Oil-wet Cores Research Articles

Preparation of amphiphilic Janus nanosheets based on thermally expandable microspheres and evaluation of their physical and chemical properties

Janus nanosheets can reduce the interfacial tension of oil and water and are of great significance for improving the recovery efficiency of remaining oil. A novel strategy for preparing amphiphilic Janus nanosheets is presented in this paper. Trialkoxysilane is adsorbed on the surface of thermally expandable microspheres (TEMS), and Janus spheres (TEMS@SiO2) are obtained by sol-gel treatment. Dodecyltrimethoxysilane (DTES) is used to modify TEMS@SiO2, which is combined with the thermal expansion of TEMS and the breaking of the outer shell of Janus spheres to prepare amino/alkyl composite silicon-based amphiphilic Janus nanosheets (ASAJN). Characterization of ASAJN is carried out via FTIR, TG, SEM, TEM, and contact angle tester, with the results showing that ASAJN boasts amphiphilicity and two-sidedness, and a sheet structure with a thickness of 210 nm. The stability, wettability evaluation, emulsification properties, and interface properties of ASAJN nanofluids have been evaluated, with the results showing that ASAJN nanofluids boast good stability without delamination after 30 days. ASAJN nanofluid can convert oil-wet core slices into water-wettable ones. ASAJN nanofluid manifests excellent emulsification, with the 240-hour emulsification index of ASAJN nanofluid and silica fluid respectively at0.40 and 0.021 under ultra-low concentration (1000 mg/L). ASAJN is obviously able to reduce oil–water interfacial tension. At 1000 mg/L (60 ℃) concentration, the oil-water interfacial tension is reduced to 2.6 mN/m, while that of nano-silica at the same concentration is 15.1 mN/m. ASAJN flooding can significantly improve the recovery efficiency of low-permeability reservoirs, increasing the recovery efficiency by 32.8 % at a permeability of 7.5 × 10-3 μm2.

Evaluation of oil displacement potential of genetically engineered strain WJPAB fermentation broth

Rhamnoolipids are the most widely studied and used biosurfactants, which can be used in microbial flooding to enhance oil recovery. Pseudomonas aeruginosa is the main species of rhamnoolipids synthesized at present. In this study, wild strain WJ was modified by directional genetic engineering, and the strong promoter PoprL was used to replace the original promoter of rhlAB gene, and the genetically engineered strain with increased copy number of Popr-Rhlab gene was constructed, which was named as the genetically engineered strain WJPAB. The optimal carbon source of WJPAB was rapeseed oil. Under the optimal fermentation conditions, the product yield of WJPAB was 57.83g/L, which was 91.17% higher than that of wild strain WJ.The metabolites of strain WJPAB are purified and analyzed by high performance liquid chromatography mass spectrometry (HPLC-MS). The products are confirmed to be rhamnose homologues, including 3 single rhamnose homologues and 5 double rhamnose homologues. The physical and chemical properties of the metabolites of strain WJPAB were studied, and it was found that the metabolites of strain WJPaB had good surface/interfacial activity, which could reduce the surface tension of water to 27.34 mN/m, and change the surface of oil-wet core from oil-wet surface to water-wet surface. The emulsification index of simulated oil, cetane and liquid paraffin is above 60%. In addition, bacterial metabolites have good stability and can maintain good surface activity even at pH 3–11, salinity 0–20g/L and temperature 120 °C, and can adapt to a wide range of reservoir environmental conditions. In the oil displacement experiment, a compound oil displacement system is established by combining fermentation broth and xanthan gum. The compound system can increase the recovery rate by 15.45%, save the separation and purification process of biosurfactant, and reduce the application cost. The results show that Pseudomonas aeruginosa WJPAB has a good application prospect in the microbial oil recovery field.

Mechanism and influencing factors of enhanced oil recovery for active SiDots nanofluid assisted fracturing-drainage in low permeability reservoirs: An experimental and numerical simulation study

