Modeling the Role of Wettability Alteration with Brine Composition and Increased Oil Recovery from Carbonate Cores

2016 ◽  
Author(s):  
Mohammed J. Alshakhs ◽  
Anthony R. Kovscek
Keyword(s):  
Oil Recovery ◽  
Wettability Alteration ◽  
Carbonate Cores ◽  
Increased Oil Recovery

Numerical Investigation of Wettability Effects on Two-Phase Flow in Naturally Fractured Reservoirs Using Complex System Modelling Platform

2021 ◽  
Author(s):  
Mohammad Sedaghat ◽  
Hossein Dashti
Keyword(s):  
Complex System ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Wettability Alteration ◽  
System Modelling ◽  
Naturally Fractured ◽  
Relative Permeability Curves

Abstract Wettability is an essential component of reservoir characterization and plays a crucial role in understanding the dominant mechanisms in enhancing recovery from oil reservoirs. Wettability affects oil recovery by changing (drainage and imbibition) capillary pressure and relative permeability curves. This paper aims to investigate the role of wettability in matrix-fracture fluid transfer and oil recovery in naturally fractured reservoirs. Two experimental micromodels and one geological outcrop model were selected for this study. Three relative permeability and capillary pressure curves were assigned to study the role of matrix wettability. Linear relative permeability curves were given to the fractures. A complex system modelling platform (CSMP++) has been used to simulate water and polymer flooding in different wettability conditions. Comparing the micromodel data, CSMP++ and Eclipse validated and verified CSMP++. Based on the results, the effect of wettability alteration during water flooding is stronger than in polymer flooding. In addition, higher matrix-to-fracture permeability ratio makes wettability alteration more effective. The results of this study revealed that although an increase in flow rate decreases oil recovery in water-wet medium, it is independent of flow rate in the oil-wet system. Visualized data indicated that displacement mechanisms are different in oil-wet, mixed-wet and water-wet media. Earlier fracture breakthrough, later matrix breakthrough and generation and swelling of displacing phase at locations with high horizontal permeability contrast are the most important features of enhanced oil recovery in naturally fractured oil-wet rocks.

Effects of Salinity on Nanosilica Applications in Altering Limestone Rock Wettability for Enhanced Oil Recovery

2015 ◽  
Vol 1125 ◽  
pp. 200-204 ◽  
Author(s):  
Wan Rosli Wan Sulaiman ◽  
A.J. Adala ◽  
Radzuan Junin ◽  
Issham Ismail ◽  
Abdul Razak Ismail ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Petroleum Industry ◽  
Wettability Alteration ◽  
Displacement Efficiency ◽  
Optimal Salinity ◽  
Reservoir Rocks ◽  
Limestone Rock ◽  
Enhance Oil Recovery

The role of nanoparticles in enhancing oil recovery from oil reservoirs is an increasingly important topic of research. Nanoparticles have the properties that are potentially useful for enhanced oil recovery (EOR) processes. One of the important roles of nanoparticles in petroleum industry is to change the wettability of reservoir rocks. The main objective of this study is to investigate the efficiency of silica nanoparticles in enhancing oil recovery in the presence of formation brine with different concentrations. The methodology of this study involved several laboratory tests. It is divided into two main sections with the aim of enhance oil recovery of oil wet reservoirs. First, the wettability alteration and oil–water interfacial tension modification induced by introducing different concentrations of nanosilica (0.01, 0.05, 0.1wt %) and different concentrations of NaCl formation brine (0.3, 1, 2, 3, 4 wt %) was studied by experimental approach. Second, the displacement test for determining oil recovery for those different concentrations of nanosilica and formation brine. There exists an optimal nanoslica concentration for varying salinity and an optimal salinity for varying nanosilica concentration at which the wettability alteration on oil wet limestone is the maximum for the study. The results revealed that IFT and contact angle tests were found to have the same optimal salinity (0.3wt %) and optimal nanosilica concentration (0.1wt %). Furthermore the highest value of displacement efficiency obtained at nanosilica (0.05wt %) and salinity (0.3 wt %) NaCl. As conclusion, as the salinity increases the extent of wettability alteration, IFT reduction, and enhanced oil recovery by nanosilica decreases.

scholarly journals Unlocking the Effects of Fluid Optimization on Remaining Oil Saturation for the Combined Sulfate-Modified Water and Polymer Flooding

