Outcrop Chalk Research Articles

Tertiary-CO2 flooding in a composite fractured-chalk reservoir

This paper presents the oil recovery mechanism by tertiary-CO2 flooding in a composite fractured chalk core. We perform two different core flooding experiments at reservoir conditions. We evaluate the efficiency of tertiary-CO2 flooding in different conditions, taking into account the effect of capillary continuity, water composition, and the heterogeneity.The composite core consists of six core plugs placed vertically in-line in the core holder with total length of 45 cm and average diameter of 3.74 cm. We use qualitative filter paper between each core plug to reserve the capillary continuity at reservoir conditions (258 bara and 110 °C). The “fracture” is represented by a centralized axial hole with a diameter of 0.6 cm. In all experiments, the composite fractured core is initially saturated with North Sea Chalk Field (NSCF) stock tank oil (STO) and synthetic connate water. Once the reservoir conditions are established, brine is injected from the bottom of the fracture and the oil is produced from the top. We stop water flooding (WF) after no more oil is being produced. CO2 is then injected from the top of the fracture and the oil is produced from the bottom.Experiments Exp-1C and Exp-2C utilize Sigerslev outcrop chalk cores. To account for the effect of initial water composition during WF, system is initially saturated with synthetic sea water with considerable amount of sulfate instead of formation water in Exp-1C. Whereas, we employ synthetic formation water with zero sulfate content in Exp-2C.The results of experimental work are reproduced via validated compositional reservoir simulator with a tuned equation of state (EOS). We develop an automated history matching algorithm to match the experimental data of WF and CO2 flooding (CF) periods.We observe a major impact of the initial water composition that results in strong- to moderate-spontaneous imbibition during WF period. Moreover, both experiments and simulations show that the tertiary CO2 recovery is significantly affected by the water saturation in the core after the secondary WF. We conduct a sensitivity analysis to study different CO2 injection scenarios such as in a single block, in a composite core with capillary continuity, and in a composite core with horizontal fractures in between. The results show the oil recovery during tertiary-CO2 flooding is barely affected by the degree of the capillary contacts between the chalk matrixes. Moreover, it is found that the mass transport during CF is mainly covered by diffusion rather than the convective flux or viscous forces.We build a modeling framework that accounts for proper modeling of imbibition and diffusion dominated processes in a composite chalk system at reservoir conditions.

Laboratory Tests and Modeling of Carbon Dioxide Injection in Chalk With Fracture/Matrix–Transport Mechanisms

Summary The main focus of this paper is to present experimental and simulation results that describe carbon dioxide (CO2) injection in a chalk sample with fracture/matrix interaction at reservoir conditions. On the basis of the experiments, simulation models were built to mimic the main transport phenomena, including diffusion, which was found to be particularly important. The first experiment consisted of a vertically oriented Sigerslev outcrop chalk core, where a single “fracture” was represented by a centralized hole along the core. Both matrix and fracture were initially saturated with a North Sea stock-tank oil (STO) at reservoir conditions. Once the initial conditions were established, CO2 was injected from the top of the fracture and the oil was produced from the bottom. Injected CO2 diffused into the oil in the matrix and swelled the oil. Once the oil in the fracture was drained, the matrix fed the fracture with oil at decreasing rates. The first experiment lasted up to approximately 24 pore volumes injected (PVinj). The second experiment is similar, but laboratory oil n-C10 was used instead of STO. Laboratory oil and CO2 have very similar densities at the chosen reservoir conditions, which minimizes gravity-driven convective (Darcy) transport and maximizes the effect of diffusion. Our modeling was conducted with a compositional reservoir simulator. We developed and used a tuned equation-of-state (EOS) model that accounts for proper estimation of the phase and volumetric properties for CO2 mixtures in the STO and n-C10 systems. Automated history matching was used to fit the experimental data. A commercial reservoir simulator could reproduce laboratory results adequately. Numerical simulations were conducted to match experimental oil-production data by tuning the oil- and gas-diffusion coefficients. Good agreement between the numerical model and the experimental data was obtained. For the n-C10 system, we found that the results were not sensitive to vertical permeability, confirming displacement was dominated by diffusion rather than convective flux. Verifying the accuracy of modeling the diffusion-dominated processes in a fractured chalk system with CO2 at reservoir conditions has been accomplished. The lesson learned from the experimental and modeling work flow obtained from this study becomes an important step toward modeling an actual fractured chalk/reservoir-oil system undergoing CO2 injection.

