Manganese Assisted Waterflooding Processes for Enhanced Oil Recovery in Carbonates

2021 ◽  
Author(s):  
Amani Alghamdi ◽  
Saleh Salah ◽  
Mohammed Otaibi ◽  
Subhash Ayirala ◽  
Ali Yousef
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Spontaneous Imbibition ◽  
Wetting Transition ◽  
Manganese Ions ◽  
Surface Charges ◽  
High Salinity Water ◽  
Zeta Potentials ◽  
Salinity Water ◽  
Oil Water

Abstract Modifying the wettability of carbonate formations through divalent foreign metal incorporation can become a cost-effective practical method for enhanced oil recovery (EOR) applications. The addition of manganese ions to both high salinity water (HSW) and tailored SmartWater at dilute concentrations is exploited in this study to maximize the interfacial potential and promote water-wet conditions in carbonate reservoirs. In this experimental investigation, the impact of manganese ions on zeta-potentials at calcite/brine and crude oil/brine interfaces is first determined by measuring zeta-potentials in calcite suspensions and oil emulsions. Two different water chemistries representative of HSW (~60,000 ppm TDS) and a low salinity tailored SmartWater (~6,000 ppm TDS) were used. The measurements were then extended to carbonate rocks and reservoir cores by performing contact angle and spontaneous imbibition tests at reservoir conditions. The oil-water interfacial tensions are also measured to understand the interactions of manganese ions at the oil/brine interface. The zeta potential results showed a positive consistent trend, with the addition of 100-1,000 ppm of Mn+2 ions in the form of MnSO4 to the high salinity water, to impact the wetting transition towards water-wet conditions in carbonates. The addition of Mn+2 ions at a concentration of 100-1,000 ppm to HSW enhanced the electrokinetic interactions to favorably alter surface charges at both oil/brine and calcite/brine interfaces. These findings based on eletrokinetic interactions demonstrated good agreement with contact angle data wherein manganese ions in HSW were able to drastically decrease the contact angles from 156 to 88°. Conversely, insignificant changes in oil-water interfacial tensions were observed due to manganese ions. The manganese assisted spontaneous imbibition oil recoveries were increased by about 10% in HSW. Mn+2 ions showed the ability to increase the negative potentials at both calcite/brine and oil/brine interfaces. The obvious trend of such enhanced electrical potential due to Mn+2 addition at the calcite interface supports the claim that Mn+2 selectively gets incorporated into the calcite crystal to modify its surface chemistry. This is expected to increase the surface charges of same polarity at the two opposing interfaces and promote the electrostatic repulsion to inherently change the surface preference towards water-wet conditions. This work for the first time identified the favorable impact of incorporating Mn+2 ions under optimized conditions to enhance the wetting transition in carbonate reservoirs. Such new knowledge gained from this experimental study highlights the practical significance of Mn+2 ions as cheap and sustainable wettability modifiers for EOR applications in carbonate reservoirs.

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 Enhanced oil recovery from carbonate reservoirs by spontaneous imbibition of low salinity water

2018 ◽  
Vol 15 (3) ◽  
pp. 564-576 ◽  
Author(s):  
Mohammad Reza Zaeri ◽  
Rohallah Hashemi ◽  
Hamidreza Shahverdi ◽  
Mehdi Sadeghi
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Spontaneous Imbibition ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water

scholarly journals Mechanism of active silica nanofluids based on interface-regulated effect during spontaneous imbibition

2021 ◽  
Author(s):  
Xu-Guang Song ◽  
Ming-Wei Zhao ◽  
Cai-Li Dai ◽  
Xin-Ke Wang ◽  
Wen-Jiao Lv
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Dynamic Contact Angle ◽  
Liquid Interface ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Low Permeability ◽  
Oil Water ◽  
Solid Liquid

AbstractThe ultra-low permeability reservoir is regarded as an important energy source for oil and gas resource development and is attracting more and more attention. In this work, the active silica nanofluids were prepared by modified active silica nanoparticles and surfactant BSSB-12. The dispersion stability tests showed that the hydraulic radius of nanofluids was 58.59 nm and the zeta potential was − 48.39 mV. The active nanofluids can simultaneously regulate liquid–liquid interface and solid–liquid interface. The nanofluids can reduce the oil/water interfacial tension (IFT) from 23.5 to 6.7 mN/m, and the oil/water/solid contact angle was altered from 42° to 145°. The spontaneous imbibition tests showed that the oil recovery of 0.1 wt% active nanofluids was 20.5% and 8.5% higher than that of 3 wt% NaCl solution and 0.1 wt% BSSB-12 solution. Finally, the effects of nanofluids on dynamic contact angle, dynamic interfacial tension and moduli were studied from the adsorption behavior of nanofluids at solid–liquid and liquid–liquid interface. The oil detaching and transporting are completed by synergistic effect of wettability alteration and interfacial tension reduction. The findings of this study can help in better understanding of active nanofluids for EOR in ultra-low permeability reservoirs.

