Effect of ionic composition in water: oil interactions in adjusted brine chemistry waterflooding: preliminary results

Maya, Gustavo; Herrera, Julia; Orrego, Jorge A.; Rojas, Fernando; Rueda, Mayra F.; Manrique, Eduardo

doi:10.18273/revfue.v16n2-2018005

Cited by 5 publications

(2 citation statements)

References 36 publications

(8 reference statements)

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“…The high residual water saturation values are attributed to changes in salinity (IS) considered in the experimental protocol. These results are also consistent with the spontaneous emulsification observed with the crude oil used in this study [14], as it will be briefly discussed later in this section.…”

Section: Core Flooding -Secondary and Tertiary Oil Recovery -Displacement Efficienciessupporting

confidence: 90%

“…These results suggest that a decrease in salinity (IS) in the Berea coreflood using the crude oil under evaluation improves the displacement efficiencies regardless of the higher Swir at the beginning of the test injecting FB2 and FB3 (Figure 7). As already mentioned, the crude oil used in this study shows a natural tendency to form a microdispersion with decreased water salinity (IS) [14]. The latter can explain the increase in Swi observed when resaturating the Berea core plug with reservoir oil in the presence of high water saturation (Sorw) at lower IS.…”

Section: Core Flooding -Secondary and Tertiary Oil Recovery -Displacement Efficienciessupporting

confidence: 53%

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Effect of ionic strength in low salinity water injection processes

Maya

Rojas

Pelayo

et al. 2020

CT&F Cienc. Tecnol. Futuro

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Low salinity water injection has been frequently studied as an enhanced oil recovery process (EOR), mainly due to promising experimental results and because operational needs are not very different from those of the conventional water injection. However, there is no agreement on the mechanisms involved in increasing the displacement of crude oil, except for the effects of wettability changes. Water injection is the oil recovery method mostly used, and considering the characteristics of Colombian oil fields, this study analyses the effect of modifying the ionic composition of the waters involved in the process, starting from the concept of ionic strength (IS) in sandstone type rocks. The experimental plan for this research includes the evaluation of spontaneous imbibition (SI), contact angles, and displacement efficiencies in Berea core plugs. Interfacial tension and pH measurements were also carried out. The initial scenario consists in formation water (FW), with a total concentration of 9,800 ppm (TDS) (IS ~ 0.17) and a 27 °API crude oil. Magnesium and Calcium brine were also used in a first approach to assess the effect of the divalent ions. Displacement efficiency tests are performed using IS of 0.17, 0.08, and 0.05, as secondary and tertiary oil recovery and the recovery of oil increases in both scenarios. Spontaneous imbibition curves and contact angle measurements show variations as a function of the ionic strength, validating the displacement efficiencies. Interfacial tension and pH collected data evidence that fluid/fluid interactions occur due to ionic strength modifications. However, as per the conditions of this research, fluid/fluid mechanisms are not as determining as fluid/rock.

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Section: Core Flooding -Secondary and Tertiary Oil Recovery -Displacement Efficienciessupporting

confidence: 90%

Section: Core Flooding -Secondary and Tertiary Oil Recovery -Displacement Efficienciessupporting

confidence: 53%

Effect of ionic strength in low salinity water injection processes

Maya

Rojas

Pelayo

et al. 2020

CT&F Cienc. Tecnol. Futuro

View full text Add to dashboard Cite

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Less-Concentrated HPAM Solutions as a Polymer Retention Reduction Method in CEOR

Lizcano¹,

Ferreira²,

Moreno³

2020

Rev. fuentes reventón enrg.