Crude Oil Quantity and Its Effect on Chalk Surface Wetting

Injection of a Smart Water, with a modified and optimized ionic composition, is an environmentally friendly and cheap enhanced oil recovery (EOR) method. To be able to optimize the ionic composition to cause wettability alteration in the reservoir, one must understand the initial wetting of the reservoir. Experimental studies have confirmed that acidic material in the crude oil, especially negatively charged carboxylates, R–COO–, are the most important wetting parameters toward positively charged carbonate surfaces that dictate the rock wettability. The carboxylate molecules bond strongly to the carbonate surface, and these crude oil anchor molecules can only be removed from the calcite surface by chemical reactions. Generating representative core wettability during core restoration in the laboratory is important for doing realistic oil recovery studies, capillary pressure and relative permeability measurements. Water-wet outcrop chalk cores showing good reproducibility were used to study adsorption of carboxylic material onto chalk. Crude oil with a known acid number (AN) was flooded in different quantities through water-wet chalk cores containing 10% formation water saturation. The core wetting was evaluated by spontaneous imbibition tests, forced imbibition tests, and chromatographic wettability tests. The results of the work showed that the core wetting was determined by the amount of crude oil flooded through the core. The one core that had seen only 5 pore volumes (PV) of crude oil behaved much more water-wet than the core that had seen 15 PV of the same crude oil. Oil recovery by spontaneous imbibition was both lower and slower from the core that had seen the most oil, owing to the difference in wetting and capillary forces. With forced imbibition, viscous forces were introduced and the oil recovery immediately increased in both cores. The increase in oil recovery from the most water-wet core was larger than that of the less water-wet core, despite the residual oil saturation and, consequently, the EOR potential being lower in the most water-wet core. This suggested that the capillary forces not only influenced the spontaneous imbibition but also the forced imbibition, leading to a difference in recovery, which was related to a difference in wetting.

Effect of the Temperature on Wettability and Optimum Wetting Conditions for Maximum Oil Recovery in a Carbonate Reservoir System

The additional oil recovery from fractured and oil-wet carbonates by ionically modified water is principally based on changing wettability and often attributed to an improvement in water-wetness. The influence of different parameters, such as dilution of salinity, potential anions, temperature, pressure, lithology, pH, and oil acid and base numbers, to improve water-wetting has been tested in recovery experiments. In those studies, the temperature is mainly investigated to observe the reactivity of potential anions (sulfate and borate) at different concentrations. However, the influence of systematically increasing the temperature on wetting conditions has not been thoroughly investigated. In this experimental study, the effect of different temperatures on wettability for brines of different ionic strength and composition has been investigated in depth. A series of flotation experiments was conducted at 23, 50, and 100 °C using Dan outcrop chalk. The effect of each individual variable on the wetting condi...

Determining Diffusion Coefficients for Carbon Dioxide Injection in Oil-Saturated Chalk by Use of a Constant-Volume-Diffusion Method

Summary This paper presents a novel technique to determine multicomponent diffusion coefficients for carbon dioxide (CO2) injection in a North Sea chalk field (NSCF) in Norway at reservoir conditions. The constant-volume-diffusion (CVD) method is used, consisting of an oil-saturated-chalk core in contact with an overlying free space, which is filled with the CO2. The experimental data are matched with an equation-of-state (EOS) -based compositional model. Transport by diffusion controls the dynamics of the constant-volume system and, together with phase equilibria, allows a consistent estimation of diffusion coefficients needed to describe the observed changes in system pressure. We conduct two experiments at reservoir conditions: One uses a core plug saturated with live oil and the other with stock-tank oil (STO). Once the experiments are completed, EOS-based compositional simulation is performed to match the experimental data by use of the oil- and gas-diffusion coefficients as history-matching parameters. The modeling work is conducted with a commercial reservoir simulator by use of a 2D radial-grid model to describe the experimental setup. The experiment uses an outcrop chalk core mounted in a vertically oriented core holder. The chalk is shorter than the core holder, thus resulting in an overlying void space. The system is initially saturated with oil at reservoir conditions. CO2 is then injected from the top, forming an overlying CO2 chamber and displacing oil toward the bottom of the core holder. Once CO2 fills the overlying bulk space, the system is isolated with no further injection or production. The CO2 and oil reach and remain in equilibrium locally at the gas/oil interface throughout the test, beginning and maintaining the diffusion mechanism. Diffusion of CO2 into the oil results in a decreasing pressure, which is the main history-matching parameter. The multicomponent diffusion coefficients are found to match the model pressure/time prediction to the experimental data. This suggests the modeling work flow incorporates a representative EOS model and the main transport dynamics controlled by diffusion are being treated properly. Proper simulation of CO2 injection in fractured-chalk reservoirs requires the ability to model multicomponent diffusion accurately. The proposed CVD method provides such modeling capabilities. Our modeling and experimental work indicate the novelty of the CVD method to determine the diffusion coefficients of a system where diffusion is the dominant displacement mechanism. The fact that the oil is contained within a low-permeability-chalk sample reduces density-driven convection that could result because of nonmonotonic oil-density changes as CO2 dissolves into the oil.

