil Recovery and Storage

2020 ◽  
Vol 9 (3) ◽  
pp. 369-376
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Co2 Storage ◽  
Water Injection ◽  
Water Flooding ◽  
Core Flooding ◽  
Displacement Efficiency ◽  
Low Salinity ◽  
Carbonated Water ◽  
Carbon Dioxide Co2

Low salinity and carbonated water flooding have been investigated as possible techniques of improved/enhanced oil recovery. Carbonated water injection consists of dissolving carbon dioxide CO2 in water prior to injection and could be considered as a way to store greenhouse gas safely. Low salinity water flooding is a process of diluting high salinity injection water to a very low level of salinity. In this project, the effect of combining the two techniques in a sequential flooding was studied. The primary aim of this study is to optimize the oil recovery and evaluate CO2 storage during this process, employing low permeability carbonate cores and different sequential carbonated and non-carbonated brines flooding. Formation brine, seawater, low salinity carbonated and non-carbonated were used in this work. Core samples grouped as composite cores with similar over all reservoir permeability. Different sequences of brines were employed to determine the optimum system. The experiment's result showed that carbonated water performs better than the noncarbonated brines. A new technique for estimate CO2 retention based on the displacement efficiency of the carbonated water flooding system is presented. The interfacial tension, contact angle measurements results indicated that wettability is the dominant mechanism of the studied systems. A sequential composite core flooding consists of carbonated low salinity followed by low salinity and seawater injection (CLSW- LSW-SW) is the optimum flooding system among the studied systems. Technically, CLSW flooding displayed an excellent incremental displacement efficiency ∆DE of 21.4% and CSW exhibited the best CO2 retention per incremental ∆Np.

Waterflooding in Carbonate Reservoirs: Does the Salinity Matter?

2014 ◽  
Vol 17 (03) ◽  
pp. 304-313 ◽  
Author(s):  
A.M.. M. Shehata ◽  
M.B.. B. Alotaibi ◽  
H.A.. A. Nasr-El-Din
Keyword(s):  
Oil Recovery ◽  
Sudden Change ◽  
Oil Production ◽  
Deionized Water ◽  
Production Performance ◽  
Shallow Aquifer ◽  
Secondary Recovery ◽  
Tertiary Recovery ◽  
The Impact ◽  
Indiana Limestone

Summary Waterflooding has been used for decades as a secondary oil-recovery mode to support oil-reservoir pressure and to drive oil into producing wells. Recently, the tuning of the salinity of the injected water in sandstone reservoirs was used to enhance oil recovery at different injection modes. Several possible low-salinity-waterflooding mechanisms in sandstone formations were studied. Also, modified seawater was tested in chalk reservoirs as a tertiary recovery mode and consequently reduced the residual oil saturation (ROS). In carbonate formations, the effect of the ionic strength of the injected brine on oil recovery has remained questionable. In this paper, coreflood studies were conducted on Indiana limestone rock samples at 195°F. The main objective of this study was to investigate the impact of the salinity of the injected brine on the oil recovery during secondary and tertiary recovery modes. Various brines were tested including deionized water, shallow-aquifer water, seawater, and as diluted seawater. Also, ions (Na+, Ca2+, Mg2+, and SO42−) were particularly excluded from seawater to determine their individual impact on fluid/rock interactions and hence on oil recovery. Oil recovery, pressure drop across the core, and core-effluent samples were analyzed for each coreflood experiment. The oil recovery using seawater, as in the secondary recovery mode, was, on the average, 50% of original oil in place (OOIP). A sudden change in the salinity of the injected brine from seawater in the secondary recovery mode to deionized water in the tertiary mode or vice versa had a significant effect on the oil-production performance. A solution of 20% diluted seawater did not reduce the ROS in the tertiary recovery mode after the injection of seawater as a secondary recovery mode for the Indiana limestone reservoir. On the other hand, 50% diluted seawater showed a slight change in the oil production after the injection of seawater and deionized water slugs. The Ca2+, Mg2+, and SO42− ions play a key role in oil mobilization in limestone rocks. Changing the ion composition of the injected brine between the different slugs of secondary and tertiary recovery modes showed a measurable increase in the oil production.

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