Water-saturated Core Research Articles

High strain rate deformation of porous sandstone and the asymmetry of earthquake damage in shallow fault zones

In contrast to coseismic pulverization of crystalline rocks, observations of coseismic pulverization in porous sedimentary rocks in fault damage zones are scarce. Also, juxtaposition of stiff crystalline rocks and compliant porous rocks across a fault often yields an asymmetric damage zone geometry, with less damage in the more compliant side. In this study, we argue that such asymmetry near the sub-surface may occur because of a different response of lithology to similar transient loading conditions. Uniaxial unconfined high strain rate loadings with a split Hopkinson pressure bar were performed on dry and water saturated Rothbach sandstone core samples. Bedding anisotropy was taken into account by coring the samples parallel and perpendicular to the bedding. The results show that pervasive pulverization below the grain scale, such as observed in crystalline rock, does not occur in the sandstone samples for the explored strain rate range (60–150 s−1). Damage is mainly restricted to the scale of the grains, with intragranular deformation occurring only in weaker regions where compaction bands are formed. The presence of water and the bedding anisotropy mitigates the formation of compaction bands and motivates intergranular dilatation. The competition between inter- and intragranular damage during dynamic loading is explained with the geometric parameters of the rock in combination with two classic micromechanical models: the Hertzian contact model and the pore-emanated crack model. In conclusion, the observed microstructures can form in both quasi-static and dynamic loading regimes. Therefore caution is advised when interpreting the mechanism responsible for near-fault damage in sedimentary rock near the surface. Moreover, the results suggest that different responses of lithology to transient loading are responsible for sub-surface damage zone asymmetry.

Quantitative evaluation of the heterogeneity for tight sand based on the nuclear magnetic resonance imaging

Tight sand exhibits high degree of heterogeneity due to the complex pore structure. It is vital to evaluate the heterogeneity since it controls the fluid storage and transportation mechanisms, as well as geophysical responses. A novel method is put forward to quantify the heterogeneity based on the magnetic resonance imaging (MRI) experiments and the variogram analysis. Images of weight transversal relaxation times of fully water saturated core samples are acquired based on the spin echo sequence, slice-selecting pulse, frequency-coding pulse and phase-coding pulse and two dimensional discrete fast Fourier transform (2D-FFT). In addition, variogram function of the first order spherical model and the genetic algorithm are implemented to characterize the heterogeneity of pore distributions along vertical and horizontal directions. Furthermore, relationships between the average heterogeneity index and the tortuosity, and the mercury withdrawal efficiency, are also investigated to reveal the physical meaning of the heterogeneity index we presented. The result shows that the average heterogeneity index is positively correlated with the tortuosity index and negatively correlated with the mercury withdrawal efficiency. Our study provides an effective way to investigate the spatial heterogeneity of pore space, which serves as an important source of information for core analysis and formation evaluation.

An experimental study on the rate and mechanism of capillary rise in sandstone

The Lucas-Washburn equation is a fundamental expression used to describe capillary rise in geologic media on the basis of pore radius, liquid viscosity, surface tension, contact angle, and time. It is known that a radius value significantly smaller than the main pore radius must be used in the equation in order for the predictions to fit the experimentally measured values. To evaluate this gap between theoretical predictions and experimental data, we conducted several capillary rise experiments using Berea sandstone. First, to investigate conditions in which pores of any size are available for capillary rise, an experiment was conducted using a dried core. Next, to adjust the size distribution of pore water before the capillary rise, gas pressure was applied to a water-saturated core and water was expelled from pores of r > 10 μm; then, capillary rise was initiated. Under this condition, capillary rise occurred only in the pores of r > 10 μm. The same experiment was conducted for r = 3, 1, and 0.36 μm. When narrower pores were made available for capillary rise, the overall rate of rise decreased and approached the rate observed when the sample was dry initially. This observation suggests that the capillary rise in narrow pores plays a significant role in the overall rate. Based on these results, we propose a conceptual capillary rise model that considers differing radii in branched pores and provide an example of a quantitative description of capillary rise.

