Sandstone Plugs Research Articles

Digital Rock Physics in Cuttings Using High-Resolution Thin Section Scan Images

Digital rock physics (DRP) has undergone significant advancements in the use of various imaging techniques to acquire three-dimensional volumes and images of rock samples for the computation of petrophysical properties. This study focuses on developing a DRP workflow using high-resolution thin section scans for computing porosity and permeability in cuttings samples. The workflow was tested on quarry sandstone plug samples and artificially generated pseudo-cuttings before applying it to real cuttings from oil and gas wells. The results show that the porosity and permeability values obtained through the DRP workflow are statistically equivalent to those obtained through conventional routine core analysis (RCAL). The workflow was also able to handle the presence of various lithologies in real cuttings samples. The study demonstrates the feasibility of obtaining porosity and permeability values in cutting samples using the DRP approach, offering a fast and cost-effective methodology that provides additional data and allows linking petrophysical properties to image data from the cuttings.

RESERVOIR CHARACTERIZATION OF THE PLIOCENE RED SERIES, LAM FIELD AND SURROUNDING AREAS, OFFSHORE WESTERN TURKMENISTAN

The sedimentology, petrography and reservoir potential of Pliocene sandstones within the Upper Red Series in the offshore LAM field, Western Turkmenistan, have been examined. Depositional settings are interpreted within the framework of the Red Series palaeoenvironments across the entire Turkmen sector of the Apsheron‐Prebalkhan uplift zone, including its onshore extension to the east.Examination of 81 m of core from three separate intervals suggests that the Red Series in the LAM field is the product of a fluvial‐dominated delta system with associated floodplain deposits, periodically flooded by the saline waters of the South Caspian Lake. Relatively thick sandstones, up to around 5 m thick, are interpreted as channel and point‐bar deposits of a meandering river system, with thinner and finer‐grained sandstones and siltstones inferred to be crevasse‐splay and interdistributary floodplain deposits. Floodplain mudstones display signs of desiccation, soil formation, plant rootlets and occasional thin layers of anhydrite. Intervals with marine trace‐fossil assemblages record incursions of saline‐lake waters. Conglomeratic layers at the base of thicker mudstone intervals may be associated with abrupt transgressions of the lake. The best reservoir qualities are associated with the fluvial channel and point‐bar sandstones. Crevasse‐splay and other overbank sandstones are of poorer quality, while intercalated floodplain to lacustrine claystone/siltstone units may constitute local seals.Eighteen sandstone plug samples from the cored intervals were examined in thin‐section and by XRD and SEM to assess how mineralogy, grain size and diagenesis affect reservoir quality. The samples consist predominantly of lithic arkoses and feldspathic litharenites; higher porosities, and therefore better reservoir potential, are associated with the feldspathic litharenites. Primary controls on porosity include compaction, clay‐matrix content and calcite cementation. XRD data reveal the presence of illite, illite‐smectite and chlorite. The presence of swelling clays has been the main cause of formation damage in the field.The interpretation of meandering fluvial channels here is thought to represent the first published account of such channels within Pliocene reservoir rocks in the north of the South Caspian Basin. Previous accounts of the Red Series sandstones deposited onshore to the east have indicated deposition within braided channels of the palaeo‐Amu Darya river delta plain, and alluvial‐fan deposits sourced from uplands to the north. Deposition of the equivalent Productive Series by the palaeo‐Volga in the Azerbaijan sector to the west has also been interpreted as having taken place within braided systems, although mixed or suspended‐load fluvial channels ascribed to the contemporary Kura delta farther south may have been associated with a meandering system. Two palaeogeographic maps are presented to illustrate depositional environments for the Red Series during relative high‐ and low‐stands of the South Caspian Lake. The maps cover the area where the Productive Series of Azerbaijan passes into the Red Series of Western Turkmenistan.