Evaluation of porosity change during chemo-mechanical compaction in flooding experiments on Liège outcrop chalk

Abstract The mechanical strength, porosity and permeability of chalk are affected by chemical and mineralogical changes induced by fluids that are chemically out of equilibrium with the host rock. Here, two high-porosity Upper Cretaceous chalk cores from Liège were tested at effective stresses beyond yield at 130°C during flooding with MgCl 2 and NaCl brines. Core L1 (flooded by MgCl 2 brine) deformed more than L2 (flooded with NaCl brine), with volumetric strains of 9.4% and 5.1%, respectively. The porosity losses estimated from strain measurements alone are 5.82% for L1 and 3.01% for L2. However, this approach does not account for dissolution and precipitation reactions. Porosity calculations that are based on strain measurements in combination with (i) the weight difference between saturated and dry cores and (ii) the solid density measurement before and after flooding show an average porosity reduction of 3.69% between the two methods for L1. This discrepancy was not observed for core L2 (with the NaCl brine). The rock and effluent chemistry show that Ca 2+ dissolved and Mg 2+ is retained within the core for the L1 experiment. Therefore, accurate porosity calculations in chalk cores that are flooded by non-equilibrium brines (e.g. MgCl 2 ) require both the volumetric strain and chemical alteration to be considered.

Adsorption of Acidic Crude Oil Components onto Outcrop Chalk at Different Wetting Conditions during Both Dynamic Adsorption and Aging Processes

Restoration of carbonate reservoir core material for special core analysis has been debated in the literature for some time. An important goal of core restoration is to reproduce initial reservoir wetting properties because wettability dictates important reservoir parameters, such as capillary pressure and relative permeability of oil and water. It has previously been found that acidic polar components in crude oil dictate the wetting properties in carbonate core material. In this paper, the effects on chalk wettability from crude oil flooding, core aging, and mild core cleaning were investigated experimentally. The experimental results confirmed that adsorption of acidic polar components is an instantaneous process and that a dynamic equilibrium was achieved with a specific adsorption capacity of the initially very water-wet chalk surface. The crude oil flooding reduced the water-wet surface area. Core aging for 2 weeks at the test temperature reduced the water-wet surface area even further, which appear...

New insight into the microtexture of chalks from NMR analysis

An integrated petrographical and petrophysical study was carried out on a set of 35 outcrop chalk samples, covering a wide range of lithologies and textures. In this study various chalk rock-types have been characterized, in terms of microtextures and porous network, by integrating both geological, sediment-petrological and petrophysical data, including porosity, permeability, low-field NMR (Nuclear Magnetic Resonance), MICP and specific surface area (BET) measurements. The data allow an in depth understanding of the NMR signal of chalks, with a focus on tight chalks, including all low reservoir quality chalks independently of their sedimentological and/or diagenetic history. The study aims to develop an NMR-based approach to characterize a broad range of chalk samples. The provided laboratory low-field NMR chalk classification can be used as a guide to interpret NMR logging data.Based on the petrographical and petrophysical analysis, 6 groups of samples were identified, each of them characterized by a unique NMR signature: (1) micritic chalks, (2) grainy chalks, (3) cemented chalks, (4) marl-seam chalks, (5) argillaceous chalks and (6) silicified chalk. NMR T2 distributions were linked to pore body size and T2 logarithmic (T2lm) was calculated. It is apparent that tight chalks, whether their characteristics are sedimentological or diagenetic, yield smaller pore body sizes (T2lm < 20 ms), as well as narrower pore throats (average radius < 150 nm) and lower permeability values (typically below 0.2 mD). Grainy chalks possess T2 distributions reflecting larger pore sizes (T2lm > 60 ms) and pore throats (average radius > 290 nm) and higher permeabilities (up to 13 mD). The marl-seam chalk samples yield bimodal T2 distributions, with a first peak related to the micritic matrix pores and a second peak related to intraparticle pores within fossils. For all samples, permeability was inferred from NMR spectra using SDR (Schlumberger Doll Research) model.

