Nanoparticles EOR Aluminum Oxide (Al2O3) Used As a Spontaneous Imbibition Test for Sandstone Core

2019 ◽  
Author(s):  
Mohammed A. Samba ◽  
Hafsa A. Hassan ◽  
Mahjouba S. Munayr ◽  
Moataz Yusef ◽  
Abdelkareem Eschweido ◽  
...  
Keyword(s):  
Aluminum Oxide ◽  
Oil Recovery ◽  
Room Temperature ◽  
Spontaneous Imbibition ◽  
Chemical Flooding ◽  
Secondary Recovery ◽  
Chemical Eor ◽  
Change Temperature ◽  
Al2o3 Concentration ◽  
Polymer Surfactant

Abstract There are three types of oil production energy operations, primary recovery, secondary recovery and enhanced oil recovery (EOR). EOR consider as the last period for production operations. Where the EOR classify into many types such as thermal injection, gas injection, microbial EOR and chemical flooding. Chemical flooding classified into many types such as polymer, surfactant, alkaline and nanoparticles (NP). NP can be classified into many types such as Iron Oxide (Fe2O3), Aluminum Oxide (Al2O3) and Magnesium Oxide (MgO) etc. In this study NP Aluminum oxide (Al2O3) were used to enhance the oil recovery. The main objective of this study is to use the Nanoparticles EOR (Al2O3) and know it is effect on increasing the extraction of oil from cores. The big motivation of using Al2O3 that it is easy to extract it from raw clay. However, the raw clay is available in Libya and using it will be more economic than using other method of chemical EOR. Nanoparticles EOR Aluminum oxide (Al2O3) used as a spontaneous imbibition test for sandstone core samples after saturated by crude oil. A spontaneous imbibition test consisting of two scenarios of nanoparticle solution (Al2O3) with change temperature and compared with one scenario of distilled water. The spontaneous imbibition test was performed in this study at room temperature to oven temperature (30C°, 40C°, 50C°, 60C°, 70C°). The results shown that the oil recovery increases with the increase of the concentration of nanoparticle (Al2O3) and increase the temperature. The higher oil recovery was 76.04% at NP (Al2O3) concentration 1%. Finally, oil swelling and adsorption (NP (Al2O3) with oil drops) have been noticed during the extraction of oil. Thus, the gravity force will be higher than the capillary force.

Experimental and Numerical Assessment of Chemical Enhanced Oil Recovery in Oil-Wet Naturally Fractured Reservoirs

SPE Journal ◽  
2016 ◽  
Vol 21 (03) ◽  
pp. 0706-0719 ◽  
Author(s):  
Bernard Bourbiaux ◽  
André Fourno ◽  
Quang-Long Nguyen ◽  
Françoise Norrant ◽  
Michel Robin ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Scale Effects ◽  
Fractured Reservoirs ◽  
Spontaneous Imbibition ◽  
Cocurrent Flow ◽  
Chemical Additives ◽  
Fluid Saturation ◽  
Aqueous Solvent ◽  
Chemical Eor

Summary Among various ways to extend the lifetime of mature fields, chemical enhanced-oil-recovery (EOR) processes have been subject of renewed interest in the recent years. Oil-wet fractured reservoirs represent a real challenge for chemical EOR because the matrix medium does not spontaneously imbibe the aqueous solvent of chemical additives. The present paper deals with chemical EOR by use of wettability modifiers (WMs). The kinetics of spontaneous imbibition of chemical solutions in oil-wet limestone plugs and mini-plugs was quantified thanks to X-ray computed-tomography (CT) scanning and nuclear-magnetic-resonance (NMR) measurements. Despite the small size of samples and the slowness of experiments, accurate recovery curves were inferred from in-situ fluid-saturation measurements. Scale effects were found quite consistent between mini-plugs and plugs. During a second experimental step, viscous drive conditions were imposed between the end faces of a plug, to account for the possibly significant contribution of fracture viscous drive to matrix oil recovery. The recovery kinetics and behavior, especially the occurrence of countercurrent and cocurrent flow, are interpreted through the analysis of modified forces in the presence of a diffusing or convected WM that alters rock wettability and reduces water/oil interfacial tension (IFT) to a lesser extent. This work calls for an extensive modeling study to specify the conditions on chemical additives and recovery-process implementation that optimize the recovery kinetics.

