Analyzing the Influence of Salinity on Produced Water Re-Injection

2021 ◽  
Author(s):  
Adekunle Tirimisiyu Adeniyi ◽  
Chimgozirim Prince Ejim
Keyword(s):  
Oil Recovery ◽  
Produced Water ◽  
Core Sample ◽  
Production Performance ◽  
Core Flooding ◽  
Daily Rate ◽  
Reservoir Conditions ◽  
Cumulative Production ◽  
Water Disposal ◽  
Incremental Oil Recovery

Abstract Produced water reinjection (PWRI) is one of the methods employed by oilfield operators to optimize production while conforming to increasingly stringent produced water disposal policies. Different produced water species from different facilities also have different salinities as a result of entrainment of treatment fluids, precipitation of salts at surface conditions, etc. During re-injection operations, the salinity of the injection fluid has to be accounted for as it affects the production. Previous studies have focused on laboratory analysis by core flooding. While this approach is indeed reasonable and offers a first-hand impression of the reservoir conditions, it presents a problem of cost and the age-old opinion that the core sample may not be representative of the entire reservoir. Therefore, I have employed a computer modeling approach using a commercial simulator to analyze the influence of salinity on production during produced water re-injection. It was found that the salinity truly affects production. Re-injection of produced water with salinity equal to the reservoir salinity of 1000 ppm was compared to three cases of re-injection of produced water from extraneous sources having salinities of 100 ppm, 500 ppm and 10000 ppm. It was found that salinity of 10000 ppm gave the best oil production performance for the reservoir model; a daily rate of 40 STB/DAY and an oil cumulative production of 40,000 STB. Incremental salinity of injected produced water led to incremental oil recovery. The mechanism resulting in incremental recovery was attributed to the increase in viscosity and decrease in mobility as the salinity increases.

Determination of Optimum Parameters for Anaerobic Thermophilic Bacterium Injection using Commercial Simulator: Core Flooding Validation and Sensitivity

2020 ◽  
Author(s):  
A. Koto
Keyword(s):  
Oil Recovery ◽  
Simulation Experiment ◽  
Previous Experiment ◽  
Core Sample ◽  
Thermophilic Bacterium ◽  
Injection Rate ◽  
Core Flooding ◽  
Optimum Parameters ◽  
Result Show

The objective of this paper is to determine the optimum anaerobic-thermophilic bacterium injection (Microbial Enhanced Oil Recovery) parameters using commercial simulator from core flooding experiments. From the previous experiment in the laboratory, Petrotoga sp AR80 microbe and yeast extract has been injected into core sample. The result show that the experiment with the treated microbe flooding has produced more oil than the experiment that treated by brine flooding. Moreover, this microbe classified into anaerobic thermophilic bacterium due to its ability to live in 80 degC and without oxygen. So, to find the optimum parameter that affect this microbe, the simulation experiment has been conducted. The simulator that is used is CMG – STAR 2015.10. There are five scenarios that have been made to forecast the performance of microbial flooding. Each of this scenario focus on the injection rate and shut in periods. In terms of the result, the best scenario on this research can yield an oil recovery up to 55.7%.

scholarly journals CO2-brine injectivity tests in high co2 content carbonate field, sarawak basin, offshore east Malaysia

2019 ◽  
Vol 89 ◽  
pp. 04005 ◽  
Author(s):  
A Giwelli ◽  
MZ Kashim ◽  
MB Clennell ◽  
L Esteban ◽  
R Noble ◽  
...  
Keyword(s):  
Packed Column ◽  
Core Sample ◽  
Chemical Analyses ◽  
Core Flooding ◽  
Flow Rates ◽  
X Ray ◽  
The Core ◽  
Reservoir Conditions ◽  
Post Test ◽  
Porosity And Permeability

We conducted relatively long duration core-flooding tests on three representative core samples under reservoir conditions to quantify the potential impact of flow rates on fines production/permeability change. Supercritical CO2 was injected cyclically with incremental increases in flow rate (2─14 ml/min) with live brine until a total of 7 cycles were completed. To avoid unwanted fluid-rock reaction when live brine was injected into the sample, and to mimic the in-situ geochemical conditions of the reservoir, a packed column was installed on the inflow accumulator line to pre-equilibrate the fluid before entering the core sample. The change in the gas porosity and permeability of the tested plug samples due to different mechanisms (dissolution and/or precipitation) that may occur during scCO2/live brine injection was investigated. Nuclear magnetic resonance (NMR) T2 determination, X-ray CT scans and chemical analyses of the produced brine were also conducted. Results of pre- and post-test analyses (poroperm, NMR, X-ray CT) showed no clear evidence of formation damage even after long testing cycles and only minor or no dissolution (after large injected pore volumes (PVs) ~ 200). The critical flow rates (if there is one) were higher than the maximum rates applied. Chemical analyses of the core effluent showed that the rock samples for which a pre-column was installed do not experience carbonate dissolution.