Fracturing-drainage in low permeability reservoirs is a special method to facilitate oil production, however, conventional chemical oil displacement agents cannot adequately take advantage of this technology. Active SiDots nanofluid has special surface/interface properties and excellent stability that can contribute to improving the effect of fracturing-drainage. This paper investigates the influencing factors and mechanisms of active SiDots nanofluid assisted fracturing-drainage to enhance oil recovery (EOR) through experiments and reservoir numerical simulation. The results on the performance of the active SiDots nanofluid show that 0.10 wt% concentration was sufficient to reduce the oil-water interfacial tension from 20 mN/m to 0.32 mN/m and modify the oil-wet core to water-wet. Experimental and reservoir numerical simulation results indicate that the incremental oil recovery after the active SiDots nanofluid fracturing-drainage was more than 10%, which was more effective than surfactant alone. The optimum injection concentration and volume of active SiDots nanofluid were 0.10 wt% and 0.6 PV, respectively. To improve the utilization of active SiDots nanofluid, the well shut-in time should be at least 24 h. One-cycle active SiDots nanofluid injection was more conducive to replenishing the formation energy and expanding the swept volume. The field injection rate of the SiDots nanofluid should not be too high to prevent breakthroughs. The EOR experimental results indicate that the fracturing-drainage could increase the injection volume to replenish energy and reduce the active SiDots nanofluid adsorption loss thereby effectively peeling the oil film. This paper addresses the supply shortage of conventional chemicals used for fracturing-drainage in low-permeability reservoirs and expands the study of the influencing factors and mechanisms of fracturing-drainage.

Residual Trapping of CO2 and Enhanced Oil Recovery in Oil-Wet Sandstone Core – A Three-Phase Pore-Scale Analysis Using NMR

HypothesisCombining Carbon Geo-sequestration (CGS) with Enhanced Oil Recovery (EOR) in three-phase flow oil reservoirs is an effective and economically attractive technology to mitigate global warming caused by emission of anthropologic CO2 from fossil fuel combustion, as it offsets some of the costs of CO2 extraction. The targeted oil reservoirs display oil-wet characteristics, primarily because of the strong affinity of polar molecules present in oil; a mixture of a large number of chemical compounds to the rock's surface; and oil-wet surfaces that drastically reduce storage capacity of geological trapping mechanisms and increase the vertical migration of CO2. Thus, it is essential to characterise the effect of wettability of rock on pore-scale physics in a pore network that dominate three-phase flow, which in turn control overall reservoir‐scale fluid dynamics and; thus, determine residual CO2 trapping and the success of CO2‐EOR projects. ExperimentalTo fully examine this, we present the first in situ NMR T1-T2 2D images and transverse relaxation time (T2) to quantify residual CO2 (capillary) trapping for an oil-wet core at reservoir conditions, representative of virgin oil reservoirs at around 1000-meter depth. We also systematically measure how much additional oil can be produced, where we compared the results with measurements performed on an analogous water-wet core. ResultsThe results show a significant residual CO2 saturation (12%) can be stored, which is similar to the values found in analogue two-phase flow for oil-wet sandstone samples, although some details are different and displacements are significantly complex, and a substantial amount of oil (51%) was recovered. In contrast, results of similar tests conducted on an identical analogous water-wet core show a higher CO2 trapping (20%), where oil production was substantially higher (77%). We have also presented the oil displacement efficiency (η) versus CO2 injection (PV), showing the percentage oil displacement efficiency of water-wet (0.6%) to be significantly higher than that of analogue oil-wet core (0.4%). Interpretation of the findingThese results significantly improve geo-storage integrity; i.e. capacities and containment security, over reservoir-scale implementations, in addition to having a substantial impact on outlining CO2-EOR projects in term of budgets and storage capacities for CO2-EOR and CO2 geo-sequestration.

Rock-Wettability Impact on CO2-Carbonate Rock Interaction and the Attendant Effects on CO2Storage in Carbonate Reservoirs

Deep saline aquifers and depleted carbonate reservoirs are generally considered promising locations for subsurface CO2 storage. However, carbonate minerals particularly calcite can react with CO2-saturated brine, resulting in dissolution of carbonate and potentially mechanical compaction. Thus, it is crucial to understand the extent of this reaction in both water-wet and oil-wet scenarios, and subsequently its consequences on CO2 storage in depleted carbonate reservoirs. In this study, medical X-ray computed tomography (CT) was used to image water-wet and oil-wet Indiana limestone core samples before and after CO2 flooding. Changes in the rock matrix and pore structure were further assessed from the porosity and permeability data computed from the CT images. In both cases, imaging shows a significant amount of dissolution resulting in an increase in pore volume after core flooding with live brine and subsequently CO2. This increase in porosity is 46.7% and 19% for the water-wet and oil-wet core, respectively. Likewise, the brine permeability for the water-wet core increased from 9.2 mD (before CO2 flooding) to 108 mD (after CO2 flooding), whereas the permeability for the oil-wet core increased modestly from 9.0 mD to 20.1 mD. These results suggests that the reactivity is less pronounced in the oil-wet rock compared to the water-wet rock. Therefore, the wettability state of a target carbonate reservoir and the subsequent potential for the wettability state to be modified should be considered when assessing the CO2 storage capacity and integrity.