Experimental Study of Enhanced-Heavy-Oil Recovery in Berea Sandstone Cores by Use of Nanofluids Applications

2015 ◽  
Vol 18 (03) ◽  
pp. 387-399 ◽  
Author(s):  
Osamah A. Alomair ◽  
Khaled M. Matar ◽  
Yousef H. Alsaeed
Keyword(s):  
Aluminum Oxide ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Silicon Oxide ◽  
Chemical Flooding ◽  
Berea Sandstone ◽  
Asphaltene Precipitation ◽  
Aluminum Oxides ◽  
Optimum Type ◽  
Incremental Oil Recovery

Summary The application of nanotechnology in the oil industry has become a useful approach in oil production. The main objective of this study is to investigate the effect of nanofluids on the recovery of heavy crude oil compared with waterflooding. The nanofluids are prepared by the addition of pure and mixed nanoparticles—silicon oxide, aluminum oxide, nickel oxide, and titanium oxide—at different concentrations to the formation water. The prepared nanofluids were screened to determine the suitable type for the heavy oil and rock samples subjected to the study. The effect of nanofluids on the interfacial tension and viscosity of emulsion were also investigated. Nanofluid-flooding tests were performed on a heavy-oil sample of 17.45 °API by use of Berea sandstone core samples with average air permeability of 184 md, liquid permeability of 60 md, and porosity of 20%. After selection of the optimum type of nanofluid, additional tests were performed including effect on asphaltene precipitation by use of a flow-assurance system. Results from the experiments show that the aluminum oxide nanofluid at concentration of 0.05 wt% reduced the emulsion viscosity by 25%. The mixed nanofluid of silicon and aluminum oxides at 0.05 wt% has shown the highest incremental oil recovery among the other nanofluids. It is expected to be the best type of chemical flooding because of its performance in reservoir condition (high pressure, temperature, and water salinity) and its capability to oppose asphaltene precipitation.

scholarly journals 3D Physical Simulation Experiment of Edge Water Reservoir by Polymer/Surfactant Binary Flooding

2020 ◽  
Vol 2020 ◽  
pp. 1-9
Author(s):  
Qunyi Wang ◽  
Wenshuang Geng ◽  
Fuquan Luo ◽  
Changcheng Gai ◽  
Xuena Zhang ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Loss Rate ◽  
Simulation Experiment ◽  
Physical Simulation ◽  
Water Reservoir ◽  
Chemical Agent ◽  
Chemical Flooding ◽  
Injection Wells ◽  
Polymer Surfactant ◽  
3D Physical Simulation

To investigate the enhanced oil recovery (EOR) technology by chemical flooding in an edge water reservoir, a 3D physical simulation experimental device for the edge water reservoir was developed, and polymer/surfactant binary flooding experiments were carried out under different edge water energies. In addition, the effect and mechanism of binary flooding on EOR under different edge water energies were comprehensively analyzed. Experimental results show that edge water intrusion considerably affects EOR by binary flooding. The stronger the edge water energy, the worse the effect of EOR by binary flooding. Edge water possibly diluted the concentration of the chemical agent medium that is injected into the reservoir, and the degree of dilution varied in different regions. The dilution region was mainly distributed between the injection wells and edge water. The stronger the edge water energy, the higher the dilution multiple of chemical agent and the greater the recovery loss rate by binary flooding.

Research on the Remaining Oil Starting Mechanism in Different Pores of Polymer Surfactants Using NMR Analysis

2014 ◽  
Vol 1010-1012 ◽  
pp. 1727-1734
Author(s):  
Yi Qiang Li ◽  
Zhe Yu Liu ◽  
Yan Yue Li ◽  
Yi Bo Xu
Keyword(s):  
Relaxation Time ◽  
Oil Recovery ◽  
Water Flooding ◽  
Good Effect ◽  
Chemical Flooding ◽  
Displacement Effect ◽  
Oil Displacement ◽  
Remaining Oil ◽  
Polymer Surfactants ◽  
Polymer Surfactant