How Stress and Temperature Conditions Affect Rock-Fluid Chemistry and Mechanical Deformation

We report the results from a series of chalk flow-through-compaction experiments performed at three effective stresses (0.5 MPa, 3.5 MPa and 12.3 MPa) and two temperatures (92℃ and and 130℃). The results show that both stress and temperature are important to both chemical alteration and mechanical deformation. The experiments were conducted on cores drilled from the same block of outcrop chalks from the Obourg quarry within the Saint Vast formation (Mons, Belgium). The pore pressure was kept at 0.7 MPa for all experiments with a continuous flow of 0.219 M MgCl2 brine at a constant flow rate; 1 original pore volume (PV) per day. The experiments have been performed in tri-axial cells with independent control of the external stress (hydraulic pressure in the confining oil), pore pressure, temperature, and the injected flow rate. Each experiment consists of two phases; a loading phase where stress-strain dependencies are investigated (approx. 2 days), and a creep phase that lasts for more than 150-160 days. During creep, the axial deformation was logged, and the effluent samples were collected for ion chromatography analyses. Any difference between the injected and produced water chemistry gives insight into the rock-fluid interactions that occur during flow through of the core. The observed effluent concentration shows a reduction in Mg2+, while the Ca2+ concentration is increased. This, together with SEM-EDS analysis, indicates that magnesium-bearing mineral phases are precipitated leading to dissolution of calcite, an observation . This is in-line with other flow-through experiments reported earlier. The observed dissolution and precipitation are sensitive to the effective stress and test temperature. Typically. H, higher stress and temperature lead to increased concentration differences of Mg2+ and Ca2+ concentration changes.. The observed strain can be partitioned additively into a mechanical and chemical driven component.

Mechanical and physical behavior of high-porosity chalks exposed to chemical perturbation

Abstract Extensive study on the effect of dissolution–precipitation on mechanical behavior of various high-porosity outcrop chalks (Liege, Aalborg, Kansas, Stevns Klint, and Mons) flooded with simplified aqueous chemistry at 130 °C under isotropic stress beyond the yield is performed. Chemical effects induced by injection of 0.219 M MgCl 2 solutions into impure chalks (Liege, Aalborg, Kansas) lead to an immediate enhancement on the macroscopic creep with more than a factor of 2 larger than that of exposed to 0.657 M NaCl solutions. In pure chalks (Stevns Klint and Mons) however, the creep response is characterized by a time lag, where creep initially diminishes before a tertiary-like creep develops. Systematic correlation between calcite dissolution and the resulting creep strain is consistently demonstrated by all the different chalk types. The chemical effects are described as precipitation of Mg-bearing minerals and dissolution processes, which involve both the carbonate and non-carbonate phases. SEM-EDS, XRD, and BET (N 2 ) analyses indicate newly formed Mg-bearing minerals primarily present as Magnesite, which precipitated in the pore space. Enhanced dissolution is shown by continuous production of Ca 2+ measured in the core effluent. The time for the dissolution to overcome intergranular friction accounts for the delay in the creep acceleration in pure chalks (Stevns Klint and Mons). For impure chalks (Liege, Aalborg, Kansas) chemical alterations on the non-carbonate phases outweigh the intergranular friction. This additional effect accounts for the immediate impact in the creep deformation. The chemical effects are also demonstrated by marked reduction in the permeability. The porosity–permeability relationship measured at the end of creep test is shifted down from the initial correlation, indicating a dramatic increase in the chalk specific surface area.