Non-Edible Oil Based Surfactant For Enhanced Oil Recovery

2021 ◽  
Author(s):  
Adekunle Tirimisiyu Adeniyi ◽  
Ijoma Onyemaechi
Keyword(s):  
Methyl Ester ◽  
Sodium Hydroxide ◽  
Sodium Carbonate ◽  
Oil Recovery ◽  
Sodium Dodecyl ◽  
Synthetic Surfactant ◽  
Chemical Flooding ◽  
Core Flooding ◽  
Incremental Oil Recovery ◽  
Increasing Demand

Abstract After the primary and secondary oil recoveries, a substantial amount of oil is left in the reservoir which can be recovered by tertiary methods like the Alkaline-Surfactant Flood. Reasons for having some unproduced hydrocarbon in the reservoir include and not limited to the following; forces of attraction fluid contacts, low permeability, high viscous fluid, poor swept efficiency, etc. Although, it is possible to commence waterflooding together chemical injection at the start of production. Reservoir simulation with commercial simulator, could guide in selecting the most appropriate period to commence chemical flooding. In this study, the performance of a new synthetic surfactant produced from Jatropha Curcas seed was compared with that of a selected commercial surfactant in the presence of an alkaline and this shows that the non-edible Jatropha oil is a natural, inexpensive and a renewable source of energy for the production of anionic surfactants and a good substitute for commercial surfactants like Sodium Dodecyl Sulphate (SDS). The Methyl Ester Sulfonate (MES) surfactant showed no precipitation or cloudiness during stability test and was able to reduce the Interfacial Tension (IFT) to 0.018 mN/m and 0.020 mN/m in the presence of sodium carbonate and sodium hydroxide respectively as alkaline at low surfactant concentration. The optimum alkaline surfactant formulation in terms of oil recovery performance obtained from the core flooding experiment corresponds to a concentration of sodium carbonate (0.5wt%), sodium hydroxide (0.5wt%) mixed in distilled water and Methyl Ester Sulfonate (MES) surfactant (1wt%). The injection of 0.5 percentage volume of alkaline surfactant slug produced an incremental oil recovery of 26.7% and 29% respectively. With these incremental oil recoveries, increasing demand for hydrocarbons product could be met, and returns on investment portfolio will be improved.

Application of Multilateral Wells for Production and Enhanced Oil Recovery: Case Studies from Canada

2021 ◽  
pp. 1-23
Author(s):  
Eric Delamaide
Keyword(s):  
Oil Recovery ◽  
Horizontal Wells ◽  
Production Performance ◽  
Water Production ◽  
Public Data ◽  
Heavy Oil Reservoirs ◽  
Complex Architectures ◽  
Cumulative Production ◽  
Tertiary Recovery ◽  
And Performance

Summary The use of multilateral wells started in the mid-1990s in particular in Canada, and they have since been used in many countries. However, few papers on multilateral wells focus on their production performance. Thus, what can be expected from such wells in terms of production is not clear, and this paper will attempt to address that gap. Taking advantage of public data, the production performance of multilateral wells in various Western Canadian fields has been studied. In the cases reviewed in this paper, these wells always target a single formation; they have been used in a variety of fields and reservoirs, mostly for primary production but also for polymer flooding in some cases. Multiple examples will be provided, mostly in heavy oil reservoirs, and production performance will be compared with nearby horizontal wells whenever possible. From the more classical dual and trilateral, to more complex architectures with seven or eight laterals, and the more exotic with laterals drilled from laterals, the paper will present the architecture and performance of these complex wells and of some fields that have been developed almost exclusively with multilateral wells. Interestingly, multilateral wells have not been used much for secondary or tertiary recovery, probably because of the difficulty of controlling water production after breakthrough. However, field results suggest that this may not be such a difficult proposition. One of the most remarkable wells producing a 1,250-cp oil under polymer flood has achieved a cumulative production of more than 3 million bbl, which puts it among the top producers in Canada. Although multilateral wells have been in use for more than 25 years, very few papers have been devoted to the description of their production performance. This paper will bring some clarity to these aspects. It will also attempt to address when multilateral wells can be used and to compare their performance to that of horizontal wells in the same fields. It is hoped that this paper will encourage operators to reconsider the use of multilateral wells in their fields.