With its unique structure and properties, polymer surfactants have been used in chemical flooding. Compared with ordinary polymer, polymer surfactants have a higher recovery degree. However, remaining oil starting mechanism in different pores using different polymer surfactants after water flooding is still unclear. NMR (Nuclear Magnetic Resonance) has a good effect on determination of rock oil saturation and analysis of pore structure. In this paper, oil displacement experiment using kerosene which contains no hydrogen was conducted and the problem caused by the similarity between oil phase relaxation time and water relaxation time in large pores was overcome. Through the change of NMR relaxation time, oil distribution situation in different pores of ordinary polymer, refining III polymer surfactant, and Haibo III polymer surfactant after polymer flooding was measured accurately. This paper also quantitatively analyzed the contribution degree to oil recovery in pores of different sizes, and evaluated oil displacement effect of the above three kinds of oil displacement systems. The results show that when only the swept volume is considered, recovery degree of Haibo III polymer surfactant is higher, reaching 53.66%. In different systems, middle pores contribute most to recovery degree. At the same time, the remaining oil in middle pores and large pores accounts more, which is the main attack direction towards tapping the potential of remaining oil in the oilfield.

Full Field EOR Implementation of A Low Cost Surfactant Continuous Injection at Arahan-Banjarsari, South Sumatra

2020 ◽  
Author(s):  
T. Ariadji
Keyword(s):  
Oil Recovery ◽  
Micellar Solution ◽  
Low Cost ◽  
Spontaneous Imbibition ◽  
Successful Implementation ◽  
Full Field ◽  
Chemical Eor ◽  
Reservoir Conditions ◽  
Water Cut ◽  
Continuous Injection

The objective of this paper is to describe a series of laboratory work results in conjunction with successful implementation of the surfactant (micellar) continuous injection in the Muara Enim sand of the Arahan-Banjarsari Field, South Sumatra. A series of lab tests were conducted using field cores and fluids taken from the Arahan-Banjarsari (AR-BS) field. The tests included phase behavior, mixture viscosity measurement, spontaneous imbibition, and static isotherm adsorption tests. Several surfactant formulas had been tested to find the most consistent and most suitable to the reservoir conditions. The surfactant injection was started in March 2009 into three AR wells. The injection was divided into 4 stages with initial concentration of 0.45% and the final concentration of 0.1%. Total volume of micellar solution injected in 110 days was 52,365 bbls. An increase in oil production was observed not only in two AR wells but also in 8 wells in the neighboring BS field (500 meters distance) after 140 days since injection of micellar solution started with injection rates of 200-250 bpd. Two BS wells were reopened and produced 28% and 54% water cut (the water cut before the two wells were shut in was 19% and 76%). This micellar solution injection managed to decrease the decline rate of 70% to 26% per year, increase production rate from AR and BS fields from 90 bopd to a peak of 220 bopd in 5 months since injection started, and reserves enhancement of 183 M bbls (10% OOIP) during 3.5 years of continuous injection. The low cost, full scale chemical EOR leads to changes in the common understanding about micellar flooding and shows a high impact on oil recovery of 183 Mbls (AB-5c sand with OOIP of 1.8 MMSTB).

scholarly journals Potential of using chemical enhanced oil recovery in the White Tiger field, offshore Vietnam

2014 ◽  
Vol 17 (3) ◽  
pp. 117-125
Author(s):  
Thinh Phu Nguyen ◽  
Khanh Quang Do ◽  
Quang Trong Hoang ◽  
Nguyen Viet Khoi Nguyen
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Energy Demand ◽  
Petroleum Reservoirs ◽  
Chemical Flooding ◽  
Screening Criteria ◽  
Chemical Eor ◽  
Petroleum Companies ◽  
White Tiger ◽  
Eor Processes

With growing global energy demand and depleting reserves, enhanced oil recovery (EOR) from existing or brown fields has become more and more necessary and important. Among the various enhanced oil recovery methods, chemical EOR has drawn increasing interest from many petroleum companies. In this paper, the popular EOR methods are introduced briefly. Next, we also consider the EOR processes of chemical flooding and the screening criteria for chemical EOR processes in detail. Finally, based on the data of the White Tiger (Bach Ho) field, we evaluate and predict the potential of using chemical EOR at the main different petroleum reservoirs from the Miocene, Oligocene to fractured basement formations.

scholarly journals CO-SURFACTANT POLYETHYLENE GLYCOL MONO-OLEATE IN THE ORMULATION OF NATURAL BASED-SURFACTANT FOR CHEMICAL EOR (SURFAKTAN PENDAMPING POLIETILEN GLIKOL MONO-OLEAT PADA FORMULASI SURFAKTAN BERBASIS NABATI UNTUK INJEKSI KIMIA EOR)