Energies ◽  
2020 ◽  
Vol 13 (12) ◽  
pp. 3049 ◽  
Author(s):  
Muhammad Tahir ◽  
Rafael E. Hincapie ◽  
Leonhard Ganzer
Keyword(s):  
Oil Recovery ◽  
Chemical Interaction ◽  
Polymer Flooding ◽  
Wettability Alteration ◽  
Viscoelastic Layer ◽  
Recovery Mechanism ◽  
Polymer Flood ◽  
Fluid Optimization ◽  
Secondary Mode

Interfacial interactions and wettability alteration remain as the main recovery mechanism when modified water is applied seeking to obtain higher oil recoveries. Fluid-fluid interaction could lead to the development of the called viscoelastic layer at the interface in oil-brine systems. This interfacial layer stabilizes thanks to the slow chemical interaction between oil polar compounds and salts in the brine. This study investigates the role of sulfate presence in injection brine that could possible lead to develop the interfacial viscoelastic layer and hence to contribute to the higher oil recovery. Furthermore, polymer flooding is performed in tertiary mode after brine flood to investigate/unlock the synergies and potential benefits of the hybrid enhanced oil recovery. Brine optimization is performed using the composition of two formation brines and four injection brines. Moreover, interfacial tension measurements and oil drop snap-off volume measurements are performed in parallel with the core flooding experiments to define the role of interfacial viscoelasticity as the recovery mechanism other than wettability alteration. Synthetic seawater spiked with double amount of sulfate depicted potential results of interfacial viscoelastic layer development and hence to contribute the higher oil recovery. Total oil recovery after secondary-mode using sulfate-modified water and tertiary-mode polymer flood was higher than the combination of seawater brine in secondary-mode and polymer flood in tertiary-mode. Nevertheless, experiments helped us concluding that the amount of sulfate added is a critical factor to obtain maximum oil recovery and to avoid pore-plugging problems. We, therefore, demonstrate that executing a detailed fluid optimization leads to promising laboratory results, potentially linked with an improvement in the economics of the field applications.

Brine Divalent Ions Impacts on Wettability Alteration of Carbonate Rock Sample at Presence of DTAB

2017 ◽  
Vol 380 ◽  
pp. 191-197
Author(s):  
S.N. Hosseini ◽  
Maziyar Sabet ◽  
Hassan Soleimani ◽  
H. Ahmadi Eshkaftaki
Keyword(s):  
Oil Recovery ◽  
Rock Sample ◽  
Ionic Composition ◽  
Research Work ◽  
Wettability Alteration ◽  
Ammonium Bromide ◽  
Chemical Flooding ◽  
Surfactant Flooding ◽  
Maximum Change

Among many Enhanced Oil Recovery (EOR) methods, chemical flooding for wettability alteration of carbonate oil-wet rock is one of the most noticeable methods amid researchers. However, several crucial aspects concerning wettability alteration are still unknown and unanswered to date. Understanding the ionic composition of brine is a very important subject to which numerous studies are being dedicated, with the objective of determining the role of brine and its composition on wettability alteration, particularly its effects on EOR. The objectives of this research work is the investigation of the effects of different brine ions (Ca2+, Mg2+ and SO42-) on wettability alteration of oil-wet carbonate rocks while using cationic surfactant flooding Dodecyl Trimethyl Ammonium Bromide (DTAB). Results showed that the presence of SO42- is crucial and can improve DTAB efficiency. Contact angle maximum change is 62o to 19o with concentration of Na2SO4 equal to 6 g/l.

Novel Application of Cationic Surfactants for Foams With Wettability Alteration in Oil-Wet Low-Permeability Carbonate Rocks

SPE Journal ◽  
2018 ◽  
Vol 23 (06) ◽  
pp. 2218-2231 ◽  
Author(s):  
Pinaki Ghosh ◽  
Kishore K. Mohanty
Keyword(s):  
Oil Recovery ◽  
Carbonate Rocks ◽  
Foam Stability ◽  
Wettability Alteration ◽  
Low Permeability ◽  
Zwitterionic Surfactants ◽  
Oil Displacement ◽  
Tertiary Oil Recovery ◽  
Carbonate Cores ◽  
Displacement Experiments