Effect of a nanoparticle on wettability alteration and wettability retainment of carbonate reservoirs

The oil recovery in many carbonate reservoirs is low due to oil-wetness and heterogeneity. In this study, nanoparticles are evaluated for altering the wettability of oil-wet limestones and their properties are compared with those of an anionic surfactant. A surface-modified silica nanoparticle (SiNP) with a negative zeta potential was found to be aqueous stable in brines. Wettability studies showed that the SiNP cannot change the wettability of an initially oil-wet calcite plate, but SiNP treated calcite surface can remain water-wet after aging in oil. Spontaneous imbibition tests confirmed the observations of wettability tests and showed that a SiNP treated carbonate core retained its water-wettability during oil injection and aging. The imbibition into a SiNP treated and oil aged core was comparable to that in a water-wet core. However, SiNP was not able to remove the oil layers in initially oil-wet cores and imbibe water into these cores. In contrast, the anionic surfactant could alter the oil-wet carbonate rocks to a more water-wet condition, but failed to prevent the water-wet surface from getting oil-wet during oil-aging. The results suggest that the SiNP can be injected into wettability-altered (water-wet) reservoirs/regions to help retain the water-wettability during the long-term oil production. The 0.5 wt% SiNP dispersions transported through 18 mD limestone cores without any plugging. The SiNP retention was measured to be 2.5 mg/m2, much higher than that of the anionic surfactant.

Surfactant enhanced imbibition in carbonate reservoirs: Effect of IFT reduction and surfactant partitioning

A majority of carbonate reservoirs are preferably oil-wet or intermediate wet. Spontaneous imbibition represents an important mechanism to enhance oil production. Targeting an oil-wet carbonate reservoir with high temperature and high salinity, several surfactant formulations were investigated to improve oil production by imbibition, focusing on the capacity in interfacial tension (IFT) reduction and surfactant partitioning in water and oil phases in addition to dominant wettability alteration effect. Oil production potentials using different surfactants were evaluated by spontaneous imbibition in Amott cells at 95 ​°C. A base case imbibition test was conducted using a high salinity water with IFT value of 15.2 ​mN/m and an oil-wet carbonate core, and the oil production was 6.4% of oil originally saturated in core. Reducing the oil-water IFT to 10° ​mN/m magnitude achieved 4% incremental oil production beyond base case. When the IFT was further reduced to 10 −1 ​mN/m magnitude, the incremental oil production reached 10%. For the case of water-wet core and at the same IFT range, the incremental oil production was 13%. When the IFT was reduced to 10 −2 ​mN/m, the incremental oil production was up to 17% for the tests using oil-wet cores, and up to 23% for the water-wet counterpart. When further reducing the IFT to ultra-low magnitude of 10 −3 ​mN/m, the oil production was close to that using the imbibition agents with IFT of 10 −2 ​mN/m magnitude. For surfactants with no obvious wettability alteration capacity, those surfactants with higher molecular fraction in oil phase and higher adsorption on rock surfaces could remove more oil from the pore wall, and yielded higher imbibition efficiency. This work systematically investigated the major effects of surfactant on oil mobilization during imbibition process, which can help for better understanding of chemical imbibition in carbonates. The findings will shed light on the selection of high performance imbibition agents for carbonate reservoirs.

Coreflood Tests to Evaluate Enhanced Oil Recovery Potential of Wettability-Altering Surfactants for Oil-Wet Heterogeneous Carbonate Reservoirs

Summary Oil-wetness and heterogeneity are two main factors that result in low oil recovery (OR) by waterflood in carbonate reservoirs. The injected water is likely to flow through high-permeability regions and bypass the oil in the low-permeability matrix. In this study, systematic coreflood tests were carried out in both “homogeneous” cores and “heterogeneous” cores with a wettability-altering surfactant. The homogeneous coreflood tests were conducted to evaluate surfactant retention, as well as to compare tertiary surfactant flooding with secondary surfactant flooding. The heterogeneous coreflood test was proposed to model bypassing in low-permeability matrix during waterfloods, and dynamic imbibition of surfactant into the low-permeability matrix. Surfactant retention results suggest that retention increases as initial oil saturation decreases. The retention of selected surfactant in the target reservoir cores was measured to be within a range of 0.07–0.12 mg/g-rock, which is economically acceptable. The results of homogeneous coreflood tests showed that both secondary waterflood and secondary surfactant flood can achieve high OR (>50%) from relatively homogeneous oil-wet cores. A shut-in phase after the surfactant injection resulted in a surge in oil production, which suggests that enough time should be given for wettability alteration by surfactants. The results of heterogeneous coreflood tests showed that more oil is bypassed in the tighter matrix by waterflood if the permeability is higher in the flooded layer and this bypassed oil is the target for the wettability-altering surfactant floods. Slow wettability-altering surfactant injection leads to imbibition into bypassed regions. When the oil-wet carbonate reservoirs have large unswept regions after waterflood, wettability-altering surfactants can significantly improve OR if enough time is given for imbibition.

