Low salinity water flooding (LSF) is a relatively simple and cheap EOR technique in which the salinit y of the injected water is optimized (by desalination and/or modification) to improve oil recovery over conventional waterflooding. Extensive laboratory experiments investigating the effect of LSF are available in the literature. Sulfate-rich as well as diluted brines have shown promising potential to increase oil production in limestone core samples. To quantify the low salinity effect, spontaneous imbibition and/or tertiary waterflooding experiments have been reported. For the first time in literature, this paper presents a comprehensive study of the centrifuge technique to investigate low salinity effect in carbonate samples. The study is divided into three parts. At first, a comprehensive screening was performed on the impact of different connate water and imbibition brine compositions/combinations on the spontaneous imbibition behavior. Second, the subsequent forced imbibition of the samples using the centrifuge method to investigate the impact of brine compositions on residual saturations and capillary pressure. Finally, three unsteady-state (USS) core floodings were conducted in order to examine the potential of the different brines to increase oil recovery in secondary mode (brine injection at connate water saturation) and tertiary mode (exchange of injection brine at mature recovery stage). The experiments were performed using Indiana limestone outcrops. The main conclusions of the study are spontaneous imbibition experiments only showed oil recovery in case the salinity of the imbibing water (IW) is lower than the salinity of the connate water (CW). No oil production was observed when the imbibing water had a higher salinity than the connate water or the salinity of the connate water and imbibing brine were identical. Moreover, the spontaneous imbibition experiments indicated that diluting the salinity of the imbibing water has a larger potential to spontaneously recover oil than the introduction of sulfate-rich sea water. The centrifuge experiments confirmed a connection between the overall salinity and oil recovery. As the salinity of the imbibing brines decreases, the capillary imbibition pressure curves showed an increasing water-wetting tendency and simultaneous reduction of the remaining oil saturation. The lowest remaining oil saturation was obtained for diluted sea water as CW and IW. The core flooding experiments reflected the results of the spontaneous imbibition and centrifuge experiments. Injecting brine at a rate of 0.05 cc/min, sea water and especially diluted sea water resulted in a significant higher oil recovery compared to formation brine. Moreover, when comparing secondary mode experiments, the remaining oil saturation after flooding by diluted sea water, sea water and formation water was 30.6 %, 35.5 % and 37.4 %, respectively. In tertiary injection mode, sea water did not lead to extra oil recovery while diluted sea water led to an additional oil recovery of 5.6 % in one out of two tertiary injection applications.

Abstract During an Alkaline-Surfactant-Polymer (ASP) flood in reservoir rock, often an in situ microemulsion phase forms upon contact of the injected ASP fluid with the residing oil. These microemulsions form as a result of the required ultra-low interfacial tensions (IFT) for oil mobilization and displacement of the residual oil, but they can have a high viscosity. The success of an ASP flood on oil recovery depends on the complex flow of the injected ASP solution, the mobilized oil and the in situ microemulsion phase, which the latter often has a higher shear-dependent viscosity than the other two. In this study, steady-state (SS) corefloods have been performed to investigate the in situ microemulsion formation and rheology during the multiphase flow. The aqueous phase, namely brine, AS or ASP, was co-injected with n-decane or reservoir ‘dead’ crude in Berea outcrop cores for a range of fractional flow ratios. The pressure differential was continuously recorded, and was then converted in an apparent, in situ, viscosity value. For this stage of the project the water and oil phase saturations in the plugs were not yet measured. For brine/oil systems some dependence of apparent viscosity on rock permeability was observed; for systems with surfactants no such trend was noticable. The addition of surfactants substantially reduced the apparent viscosities; the viscosity reducing impact of surfactants could be balanced by the addition of polymer. Fractional flow analysis showed that the addition of surfactants reduces the impact of capillary forces resulting in straightened relative permeability curves and higher aqueous phase relative permeability end points. It is anticipated that this study leads to a fast and fit for purpose characterization method of ASP-crude oil systems that provides data in a form, such as relative permeability data and residual oil saturation that can be applied directly in reservoir simulators.