2018 ◽  
Vol 40 (1) ◽  
pp. 1-8
Author(s):  
Yani Faozani Alli ◽  
Letty Brioletty ◽  
Hestuti Eni ◽  
Yan Irawan
Keyword(s):  
Polyethylene Glycol ◽  
Oil Recovery ◽  
Raw Materials ◽  
Oil Field ◽  
Laboratory Scale ◽  
Chemical Flooding ◽  
Core Flooding ◽  
Central Java ◽  
Chemical Eor ◽  
Enhance Oil Recovery

Natural-based surfactant such as methyl esther sulfonate, which is derived from palm oil, has increasingly become the focus of study for the last decade to improve oil recovery due to the abundant raw materials availability and the need for oil as a source of energy. Surfactant MES development with the targeted fluid reservoir characteristic has been conducted in the laboratory scale as well as in the field scale. In this study, the addition of polyethylene glycol mono-oleate as co-surfactant to enhanced oil recovery in the L oil field in Central Java was investigated in the laboratory scale through compatibility observation, IFT measurement, thermal stability and core flooding tests. The results showed that the presence of PMO improved the solubility of surfactant mixture in the water which formed one phase milky solution. Decreasing IFT as the crucial factor for surfactant flooding was also achieved until 10-3 dyne/cm and thermally stable for two months. Furthermore, core flooding experiments to study the performance of surfactant to recover oil production showed that the mixture of MES and PMO are able to enhance oil recovery until 55.35% Sor and have potential to be used as chemicals for chemical flooding in the targeted oil field.Surfaktan berbasis nabati seperti surfaktan metil ester sulfonat (MES) dari bahan minyak kelapa sawit telah menjadi fokus penelitian selama satu dekade terakhir untuk meningkatkan perolehan minyak, mengingat ketersediaan bahan baku kelapa sawit yang melimpah di Indonesia serta kebutuhan akan minyak sebagai sumber energi yang terus meningkat. Pengembangan surfaktan MES agar sesuai dengan karakteristik fluida reservoar lapangan target juga telah berhasil dilakukan dalam skala laboratorium dan skala lapangan. Pada penelitian ini, pengaruh penambahan surfaktan pendamping polietilen glikol mono-oleat (PMO) untuk meningkatkan kemampuan surfaktan dalam meningkatkan produksi minyak pada lapangan L di Jawa Tengah dalam skala laboratorium dilakukan melalui uji kompatibilitas, ujitegangan antarmuka (IFT), uji kestabilan termal dan uji core flooding. Hasil penelitian menunjukkan bahwa penambahan PMO sebagai surfaktan pendamping MES dapat meningkatkan kelarutan surfaktan di dalam air formasi terkait dengan keberadaan gugus etoksi yang mempunyai sifat antarmuka di dalam struktur molekul PMO. Penurunan IFT sebagai faktor penentu dalam injeksi surfaktan juga dapat dicapai hingga 10-3 dyne/cm, dan dapat bertahan hingga dua bulan pada suhu reservoar. Adapun pengujian kemampuan surfaktan dalam meningkatkan perolehan minyak melalui uji core flooding menunjukkan bahwa campuran surfaktan MES dan PMO dapat meningkatkan produksi minyak hingga 55.35% Sor dan berpotensi untuk dijadikan bahan injeksi kimia di lapangan target.

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.

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.

Study on the Mechanism of Enhancing Oil Recovery by Molecular Film Displacement

2011 ◽  
Vol 236-238 ◽  
pp. 2135-2141
Author(s):  
Qi Cheng Liu ◽  
Yong Jian Liu
Keyword(s):  
Oil Recovery ◽  
Electrostatic Interaction ◽  
Ultrathin Films ◽  
Water Solution ◽  
Wettability Alteration ◽  
Nanometer Scale ◽  
Rock Surface ◽  
Capillary Imbibition ◽  
Molecular Film ◽  
Polymer Surfactant

Molecular film displacement is a new nanofilm EOR technique. A large number of experiments show that the mechanism of molecular film displacement is different from conventional chemical displacement (polymer, surfactant, alkali and ASP displacement etc). With water solution acting as transfer medium, molecules of the filming agent develop the force to form films through electrostatic interaction, with efficient molecules deposited on the negatively charged rock surface to form ultrathin films at nanometer scale. This change the properties of reservoir surface and the interaction condition with crude oil, making the oil easily be displaced as the pores swept by the injected fluid. Thus oil recovery is enhanced. The mechanism of molecular filming agent mainly includes absorption, wettability alteration, diffusion and capillary imbibition etc.

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