A new method of pressure drop modelling in sandstone rocks

Production capacity of any hydrocarbon reservoir is the most important question that needs to be answered. This depends on both the obtainable drawdown between the well and reservoir and the petrophysical properties (pore size distribution, wettability properties, saturations etc.) of the porous rock material. Permeability, introduced by Darcy is the parameter describing restrictions present during fluid flow in porous media. Although this method is the one currently accepted and implemented in the industry it has a major flaw because it considers flow in the geometric (total) rather than the effective volume, where it truly develops. During this study a new approach of flow restriction modelling was found, where flow restrictions, measured from sandstone plug samples were compared with the theoretic flow volumes which are equal to the total pore volumes, constructed of steel capillaries of equal diameter. Results show that flow restrictions of incompressible fluids in sandstone can be demonstrated by the new model.

Laboratory Investigation of Impact of Slickwater Composition on Multiphase Permeability Evolution in Tight Sandstones

Summary Fracturing fluid filtrate that leaks off during injection is imbibed by strong capillary forces present in low-permeability sandstones and may severely reduce the effective gas permeability during cleanup and post-fracture production. This work aims to investigate the role fracturing fluid filtrate from slickwater has on rock-fluid and fluid-fluid interactions and to quantify the resulting multiphase permeability evolution during imbibition and drainage of the filtrate by means of specialized core laboratory techniques. Three suites of experiments were conducted. In the first suite of experiments, a fluid leakoff test was conducted on selected core samples to determine the extent of polymer invasion and leakoff characteristics. In the second suite, multigas relative permeability measurements were conducted on sandstone plugs saturated with fracturing fluid filtrate. A combination of controlled fluid evaporation and pulse decay permeability technique was used to measure liquid and gas effective permeabilities for both drainage and imbibition cycles. These experiments aim to capture dynamic permeability evolution during invasion and cleanup of fracturing fluid (slickwater). The final suite of experiments consists of adsorption flow tests to investigate, identify, and quantify possible mechanisms for adsorption of the polymeric molecules of friction reducers present in the fluid filtrate to the pore walls of the rock sample. Imbibition tests and observations of contact angles were conducted to validate possible wettability changes. Results from multiphase permeability flow tests show an irreversible reduction in endpoint brine permeability and relative permeability with increasing concentration of friction reducer. Our results also show that effective gas permeability during drainage/cleanup of the imbibed slickwater fluid is controlled to a large degree by trapped gas saturation than by changes in interfacial tension. Adsorption flow tests identified adsorption of polymeric molecules of the friction reducer present in the fluid to the pore walls of the rock. The adsorption friction reducer increases the wettability of the rock surface and results in the reduction of liquid relative permeability. The originality of this work is to diagnose formation damage mechanisms from laboratory experiments that adequately capture multiphase permeability evolution specific to a slickwater fluid system, during imbibition and cleanup. This will be useful in optimizing fracturing fluid selection.

Investigation of waterflood front digitations during immiscible displacements in porous media

In this work, unstable displacements were conducted using special equipment designed to run in-situ CT-scanner experiments. All the displacements were conducted on a homogeneous Bentheimer sandstone plug, of 10 cm in diameter and 40 cm in length. Digitations (or fingering) have been observed under varying conditions of injection flowrate, displaced fluid viscosity, and core wettability. They have been characterized at both the core scale, using the core average oil saturation and the water breakthrough; and at the local scale, using the local saturations and had-hoc image processing analysis. It was found that the effect of the different flowing conditions on the front digitations could not be interpreted independently. The oil recovery at brine breakthrough showed a good correlation with the viscous fingering number for the water-wet case. However, a different scaling was observed for the oil-wet case. The interplay of the different flowing conditions mitigates the possibility of constructing a unique scaling number to account for all experimental condition. The local saturation monitoring has provided a new insight to characterize the finger shapes and analyze the production mechanisms. It allowed to distinguish two independent contributions to early breakthrough: viscous dominated digitations and capillary dominated digitations. A two-phases diagram has been constructed to plot and compare these contributions for all flowing conditions. Their evolutions show the main production mechanisms during the flooding. We observed that the viscous digitations were not causing phase trapping at core scale: the core is completely swept after breakthrough. For the water-wet case, we found that the local oil recovery of swept zone remained constant before and after breakthrough while for the oil-wet case it is improving during all the water flooding process.