Qualitative assessment of improved oil recovery and wettability alteration by low salinity water injection for heterogeneous carbonates

This study aims to evaluate the qualitative potential for low salinity water injection (LSWI) to alter the wettability and increase oil production in heterogeneous oil-wet coquina cores (one of the facies of Pre-Salt reservoirs) in relevant conditions of brine salinity, temperature, and initial wettability. We also aimed to verify the impact of micro-porosity fraction on oil recovery. Finally, we verified whether the presence of micro-dispersion in the oil phase upon contact with low salinity would have a positive correlation with improved oil recovery due to low salinity water injection.To achieve these objectives, we performed zeta-potential experiments to evaluate the charges at the oil-brine and brine-rock interfaces that affect rock wetting state and contact tests to test for the presence of micro-dispersions in the oil phase and potential for LSWI. A series of spontaneous imbibition and coreflood experiments were performed to calculate the Amott index and evaluate wettability of coquinas in core-scale as a function of brine salinity. Tertiary and secondary low salinity waterfloods were carried out to investigate whether a diluted desulfated seawater would increase oil production in coquina cores. The effect of predominance of macro-, meso-, and micro-porosity on secondary low salinity waterflood was also evaluated. Our results have shown that heterogeneity had a greater impact on recovery factor compared to brine salinity. Oil recovery for low salinity brine for a core with predominance of macro-pores was smaller than for cores with higher fraction of micro-pores flooded with FW and DSW. Low-salinity oil recovery was also smaller than high-salinity was for core with microporosity but with presence of dead-end pores. Secondary injection of low-salinity using the same core with large fraction of micro-porosity showed that it accelerated oil production compared to high-salinity brine. We have also observed that LSWI resulted in increased oil recovery in coquinas both in tertiary mode (average 10%) compared to FW/DSW and secondary mode using the same core (18% compared to FW) due to wettability alteration. This result was supported by spontaneous imbibition as well as zeta-potential results. The contact test between crude oil and low salinity brine resulted in a micro-dispersion ratio of 11.7, showing that a positive oil is likely to result in improved oil recovery due to low salinity injection. Despite the increased oil recovery seen during the tests, the results showed that oil production in tertiary mode was significantly delayed (after 4 PV), likely due to adverse oil/water viscosity ratio and water dispersion due to mixing between low- and high-salinity brines. We observed that for the shorter more oil-wet core significant oil production was measured during bump flow with both high-salinity and low-salinity brines, due to capillary end effects. This could mean that residual oil saturation was not achieved during high-salinity water injection and an overestimation of recovery factor due to low-salinity was seen.

Water flooding of sandstone oil reservoirs: Underlying mechanisms in imbibition vs. drainage displacement

In this work the effect of wettability in waterfloods of viscous oil is investigated in a combination of experiments in sandpacks and microfluidic chips. Thirty-nine sand-pack flooding experiments were conducted to investigate the effect of core wettability, oil viscosity, and injection velocity on oil recovery to water flooding. An in-line densitometer, installed downstream of the core, was used to record the instantaneous fluid production and help understanding the mechanism of oil displacement in porous media. Additional microfluidic experiments were conducted to understand the mechanism of viscous oil displacement in imbibition vs. drainage.The effect of injection velocity on oil recovery is a strong function of core wettability and oil viscosity. In water-wet systems, below a critical viscosity (∼60 mPa s), increasing injection velocity enhances oil displacement. In more viscous oil systems, injection velocity reduction improves imbibition. This is confirmed through visualization in microfluidic tests. Post breakthrough bypassed oil is produced in the form of low viscosity oil in water emulsion. In oil-wet waterflooding, oil imbibition into the preformed water channels pinches off (snaps-off) some continuous fingers, diverting water to un-swept regions. This temporary channel closure can explain the cyclic pressure build-ups observed oil-wet core flooding experiments. casein oil-wet systems, oil is produced as a series of viscous oil slugs rather than an emulsion.A new dynamic dimensionless time is presented to quantify imbibition time to which imbibition data are well correlated. This number along with the previously presented “viscous drainage number” can quantify different mechanisms responsible for oil displacement in systems of different viscosity ratio, injection velocity, and core wettability. The proposed dimensionless numbers can be used to determine expected viscous oil recovery efficiency in different wettability systems.