Summary Carbonate rocks are typically heterogeneous at many scales, leading to low waterflood recoveries. Polymers and gels cannot be injected into nonfractured low-permeability carbonates (k < 10 md) because pore throats are smaller than the polymers. Foams have the potential to improve both oil-displacement efficiency and sweep efficiency in such carbonate rocks. However, foams have to overcome two adverse conditions in carbonates: oil-wettability and low permeability. This study evaluates several cationic-foam formulations that combine wettability alteration and foaming in low-permeability oil-wet carbonate cores. Contact-angle experiments were performed on initially oil-wet media to evaluate the wettability-altering capabilities of the surfactant formulations. Static foam-stability tests were conducted to evaluate their foaming performance in bulk; foam-flow experiments (without crude oil) were performed in porous media to estimate the foam strength. Finally, oil-displacement experiments were performed with a crude oil after a secondary gasflood. Two different injection strategies were studied in this work: surfactant slug followed by gas injection and coinjection of surfactant with gas at a constant foam quality. Systematic study of oil-displacement experiments in porous media showed the importance of wettability alteration in increasing tertiary oil recovery for oil-wet media. Several blends of cationic, nonionic, and zwitterionic surfactants were used in the experiments. In-house-developed Gemini cationic surfactant GC 580 was able to alter the wettability from oil-wet to water-wet and also formed strong bulk foam. Static foam tests showed an increase in bulk foam stability with the addition of zwitterionic surfactants to GC 580. Oil-displacement experiments in oil-wet carbonate cores revealed that tertiary oil recovery with injection of a wettability-altering surfactant and foam can recover a significant amount of oil [approximately 25 to 52% original oil in place (OOIP)] over the secondary gasflood. The foam rheology in the presence of oil suggested propagation of only weak foam in oil-wet low-permeability carbonate cores.

Cost-Effective Chemical EOR for Heterogenous Carbonate Reservoirs Using a Ketone-Surfactant System

2021 ◽  
Author(s):  
Etaf Alghunaim ◽  
Ozan Uzun ◽  
Hossein Kazemi ◽  
J. Frederick Sarg
Keyword(s):  
Oil Recovery ◽  
Vacuum Field ◽  
Wettability Alteration ◽  
Environmental Concerns ◽  
Ionic Surfactant ◽  
Low Salinity ◽  
Surfactant System ◽  
Chemical Eor ◽  
Carbonate Cores ◽  
San Andres

Abstract The complexity, high cost, and potential environmental concerns of chemical enhanced oil recovery (EOR) methods have diminished their field applications considerably. However, considering the significant incremental oil recoveries that can be obtained from these methods encourage researchers to explore ways to reduce both complexity, cost, and environmental concerns of such systems. This is especially important in carbonate formations, where after waterflooding, much of the oil remains trapped in complex reservoir pores—especially if the reservoir contains an interconnected fracture network of flow channels within the bulk rock matrix. In this paper, we present an experimental assessment of several simple chemical EOR waterflooding systems comprising of small concentrations of a low cost, low molecular weight ketone and a non-ionic surfactant in association with low-salinity brine. The experiments were conducted in carbonate cores from a Permian Basin San Andres Formation. Four different oil displacement scenarios were investigated using San Andres carbonate cores from the Central Vacuum Field in New Mexico. This included 1) low-salinity brine, 2) low-salinity brine with a surfactant, 3) low-salinity brine with a ketone, and 4) low-salinity brine with a combined ketone-surfactant system. Static imbibition experiments were conducted using a spontaneous imbibition apparatus in addition to the use of a high-speed centrifuge to saturate the cores to irreducible brine saturation. Adding a 1% concentration of 3-pentanone and a 1% non-ionic surfactant to a low-salinity brine yielded oil recoveries of 44% from the 3-pentanone system, compared to 11.4% from low-salinity brine only. The oil recovery is enhanced by a single mechanism or synergy of several mechanisms that includes interfacial tension (IFT) reduction by surfactant, capillary imbibition, favorable wettability alteration by ketone, and osmotic low-salinity brine imbibition. The IFT decreased to 1.79 mN/m upon addition of non-ionic surfactant to low-salinity brine, and it reduced to 2.96 mN/m in a mixture of 3-pentanone and non-ionic surfactant in low-salinity brine. Furthermore, ketone improved the core wettability by reducing the contact angle to 43.9° from 50.7° in the low-salinity brine experiment. In addition, the low-salinity brine systems caused mineral dissolution, which created an alkali environment confirmed by an increase in the brine pH. We believe the increase in pH increased the hydrophilic character of the pores; thus, increasing oil recovery.