Description: This paper describes a series of experiments that used X-ray tomography to visualize the mobilization of remaining oil by Alkaline Surfactant Polymer (ASP) flooding after conventional waterflooding. The experiments were conducted in cores drilled from Bentheim sandstone outcrop material with diameters of approximately 7.55 cm and lengths of 14.9, 27.5 and 100 cm. The crude used in the experiments has an in-situ viscosity of about 100 cP and contains petroleum acids that are converted to soaps in the presence of alkali. Application: In addition to pressure and effluent data collected during conventional coreflood experiments phase and saturation distributions in space and time are needed to more completely interpret the results of core floods. This additional information reveals underlying mechanisms, and assists the development of models that capture the physics of ASP that can ultimately be used to provide field scale predictions for ASP performance. Results, Observations, and Conclusions: • A significant oil bank was created, propagated, and produced in each of the experiments. • The size of the oil bank in terms of length and maximum oil saturation is largely dependent on the post-waterflood saturation distribution along the cores. • Large variations in both the absolute value and the spatial distribution of the post-waterflood saturation distribution were observed in the different experiments. • A characteristic self-similar cross-sectional averaged oil saturation profile develops for floods conducted in the longer length cores. • Detailed analyses of individual frames revealed separate “oil” and “ASP fingers” in the area downstream of the oil bank. Significance: The displacement mechanisms involved in ASP flooding relatively viscous crudes are revealed by X-ray CT visualization. The resulting improved understanding of the process increases the confidence in the potential full-field application of ASP flooding.

Injection of acids and CO2 into geologic formations leads to dissolution of soluble minerals comprising reservoirs rocks. This increases the uncertainty in predicting the security and injectivity of geologic CO2 storage. Here through time‐lapse computed tomography of injection experiments, we present the first dynamic data on wormhole formation and the fluid flow therein. We show that the dissolution during single‐phase flow produces wormholes, as found previously, but that two‐phase flow during CO2‐brine injection leads to compact dissolution. The latter is explained by CO2 preferentially occupying wormhole seeds, which prevents their growth as CO2 is less reactive than acidic brine. On the other hand, the wormhole seeds continue to grow under single‐phase flows with only acidic fluid. The results also suggest that initial Péclet and Damköhler numbers for the single‐phase flow process would fail to describe the dynamic process of whether compact or wormhole dissolution would ensue.

AbstractThis paper describes a series of experiments that used X-ray computer tomography (CT) to visualize the mobilization of remaining oil by Alkaline Surfactant Polymer (ASP) flooding after conventional waterflooding. The experiments were conducted in cores drilled from Gildehauser and Berea sandstone outcrop material with diameters of approximately 7.55 cm and lengths of 27.5 and 99 cm. Two light crude oils with in-situ viscosities of 1.3 cP and 3.2 cP were used in the experiments. The changes in the fluid saturation distributions with time obtained with X-ray computer tomography are subsequently used to improve the conceptual understanding of the ASP process.In addition to pressure and effluent data collected during conventional core flood experiments, phase and saturation distributions in space and time are needed to more completely interpret the results of core floods. This additional information reveals underlying mechanisms, and assists the development of models that capture the physics of ASP that can ultimately be used to provide field scale predictions for ASP performance.One important observation from the experiments is that there exist a typical fingering pattern in the zone upstream of the oil bank. Although fingering is often considered a bad sign for a displacement process the experiments also demonstrate that the fingering zone is contained in the area upstream of the oil bank and that the velocity of the front of the oil bank is significantly greater than that of the fingering zone. The tail production observed in many ASP core floods is a consequence of the formation of this fingering zone.Effluent analyses conducted on the produced fluids from the long core experiments showed an instantaneous build up in polymer viscosity that coincides with the beginning of the tail production while the surfactant concentration only gradually increases to its injection value during the tail production.Another important observation is that a characteristic self-similar cross-sectional averaged oil saturation profile develops during ASP injection after water flood in cores containing non reactive light crude oil.The implications of the self-similarity of the saturation profiles in combination with the observation that the surfactant propagation is retarded with respect to the polymer propagation results in a polymer flood ahead of the ASP-slug and a corresponding characteristic oil production profile. The characteristics of this process can be captured with an extended fractional flow approach that utilizes three fractional flow curves: one for the ASP-slug, one for polymer, and the original fractional flow curve for oil-water.

