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In this study, eight tri-axial tests on Cretaceous age outcrop chalk from Aalborg have been performed systematically by injecting MgCl 2 for the first time at different temperatures (25, 60, 92, 110 and 130 °C) and for comparison, NaCl at 130 °C. Whole-rock geochemistry, stable isotope measurements, pycnometry, Field Emission Gun Scanning Electron Microscopy with Energy-Dispersive X-ray Spectroscopy, X-Ray Diffraction (XRD) and measurements of Specific Surface Area (Brunauer-Emmett-Teller theory (N 2 )) were applied to analyse unflooded and flooded cores. Based on analyses of changes in brine composition, mineralogy, specific surface area, solid density, porosity and permeability some conclusions can be drawn on temperature effects on rock engineering properties and rock-fluid chemistry. The MgCl 2 flooded cores show systematically higher creep rates at higher temperature and the cores tested at 25 and 60 °C show similar creep rates as the two NaCl flooded cores at 130 °C. All fluid-rock interactions were more pronounced at higher temperature. After flooding with MgCl 2 at 110 and 130 °C newly formed magnesite is observed. In the cores tested at 25, 60 and 92 °C magnesite crystals have not been positively identified, but minute increases in MgO in whole-rock geochemistry analyses are seen. Si 4+ originating from the dissolution of silica bearing phases (mainly diagenetic opal-CT), has taken part in the re-precipitation of Si-Mg-bearing minerals during MgCl 2 injection from 25 to 130 °C, leading to an increase of the specific surface area. This is partly balanced by opal-CT dissolution, which should lower the specific surface area. The flaky Si-Mg-bearing minerals, covering significant portions of the pore surfaces and throats are the main drivers to reduce permeability in cores flooded at high temperatures. Additionally, in NaCl flooded cores where mineralogical changes are minute, the dissolution of parts of the existing opal-CT has lowered the SSA. At high temperatures, the following chemical changes must be carefully acknowledged when porosity reduction is calculated: calcite and opal-CT dissolution and precipitation of new minerals, particularly Mg-bearing minerals. The presence of opal-CT strongly influences the mineralogical alterations in flooded cores, hence the geo-mechanical evolution. [ABSTRACT FROM AUTHOR]

Water flooding with selective ions has in some cases lead to increased oil recovery. We investigate the physical processes on a pore scale that are responsible for changes in petrophysical and mechanical properties of four oil-bearing chalk and four oil-bearing greensand samples caused by flooding with brines containing varying amounts of dissolved NaCl, Na 2 SO 4 , MgCl 2 and MgSO 4 . Ultrasonic P-wave velocity and AC resistivity measurements were performed prior to, during and after flow through experiments in order to identify and quantify the processes related to water flooding with selective ions. Low field Nuclear Magnetic Resonance (NMR) spectrometry measurements were performed at full water saturation, at irreducible water saturation, after aging and after flooding. CT-scanning, X-ray diffraction (XRD), backscatter electron microscopy images (BSEM), mercury injection capillary pressure (MICP) curves and specific surface analysis (BET) reveal the mineralogy and texture of the rock samples before and after the injection. Low field NMR data indicates changes in the pore fluid distribution and wettability of chalk after aging of one of the samples. NMR data for other samples indicate that chalk is water-wet after flooding. Greensand remained mixed wet throughout the experiments. Electrical resistivity data are in agreement with this interpretation. The electrical resistivity data during flooding revealed that the formation brine is not fully replaced by the injected water in both chalk and greensand. Changes in the elasticity of chalk during flooding illustrate the softening effect of magnesium bearing brines as compared to the sodium bearing brines. The stiffness of greensand was not affected by water flooding with selective ions as determined from the elastic wave measurements. Precipitation of fines during flooding of chalk samples is indicated by an increase in specific surface area and a shift in the MICP to lower values but no fines were detected by NMR. No changes were observed for greensand samples. [ABSTRACT FROM AUTHOR]

The effects of divalent ions on the elasticity and the pore collapse of chalk were studied through rock-mechanical testing and low-field Nuclear Magnetic Resonance (NMR) measurements. Chalk samples saturated with deionized water and brines containing sodium, magnesium, calcium and sulfate ions were subjected to petrophysical experiments, rock mechanical testing and low-field NMR spectroscopy. Petrophysical characterization involving ultrasonic elastic wave velocities in unconfined conditions, porosity and permeability measurements, specific surface and carbonate content determination and backscatter electron microscopy of the materials were conducted prior to the experiments. The iso-frame model was used to predict the bulk moduli in dry and saturated conditions from the compressional modulus of water-saturated rocks. The effective stress coefficient, as introduced by Biot, was also determined from density and ultrasonic velocities measured on core plugs. Low-field NMR spectroscopy was used in addition to the mechanical testing to prove any changes observed after the saturation related to the surface-to-volume ratio of the pore space in each of the samples or to surface relaxivity. Backscatter-electron (BSE) images were recorded in order to identify the texture of the core plugs under investigation. The experimental results revealed that both elasticity and pore collapse are influenced by the presence of divalent ions in distinct ways. Compressional wave velocities indicate that saturation with water rich in magnesium and calcium ions softens the contact among the mineral grains. Pore collapse strength is deteriorating after the saturation of chalk with water rich in divalent ions. The presence of calcium and sulfate ions in the saturating fluid results in pore collapse at lower stresses than in the case when samples are saturated with deionized water or sodium chloride solution. Low field NMR spectrometry revealed precipitation of crystals in the pore space of chalk saturated with Mg-rich brine. The precipitation of Mg-carbonates was not used to explain the deteriorating pore collapse strength and effects on the elasticity after the saturation since none of the other plugs saturated with divalent ions (Ca 2+ and SO 4 2 + ) experienced it. [ABSTRACT FROM AUTHOR]