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Polymer Flooding has become one of the most implemented EOR techniques, due to three factors: First, Polymer flooding has expanded the range of the screening criteria parameters. Second, this EOR method is more effective than water injection, while handling water management issues in high water-cut reservoirs. Nevertheless, polymer retention can turn a viable technical project into an uneconomical one. Polymer loss due to retention is an inevitable phenomenon, which happens during injection processes. The development of experimental analysis aiming to minimize or reduce polymer loss from the displacing fluid bank is beneficial to broaden the application of this CEOR method. This experimental work evaluated the injection schemes aiming to reduce polymer retention in porous media. The approach consisted of injecting less-concentrated polymer banks followed for the main polymer bank designed for mobility control. An experimental methodology to quantify polymer retention due to each injected polymer bank, cumulative polymer retention, resistance factor, residual resistance factor and inaccessible pore volume (IPV) was developed. The measurement process was based on the injection of 20 PV polymer banks at a constant flow rate of 1ml/min at 25°C, separated by 30 PV brine banks. Two HPAM with molecular weights of 6-8 million and 20 million Daltons using 350mD and 5000 mD sandstone cores were tested, respectively. The HPAM solutions considering a Colombian field (0.7% NaCl) and seawater (3.5% TDS) salinities were prepared. All rock samples were previously submitted to the injection of 50 PV for preventing fines migration. Two injection schemes with variable polymer concentrations were performed: The first one in which the polymer concentration increased in each successive bank, and the second one in which the concentration decreased. HPAM concentration solutions from 50 ppm to 2000 ppm were sequentially used in both injection schemes. By comparing the results of these two schemes, the effect of the injection of the less-concentrated polymer solutions was evaluated. For the increasing concentration experiments, cumulative retention values of 175.7 μg/g and 58.9 μg/g were calculated for the low-molecular weight polymer and the high-molecular weight polymer, respectively. While comparing with decreasing concentration experiments, for the high-molecular weight HPAM a 19% of retention reduction was evidenced, but no retention reduction was observed for the low-molecular weight one. The results indicate that different retention mechanisms are strongly dependents on the absolute permeability of the samples. Additionally, IPV values of 0.5 PV and 0.25 PV were calculated using low and high permeability samples, respectively. There was no linear relation between the absolute permeability reduction and the polymer concentration of the first bank injected into the sample. The novelty of this work is to use sacrificial banks of less-concentrated HPAM solutions as a reducing retention agent for the polymer bank designed for mobility control.

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Experimental Design for Evaluation of Formation Damage by Microbial Contamination in Water Flooding Processes. A Colombian Study Case

Plata

Hernández

Torres

2019

revfue

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Microbial contamination is well known in the oil and gas industry and it occurs in most processes where water processing systems are involved. Microorganisms are spread everywhere, even in the subsurface, where operations of oil exploration and production are developed. For this reason, different genera of microorganisms can affect the Oil & Gas Industry. One of the major problems in oil mature fields undergoing secondary recovery is the contamination with sulfate reducing bacteria (SRB), caused generally by the injection water system (fresh and/or production) and/or of the reservoir (natural or by drilling fluids, completion, stimulation, etc.). This problem causes formation damage and microbiological induced corrosion (MIC) in the injection-production system. In many producing wells, formation damage by microbiological contamination is initially masked by a decline in reservoir pressure; however, initial production of H2S does provide a possible microbial contamination of water production, water injection and eventually petroleum reservoir. In some producing wells, H2S concentrations have exceeded the lethal limits of 250 ppm and there are cases of producing wells with levels above 1000 ppm. In this work, both a conceptual study and an experimental protocol were developed for the evaluation of formation damage by microbial contamination in water flooding processes. It is focused on finding the best stimulation treatment with biocides to H2S and corrosion control in Producer Wells of Oil Fields Undergoing Secondary Recovery as part of the comprehensive strategy to implement in the injection-reservoir-production system of the Chichimene field in Colombia. This study included the following stages:1. State of the art to define main bactericides, matrix stimulation treatments to H2S and corrosion control, removal of biomass (biofilm) and iron sulfide, etc. in producers wells. 2. Conceptual study of the formation damage by growth of sulfate-reducing bacteria.3. Experimental protocol for the evaluation of formation damage due to microbial contamination in water flood processes.4. Experimental evaluation of formation damage due to microbial contamination in cores of the Chichimene field, in Colombia. Finally, the main findings, conclusions and recommendations obtained in this study are shown.Keywords: microbial contamination, microorganisms, secondary recovery, stimulation, formation damage, sulfate-reducing bacteria, water production, waterflooding.

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Effect of ionic composition in water: oil interactions in adjusted brine chemistry waterflooding: preliminary results

Cited by 5 publications

References 36 publications

Effect of ionic strength in low salinity water injection processes

Effect of ionic strength in low salinity water injection processes

Less-Concentrated HPAM Solutions as a Polymer Retention Reduction Method in CEOR

Experimental Design for Evaluation of Formation Damage by Microbial Contamination in Water Flooding Processes. A Colombian Study Case

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