The displacement of brine by CO2 is an important process controlling plume migration and initial pore-space utilization in geological CO2 storage. We present CO2–brine unsteady-state core flood experiments to characterize CO2–brine primary displacement in Estaillades limestone, a model system for dual-porosity carbonates. We analyze the experiments by means of numerical simulations assuming 2-D homogeneous rock and parameterized kr(SW) relationships. Assisted history matching methodologies were used to find the kr(SW) parameters which minimize a mismatch function, giving the best match to the experimental data. We refer the results to the microscopic rock structure and we discuss the limits of applicability. Larger-scale heterogeneity was considered as intrinsic to arrive at a practical and upscaled description of the displacement process. Heterogeneity is discussed by comparing the results to classical relative permeability measurements on samples with a 24× smaller volume, which are less affected by heterogeneity. We found that larger-scale heterogeneity results in lower fluid-phase mobilities.

In enhanced oil recovery (EOR) surfactants are used to reduce the oil/brine interfacial tension (IFT) by several orders of magnitude to mobilize and produce residual, capillary-trapped, oil. The reduction in IFT is usually accompanied by the formation of a separate microemulsion phase. Microemulsions are thermodynamically stable mixtures of oil, brine and surfactants, and have ultra-low IFT with both excess oil and brine phases which they are in contact with. Such ultra-low IFT facilitates oil mobilization even under low pressure gradients. However, the existence of a third-phase microemulsion introduces further unknowns to flow behavior in the porous media. For example, it is commonly observed that the microemulsions have considerably higher viscosities than their single components. Consequently, such higher viscosities will affect surfactant transport in the porous medium, and can lead to high surfactant retention values. Understanding the microemulsion flow properties is essential not only in the design of optimized surfactant systems, but also in modelling the relevant EOR processes. In this paper the microemulsion rheological behavior is analyzed in the rheometer and under flowing conditions in the cores. Large volumes of microemulsion were injected into outcrop core plugs with different permeabilities in the range of 72 mDarcy to 2 Darcy. The cores were mounted in a core holder and the pre-mixed microemulsion was injected at several fixed rates. Pressure along the core was continuously recorded during the entire experiment. An in situ, or apparent, viscosity was calculated using the Darcy flow equation. All measurements were performed at 30 °C. Comparisons between the rheometer-measured microemulsion viscosity and the in situ viscosity in the core revealed that the permeability had a significant impact on the microemulsion rheology. The highest permeability core showed in situ viscosity values similar to the rheometer viscosity, while in the lowest permeability core the in situ viscosity was a factor of two higher than the rheometer-measured one. Here, several possible mechanisms for this permeability-dependent microemulsion viscosity will be discussed, such as pore plugging, effect of shear, separation into oil and brine, and microemulsion structure size.

The influence of chemical reactions between injected CO2, formation fluids and the target rock formation leads to uncertainties for geological sequestration projects. Reactions may influence the fluid-flow field, i.e. reactive transport, and the mechanical rock properties, which might degrade, leading to uncertainties with respect to the rock integrity in the affected region. We investigate both the influence of calcite dissolution on the fluid flow and the mechanical rock properties for two cases: first under realistic CO2/brine field flow rates leading to heterogeneous dissolution, i.e. wormholing, and second under noflow conditions leading to a rather homogeneous dissolution. We find a significant influence of dissolution on singleand two-phase flow and changes of the elastic rock properties and the failure behavior. The study is an essential step toward understanding CO2 plume migration and the effects caused by long-term migration of CO2 in carbonate reservoirs, providing input parameters for reservoir models and reservoir surveillance.

The process of displacement and mass transfer between CO2 and brine, which are relevant for the prediction of plume migration and pore-space utilization during CO2 injection in saline aquifers, were studied by conducting unsteady-state core flood experiments in nearly homogeneous Berea sandstone rock. Mutually saturated and unsaturated CO2 and brine phases were injected in the rock under realistic sequestration conditions.Relative permeability and capillary pressure curves were extracted by history matching the unsteady state experiments conducted with mutually saturated CO2 and brine. As a reference and for comparison, decane-brine primary drainage was conducted on the same sample. The CO2-brine relative permeability was found to be different from the decane-brine relative permeability (which had been validated against steady-state experiments on twin-samples), reflecting the change in the wetting state from water-wet decane-brine/Berea to the rather intermediate-wet behavior of CO2-brine/Berea, which is in agreement with literature data on contact-angles for the two cases. However, the CO2 brine data are somewhat different from data on the same rock type as reported by Perrin and Benson (2010) which is likely a consequence of sample heterogeneity.Aspects of the mass transfer between the CO2 and the brine phase were studied by drainage and imbibition with unsaturated phases. When comparing saturated and unsaturated CO2-brine primary drainage, the mass transfer due to mutual solubility leads to two effects: (1) evaporation near the inlet due to water dissolving in CO2 and (2) a diminished displacement of brine by CO2 due to CO2 dissolving in brine. In addition, an imbibition experiment was conducted where unsaturated brine was injected into rock filled with mutually saturated CO2 and brine phase at near-residual CO2 saturation. After the CO2-saturated brine had been miscibly displaced by unsaturated brine, dissolution of the trapped CO2 in the injected brine was subsequently observed. These experiments represent the transition from residual trapping to solubility trapping and indicate the time and length scales involved. (C) 2012 Shell Global Solutions International B.V. Published by Elsevier Ltd. All rights reserved.