Characterization and likelihood application of extracted mucilage from Hollyhocks plant as a natural polymer in enhanced oil recovery process by alkali-surfactant-polymer (ASP) slug injection into sandstone oil reservoirs

Injection of water-based polymeric solutions into oil reservoirs is a common way to enhance oil recovery in the tertiary oil production stage. Polymers are normally injected under different scenarios individually, or with surfactants and alkalis, or both as a slug. Adjusting the ratio of water and oil mobility, preventing the phenomenon of fingering and early production of injectable water by increasing water viscosity are the most important mechanisms of polymer injection in enhanced oil recovery (EOR) process. In this study, the possibility of using extracted mucilage from Hollyhocks plant as a natural polymer for injection as a slug with surfactant and alkaline in sandstone reservoirs was investigated. The plant polymer was characterized by Fourier Transform Infrared Spectroscopy (FTIR), Energy Dispersive X-ray Analysis (EDAX) and Thermal Gravimetric Analysis (TGA) after extraction and preparation. Viscosity tests were performed at different shear rates and the effects of polymer concentration, polymer hydration time, temperature and salinity on the viscosity of the polymeric solutions were investigated. Finally, a polymeric slug containing the polymer, an anionic surfactant at the critical concentration of micelle (CMC) and NaOH alkali at the optimum concentration was injected into a sandstone plug to calculate the oil recovery rate by the Alkali-Surfactant-Polymer (ASP) slug injection process. The novelty of this research is the introduction and use of a new, affordable and inexpensive polymer for use in ASP-slug injection into sandstone reservoirs, which can solve many of the challenges in this method. Based on the results, TGA analysis confirms the stability of the polymer at reservoir temperatures. Decreased viscosity versus increased shear rate shows non-Newtonian behavior of the polymeric solutions. The viscosity values of the polymeric solutions are several tens of times more than the surfactant solutions viscosities even at the low concentrations. Therefore, the polymer can be considered suitable for use in the ASP-slug injection process. The viscosity of polymeric solutions decreases with increasing temperature and salinity. However, the final values are not low enough to counteract the polymer effect. Finally, an increase in oil recovery of 27.9% is achieved under the ASP slug injection process containing an anionic surfactant synthesized from waste chicken fat at CMC, NaOH alkali at 2500 ppm and the polymer extracted from Hollyhocks at 2000 ppm. At last, it should be mentioned that the main purpose of this study was to introduce a new polymer for EOR process by injecting ASP slug. However, its application does not lead to this only. Polymers are used in various oil and gas industries. Due to the properties and behavior of the polymer solution, it can be used to reduce water production from oil reservoirs, improve the properties of drilling fluids and inject it with other additives to increase oil recovery.

An experimental investigation of the proportion of mortar components on physical and geomechanical characteristics of unconsolidated artificial reservoir sandstones

Physical properties of sedimentary rocks such as porosity, permeability, bulk density, and compression-tensile strengths are directly related to the features corresponding to the rock texture. The main characteristics of rock structure are principally grain size distribution, degree of sorting, type and amount of the cement located between the discrete particles in rock framework. In this study, three different types of sandstone core samples have been artificially prepared. From each type, two specimens were used to evaluate the physical properties and tests reliability. The samples utilized here represent two different grain sizes distribution with three different textural compositions. The results indicate that the grain size distribution and water-cement ratio (WCR) have considerable effects on the physical properties of artificial sandstone plugs. According to the experimental outcomes, an increment of cement content of 15% in mortar composition would lead to 9% rock porosity reduction. Less surface area in rock structure means lower rock volume unit indicating higher rock sample density. It was observed that there is a direct proportion between rock porosity and permeability. However, the functionality of rock permeability to cement content and consequently WCR is more intensive than the porosity. In this regard, results reveal that there is a critical point of WCR above which the rock permeability shows a sharp enhancement. The outcomes also indicated that the increase of cement content would result in higher uniaxial compression strength (UCS) of the core specimens as an increase in cement content of 50% would result in three times more UCS. Besides, the functionality of UCS and cement content and rock porosity have been investigated.