Coal seam porosity and fracture heterogeneity of macrolithotypes in the Hancheng Block, eastern margin, Ordos Basin, China

Heterogeneity in cleats and pore size distribution within coal macrolithotypes (bright, semi-bright, semi-dull, and dull coals, determined from the overall relative luster and percentage of bright components) impact coalbed methane (CBM) extraction. However, few studies have investigated the characteristics of macrolithotypes across multiple length scales. Here, the macrolithotype description was performed for the No. 3, 5, and 11 coal seams in the Hancheng Block of Ordos Basin. The cleats were characterized by optical microscopy and X-ray computed tomography (CT) while pores and their connectivity were determined from mercury intrusion porosimetry, N2 and CO2 adsorption, and low field nuclear magnetic resonance (NMR) of water saturated cores evaluated both cleats and pores. The CH4 adsorption capacity of coal samples scraped from the surface of the macrolithotype layers was also determined. Dull lithotypes (semi-dull and dull) were dominant, followed by bright lithotypes (bright and semi-bright) in these seams. The bright lithotype coal has a higher microfracture density (averaging 339 microcleats per 9cm2, μm–mm), better connectivity, and a larger fractal dimension (averaging 1.7) from optical microscopy. The dull lithotype has a lower average microfracture density (272 microcleats per 9cm2) and a smaller fractal dimension (~1.6). This higher connectivity observation was consistent with X-ray CT observations and low field NMR of the water saturated cores (and the transition upon water removal from the fractures and larger pores). Also the ease of mercury injection from cores also supported higher connectivity in the bright lithotypes. Both the semi-bright and semi-dull lithotypes have equivalent pore proportions micro- to macropores and good apparent connectivity at the nm–μm scale; despite mineral occlusions. Based on the CH4 adsorption capacities of the macrolithotypes, the bright coal has the greatest gas adsorption capacity, due to the largest smaller micropores (<2nm) and a higher specific surface area. These observations aid in understanding the complex behavior observed in CBM extraction and evaluating the impacts of heterogeneity and scale on the degassing behavior.

SUBSTANTIATION OF SELECTIVITY OF GEL-FORMING COMPOSITION DURING WATER-SHUT TREATMENT IN RESERVOIR OF FRACTURED-POROUS TYPE

The article is devoted to one of the main problems of oil production industry – high level of watering. Several methods of water control are investigated, but the accent is made on selective methods and materials, that increase filtration resistance in water-saturated part of a layer. Water shutoff agent based on sodium silicate is developed for selective restraining of water inflow in fractured-porous reservoir. Laboratory research of the developed gelling agent helped to establish interdependence of gel strength and period of gellation between agent concentration and temperature. It is revealed, that addition of polyatomic spirit in water shutoff agent leads to the increase of hydrophilicity if related to water-saturated rock and decrease of hydrophilicity if related to oil-saturated rock. Furthermore, high wettability of the waterproof agent in relation to water-saturated rock in comparison with oil-saturated rock proves the selective characteristic of the developed agent – when the plugging material gets to the water-saturated part it makes firm insulating barrier due to better contact with rock. Besides the change of wettability the addition of polyatomic spirit in water shutoff agent improves operational characteristic of developed plugging material in account of increasing of interionic forces and expands the exploitation temperature range. The filtration tests proved the effective influence of inorganic gel on core sample of fractured porous reservoir from the eastern part of Orenburg oil-gas-condensate field. Also, permeability of water-saturated core samples decreases better than of oil-saturated ones. This fact proves the selectivity of the developed agent.

New Insight into Wettability Alteration to Gas Wetness: Core Experiment and Modeling

Many attentions have been paid on wettability alteration to gas wetness since it is widely concerned in 2000. Although many researchers tried to explain or realize such phenomenon, several problems have not been resolved now including possibility and mechanism of wettability alteration in water saturated cores. In this study, new insight is made into wettability alteration to gas wetness, both experimental and simulate. A serial of spontaneous water imbibition experiments are conducted to evaluate applicability of wattability alteration in different water saturated cores. SEM observation indicates microcosmic mechanism by compare of pore surface before and after chemical treatment. Numerical simulation in Eclipse gives theoretical evidence of wettability alteration phenomenon and also proves almost the same result with that in spontaneous water imbibition experiments.