influence of chemical reactions between injected CO 2, formation fluids and the target rock formation leads to uncertainties for geological sequestration projects. Reactions may influence the fluid-flow field, i.e. reactive transport, and the mechanical rock properties, which might degrade, leading to uncertainties with respect to the rock integrity in the affected region. We investigate both the influence of calcite dissolution on the fluid flow and the mechanical rock properties for two cases: first under realistic CO2/brine field flow rates leading to heterogeneous dissolution, i.e. wormholing, and second under no- flow conditions leading to a rather homogeneous dissolution. We find a significant influence of dissolution on single- and two-phase flow and changes of the elastic rock properties and the failure behavior. The study is an essential step toward understanding CO2 plume migration and the effects caused by long-term migration of CO2 in carbonate reservoirs, providing input parameters for reservoir models and reservoir surveillance.

The displacement and fluid/fluid mass transfer between CO2 and brine in Berea sandstone have been investigated by unsteady-state core-flood experiments combined with x-ray computed tomography. Relative permeability and capillary pressure saturation functions of primary drainage for mutually saturated fluid phases have been determined from production data and the saturation profiles by history matching and have been benchmarked against standard SCAL. The displacement stability of the CO2/brine drainage process has been investigated by numerical modeling, and the consequences for experimental procedures and for geological storage of CO2 are discussed. Aspects of mass transfer during drainage and imbibition that are relevant for nonequilibrated fluid phases were studied by core flooding with unsaturated CO2 and brine phases.

Abstract Modifying the chemistry of injection water yields improved wettability behavior on carbonate rock surfaces. Previous work has focused on demonstrating the effect of modified brine formulation on particular carbonate samples. Here the results of a more general screening study consisting of Amott spontaneous imbibition experiments on the samples from oil-bearing zones and from outcrops of different carbonate formations are reported. Tertiary incremental oil production due to increased water-wetness was observed upon transition to brine of lower ionic strength. Additional oil recovery from the spontaneous imbibition tests ranged from 4 to 20% of OIIP (Oil Initially In Place), reflecting a large variability in the response and indicating a high complexity of the mechanism(s). Consistent with numerous published reports, Stevns Klint outcrop chalk samples were a clear exception and exhibited increased oil recovery with increasing sulfate ion concentration. These did not respond to lowering the salinity of the imbibing brine. Tertiary oil recovery from samples containing evaporites occurred simultaneously with dissolution of salt minerals, as evident from brine analysis. However, incremental oil recovery in the same range was measured for samples without evaporites but from the same geological formation. Hence, mineral dissolution as a mechanism for enhanced oil recovery could not be confirmed. The results show that injection of low salinity brine into carbonate reservoirs has potential as an EOR technology. However, additional research is needed to improve the understanding of the underlying chemical and physical mechanisms and improve a priori predictability.