Laboratory core investigations of sandstone-hosted uranium for in situ recovery

ABSTRACTSeveral core plugs from a 1243 m-deep borehole penetrating the Westwater Canyon Member of the Morrison Formation in New Mexico (USA) have been investigated by various petrophysical methods to evaluate the potential of extracting deeply buried sandstone-hosted uranium deposits by in situ recovery (ISR). Petrophysics and mineralization patterns of the host rock in the target aquifer are crucial parameters for ISR amenability and were determined according to the ISR feasibility criteria. Mineralogical investigations revealed a secondary uranium mineralization mainly coating the silica grains of the arkosic sandstone and some interstitial pore fillings. The differences between mineralized and non-mineralized sandstone plugs are highlighted by nuclear magnetic resonance (NMR), X-ray microcomputed tomography, and spectral induced polarization (SIP). The NMR results show a doubling of the clay- and capillary-bound water and a decease of free-fluid porosity of mineralized samples. A correlation of mineralization grade and polarization is observed through the SIP investigations.

Transport properties of saline CO2 storage reservoirs with unconnected fractures from brine-CO2 flow-through tests

CO2 storage in fractured reservoirs may lead to fast CO2 flow through interconnected fracture networks; but the role of isolated fractures on brine-CO2 multiphase flow systems remains unclear. We present the results of a brine-CO2 flow-through experiment in which we assess the change in transport properties of a synthetic sandstone plug (a surrogate of a saline siliciclastic CO2 reservoir) containing non-connected fractures aligned 45° from its axis. The test was performed at 40 MPa of constant hydrostatic confining pressure and ~11 MPa of pore pressure, at room temperature (~19.5 °C), using pure liquid-CO2 and 35 g L−1 NaCl salt solution. The injected CO2-brine volume fraction was increased from 0 to 1 in 0.2 units-steps (drainage). Upon achievement of the maximum CO2 saturation (SCO2 ~0.6), the plug was flushed-back with the original brine (imbibition). During the test, we monitored simultaneously pore pressure, temperature, axial and radial strains, and bulk electrical resistivity. The fractured sample showed lower values of cross- and end-points in the relative permeability curves to CO2 compared to non-fractured samples, from comparable experiments performed at similar pressure and brine salinity conditions, but different temperature. Our results suggest that a non-connected fracture network affects the mobility of the individual phases, favouring the trapping of CO2 in the porous medium and improving the storage efficiency of the reservoir. These evidences show the need of a better understanding of fracture connectivity prior to discard fractured reservoirs as unsuitable geological formations for CO2 storage.

Image analytical sandstone plug poro-perm prediction using angle measure technique (AMT) and chemometrics – A feasibility study

This feasibility study evaluates an approach for prediction of sandstone plug porosity and permeability based on low-angle illumination imaging, the Angle Measure Technique (AMT) and chemometric multivariate calibration/validation. The AMT approach transforms 2-D texture images of drill core plug ends into 1-D ‘complexity spectra’ in which inherent porosity- and permeability-correlated features are subsequently extracted and subjected to multivariate calibration modelling. A training data set was selected because of its wide-spanning porosity and permeability ranges allowing evaluation of realistic prediction performance for typical North Sea/Scandinavian sandstone oil/gas reservoir rocks. This first study makes use of sand stone plugs from a single drill core from the Danish underground. Contingent upon proper test set validation (deliberately not deleting a few small, potential outliers), prediction performance assessment were for porosity [%] slope: 0.86; RMSEP: 2.2%; R2 = 0.90 and for permeability [mDarcy]: slope: 0.91; RMSEP: 458 mDarcy; R2 = 0.87, which translates into RMSEPrel of 12% and 19% respectively. These results pertain to a typical, well-spanning training data set (18 sandstone plugs); it is therefore concluded that the AMT approach to poro-perm prediction from images is feasible, but further, extended calibrations must be based on a more comprehensive training data sets covering the full geological regime of reservoir sandstones. We discuss possible application potentials and limitations of this approach.