Effects of cleaning process using toluene and acetone on water-wet-quartz/CO2 and oil-wet-quartz/CO2 wettability

Acetone, toluene, and heptane have been perceived as the conventional cleaning agents for the preservation of original water-wet rock reservoir wettability, and for restoration of oil-wet core to its initial wetting condition, prior to measurement of contact angles of CO 2 -brine-rock systems. However, these organic solvents could be adsorbed on rock surfaces, which modifies the wettability of the reservoir rock and thus triggers uncertainties of the CO 2 containment estimation. Presently, there is scarcity of data in literature on the impact of cleaning agents on the wettability of rock/CO 2 /brine/systems and its attendant effect on CO 2 storage capacities. To provide insights on the impact of cleaning agents on CO 2 wettability of sandstone, water-wet and oil-wet quartz substrates were aged in acetone, toluene, and heptane, respectively. Advancing and receding contact angles of CO 2 -brine-quartz systems were measured at a constant temperature (323 K) and varying pressures (5–20 MPa). Impact of cleaning the minerals surfaces with air plasma, N 2 and oven after cleaning with either toluene or acetone on CO 2 wettability was also assessed and compared. The results show that chemicals that are used quite often to clean mineral surfaces can alter the rock wettability. Significant alterations in wetting conditions were observed when oil wet-rock was cleaned with toluene and water-wet rock was cleaned with acetone. Our results suggest that to preserve the original wettability, we will need to use toluene to clean the water-wet rock and acetone to clean the oil-wet rock. Heptane is only suitable for wettability modification of the oil-wet cores and not for restoration of oil-wet core to its original reservoir wettability. The results confirm that air plasma is the only way to remove surface contamination and organic carbon from the quartz substrates. Cleaning minerals surfaces or rock samples by toluene, acetone and heptane without air plasma will lead to incorrect contact angle and bias wettability measuments. Equilibrium brine contact angles for CO 2 /brine on quartz substrate as a function of pressure at constant temperature (323 K) for clean (pure), aged in crude oil, soaked in toluene after ageing in crude oil, and soaked in acetone after aging in crude oil. • Effects of toluene, acetone and heptane on CO 2 -brine-quartz wettability was studied. • Toluene preserved the original wettability of water-wet rock. • Acetone preserved the original wettability of oil-wet rock. • Heptane is not suitable for restoration of oil-wet core to original wetting state. • Air plasma is the only way to remove organic carbon from the quartz substrates.

Associative polymers for disproportionate permeability reduction – Formation wettability effects

Core-based laboratory experiments were performed on water- and chemically-treated-oil-wet Berea sandstone long-core samples to investigate the disproportionate permeability reduction (DPR) potential of a low-molecular weight associative polymer. The impact of single- and two-phase DPR treatments were considered at 60 °C. In the experiments conducted, real-time electrical resistivity measurements were obtained during the coreflood tests to serve as (a) a valuable tool for fluids saturation monitoring and (b) improved core fluids saturation evaluation in flooded porous media. Results from DPR treatments in water-wet cores showed high initial oil residual resistance factors, RRFo (≈20), followed by relatively long clean-up times; stabilized RRFo was achieved at relatively high PVs of oil injection (≈25). For the range of the post-treatment pressure gradients applied in the laboratory experiment, no DPR effects were observed for the water-wet core samples. However, the different shear-dependent behavior for the oil and water phases in the treated zone suggests that a positive DPR effect is possible at extrapolated low post-treatment applied pressure gradients; this could also be translated as higher clean-up times. For the two-phase DPR treatments in water-wet cores, RRFo can be significantly reduced to approximately 8, while RRFw stabilized at the relatively high value of 40. However, the required significantly long clean-up period during oil flow through the treated zone may question the efficiency of the achieved DPR effect. For the two-phase DPR treatment in oil-wet cores, stabilized RRFo were achieved at considerably lower injected oil PVs, i.e., shorter post-treatment clean-up periods were required. In addition, distinguishably smaller RRFo values were achieved for the oil-wet cores compared to the water-wet ones with a substantial separation from the achieved RRFw values (i.e., faster attainment of low values ranging between 6 and 4 for 15 to 40 injected PVs clean-up duration). These results indicate greater potential for effective positive DPR treatment for oil-wet medium treated through two-phase injection methods. Multi-rate tests conducted during polymer injection showed that the mobility reduction (resistance factor, RF) during DPR treatments, for both single- and two-phase methods, are shear dependent. In addition, post-treatment water and oil injection (production) showed different behavior regarding permeability reduction (RRF). In both core wettability cases, water flow experienced a noticeable power-law dependency to the applied differential pressure. On the other hand, the oil flow behavior in the two wettability cases was different; slightly shear-thinning for the water-wet cases and weakly shear-thickening for the oil-wet cores. In both cases the shear dependency of oil flow was much less pronounced than that of the water flow. Finally, the production water cut can be decreased to a noticeable amount using associative polymer DPR treatments. However, one must note that the water cut reduction (economic gain) is associated with a reduced total (oil) production rate (time loss); therefore, implementation of an associative polymer DPR treatment should be considered carefully.