An Experimental Investigation of Water-alternating-CO2 Coreflooding in a Carbonate Oil Reservoir in Different Initial Core Conditions

Due to the lack of any significant primary recovery mechanism in one of the Iranian oil reservoirs, enhanced oil recovery methods are considered for early stage application because it has been depleted rapidly about 200 Psig by primary recovery. Therefore, the objective of this study was to experimentally investigate the performance of water alternating gas injection of this field. Core samples were drilled out of reservoirs' rock matrix and were cut approximately 11–15 cm long and 3.28 cm in diameter. The live oil used in the experiments has been made by recombination of the stock tank oil with a synthetic gas mixture. All coreflood experiments were conducted using live (recombined) oil at 1,700 psig and a reservoir temperature of 115°F. A total number of four displacement experiments were performed on the cores, including two experiments on secondary wag alternation gas injection and others on tertiary water and gas invaded zones wag alternation gas injections. Prior to each test porosity and permeability of dried core were calculated then 100% water-saturated core was oil flooded to obtain connate water saturation. Therefore, all coreflooding tests started with the samples at irreducible water saturation. These experiments showed that there was significant improvement in the oil recovery for alternating injection of water and CO2. Thus, this method could be suggested as one of the enhanced oil recovery methods for this field with consideration of the economical studies. This laboratory study investigates the potential effectiveness of wag alternation gas injection for recovering hydrocarbons from target reservoir as it would exist in one of these conditions: after naturally depleted as secondary recovery, after waterflooding and gasflooding as tertiary recovery. All of the experiments were conducted at 115°F and 1,700 psig, which represents a low-temperature and low-pressured reservoir with 5,000 ppm brine salinity. The most similar experimental work with the main reservoir condition indicated that approximately 64% oil was recovered after 1 pore volume of wag alternation gas process at 136,000 ppm brine salinity. Tertiary oil recovery efficiency resulting from wag alternation gas injection was significant, leading to final pore volume injected, 50 and 36 for gas and water invaded zones, respectively.

Petrophysical characterization of Chinese coal cores with heat treatment by nuclear magnetic resonance

For the past decades the nuclear magnetic resonance (NMR) technology has gained acceptance as a petrophysical tool for evaluating reservoir properties. Comprehensive reservoir evaluation requires determination of irreducible fluids, movable fluids and permeability. Although the NMR petrophysical properties of coals have been studied for decades, the impact of heat on these properties (pore size distribution, pore structures, porosity and permeability) has not yet been systematically investigated. However, these are key properties for coalbed methane (CBM) generation and production. Therefore, they may have significant implications for the effects of heat from geothermal dynamics and magma intrusion on CBM concentration and transport in coals with different ranks. Thus, NMR experiments for samples treated at different temperatures (from 25°C to 375°C) were designed to study the variation of petrophysical properties of three Chinese coal cores with different ranks. Results show that NMR transverse relaxation (T2) distributions of the water saturated cores strongly relate to the coal pore structure and coal rank. Furthermore, based on T2 cutoff time method, five models for calculating the permeability of coals to water were evaluated. The results show that the Schlumberger Doll Research (SDR) model and its improved model provided the best estimation among the five models because these two models are generally able to represent the matrix permeability of the coal, based on the comparison between the results from measured gas permeability and NMR permeability models. Further calculations indicate that the porosity of all three different rank coals have an increasing trend with exposure to temperature, but with different increments for these coals. The low-volatile bituminous coal has the largest increment (9.44%), which is an improvement of more than 200% from its original porosity (4.02%). While the permeability has no similar trend for these three rank coals after heat treatment due to the strong heterogeneity of pore structure in coals. The results may suggest complex microfractures widths change for forming/closing at different heating stages.

An Experimental Study on the Applicability of Water-alternating-CO2 Injection in the Secondary and Tertiary Recovery in One Iranian Reservoir