Porosity and permeability development in compacting chalks during flooding of nonequilibrium brines: Insights from long‐term experiment

AbstractWe report the complete chemical alteration of a Liège outcrop chalk core resulting from a 1072 flow‐through experiment performed during mechanical compaction at 130°C. Chemical rock‐fluid interactions alter the volumetric strain, porosity, and permeability in a nontrivial way. The porosity reduced only from 41.32% to 40.14%, even though the plug compacted more than 25%. We present a novel analysis of the experimental data, which demonstrates that the geochemical alteration does not conserve the volume of the solids, and therefore, the strain is partitioned additively into a pore volume and solid volume component. At stresses beyond yield, the observed deformation can be explained by grain reorganization reducing the pore space between grains and solid volume changes from the rock‐fluid interactions. The mechanical and chemical effects are discussed in relation to the observed permeability development.

Evaluation of the compositional changes during flooding of reactive fluids using scanning electron microscopy, nano-secondary ion mass spectrometry, x-ray diffraction and whole rock geochemistry

Outcrop chalk of late Campanian age (Gulpen Formation) from Liege (Belgium) was flooded with in a triaxial cell for 516 days under reservoir conditions to understand how the non-equilibrium nature of the fluids altered the chalks. The study is motivated by enhanced oil recovery (EOR) processes because dissolution and precipitation change the way in which oils are trapped in chalk reservoirs. Relative to initial composition, the first centimeter of the flooded chalk sample shows an increase in MgO by approximately 100, from a weight percent of 0.33% to 33.03% and a corresponding depletion of CaO by more than 70% from 52.22 to 14.43 wt.%. Except for Sr, other major or trace elements do not show a significant change in concentration. Magnesite was identified as the major newly grown mineral phase. At the same time, porosity was reduced by approximately 20%. The amount of in the effluent brine remained unchanged, whereas was depleted and enriched. The loss of and gain in are attributed to precipitation of new minerals and leaching the tested core by approximately 20%, respectively. Dramatic mineralogical and geochemical changes are observed with scanning electron microscopy–energy-dispersive x-ray spectroscopy, nano secondary ion mass spectrometry, x-ray diffraction, and whole-rock geochemistry techniques. The understanding of how fluids interact with rocks is important to, for example, EOR, because textural changes in the pore space affect how water will imbibe and expel oil from the rock. The mechanisms of dissolution and mineralization of fine-grained chalk can be described and quantified and, when understood, offer numerous possibilities in the engineering of carbonate reservoirs.

The surface reactivity of chalk (biogenic calcite) with hydrophilic and hydrophobic functional groups

The surface properties of calcium carbonate minerals play an important role in a number of industrial and biological processes. Properties such as wettability and adsorption control liquid–solid interface behaviour and thus have a strong influence on processes such as biomineralisation, remediation of aquifers and oil recovery. We investigated how two model molecules of different polarity, namely water and ethanol, interact with reservoir and outcrop chalk samples and we compared their behaviour with that of pure, inorganically precipitated calcite. Thermodynamic quantities, such as the work of wetting, surface energy and isosteric adsorption enthalpy, were determined from vapour adsorption isotherms. The chalks were studied fresh and after extraction of organic residues that were originally present in these samples. The work of wetting correlates with the amount of organic matter present in the chalk samples but we observed a fundamental difference between the adsorption properties of chalk and pure, inorganically precipitated calcite toward the less polar, ethanol molecule. Further analysis of the chemical composition of the organic matter extracted from the chalk samples was made by gas chromatography (GC–MS). Monitoring surface composition by X-ray photoelectron spectroscopy (XPS) before and after extraction of the organic material, and with atomic force microscopy (AFM), showed that nanometer sized clay crystals observed on the chalk particle surfaces could be an important part of the reason for the differences. Removal of the extractable portion of the hydrocarbons liberates adsorption sites that have different wetting properties than the rest of the chalk and these have an energy distribution that is similar to clays. Thus, the results exemplify the complexity of biogenic calcite adsorption behaviour and demonstrate that chalk wetting in drinking water aquifers as well as oil reservoirs is controlled partly by the nanoparticles of clay that have grown on the chalk surfaces and partly by adsorbed organic material.

Adsorption Properties of Chalk: Contributions from Calcite and Clays

Water and ethanol vapour adsorption measurements were used to estimate the contribution from calcite and clay (kaolinite) on the adsorption behaviour of outcrop chalk. Both sets of measurements indicate that adsorption isotherms of chalk can be closely mimicked by a linear combination of clay and calcite adsorption isotherms. The values of the isosteric heat of adsorption for all investigated surfaces were determined in the temperature range 273 – 293K. Pure calcite adsorbs water and ethanol vapour with energies typical of chemisorption, while chalk and kaolinite show adsorption energies more typical for physisorption and form multilayers of adsorbed water and ethanol on their surfaces.