Experimental study on the mechanism of adsorption-improved imbibition in oil-wet tight sandstone by a nonionic surfactant for enhanced oil recovery

In recent years, production from tight oil reservoirs has increasingly supplemented production from conventional oil resources. Oil-wet formations account for a considerable proportion of tight oil reservoirs. Surfactant can change wettability and reduce interfacial tension, thus resulting in a better oil recovery. In this manuscript, a nonionic surfactant was introduced for tight oil-wet reservoirs. The oil recovery in the oil-wet sandstone due to spontaneous imbibition was 8.59% lower than that of the water-wet sandstone due to surfactant. The 0.1% surfactant solution corresponded to the highest imbibition recovery rate of 27.02% from the oil-wet sample. With the surfactant treatment, the treated core quickly changed from weakly oil-wet to weakly water-wet. The capillary force acted as the driving force and promoted imbibition. The optimal surfactant adsorption quantity in the oil-wet sandstone was observed in the sample at concentrations ranging from 0.1% to 0.3%, which also corresponded to the highest oil recovery. Analysis of the inverse Bond number N B − 1 suggested that the driving force was gravity for brine imbibition in the oil-wet cores and that it was capillary force for surfactant imbibition in the oil-wet cores. When the surfactant concentration was lower than the critical micelle concentration, the surfactant concentration was negatively correlated with the inverse Bond number and positively correlated with the oil recovery rate. When the surfactant concentration was higher than the critical micelle concentration, the oil recovery increased with a smaller interfacial tension. Nuclear magnetic resonance suggested that the movable pore and pore throat size in the oil-wet sample decreased from 0.363 μm in the untreated rock to 0.326 μm with the surfactant treatment, which indicated that the surfactant improved the flow capacity of the oil. The findings of this study can help to better understand the adsorption impact of surfactants on the characteristics of the oil/water and solid/liquid interfaces. The imbibition mechanism in oil-wet tight sandstone reservoirs was further revealed. These systematic approaches help to select appropriate surfactants for better recovery in oil-wet tight sandstone reservoirs through imbibition.

Determining water-oil relative permeability and capillary pressure from steady-state coreflood tests

This study aims at the simultaneous determination of relative permeability and capillary pressure from steady-state corefloods. Besides using the measurements of pressure-drop across the core and average saturation under steady-state conditions, we use the transient data between the sequential steady states. The inverse algorithm is based on four type curves “stabilizsation period versus water-cut” revealed by asymptotic analysis of the transient solution near end-point saturations, and on the exponential shape of transition data histories observed by direct numerical runs. The transition measurements are approximated in the stabilisation periods by the type curves using non-linear least-square optimisation. The Corey parameters for relative permeability and capillary pressure are fitted for each interval of sequential water-cuts. The inverse solver is applied to three sets of steady-state tests in oil-wet cores, where saturation profiles during steady-state flows have been measured along with the transition data. Extensive sensitivity analysis of the inverse solutions with respect to the small perturbation of the measured data reveals the stability of obtained relative permeability and capillary pressure. The close agreement between the measured stabilised saturation profiles and those obtained by the matched-based modelling in three oil-wet cases validates the method developed.

Experimental investigation on the dominating fluid-fluid and rock-fluid interactions during low salinity water flooding in water-wet and oil-wet calcites