The objective of this study was to experimentally investigate the performance of water-alternating gas (WAG) injection in one of Iran's oil reservoirs that encountered a severe pressure drop in recent years. Because one of the most appropriate studies to evaluate the reservoir occurs generally on rock cores taken from the reservoir, core samples drilled out of the reservoir's rock matrix were used for alternating injection of water and gas. In the experiments, the fluid system consisted of reservoir dead oil, live oil, CO2, and synthetic brine; the porous media were a number of carbonate cores chosen from the oilfield from which the oil samples had been taken. All coreflood experiments were conducted using live (recombined) oil at 1,700 psi and reservoir temperature of 115°F. A total of four displacement experiments were performed in the core, including two experiments on secondary WAG injection and others on the tertiary water and gas invaded zones WAG injections. Prior to each test porosity and permeability of dried cores were calculated then 100% water-saturated cores were oil-flooded to obtain connate water saturation. Therefore, all coreflooding tests started with the samples at irreducible water saturation. Parameters such as oil recovery factor, water cut, and gas-oil ratio and production pressure of the core were recorded for each test. The most similar experimental work with the main reservoir condition, indicated that approximately 64% oil were recovered after 1 pore volume of WAG process at 136,000 ppm brine salinity. Although tests show ultimate recovery of 79% and 55% for secondary and tertiary injection in gas and water invaded zones, respectively, immiscible WAG injection efficiency in the gas and water invaded zones will not be proper. In the similar test to field properties, the average pressure difference about 70 Psig was observed, which shows stable front displacement. These experiments showed that there was significant improvement in the oil recovery for alternating injection of water and CO2, especially in the secondary recovery process. Water breakthrough time in almost all of the tests shows frontal displacement of injected fluid in cores and produced gas-oil ratio changes a little whenever the injection is miscible and increases rapidly in immiscible processes.

Probing pore characteristics of deformed chalk by NMR relaxation

1H Nuclear Magnetic Resonance (NMR) relaxation time was applied to investigate pores characteristic of chalk cores which were subjected to prior mechanical loading. The NMR relaxation responses of the cores loaded in elastic region (before yield) and in plastic region (after yield) were compared. T1,2 relaxation measurements performed on fully water saturated cores resolved a typical pore size corresponding to large pore body, which is affected by stress application particularly beyond the yield point. The 1/T1,2 relaxation rate also appeared to correlate with the volumetric strain. The NMR signal from the partially saturated cores (Sw<13%), however, showed no respectable change despite being loaded beyond the yield point. The T2 signal was dominated by two relaxation rates, which we argue corresponds to the surface water film (∼10nm) and micropores (∼0.1μm). The point that T1,2 NMR relaxation showed no significant change on partially saturated cores loaded beyond the yield point may indicate that the structure of water film remains unchanged despite progressive decay of pores structure during pore collapse failures.

Dissociation Behavior of Methane Hydrate in Sandy Porous Media below the Quadruple Point

To investigate the effect of ice formation on gas production from gas-hydrate-bearing sandy porous media, we conducted dissociation experiments using artificial methane hydrate cores by depressurizing them to below the quadruple point. We prepared water- and gas-saturated hydrate cores to evaluate the influence of water content on ice formation. The experiments showed that gas production under the ice formation regime had a unique high-rate period in the early stage of production, whereas under the water generation regime, the high-rate period was not observed. During ice formation, the gas production rates of the water-saturated cores exhibited greater acceleration than those of the gas-saturated cores. We conducted numerical simulations using the hydrate reservoir simulator MH21-HYDRES for quantitative analyses. The results showed that ice forms faster in a water-saturated core because of the availability of pore water for ice formation. This further enhances the gas production rate of a water-saturated core. Sensitivity analyses indicated that the rate of ice formation and the permeability reduction by ice formation are key model parameters affecting gas production behavior. From the experimental and numerical investigations, we conclude that depressurization-induced gas production can be accelerated by ice formation during hydrate dissociation at a pressure below the quadruple point.

An enhancement of the formation factor parameters ‘a’ and ‘m’

The use of incorrect values of the formation constants a, tortuosity factor,and m, cementation exponent, in Archie’s water saturation equation, can result in the overlooking of potential producible zones. Usually, assumptions are made to approximate a and m where often m is 2, while a may be 0.81 or 1.0, depending on the type of lithology. When core is available, accepted laboratory practices exist to calculate a and m, however, these laboratory steps are generally not considered routine analysis and, in order to save time and money, may not be conducted.Core analysis for a and m require saturating to 100% multiple plugs of varying porosity with water of known resistivity. The resistivity of each water saturated core is graphed on a log-log graph with porosity to determine a and m.This work illustrates a simple method of calculating a and m that is dependent on sonic transit time and bulk density, and on knowing one cementation exponent value from core measurements.The method is tested and applied on a large number of samples to ensure its ability to determine formation factor parameters a and m.