scholarly journals Salt tolerant acrylamide-based quenched polyampholytes for polymer flooding

2020 ◽  
Vol 100 (4) ◽  
pp. 119-127
Author(s):  
N. Mukhametgazy ◽  
◽  
I.Sh. Gussenov ◽  
A.V. Shakhvorostov ◽  
S.E. Kudaibergenov ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Saline Water ◽  
Core Sample ◽  
Polymer Flooding ◽  
Trimethylammonium Chloride ◽  
Salt Tolerant ◽  
High Salinity Water ◽  
Cationic Monomer ◽  
Aqueous Salt Solutions ◽  
Salinity Water

In our previous papers [1, 2] we considered the behavior of linear and crosslinked polyampholytes based on fully charged anionic monomer — 2-acrylamido-2-methyl-1-propanesulfonic acid sodium salt (AMPS) and cationic monomer — (3-acrylamidopropyl)trimethylammonium chloride (APTAC) in aqueous-salt solutions, swelling and mechanical properties. In the present paper we report the applicability of salt tolerant amphoter-ic terpolymers composed of AMPS, APTAC and acrylamide (AAm) in enhanced oil recovery (EOR). The amphoteric terpolymers of different compositions, particularly [AAm]:[AMPS]:[APTAC] = 50:25:25; 60:20:20; 70:15:15; 80:10:10 and 90:5:5 mol.% were prepared by free-radical polymerization, identified and their viscosifying ability with respect to reservoir saline water (salinity is 163 g⋅L-1) at 60 °C was tested. It was found that due to polyampholytic nature, the AAm-AMPS-APTAC terpolymers exhibited improved viscosifying behavior at high salinity water. As a result, the appropriate salt tolerant sample [AAm]:[AMPS]:[APTAC] = 80:10:10 mol.% was selected for polymer flooding experiments. Polymer flood-ing experiments on high permeable sand pack model demonstrated that only 0.5 % oil was recovered by am-photeric terpolymer. While injection of polyampholyte solution into preliminarily water flooded core sample resulted in the increase of oil recovery up to 4.8–5 %. These results show that under certain conditions the amphoteric terpolymers have a decent oil displacement ability.

scholarly journals Modelling Low-Salinity Water Flooding as a Tertiary Oil Recovery Technique

2020 ◽  
Vol 2020 ◽  
pp. 1-9
Author(s):  
Oluwasanmi Olabode ◽  
David Alaigba ◽  
Daniel Oramabo ◽  
Oreofeoluwa Bamigboye
Keyword(s):  
Oil Recovery ◽  
Water Flooding ◽  
High Salinity Water ◽  
Low Salinity ◽  
Low Salinity Water ◽  
First Case ◽  
Short Period ◽  
Tertiary Oil Recovery ◽  
Salinity Water ◽  
Field Production

In this project, low-salinity water flooding has been modeled on ECLIPSE black oil simulator in three cases for a total field production life of twenty-five years. In the first case, low-salinity water flooding starts fifteen years after secondary water flooding. For the second case, low-salinity water flooding starts five years after secondary water flooding and runs till the end of the field production life. For the third case, low-salinity water flooding starts five years after secondary water flooding, but low-salinity water flooding is injected in measured pore volumes for a short period of time; then, high-salinity water flooding was resumed till the end of the field production life. This was done to measure the effect of low-salinity water flooding as slug injection. From the three cases presented, oil recovery efficiency, field oil production rate, and field water cut were observed. Increased percentages of 22.66%, 35.12%, and 26.77% were observed in the three cases, respectively.

scholarly journals Enhanced Wettability Modification and CO2 Solubility Effect by Carbonated Low Salinity Water Injection in Carbonate Reservoirs