Experimental investigation of injection pressure effects on fault reactivation for CO2 storage

Laboratory tests were conducted in a triaxial load frame with acoustic emission and transmission capability to investigate mechanisms that might be initiating the microseismicity experienced in CO2 injection operations. Although often related to reactivation of mapped faults or local fracturing due to reduced injectivity, the case of the Illinois Basin – Decatur Project is used here to illustrate the need for better understanding of what triggers microseismic events in relatively large permeability, good reservoir candidates. There, microseismicity has occurred in the CO2 storage target formation, the Mt. Simon sandstone, as well as in the underlying Precambrian basement. The microseismicity in the Mt. Simon sandstone occurred ahead of CO2 plume arrival and at relatively low injection pressure conditions, well below the fracturing pressure at the injection well. A hypothesis is suggested for the occurrence of such events in the field, whereby critically stressed planes are activated by the passage of the pressure front at injection start; these faults are small and thus not visible in the seismic survey. In order to test this hypothesis, sandstone plugs were prepared by two different methods to incorporate a fracture plane, which we attempted to reactivate by pore pressure pulses. The reactivation was successful at low pressure for a fracture created in the laboratory at reservoir conditions but was unsuccessful except at a much higher pore pressure in a saw-cut artificial fracture. The results suggest that tortuous, rough stress-induced fractures may be easier to reactivate because of the higher probability that sections are already favorably oriented with respect to critical shear stress at a low pore pressure increase. Saw-cut fractures may close completely under isotropic stress loading and may be difficult to activate unless exactly oriented with respect to critical shear stress at a low pore pressure increase. Acoustic emission accompanying fracture reactivation was also recorded and analyzed. This revealed a different event distribution energy between creating and reactivating the fracture.

Application of Ultrasound Wave for Stimulation of Asphaltene Damaged Reservoir Rocks: An Experimental Study

In this study, application of ultrasound wave for permeability enhancement of reservoir rocks was experimentally examined. In this regards, a specific core holder apparatus was designed with the ability of in-situ exposure of ultrasound to the plug at high-pressure condition, which is a better representative of ultrasound application in real wellbores. The effect of ultrasound power and exposure time as well as probe-plug distance on permeability stimulation was evaluated. The results showed that ultrasound could stimulate the permeability of asphaltene-damaged rocks, in which its efficiency is significant in sandstone rock. Analysis of asphaltene content in the output fluid showed that, as the result of ultrasound exposure, 84% of deposited asphaltenes in the sandstone plug was removed, which is corresponding to 67% of permeability recovery. It was also found that the stimulated permeability increases with increasing exposure time and power while decreases with increasing probe-plug distance, however an optimum value for exposure time and power, after which the permeability recovery is not significantly enhanced, was observed. Analysis of experiments also showed that probe-plug distance has the most prominent effect on recovery of damaged permeability in comparison to ultrasound time and power.