The displacement and fluid/fluid mass transfer between CO2 and brine in Berea sandstone have been investigated by unsteady-state core-flood experiments combined with x-ray computed tomography. Relative permeability and capillary pressure saturation functions of primary drainage for mutually saturated fluid phases have been determined from production data and the saturation profiles by history matching and have been benchmarked against standard SCAL. The displacement stability of the CO2/brine drainage process has been investigated by numerical modeling, and the consequences for experimental procedures and for geological storage of CO2 are discussed. Aspects of mass transfer during drainage and imbibition that are relevant for non-equilibrated fluid phases were studied by core flooding with unsaturated CO2 and brine phases. INTRODUCTION For CO2 injection in saline aquifers the properties of the formation rock and the fluids play an important role. CO2 and brine are immiscible fluids and hence subject to immiscible displacement. The two fluids are mutually soluble, leading to a mass transfer between the two fluid phases, with a potential impact on the displacement process in those areas where the two fluid phases are not yet equilibrated such as near the injection point and close to the flood front. The major part of the plume, however, might be subject to true immiscible displacement, and hence the pore space utilization and the extent of the plume are largely determined by relative permeability and capillary pressure saturation functions, kr(SW) and pC(SW), respectively. Characterization of the primary drainage process is essential for geological sequestration. The microscopic displacement efficiency (shock front height) and also the degree of gravity overrun, viscous fingering and channeling through rock heterogeneities determine how effectively the pore space is used for CO2 storage. Shock front height, fingering and gravity overrun depend on fluid viscosity, kr and pC. Bypassing due to channeling and/or viscous instabilities is a concern, especially at a high viscosity ratio between the displaced and the displacing fluids i.e. CO2 and brine. For a comprehensive analysis of the CO2/brine displacement process we conducted unsteady-state (USS) core flood experiments in Berea sandstone. Mutually saturated and unsaturated CO2 and brine phases were injected in the rock under realistic sequestration conditions to obtain kr(SW) and pC(SW) and to study the influence of mass

The performance of carbon disulfide (CS2) as a novel agent for enhanced oil recovery has been investigated by conducting a comprehensive series of core flooding experiments where in porous rock, CS2 miscibly displaces “oil” (model fluids such as n-Decane, mineral oils, and crude oils) with a large range of viscosities and field-relevant flow rates. The recovery of oil and the three-dimensional spatial distribution of injected and displaced fluids were obtained from x-ray computed tomography. In all experiments, the displacement was unstable. The dominating displacement patterns were gravity under-run of the more dense CS2, channeling in higher permeable layers and viscous fingering. Since CS2 was fully miscible with all considered fluids, no difference in behavior between model fluids and crude oils was found. The recovery after injection of one pore volume of CS2 was parametrized using the dimensionless scaling groups Péclet number, gravity to viscous forces ratio G, and the logarithmic viscosity ratio R. At small viscosity ratios and large flow velocities (viscous dominated flow, small values of G), recoveries over 90% were observed. Slower flow and more viscous oils reduce the oil recovery.

1. ABSTRACT Oil recovery from fractured oil-wet and mixed-wet carbonate reservoirs by water flooding is generally poor. Injected water preferentially flows through the fractures and by-passes most of the oil in the matrix. For the water to displace oil from the matrix, a pressure drop needs to be created at the fracture-matrix interface that exceeds the capillary entry pressure which is significant especially for low permeable and oil-wet rock matrix. In the last decade, surfactant flooding has emerged as a potential EOR method to improve oil recovery from fractured carbonate reservoirs. Surfactant can improve oil recovery by either altering the wettability of the matrix and enhances spontaneous imbibition of water or reducing interfacial tension between oil and water and thus enhances oil-water gravity drainage or both. The focus of this paper is on understanding the surfactant enhanced gravity drainage (SEGD) process.

ABSTRACT The inflow performance of gas wells in gas/condensate fields may be impaired when condensate banks form near the wellbore as a result of the pressure dropping below the dewpoint. This impairment may be alleviated to some extent, however, by the increase in condensate mobility at the prevailing conditions, which are characterised by high gas flow rates and relatively low interracial tension. Scouting reservoir simulations indeed identified this mobility improvement to be a key uncertainty in well-deliverability forecasting for gas/condensate reservoirs. Model experiments with core material from various gas/condensate reservoirs in Europe and the Middle East were therefore conducted at ambient conditions to assess the degree to which the mobility of condensate could be improved by the applied flow conditions. A wide range of relative permeability and of saturation were probed, and several orders of magnitude of capillary number, interfacial tension and absolute permeability were covered. In all cases, the results reveal a truly significant mobility increase. Moreover, it was experimentally demonstrated that the key parameter controlling this effect is the capillary number and not the interfacial tension alone. The dynamic relative permeabilities that were obtained from our experiments are currently being used for history-matching well tests with equation-of-state reservoir simulations.