Thermal properties of rocks of the borehole Yaxcopoil-1 (Impact Crater Chicxulub, Mexico)

SUMMARY The results of thermal property measurements on cores from the scientific well Yaxcopoil-1 (1511 m in depth) drilled in the Chicxulub impact structure (Mexico) are described. The thermal conductivity, thermal diffusivity, volumetric heat capacity, thermal anisotropy coefficient, thermal heterogeneity factor, and, in addition, porosity and density were measured on 451 dry and water-saturated cores from the depth interval of 404–1511 m. The acoustic velocities were determined on a subgroup of representative samples. Significant vertical short- and long-scale variations of physical properties related to the grade of shock-thermal metamorphism and correlations between thermal and other physical properties are established. Rocks of the post-impact and impact complexes differ significantly in heterogeneity demonstrating that the impact complex has larger micro- heterogeneity on sample scale. The pre-impact rocks differ essentially from the impact and post-impact rocks in the thermal conductivity, thermal diffusivity, density and porosity. The thermal anisotropy of rocks of all structural-lithological complexes is very low (K = 1.02 … 1.08), which is similar to the situation in the Puchezh-Katunk and Ries impact structures. Correlations are established between the thermal conductivity and elastic wave velocities measured in laboratory. For limestone-calcarenites, the thermal conductivity (λ) can be calculated from the compressional wave velocity (Vp) using the formula λ= 0.346 Vp + 0.844, and for dolomite-anhydrites this relation has the form λ= 0.998 Vp + 1.163 [for λ in W (m K)−1 and Vp in km s−1]. These correlations are used for downscaling of the sonic velocities to the decimetre scale. The effective medium theory is applied to invert the matrix thermal conductivity and pore/crack geometry from the thermal conductivity measured on the studied samples. Representative experimental data on the thermal properties for all lithological groups encountered by the Yaxcopoil-1 well essentially extend an existing database on the thermal properties of rocks of impact structures and can be used for determination of the heat flow density, interpretation of temperature logging data, theoretical modelling of heat and mass transfer processes and constructing thermal models of the Chicxulub impact structure as well as for the lithological interpretation. The research results confirm the necessity of dense sampling for the thermal property measurements to obtain reliable results in petrophysical and geothermal investigations of impact structure formations.

Observations of fluid-dependent shear-wave splitting in synthetic porous rocks with aligned penny-shaped fractures‡

P- and S-wave velocity and attenuation coefficients (accurate to ±0.3% and ±0.2 dB/cm, respectively) were measured in synthetic porous rocks with aligned, penny-shaped fractures using the laboratory ultrasonic pulse-echo method. Shear-wave splitting was observed by rotating the S-wave transducer and noting the maximum and minimum velocities relative to the fracture direction. A block of synthetic porous rock of fracture density 0.0201 ± 0.0068 and fracture size 3.6 ± 0.38 mm (measured from image analysis of X-ray CT scans) was sub-sampled into three 20–30 mm long, 50 mm diameter core plugs oriented at 0°, 45° and 90° to the fracture normal (transversely isotropic symmetry axis). Full waveform data were collected over the frequency range 500–1000 kHz for both water and glycerin saturated cores to observe the effect of pore fluid viscosity at 1 cP and 100 cP, respectively. The shear-wave splitting observed in the 90° core was 2.15 ± 0.02% for water saturated and 2.39 ± 0.02% for glycerin saturated, in agreement with the theory that suggests that the percentage splitting should be 100 times the fracture density and independent of the saturating fluid. In the 45° core, by contrast, splitting was 0.00 ± 0.02% for water saturation and −0.77 ± 0.02% for glycerin saturation. This dependence on fracture orientation and pore fluid viscosity is consistent with the poro-visco-elastic theory for aligned, meso-scale fractures in porous rocks. The results suggest the possible use of shear- or converted-wave data to discriminate between fluids on the basis of viscosity variations.