Permeability Evolution in Sandstone Due to CO2 Injection

Permeability variation is one of the key factors influencing the injectivity of CO2 in CO2 sequestration projects. Despite the research carried out on the subject, the results are highly inconsistent. In this study, the injection of brine (5 wt % NaCl + 1 wt % KCl), CO2-saturated (live) brine, and supercritical CO2 was performed on three homogeneous Berea sandstone plugs with a low clay content and two Bandera Gray sandstone plugs with a high clay content at reservoir conditions (10 MPa and 323 K). Porosity and permeability of the samples were measured using nuclear magnetic resonance (T2 relaxation time), and a dynamic (during flooding) permeability measurement technique, respectively, at different injection rates and injection durations. The mercury intrusion test was also performed on each sample to further evaluate its pore throat size distributions. From the results of this study, it was revealed that the CO2 injection rate is unlikely to affect the permeability significantly. It was also shown that ...

Capillary trapping quantification in sandstones using NMR relaxometry

AbstractCapillary trapping of a non‐wetting phase arising from two‐phase immiscible flow in sedimentary rocks is critical to many geoscience scenarios, including oil and gas recovery, aquifer recharge and, with increasing interest, carbon sequestration. Here we demonstrate the successful use of low field 1H Nuclear Magnetic Resonance [NMR] to quantify capillary trapping; specifically we use transverse relaxation time [T2] time measurements to measure both residual water [wetting phase] content and the surface‐to‐volume ratio distribution (which is proportional to pore size] of the void space occupied by this residual water. Critically we systematically confirm this relationship between T2 and pore size by quantifying inter‐pore magnetic field gradients due to magnetic susceptibility contrast, and demonstrate that our measurements at all water saturations are unaffected. Diffusion in such field gradients can potentially severely distort the T2‐pore size relationship, rendering it unusable. Measurements are performed for nitrogen injection into a range of water‐saturated sandstone plugs at reservoir conditions. Consistent with a water‐wet system, water was preferentially displaced from larger pores while relatively little change was observed in the water occupying smaller pore spaces. The impact of cyclic wetting/non‐wetting fluid injection was explored and indicated that such a regime increased non‐wetting trapping efficiency by the sequential occupation of the most available larger pores by nitrogen. Finally the replacement of nitrogen by CO2 was considered; this revealed that dissolution of paramagnetic minerals from the sandstone caused by its exposure to carbonic acid reduced the in situ bulk fluid T2 relaxation time on a timescale comparable to our core flooding experiments. The implications of this for the T2‐pore size relationship are discussed.

Diagenetic alterations and reservoir heterogeneity within the depositional facies: A case study from distributary-channel belt sandstone of Upper Triassic Yanchang Formation reservoirs (Ordos Basin, China)

Diagenesis is of decisive significance for the reservoir heterogeneity of most clastic reservoirs. Linking the distribution of diagenetic processes to the depositional facies and sequence stratigraphy has in recent years been discipline for predicting the distribution of diagenetic alterations and reservoir heterogeneity of clastic reservoirs. This study constructs a model of distribution of diagenetic alterations and reservoir heterogeneity within the depositional facies by linking diagenesis to lithofacies, sandstone architecture and porewater chemistry during burial. This would help to promote better understanding of the distribution of reservoir quality evolution and the intense heterogeneity of reservoirs. Based on an analogue of deltaic distributary channel belt sandstone in Upper Triassic Yanchang Formation, 83 sandstone plug samples were taken from 13 wells located along this channel belt. An integration of scanning electron microscopy, thin sections, electron microprobe analyses, rate-controlled porosimetry (RCP), gas-flow measurements of porosity and permeability, and nuclear magnetic resonance (NMR) experiments, together with published data, were analysed for the distribution, mineralogical and geochemical characteristics of detrital and diagenetic components and the distribution of reservoir quality within the distributary channel belt.Distribution of diagenetic alterations and reservoir heterogeneity within the distributary channel belt sandstones include (i) formation of high quality chlorite rims in the middle part of thick sandstones with coarser grain sizes and a lower content of ductile components resulted from the greater compaction resistance of these sandstones (providing larger pore spaces for chlorite growth), leading to formation of the intergranular pore – wide sheet-like throat and intergranular pore - intragranular pore – wide sheet-like throat (Φ>15%, k>1mD) in the middle part of thick sandstones; (ii) formation of thinner chlorite rims in the middle part of thinner sandstones is associated with the intergranular pore - intragranular pore – narrow sheet-like throat (9%<Φ<14%, 0.2mD<k<0.8mD); (iii) strong cementation by kaolinite in the more proximal sandstones of distributary channel owing to the strong feldspar dissolution by meteoric water, resulting in the intragranular pore - group of interstitial cement pores – narrow sheet-like throat/extremely narrow sheet-like throat (8%<Φ<11%, 0.1mD<k<0.3mD) due to the pore-filling kaolinite occluding porosity; (iv) formation of dense ferrocalcite zones (δ18OVPDB = −23.4‰ to −16.6‰; δ13 CVPDB = −4.0‰ to −2.3‰) favoured in the top and bottom of the channel sandstone which near the sandstone-mudstone bouding-surface, destroying pore space (Φ<8%, k<0.1mD); (v) strong compaction in sandstone of distributary channel edge laterally as a result of fine grain size and high content of ductile components in those sandstones, forming the group of interstitial cement pores – extremely narrow sheet-like throat with porosity values less than 8%.