Low salinity water flooding (LSWF) has the potential to enhance the oil recovery by affecting the fluid-fluid and rock-fluid interactions. Therefore, a systematic investigation on the effect of initial wetting state (water-wet or oil-wet) of pure calcite is conducted to study the importance of these interactions on the effectiveness of LSWF. In the case of initially water-wet cores, more oil recovery efficiency is observed for more saline water cases. To shed light on the possible involved mechanisms, dynamic IFT, dynamic contact angle (CA), oil/brine and rock/brine surfaces zeta potentials, and effluent pH are measured. It is shown that the short-term effect of IFT reduction and long-term effect of wettability alteration toward neutral-wetness (due to change in the electric charge of the crude-oil/brine and calcite/brine) are the dominating recovery mechanisms. However, the oil recovery behavior of oil-wet cores is in the opposite direction of that of water-wet cores, which demonstrates the wettability dependency of the involved mechanisms. CA measurement shows that diluted sea water (dSW) has more ability to change wettability toward water-wetness. The zeta potential results show that as brine salinity reduces, both crude-oil and rock surfaces become more negatively charged. Therefore, the observed wettability alteration behavior with salinity reduction is attributed to larger repulsion between these surfaces at lower salinity. pH results suggest CO 3 2− ions are responsible to make calcite surface more negative with diluting SW brine. The oil recovery behavior is also a strong function of the initial wetting state. SW brine, recovered less oil and experienced an earlier breakthrough in an initially oil-wet core compared to an initially water-wet core. Unlike the previous case, dSW experienced higher ultimate oil recovery and almost the same breakthrough time in an initially oil-wet core compared to an initially water-wet core. The superior performance of the low salinity water in an oil-wet core is a result of the wettability alteration toward more water-wetness which triggers more piston-like advancement. • A systematic investigation on the contribution of different fluid-fluid and rock-fluid interactions in the oil recovery of low salinity water flooding in pure water-wet and oil-wet calcite rocks. • Dynamic IFT, dynamic contact angle, the zeta potential of both crude oil/brine and calcite/brine surfaces, and the effluent pH are measured to asses these interactions. • In the case of initially water-wet calcite, the oil recovery increases with the rise in the salinity. • In the case of oil-wet calcite, higher oil recovery achieved in the case of brine with lower salinity. • The effectiveness of low salinity water flooding, optimum salinity, ultimate oil recovery factor and breakthrough times are functions of rock wettability.

A novel hybrid technique to enhance oil production from oil-wet carbonate reservoirs by combining a magnetic field with alumina and iron oxide nanoparticles

This paper examined a new study into the effect of combined magnetic field and nanoparticles (NPs) on oil-wet carbonate reservoirs. A novel hybrid enhanced oil recovery (EOR) technique was used to investigate the effect of a magnetic field and aluminium oxide (Al2O3) and iron oxide (Fe2O3) nanoparticles (NPs) on oil recovery from Austin chalk, based on measurements of contact angle, surface tension, rock compaction and rock surface charge. An Amott cell with a surrounding magnetic belt was used to perform spontaneous imbibition tests. When oil-wet cores with an extremely low recovery factor (RF) of 2.73% were imbibed with deionized water, the effect of the combination of magnets and alumina was pronounced and an incremental RF of 14.7% was recorded. However, changing the displacing fluid from deionized water to seawater led to a lower recovery of 9.2%, which can be attributed to the poor dispersion of alumina NPs. Adding iron oxide NPs to the displacing fluid in the presence of magnets also resulted in higher recovery factors, with increases of 22.27% and 12.78% observed for deionized water and seawater respectively. The analysis of zeta potential, contact angle and surface tension data suggests that the combined driving mechanisms of alteration in wettability and interfacial forces caused the improvements found in oil recovery from oil-wet carbonate rocks during water-based nanoparticle flooding when exposed to a magnetic field. In addition, concentrations of aluminium oxide and iron oxide NPs were reduced by factors of 40 and 5 respectively compared to previous studies. Hence, this technique offers cleaner EOR, allows the oil industry to optimize oil production with the lowest chemical use by implementing magnets, ultimately increasing revenue in the long term.

Variations in Wettability and Interfacial Tension during Alkali-Polymer Application for High and Low TAN Oils.

The injection of chemicals into sandstones can lead to alterations in wettability, where oil characteristics such as the TAN (total acid number) may determine the wetting state of the reservoir. By combining the spontaneous imbibition principle and the evaluation of interfacial tension index, we propose a workflow and comprehensive assessment to evaluate the wettability alteration and interfacial tension (IFT) when injecting chemical-enhanced oil-recovery (EOR) agents. This study examines the effects on wettability alteration due to the application of alkaline and polymer solutions (separately) and the combined alkali–polymer solution. The evaluation focused on comparing the effects of chemical agent injections on wettability and IFT due to core aging (non-aged, water-wet and aged, and neutral to oil-wet), brine composition (mono vs. divalent ions); core mineralogy (~2.5% and ~10% clay), and crude oil type (low and high TAN). Amott experiments were performed on cleaned water-wet core plugs as well as on samples with a restored oil-wet state. IFT experiments were compared for a duration of 300 min. Data were gathered from 48 Amott imbibition experiments with duplicates. The IFT and baselines were defined in each case for brine, polymer, and alkali for each set of experiments. When focusing on the TAN and aging effects, it was observed that in all cases, the early time production was slower and the final oil recovery was longer when compared to the values for non-aged core plugs. These data confirm the change in rock surface wettability towards a more oil-wet state after aging and reverse the wettability alteration due to chemical injections. Furthermore, the application of alkali with high TAN oil resulted in a low equilibrium IFT. By contrast, alkali alone failed to mobilize trapped low TAN oil but caused wettability alteration and a neutral–wet state of the aged core plugs. For the brine composition, the presence of divalent ions promoted water-wetness of the non-aged core plugs and oil-wetness of the aged core plugs. Divalent ions act as bridges between the mineral surface and polar compound of the in situ created surfactant, thereby accelerating wettability alteration. Finally, for mineralogy effects, the high clay content core plugs were shown to be more oil-wet even without aging. Following aging, a strongly oil-wet behavior was exhibited. The alkali–polymer is demonstrated to be efficient in the wettability alteration of oil-wet core plugs towards a water-wet state.