Analysis of the Effect of Residual Oil on Particle Trapping During Produced-Water Reinjection Using X-Ray Tomography

Summary Recently, it has been shown that the presence of residual oil in a formation can have a considerable influence on the trapping mechanisms for particles present in reinjected produced water (Ali 2007; Ali et al. 2005, 2007, 2009). This article reports on a further set of extensive coreflow experiments that confirm and extend these results. The tests were conducted in a computerized-tomography (CT) scanner, allowing direct observation of the buildup of particle deposition along the core. These experiments are relevant to operational issues associated with produced-water reinjection (PWRI). In many cases, produced water is injected into formations containing oil, so reduced oil saturation is achieved rapidly in the area around the well. Even if the well is outside the oil zone, trapped oil droplets are always present in produced water, and a residual-oil zone will gradually build up around the well. Major differences are found between the deposition profiles for fully water-saturated cores and the cores having residual-oil saturation. In particular, particles penetrate deeper into the core with residual-oil saturation, and considerably more particles pass completely through the core without being trapped. The X-ray technique allows direct observation during the experiment of the deposition process inside the core, eliminating the complicating effect of any external filter cake. As a result, an analysis can be performed of the deposition parameters relevant inside the core using deep-bed-filtration theory, and the results of this analysis are presented. In particular, it is shown that the values of the filtration function determined from the CT-scan (X-ray) data are consistent with those obtained from analysis of the effluent concentration. Moreover, both methods of analysis find quite clearly that the filtration coefficient increases with decreasing flow rate. The results indicate that formation damage near a wellbore during water injection will be reduced by the presence of residual oil, and that particles will penetrate deeper into the formation. The result is also relevant to injection under fracturing conditions because particle deposition in the wall of the fracture (where residual oil may be present) is one of the mechanisms governing fracture growth.

Raman mapping and numerical simulation of calcium carbonates distribution in experimentally carbonated Portland-cement cores

The spatial distribution of CaCO 3 polymorphs formed during the experimental carbonation of water saturated Portland-cement cores (30 mm in diameter), with supercritical CO 2 at 90 °C and 30 MPa, has been investigated using Raman microspectrometry on polished sample sections and X-ray microdiffraction. The three calcium carbonate polymorphs (calcite, aragonite and vaterite) were clearly distinguished using both techniques and their distribution along the main CO 2 diffusion direction could be mapped at the millimetre scale using a dynamic line-scanning Raman mapping tool. The calcium carbonate 2D distribution clearly shows that vaterite, the least stable of the three CaCO 3 polymorphs, is mostly located in a 500 μm wide ring ahead of the carbonation zone. This feature indicates that vaterite is the first CaCO 3 polymorph to crystallize within the cement sample in the course of the carbonation process. The presence of a vaterite front indicates that local mineral-solution equilibration can be slower than species transport, even above ambient conditions, and that kinetics cannot be ignored in the cement carbonation process. By using calcite and vaterite precipitation kinetic data from the literature and assuming water-mineral kinetics based on the Transition State Theory, the vaterite front inferred from Raman mapping is reproduced with a purely diffusive 1D transport code.

A rapid measurement of [formula omitted]: The DECPMG sequence

The Driven-Equilibrium Carr–Purcell Meiboom–Gill (DECPMG) pulse sequence is a rapid method for obtaining the average ratio of longitudinal to transverse relaxation times 〈 T 1 / T 2 〉 as a function of T 2 . Since this is a one-dimensional experiment, the 〈 T 1 / T 2 〉 T 2 ratio can be acquired, potentially, in just two scans; the second scan being a reference CPMG measurement. Conventionally, T 1 / T 2 is determined from a two-dimensional T 1 - T 2 relaxation correlation experiment. The method described here offers a significant reduction in experimental time without a reduction in signal-to-noise. The 〈 T 1 / T 2 〉 ratio is useful for comparing the behaviour of liquids in porous media. Here we demonstrate the application of the DECPMG sequence to the study of oil-bearing rocks by differentiating oil or water saturated rock cores, and by observing the relative strengths of surface interaction for water in two types of rock by measuring 〈 T 1 / T 2 〉 as a function of magnetic field strength.