Numerical modelling of microwave heating treatment for tight gas sand reservoirs

Formation Heat Treatment (FHT) has been proved effective in removing water phase and creating micro-fractures in the near wellbore area previously. In order to improve the cost and time efficiency of FHT, microwave heater is considered as an alternative in this paper, and its feasibility in FHT is discussed in this paper. Numerical simulation is carried out to investigate the effects of microwave heating on reservoir quality and gas production. It is found that the water phase can be effectively removed by microwave heating, as a result, the relative permeability to gas increased significantly after heating. In terms of gas production rate, the cumulative gas in 90 days in heated well is 4×105 m3 more than the non-heated well. As the most important parameter, the temperature distributions in the reservoir are computed with two methods and their value against the heating depth agree with each other reasonably. On the other hand, the surface temperature variations of tlhree tight sandstone plugs are heated with microwave in the lab and their surface temperatures are carefully recorded against time. Then the laboratory data are compared with simulation results, and they correlate well with each other. The simulation work conducted in this paper shows the promising improvement of gas relative permeability and production by microwave heating.

A Multi-Scale Investigation of Pore Structure Impact on the Mobilization of Trapped Oil by Surfactant Injection

The evolution of the residual oil saturation as a function of the trapping number $$N_\mathrm{t}$$ (capillary number plus Bond number), is generally known as the capillary desaturation curve (CDC) and constitutes an important input parameter in chemical enhanced oil recovery flooding. However, less importance has been paid to the investigation of the influence of oil ganglia evacuation on relative permeabilities. We report on an experimental investigation dealing with the effect of flooding parameters, fluid interfacial properties and rock structure on the CDC and on the water relative permeability. Experiments were performed on a set of water-wet sandstone plugs with different petrophysical properties, and X-ray computed tomography (CT-scan) imaging was used to accurately measure the local oil saturation. Oil ganglia size distribution as well as pore scale geometrical properties was also quantified at the scale of the micrometer using high-resolution micro-computed tomography (MCT). Results showed that the CDC depends on the pore structure and specifically on the average throat radius and the inverse of the relative permeability. Oil ganglia size distribution obtained by MCT follows a typical power law as suggested by percolation theory. We also showed that CDC obtained from macroscopic measurements can be predicted from the measured oil ganglia size distribution and rock structure geometrical parameters. In parallel, we observed that for low trapping numbers, water relative permeability is independent of the trapping number. However, for intermediate trapping numbers, a strong dependence of the water relative permeability on the latter can be noticed. In this range, we showed that water relative permeability has a specific scaling with the trapping number.