Ultralow Concentration of Amphiphilic Molybdenum Disulfide Nanosheets for Enhanced Oil Recovery-Research and Field Application

2021 ◽  
Author(s):  
Ming Qu ◽  
Tuo Liang ◽  
Jirui Hou ◽  
Weipeng Wu ◽  
Yuchen Wen ◽  
...  
Keyword(s):  
Contact Angle ◽  
Molybdenum Disulfide ◽  
Solid Surface ◽  
Oil Recovery ◽  
Production Performance ◽  
Core Flooding ◽  
Mos2 Nanosheets ◽  
Ultralow Concentration ◽  
Oil Water ◽  
Molybdenum Disulfide Nanosheets

Abstract Recently, spherical nanoparticles have been studied to enhance oil recovery (EOR) worldwide due to their remarkable properties. However, there is a lack of studies of nanosheets on EOR. In this work, we synthesize the amphiphilic molybdenum disulfide nanosheets through a straightforward hydrothermal method. The octadecyl amine (ODA) molecules were grafted onto the surfaces of molybdenum disulfide nanosheets due to the presence of active sites over the surfaces of MoS2 nanosheets. The synthesized amphiphilic molybdenum disulfide nanosheets (ODA-MoS2 nanosheets) are approximate 67 nm in width and 1.4 nm in thickness. The effects of ultralow concentration ODA-MoS2 nanosheets on the dynamic wettability change of solid surfaces and emulsion stability were also studied and discussed. Besides, the core flooding experiments were also conducted to reveal the adsorption rules and the oil displacement effects of ultralow concentration ODA-MoS2 nanosheets. Experimental results indicate that the oil-wet solid surface (a contact angle of 130°) can transform into the neutral-wet solid surface (a contact angle of 90°) within 120 hrs after 50 mg/L ODA-MoS2 nanosheets treatment. In addition, micro-scale emulsions in size of 2 µm can be formed after the addition of ODA-MoS2 nanosheets by adsorbing onto the oil-water interfaces. The desorption energy of a single ODA-MoS2 nanosheet from the oil-water interface to the bulk phase is proposed. When the concentration of ODA-MoS2 nanosheets is 50 mg/L, the emulsions are the most stable. Core flooding results demonstrate that the ultimate residue of ODA-MoS2 nanosheets in porous media is less than 11%, and the highest increased oil recovery of around 16.26% is achieved. Finally, the production performance of ultralow concentration of ODA-MoS2 nanofluid (50 mg/L) in the application of Daqing Oilfield is summarized and discussed.

Performance of Silica Nanoparticles in CO2 Foam for EOR and CCUS at Tough Reservoir Conditions

SPE Journal ◽  
2019 ◽  
Vol 25 (01) ◽  
pp. 406-415 ◽  
Author(s):  
Arthur U. Rognmo ◽  
Noor Al-Khayyat ◽  
Sandra Heldal ◽  
Ida Vikingstad ◽  
Øyvind Eide ◽  
...  
Keyword(s):  
Silica Nanoparticles ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Elevated Temperatures ◽  
Co2 Storage ◽  
Sweep Efficiency ◽  
Co2 Foam ◽  
Reservoir Conditions ◽  
Incremental Oil Recovery ◽  
Surface Modified

Summary The use of nanoparticles for CO2-foam mobility is an upcoming technology for carbon capture, utilization, and storage (CCUS) in mature fields. Silane-modified hydrophilic silica nanoparticles enhance the thermodynamic stability of CO2 foam at elevated temperatures and salinities and in the presence of oil. The aqueous nanofluid mixes with CO2 in the porous media to generate CO2 foam for enhanced oil recovery (EOR) by improving sweep efficiency, resulting in reduced carbon footprint from oil production by the geological storage of anthropogenic CO2. Our objective was to investigate the stability of commercially available silica nanoparticles for a range of temperatures and brine salinities to determine if nanoparticles can be used in CO2-foam injections for EOR and underground CO2 storage in high-temperature reservoirs with high brine salinities. The experimental results demonstrated that surface-modified nanoparticles are stable and able to generate CO2 foam at elevated temperatures (60 to 120°C) and extreme brine salinities (20 wt% NaCl). We find that (1) nanofluids remain stable at extreme salinities (up to 25 wt% total dissolved solids) with the presence of both monovalent (NaCl) and divalent (CaCl2) ions; (2) both pressure gradient and incremental oil recovery during tertiary CO2-foam injections were 2 to 4 times higher with nanoparticles compared with no-foaming agent; and (3) CO2 stored during CCUS with nanoparticle-stabilized CO2 foam increased by more than 300% compared with coinjections without nanoparticles.