Effect of spontaneous emulsification on oil recovery in tight oil-wet reservoirs

Surfactants improve oil recovery from tight oil-wet formations through wettability alteration and interfacial tension (IFT) reduction. The popular perspective believes that wettability alteration induced capillary-driven spontaneous imbibition is the major mechanism of Enhanced Oil Recovery (EOR) in tight oil reservoirs. Therefore, surfactant with functions of wettability alteration while guarding a relatively high IFT should be chosen as the best candidate. However, ultra-low IFT may change the phase behavior and flow-pattern within the porous media to improve the oil recovery through emulsification.Therefore, in this paper, we investigated the effect of spontaneous emulsifying surfactants on the oil recovery from tight sandstones through spontaneous imbibition experiments and the results are compared with that of regular surfactants The results manifested that the spontaneous-emulsifying surfactants with ultra-low IFT can improve oil recovery from oil-wet cores, and the performance surpassed that of regular surfactants through wettability alteration. It is because a spontaneous-emulsifying surfactant is capable of accelerating the oil dispersion and reducing the residual oil saturation by emulsifying the oil phase. Partly, it diffuses out from the porous media in the form of the microemulsion, and partly small oil droplets with ultra-low IFT may coalesce into larger ones so that it is easy for them to deform and to be produced by buoyancy. Therefore, comparing with the traditional viscous flow, the change of the flow pattern due to the addition of spontaneous-emulsifying surfactants further enhanced the recovery in term of producing rate and final recovery factor.

Rock wettability effect on Colloidal Gas Aphron invasion near wellbore region

Colloidal Gas Aphron drilling fluid is colloidal dispersions of gas microbubbles, which are designed to reduce the loss of circulation in depleted reservoirs. This fluid creates a robust and elastic micro-bubble network, to block the pores of the formation and minimize filtration loss. In this study, Xanthan Gum (XG) polymer and Sodium Dodecyl Benzene Sulphonate (SDBS) surfactant were the primary materials utilized to generate a water-based Colloidal Gas Aphron drilling fluid. A dynamic and static invasion of prepared Aphron drilling fluid in carbonate rock with different wettabilities was investigated. Moreover, the formation damage induced by the invasion of Aphron fluid to porous media was also studied. Results demonstrated that wettability alteration of a water-wet porous media to oil-wet lead to an increment of differential pressure throughout porous media during Aphron drilling fluid invasion. A significant influence of wettability was also observed on return permeability of carbonate rock. A reduction of 73.53% of carbonate rock permeability was observed in oil-wet core invaded by water-based Aphron drilling fluid.

The Control of Apparent Wettability on the Efficiency of Surfactant Flooding in Tight Carbonate Rocks

In this research, a state-of-the-art experimental core flooding setup is used to assess the efficiency of surfactant flooding as an enhanced oil recovery (EOR) technique in tight carbonate rocks. Specifically, we investigate the role of apparent wettability in governing the effectiveness of surfactant flooding. A series of flooding experiments with well-defined boundary conditions were performed on the low permeability core plug samples of Indiana Limestone (calcite-cemented carbonate grainstones). Experiments were conducted on three samples exhibiting differing apparent wetting characteristics: strongly oil-wet, moderately oil-wet and weakly oil-wet. Initially, the oil-saturated core samples were flooded with brine until the residual oil saturation was achieved, with surfactant flooding performed as a tertiary recovery technique. Interestingly, our experimental results reveal that the efficiency of surfactant flooding increases with the degree of oil-wetness of the tight carbonate rocks. The strongly oil-wet core showed the highest recovery, while the weakly oil-wet core manifested the least additional oil recovery associated with surfactant flooding. Moreover, we provided a pore-scale argument that explains the macroscopic role of surfactant flooding in tight carbonate rocks. We hypothesized that at the pore-scale the presence of thin film plays a critical role in controlling the effectiveness of surfactant flooding in the strongly oil-wet tight carbonate rocks. Overall, we believe that our macroscopic study provides novel insight into the dynamics of surfactant flooding in tight carbonate reservoirs and can aid in optimizing the field development plans for oil recovery.