Wettability effects on water mixing during waterflood oil recovery

We present experimental results of the mixing of injection water and connate water during oil production by waterflooding in two outcrop chalk samples at three different wettabilities. The displacement of connate water by the injected water was determined using nuclear tracer imaging (NTI). For all three wettabilities investigated, strongly water-wet (Iw=1.00), moderately water-wet (Iw=0.44) and less water-wet (Iw=0.28) conditions, the connate water was fully removed from the core by the injected water. The connate water accumulated in front of the injected water, and constituted a large fraction of the water that immiscibly displaced the oil from the core plug. The connate water bank was less pronounced at reduced water-wet conditions, and the mixing between connate and injected water was increased at less water-wet conditions. Connate water breakthrough was observed at one mobile-oil-pore-volume of water injected at all three wettabilities. Breakthrough of the injected water was delayed at strongly water-wet conditions compared with less water-wet conditions, where both water phases were produced simultaneously.

Effect of Water-Extractable Carboxylic Acids in Crude Oil on Wettability in Carbonates

The acidic components of the crude oil have a profound effect on the initial wetting conditions and possible wettability alteration by seawater in carbonates. In this work, three types of crude oils with different concentrations of water-extractable acidic components were prepared from a base oil: (1) a reference oil, RES-40 [acid number (AN) = 1.90 mg of KOH/g and base number (BN) = 0.51 mg of KOH/g], (2) a treated oil depleted in water-extractable acidic components, termed treated oil (TO) (AN = 1.50 mg of KOH/g and BN = 0.53 mg of KOH/g), and (3) a crude oil containing only water-extractable acidic components, termed EWS-oil (AN = 1.90 mg of KOH/g and BN < 0.01 mg of KOH/g). Outcrop chalk cores were used as the porous medium, and the difference in oil displacement efficiency and wettability was compared. The spontaneous imbibition (SI) process was performed in two steps: first imbibing with formation water without any wettability modification and then with seawater, which acted as a wettability modifier. The oil recovery decreased as the content of water-extractable acidic material in the crude oil increased, for both formation water and seawater as imbibing fluids. The difference in wetting properties was also confirmed by chromatographic wettability analysis. The water wetness appeared to be lower for the cores saturated with the crude oil containing only water-extractable acids. It was concluded that water-extractable carboxylic acids present in crude oil have a great impact on the stability of the water film between the carbonate surface and the oil and seawater was less efficient as a wettability modifier when the extractable acids were adsorbed onto the carbonate surface. Observations from both SI and chromatographic wettability tests emphasize the importance of acid structures or acid types present in the crude oil compared to the acid concentrations.

Use of Sulfate for Water Based Enhanced Oil Recovery during Spontaneous Imbibition in Chalk

The effect of increased sulfate concentration in the imbibing water during oil recovery by spontaneous imbibitions in different outcrop chalks at various wettability conditions at 130 °C has been determined. Core plugs from three chalk outcrops, Rordal, Niobrara, and Stevns, were aged in crude oil and included in this study. Stevns chalk exhibited increased oil recovery during spontaneous imbibition with increased concentration of sulfate in the imbibing water phase. The effect was less than reported by others and was wettability dependent. Spontaneous imbibition tests showed that the added oil recovery was greatest at Amott water indices below 0.2, and tests at and above 0.25 showed only minor effects from sulfate. Niobrara and Rordal chalk did not show increased oil recovery with increased sulfate concentration in the brine. These core plugs reflected more water-wet imbibition characteristics at elevated temperature, and the effect of sulfate could not be isolated. Measurements of Amott water indices be...