Novel Insights Into Mechanisms of Oil Recovery by Use of Low-Salinity-Water Injection

SPE Journal ◽  
2016 ◽  
Vol 22 (02) ◽  
pp. 407-416 ◽  
Author(s):  
M.. Sohrabi ◽  
P.. Mahzari ◽  
S. A. Farzaneh ◽  
J. R. Mills ◽  
P.. Tsolis ◽  
...  
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Water Injection ◽  
Wettability Alteration ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Low Salinity Water Injection ◽  
Fluid Interactions

Summary The underlying mechanism of oil recovery by low-salinity-water injection (LSWI) is still unknown. It would, therefore, be difficult to predict the performance of reservoirs under LSWI. A number of mechanisms have been proposed in the literature, but these are controversial and have largely ignored crucial fluid/fluid interactions. Our direct-flow-visualization investigations (Emadi and Sohrabi 2013) have revealed that a physical phenomenon takes place when certain crude oils are contacted by low-salinity water, leading to a spontaneous formation of micelles that can be seen in the form of microdispersions in the oil phase. In this paper, we present the results of a comprehensive study that includes experiments at different scales designed to systematically investigate the role of the observed crude-oil/brine interaction and micelle formation in the process of oil recovery by LSWI. The experiments include direct-flow (micromodel) visualization, crude-oil characterization, coreflooding, and spontaneous-imbibition experiments. We establish a clear link between the formation of these micelles, the natural surface-active components of crude oil, and the improvement in oil recovery because of LSWI. We present the results of a series of spontaneous- and forced-imbibition experiments carefully designed with reservoir cores to investigate the role of the microdispersions in wettability alteration and oil recovery. To further assess the significance of this mechanism, in a separate exercise, we eliminate the effect of clay by performing an LSWI experiment in a clay-free core. Absence of clay minerals is expected to significantly reduce the influence of the previously proposed mechanisms for oil recovery by LSWI. Nevertheless, we observe significant additional oil recovery compared with high-salinity-water injection (HSWI) in the clay-free porous medium. The additional oil recovery is attributed to the formation of micelles stemming from the crude-oil/brine-interaction mechanism described in this work and our previous related publications. Compositional analyses of the oil produced during this coreflood experiment indicate that the natural surface-active compounds of the crude oil had been desorbed from the rock surfaces during the LSWI period of the experiment when the additional oil was produced. The results of this study present new insights into the fundamental mechanisms involved in oil recovery by LSWI and new criteria for evaluating the potential of LSWI for application in oil reservoirs. The fluid/fluid interactions revealed in this research can be applied to oil recovery from both sandstone and carbonate oil reservoirs because they are mainly derived from fluid/fluid interactions that control wettability alteration in both sandstone and carbonate rocks.

scholarly journals The Effect of Carbonyl and Hydroxyl Compounds on Swelling Factor, Interfacial Tension, and Viscosity in CO2 Injection: A Case Study on Aromatic Oils

Processes ◽  
2021 ◽  
Vol 9 (1) ◽  
pp. 94
Author(s):  
Asep Kurnia Permadi ◽  
Egi Adrian Pratama ◽  
Andri Luthfi Lukman Hakim ◽  
Doddy Abdassah
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Viscosity Reduction ◽  
Co2 Injection ◽  
Minimum Miscibility Pressure ◽  
Lower Viscosity ◽  
Hydroxyl Compounds ◽  
Swelling Factor

A factor influencing the effectiveness of CO2 injection is miscibility. Besides the miscible injection, CO2 may also contribute to oil recovery improvement by immiscible injection through modifying several properties such as oil swelling, viscosity reduction, and the lowering of interfacial tension (IFT). Moreover, CO2 immiscible injection performance is also expected to be improved by adding some solvent. However, there are a lack of studies identifying the roles of solvent in assisting CO2 injection through observing those properties simultaneously. This paper explains the effects of CO2–carbonyl and CO2–hydroxyl compounds mixture injection on those properties, and also the minimum miscibility pressure (MMP) experimentally by using VIPS (refers to viscosity, interfacial tension, pressure–volume, and swelling) apparatus, which has a capability of measuring those properties simultaneously within a closed system. Higher swelling factor, lower viscosity, IFT and MMP are observed from a CO2–propanone/acetone mixture injection. The role of propanone and ethanol is more significant in Sample A1, which has higher molecular weight (MW) of C7+ and lower composition of C1–C4, than that in the other Sample A9. The solvents accelerate the ways in which CO2 dissolves and extracts oil, especially the extraction of the heavier component left in the swelling cell.

IFT or wettability alteration: What is more important for oil recovery in oil-wet formation?

Fuel ◽  
2021 ◽  
Vol 291 ◽  
pp. 119986
Author(s):  
Z. Zhang ◽  
Madhar Sahib Azad ◽  
J.J. Trivedi
Keyword(s):  
Oil Recovery ◽  
Wettability Alteration

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.

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