Retention of CO2-Foaming Agents on Chalk: Effects of Surfactant Structure, Temperature, and Residual-Oil Saturation

Summary Injection of carbon dioxide (CO2) is a well-known enhanced-oil-recovery (EOR) technique. Formation of stable foam inside the reservoir can improve macroscopic sweep efficiency. On the other hand, retention of surfactants decreases the cost-efficiency of the EOR process. This paper presents flow-through retention experiments with CO2-foaming agents on outcrop Liege chalk plugs at two different temperatures: 55 and 70°C. Two branched ethoxylated (EO) sulfonates with different ethoxylation degree, S1 (EO = 7) and S2 (EO = 12), were used. The aim was to investigate the effect of ethoxylation degree on surfactant retention. Furthermore, the effects of temperature and residual oil on surfactant retention were studied. The effect of waterflooding followed by CO2 flooding on surfactant retention at reservoir conditions was also examined. Partitioning of the foaming agents between water and oil phases was studied. Results show that increasing the ethoxylation degree of the surfactant decreases the retention on chalk cores saturated with formation water at 55°C. S2, which was found to give the lowest retention at 55°C, was found to have a higher retention at 70°C. The presence of residual-oil saturation after waterflooding (Sorw) decreased the retention of S1 and increased the retention of S2 in comparison to the absence of residual oil. The retention of S2 after waterflooding followed by CO2 flooding at 340 bar and 55°C was in the same range as retention on 100%-water-saturated core, but significantly lower than retention in residual-oil-saturated cores. The experiments have shown that not only are surfactant structure and temperature important for the retention of surfactants, but also the presence of oil.

Computed tomography scan imaging of natural open fractures in a porous rock; geometry and fluid flow

ABSTRACTComputed tomography scan imaging techniques have been used on core samples to investigate the effect of natural open fractures on reservoir flow in the Snøhvit Gas Condensate Field. Firstly, computed tomography (CT) scanning was used to describe the 3D geometrical properties of the fracture network including orientation and fracture density. Two types of fractures were observed: F1 fractures are short and stylolite related and F2 fractures are longer, cross‐cutting the core and without any obvious relationship to stylolites. Secondly, monitoring of single and two phase flow experiments on samples containing these two types of natural open fractures was performed under 10 and 80 bar net confining pressure while using CT scanning. 1‐phase miscible flooding experiment shows approximately 3 times higher flooding velocity in an open F2 fracture than in the matrix. 2‐phase flooding by gas injection into a 100% water saturated core gave early gas breakthrough due to flow in the fracture and thereafter very little water production. The flow experiments showed that the presence of open fractures has a significant local effect on fluid flow even in a case with relatively high matrix porosity (200–300 mD). The sample containing F1 fractures showed a complex flow pattern influenced both by open fractures and stylolites. The CT scan data enables an exact representation of the fracture network in core scale simulation models and therefore improves the understanding of fracture influence on flow in a fractured porous medium. CT scanning of core samples provides an effective tool for integrating geology and fluid flow properties of a porous fractured medium.

Wettability Alteration in Gas-Condensate Reservoirs To Mitigate Well Deliverability Loss by Water Blocking

Summary Liquid blocking in some gas-condensate reservoirs is a serious problem when the permeability is low (for example, of the order of 10 md or less). The current practice centers mainly on hydraulic fracturing to improve gas flow. In most cases, the frequency of application results in high costs. An alternative is the permanent alteration of wettability from liquid-wetting to preferentially gaswetting. In this work, we present an experimental study of wettability alteration to preferential gas-wetting using a multifunctional surfactant and polymer synthesized for this particular application. The treatments are performed with an alcohol-based-surfactant/ polymer solution. We treat Berea cores and reservoir-rock samples from two gas-condensate reservoirs. In one of the reservoirs, water blocking has resulted in a significant reduction of well deliverabil-ity. The treatment provides significant improvement on the phase mobility. In this study, our focus is the investigation of water/gas two-phase flow at high temperatures (80 and 140°C). Basic measurements such as contact angle, spontaneous imbibition, and the effect on the absolute permeability are discussed. The initial liquid saturation at the time of treatment may have an influence on the wettability alteration. The results of the treatment on oil-saturated and water-saturated cores are presented. The treatment by alcohol without using the polymer is compared and discussed. Two-phase-flow tests in single-phase and two-phase injections are performed before and after the treatment using brine and gas. Relative permeabilities of gas and water are measured, and the improvement after the treatment is presented. Various measurements in our work show that water and gas relative permeability increase significantly in a wide range, especially at high liquid saturation.