2017 ◽  
Vol 2017 ◽  
pp. 1-10 ◽  
Author(s):  
Ji Ho Lee ◽  
Kun Sang Lee
Keyword(s):  
Oil Recovery ◽  
Saline Water ◽  
Water Injection ◽  
Carbonate Reservoirs ◽  
Viscosity Reduction ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Geochemical Reactions ◽  
Salinity Water ◽  
Low Salinity Water Injection

Carbonated water injection (CWI) induces oil swelling and viscosity reduction. Another advantage of this technique is that CO2 can be stored via solubility trapping. The CO2 solubility of brine is a key factor that determines the extent of these effects. The solubility is sensitive to pressure, temperature, and salinity. The salting-out phenomenon makes low saline brine a favorable condition for solubilizing CO2 into brine, thus enabling the brine to deliver more CO2 into reservoirs. In addition, low saline water injection (LSWI) can modify wettability and enhance oil recovery in carbonate reservoirs. The high CO2 solubility potential and wettability modification effect motivate the deployment of hybrid carbonated low salinity water injection (CLSWI). Reliable evaluation should consider geochemical reactions, which determine CO2 solubility and wettability modification, in brine/oil/rock systems. In this study, CLSWI was modeled with geochemical reactions, and oil production and CO2 storage were evaluated. In core and pilot systems, CLSWI increased oil recovery by up to 9% and 15%, respectively, and CO2 storage until oil recovery by up to 24% and 45%, respectively, compared to CWI. The CLSWI also improved injectivity by up to 31% in a pilot system. This study demonstrates that CLSWI is a promising water-based hybrid EOR (enhanced oil recovery).

Chelating-Agent Enhanced Oil Recovery for Sandstone and Carbonate Reservoirs

SPE Journal ◽  
2015 ◽  
Vol 20 (03) ◽  
pp. 483-495 ◽  
Author(s):  
M. A. Mahmoud ◽  
K. Z. Abdelgawad
Keyword(s):  
Zeta Potential ◽  
Oil Recovery ◽  
Chelating Agents ◽  
Water Injection ◽  
Chelating Agent ◽  
Carbonate Reservoirs ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Core Permeability

Summary Recently low-salinity waterflooding was introduced as an effective enhanced-oil-recovery (EOR) method in sandstone and carbonate reservoirs. The recovery mechanisms that use low-salinity-water injection are still debatable. The suggested possible mechanisms are: wettability alteration, interfacial-tension (IFT) reduction, multi-ion exchange, and rock dissolution. In this paper, we introduce a new chemical EOR method for sandstone and carbonate reservoirs that will give better recovery than the low-salinity-water injection without treating or diluting seawater. In this study, we introduce a new chemical EOR method that uses chelating agents such as ethylenediaminetetraacetic acid (EDTA), hydroxyethylethylenediaminetriacetic acid (HEDTA), and diethylenetriaminepentaacetic acid (DTPA) at high pH values. This is the first time for use of chelating agents as standalone EOR fluids. Coreflood experiments, interfacial and surface tensions, and zeta-potential measurements are performed with DTPA, EDTA, and HEDTA chelating agents. The chelating-agent concentrations used in the study were prepared by diluting the initial concentration of 40 wt% with seawater and injecting it into Berea-sandstone and Indiana-limestone cores of a 6-in. length and a 1.5-in. diameter saturated with crude oil. The coreflooding experiments were performed at 100°C and a 1,000-psi backpressure. Low-salinity-water and seawater injections caused damage to the reservoir because of the calcium sulfate scale deposition during the flooding process. The newly introduced EOR method did not cause calcium sulfate precipitation, and the core permeability was not affected. The core permeability was measured after the flooding process, and the final permeability was higher than the initial permeability in the case of chelating-agent injection. The coreflooding effluent was analyzed for cations with the inductively coupled plasma (ICP) spectroscopy to explain the dissolution-recovery mechanism. The effect of iron minerals on the rock-surface charge was investigated through the measurements of zeta potential for different rocks containing different iron minerals. HEDTA and EDTA chelating agents at 5 wt% concentration prepared in seawater were able to recover more than 20% oil from the initial oil in place from sandstone and carbonate cores. ICP measurements supported the rock-dissolution mechanism because the calcium, magnesium, and iron concentrations in the effluent samples were more than those in the injected fluids. The IFT-reduction mechanism was confirmed by the low IFT values obtained in the case of chelating agents. The type and concentration of chelating agents affected the IFT value. Higher concentrations yielded lower IFT values because of the increase in carboxylic-group concentration. We found that the high-pH chelating agents increased the negative value of zeta potential, which will change the rock toward more water-wet.

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