Chemical Alterations Induced by Rock–Fluid Interactions When Injecting Brines in High Porosity Chalks

Effect of the aqueous chemistry on the mechanical strength of chalk has extensively been studied during the last decade. At high temperatures (~130°C), chalk exposed to seawater is significantly weaker compared to chalk exposed to distilled water when considering the hydrostatic yield strength and the following creep phase. The explanation of these experimental results must be of a chemical nature, as the density and viscosity of the aqueous phase vary little among these different brines. We present the results from simplified aqueous chemistry using MgCl2 brines, and compare these results with seawater. Previous studies show that different ions, e.g. Ca2+, Mg2+, \({{\rm SO}{_{4}}^{2-}}\) in the injected brine, as well as the chalk mineralogy have an impact on the stability of the rock. We performed mechanical tests on chalk cores from Liege and Stevns Klint; it was found that these two outcrop chalks exhibit an unexpected difference in their mechanical responses when comparing cores flooded with NaCl and MgCl2 at 130°C. The results of this study show that the effects of magnesium seem to be governed not only by the differences in mineralogy, but also a time dependency on chalk deformation is additionally observed. Independent of the chalk type tested, the chemical analyses performed show that when MgCl2 is flooded through the core, a significant loss of magnesium and a considerable additional amount of calcium are detected in the effluent. The experimental observations fit very well with the time-dependent chemical changes gained from the mathematical model of this study that accounts for transport effects (convection and molecular diffusion) as well as chemical processes such as precipitation/dissolution. Based on the calculations and chemical analyses, we argue that the loss of magnesium and the production of calcium cannot solely be a consequence of a substitution process. The calculations rather indicate that magnesium is precipitated forming new mineral phases and in this process not only calcite, but also silicates are dissolved. The amount of dissolved calcium and silicon from the rock matrix is significant and could thus cause an additional deformation to take place. Both the retention of magnesium in the chalk core and the formation of newly precipitated magnesium-bearing carbonates and/or magnesium-bearing clay-like minerals after flooding with MgCl2 brine were demonstrated using scanning electron microscopic methods. In addition, precipitation of anhydrite as a result of flooding with seawater-like brine was proven. The water-induced strain not only depends on the ion composition of the injected brine; moreover, the presence of non-carbonate minerals will most likely also have a significant influence on the mechanical behaviour of chalk.

Dynamic Laboratory Wettability Alteration

We present experimental wettability alteration results in originally strongly water-wet, outcrop chalk core plugs using a static and two dynamic aging methods. Dynamic aging with continuous crude oil injection during the entire aging process exhibited greater reduction in water-wetness of the strongly water-wet chalk plugs than static aging without flushing. Two dynamic aging procedures were tested to find an optimal flooding rate for the most efficient reduction in water-wetness: (1) a constant crude oil flooding at 3 cm3/h using variable aging times (48, 96, and 192 h) and (2) a constant aging time (96 h) with variable flooding rates (1, 3, and 5 cm3/h). The aging temperature was kept constant in all tests (90 °C), and the impacts from varying aging times, pore volumes injected, and crude oil injection rate on the wettability alteration process were investigated. Aging was performed on consolidated, porous chalk samples with initial water present in the pore space. It was shown that static aging, i.e., aging in a stagnant, limited amount of crude oil, and dynamic aging, i.e., with continuous flooding of crude oil, performed equally well in terms of average Amott−Harvey water indices (Iw ∼ 0.6) for short aging times (72 h or less). For longer aging times, the static approach failed to established an Amott−Harvey water index under Iw = 0.25 and required 3 times as long of an aging time compared to dynamic aging (7 days for dynamic or 24 days for static required to establish Iw ∼ 0.25). Amott−Harvey water indices lower than Iw = 0.25 were established with dynamic aging for shorter aging times (less than 12 days). At a given constant aging time (96 h), it was found that wetting was sensitive to the crude oil injection rate and that there exists an optimal crude oil injection rate with the greatest change in wettability.

In-Situ Phase Pressures and Fluid Saturation Dynamics Measured in Waterfloods at Various Wettability Conditions

Summary During waterfloods of six outcrop chalk core-plug samples prepared at various wettabilities, simultaneous local pressures and in-situ fluid saturations were measured. Using high-spatial-resolution magnetic-resonance imaging (MRI) to image fluid saturations and pressure taps with semipermeable disks to measure individual phase pressures allowed calculations of relative permeabilities and the dynamic capillary pressure curves for the imbibition processes. A second objective was to identify individual-fluid saturation changes caused by spontaneous imbibition and viscous displacement to determine the local recovery mechanism and to calculate local recovery factors and in-situ Amott-Harvey indices. The obtained results contribute to improved description and understanding of multiphase-fluid flow in porous media, including in situ measurements of relative permeabilities, dynamic capillary pressure curves, Amott-Harvey Indices, and local oil-recovery mechanisms.