Brine Chemistry Effects in Waterflood and CO2 Injection in Carbonate Reservoirs

2014 ◽  
Author(s):  
Hemanta K. Sarma ◽  
Yi Zhang
Keyword(s):  
Oil Recovery ◽  
Co2 Injection ◽  
Sulfate Concentration ◽  
Water Barrier ◽  
Co2 Diffusion ◽  
Reservoir Conditions ◽  
Brine Chemistry ◽  
Incremental Oil Recovery ◽  
The Impact ◽  
Brine Salinity

It has been reported that the waterflood performance in carbonate reservoirs could be significantly ameliorated by tuning the injected brine salinity and ionic composition. Also, it is noted that the brine salinity affects the CO2 injection process. This study looked into such possible effects of brine chemistry on waterflood and CO2 injection for typical UAE carbonate reservoir conditions of high temperature and pressure (T = 120°C and P = 20.68MPa). Effects on waterflood performance were investigated experimentally by a series of flooding tests at temperatures of 70°C and 120°C. In addition, an imbibition test was conducted at 70°C, followed by wettability monitoring tests at 90°C to investigate the impact of brine salinity variations and ionic compositions on waterflood performance. The impact of brine salinity on CO2-brine system properties including CO2 solubility in brine, interfacial tension between CO2 and CO2-saturated brine, and density and viscosity of CO2-saturated brine were evaluated through correlation-based studies in conjunction with some experimental data. A mathematical pore-scale model was developed to assess the brine salinity effect on water-isolated oil recovery by CO2 diffusion through water barrier. This study led to the following findings: (1) Incremental oil recovery could be obtained by either reducing salinity or increasing sulfate concentration of the tertiary injected brine at both 70°C and 120°C. However, the incremental recovery was more remarkable at the higher temperature of 120°C. (2) At 70°C, lowering the water salinity is more effective than raising the sulfate concentration in injected water in terms of incremental oil recovery. It also exhibited a similar potential for increased oil recovery at 120°C. (3) Wettability monitoring tests showed that water-wetness of carbonate rock studied could be increased by either reducing the water salinity or increasing sulfate concentration of the surrounding water. This is consistent with the imbibition test, in which wettability alteration towards more water-wetness by low salinity water was noted. (4) Under typical UAE reservoir conditions, reducing the brine salinity could significantly enhance CO2 dissolution in brine, consequently inducing significant variation to the CO2-brine system properties. This would undoubtedly impact CO2 injection performance. (5) Under typical UAE reservoir conditions, the capacity and rate of CO2 diffusion through water barrier to oil phase could be significantly reinforced by lowering the brine salinity of the water barrier.

scholarly journals Experimental Investigation of Polymer-Coated Silica Nanoparticles for EOR under Harsh Reservoir Conditions of High Temperature and Salinity

Nanomaterials ◽  
2021 ◽  
Vol 11 (3) ◽  
pp. 765
Author(s):  
Alberto Bila ◽  
Ole Torsæter
Keyword(s):  
High Temperature ◽  
Silica Nanoparticles ◽  
Oil Recovery ◽  
Data Bank ◽  
Sweep Efficiency ◽  
Reservoir Conditions ◽  
Wet Condition ◽  
Incremental Oil Recovery ◽  
Original Oil In Place

Laboratory experiments have shown higher oil recovery with nanoparticle (NPs) flooding. Accordingly, many studies have investigated the nanoparticle-aided sweep efficiency of the injection fluid. The change in wettability and the reduction of the interfacial tension (IFT) are the two most proposed enhanced oil recovery (EOR) mechanisms of nanoparticles. Nevertheless, gaps still exist in terms of understanding the interactions induced by NPs that pave way for the mobilization of oil. This work investigated four types of polymer-coated silica NPs for oil recovery under harsh reservoir conditions of high temperature (60 ∘C) and salinity (38,380 ppm). Flooding experiments were conducted on neutral-wet core plugs in tertiary recovery mode. Nanoparticles were diluted to 0.1 wt.% concentration with seawater. The nano-aided sweep efficiency was studied via IFT and imbibition tests, and by examining the displacement pressure behavior. Flooding tests indicated incremental oil recovery between 1.51 and 6.13% of the original oil in place (OOIP). The oil sweep efficiency was affected by the reduction in core’s permeability induced by the aggregation/agglomeration of NPs in the pores. Different types of mechanisms, such as reduction in IFT, generation of in-situ emulsion, microscopic flow diversion and alteration of wettability, together, can explain the nano-EOR effect. However, it was found that the change in the rock wettability to more water-wet condition seemed to govern the sweeping efficiency. These experimental results are valuable addition to the data bank on the application of novel NPs injection in porous media and aid to understand the EOR mechanisms associated with the application of polymer-coated silica nanoparticles.

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