Interfacial Tension and Wettability Change Phenomena during Alkali–Surfactant Interactions with Acidic Heavy Crude Oil

In this work, a newly formulated sulfonate-based surfactant and two other commercial sulfate-based surfactants with the capability of tolerating harsh underground reservoir conditions, such as high-saline formation water and high temperature, were prepared. Sodium metaborate as an effective alkali compound was also used to provide alkali–surfactant combination. Interfacial tension (IFT) measurements as well as wettability examinations for different salinities and mixture conditions were performed for an extended range of the chemical concentrations. The wettability tests including both contact angle measurements and Amott cell tests were performed on saturated Berea sandstone plug samples and rock slices, while the precise spinning drop technique was used for IFT measurements. The mixtures of both surfactant groups and alkali resulted in a minimum IFT value required to attain an optimum three-phase region at high-salinity conditions. The addition of the alkali to the surfactant solution reduced the lowest IFT value to less than 0.005 mN/m in the solutions containing 0.5 wt % alkali and 0.2 wt % of each surfactant. The synergistic effect of the surfactants and in-situ-generated soap as the result of the injected alkali reaction with the carboxylic compounds of the crude oil provided promising results for microemulsion generation in the solution; however, with special composition of the sulfonate-based surfactant, the acquired optimum solution salinity was reduced. Although both contact angle and Amott cell tests were performed to assess the wettability changes, the results indicated that the contact angle technique was not reliable enough when the solution contains highly reactive materials. Both of the surfactant groups were able to reduce the oil-wetness of the core plugs; however, mixtures of the sulfonate-based surfactant and sodium metaborate improved the spontaneous oil recovery efficiency from core plugs during imbibition and drainage processes.

Evaluation of pH‐sensitive hydrogels to control the permeability anisotropy of oil reservoirs

ABSTRACTIn stratified or fractured oil reservoirs, the oil recovery efficiency tends to be low as the injected fluid flows mainly through the matrix's most permeable regions, leaving behind part of the displaceable oil in the matrix's unswept zones. Given this issue, this study aims to evaluate the potential of applying seven commercial samples, based on poly(acrylic acid), to control the anisotropic permeability profile of reservoirs. To perform this study, first, continuous and oscillatory shear tests were conducted to characterize the hydrogel's rheological and viscoelastic behavior in various subsurface conditions (salinity, temperature, and/or pH value). Second, polymer dispersion elution tests were performed in a porous medium to evaluate the matrix's permeability reduction after treatment with hydrogels. The seven commercial samples were classified as pseudoplastic fluids at pH values ranging from 1 to 10. Under typical reservoir conditions, PAAr 70 (which has intermediate molar mass and intermediate number of crosslinks) was the only sample to behave as a strong gel (G′/G″ &gt; 10). Elution tests confirmed that the PAAr 70 hydrogel gelified inside the consolidated sandstone plugs and reduced the matrix's permeability four‐fold. Therefore, samples based on poly(acrylic acid) with high crosslink density proved to be the most promising for controlling the anisotropic permeability profile of heterogeneous oil reservoirs. © 2014 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2014, 131, 40665.

Acoustic Response of Reservoir Sandstones during Injection of Supercritical CO2

We report experimental results for acoustic response measurements conducted during injection of supercritical carbon dioxide into a brine saturated sandstone plug. We measured P- and S-wave velocities (Vp, Vs) as a function of effective stress and CO2 saturation in a sandstone plug. We demonstrate that Gassmann's fluid substitution procedure matches the experimental results well for this sample. A 3.5% reduction of P-wave velocity after injection of two pore volumes of CO2 into brine-saturated sample was measured. We conclude that measurement of Vp can be used to estimate CO2 saturations in rock. In addition, x-ray computer tomography (CT) images were acquired at reservoir conditions with a resolution of 33 μm, which provided more detailed information about CO2 saturations and distributions in the rock. It is envisaged that these techniques (seismic and CT) can be combined in the future to enable a more holistic understanding of how fluid-fluid displacement processes are coupled with the acoustic response characteristics of the rock.