Water based EOR by wettability alteration is of interest among the oil companies because of economic and environmental reasons. It is well known that seawater acts as a wettability modifier in carbonate reservoirs, and the seawater can even be improved as a smart EOR fluid by removing Na + and Cl − ions, and spiking this NaCl-depleted seawater with SO 4 2 - ions. In this paper we have addressed the degree of seawater modification needed to achieve reasonable improvements in oil recovery in spontaneous imbibition processes at 90 °C. Compared to ordinary seawater as imbibing fluid, more than 90% of the NaCl content must be removed in order to increase the oil recovery by 7–8% OOIP. Furthermore, compared to seawater depleted in NaCl, the oil recovery could be increased by 10% OOIP by spiking the NaCl depleted seawater with sulfate, 3–4 times the sulfate concentration present in seawater. The increased efficiency of modified seawater as a smart EOR fluid in carbonate is discussed in terms of a decrease in the ionic density of the double layer close to the positively charged calcite surface. [ABSTRACT FROM AUTHOR]

Extensive study on the effect of dissolution–precipitation on mechanical behavior of various high-porosity outcrop chalks (Liége, 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 (Liége, 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 (Liége, 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. [ABSTRACT FROM AUTHOR]

The injection of low-salinity water into carbonate oil-reservoirs has been the subject of much interest as a potential method to enhance oil recovery (EOR). Low salinity water injection has been shown to alter the geochemical equilibrium in the reservoir, and consequentially potentially change the surface wettability of the reservoir rocks. Nevertheless, the geochemical reaction pathways during low salinity water flooding in carbonates remain poorly understood. In order to provide a more comprehensive insight into the geochemical reaction pathways, a series of batch and core-flooding experiments have been performed at 70 °C. The experiments made use of analogous and authentic reservoir material from the Danish North Sea oil reservoirs, and brines with chemical composition similar to the formation water and injection water available in offshore flooding operations. Results show that both mineral dissolution and the precipitation of new secondary phases can accurately describe the geochemical changes observed in the experimental effluents during the course of a low-salinity water core-flooding scenario. The dissolution of amorphous silica (SiO 2) present in the chalk, and the precipitation of a Mg–Si clay mineral, identified here as sepiolite, are key reactions that take place during low-salinity water core-flooding in chalks. The suggested geochemical pathway was successfully fitted by a simplified geochemical simulation which can accurately describe the experimental observations. Surface reactions which take place during modified-salinity water flooding were put into perspective by quantifying their contribution to the overall effluent composition. [Display omitted] • The geochemical processes that occur during water flooding in chalks are affected by their content of amorphous silica.. • Sepiolite was identified as the main Mg-Si mineral precipitating during modified-salinity water flooding. • Sepiolite precipitates on existing silicate phases coating their surfaces. • A geochemical pathway was fitted using a simplified geochemical simulation which describes the experimental observations. • Surface reactions have a small contribution to the effluent chemical composition during modified-salinity water flooding. [ABSTRACT FROM AUTHOR]

We aimed to relate changes in porosity and sonic velocity data, measured on water-saturated Eocene chalks from 36 Ocean Drilling Program drill sites in the Atlantic Ocean, to vertical effective stress and thermal maturity. We considered only chalk of Eocene age to avoid possible influence of geological age on chalk compaction trends. For each depth, vertical effective stresses as defined by Terzaghi and by Biot were calculated. We used bottom-hole temperature data to calculate the time–temperature index of thermal maturity (TTI) as defined by Lopatin. Porosity and compressional wave velocity data were correlated to vertical effective stresses and to TTI. Our porosity data showed a broader porosity trend in the mechanical compaction zone, and the onset of the formation of limestone at a shallower burial depth than the porosity data of the Ontong Java Plateau chalk show. Our porosity data do not show or at least it is difficult to define a clear pore-stiffening contact cementation trend as the Ontong Java Plateau chalk. Mechanical compaction is the principal cause of porosity reduction (at shallow depths) in the studied Eocene chalk, at least down to about 5 MPa Terzaghi׳s effective stress corresponding to a porosity of about 35%. This indicates that mechanical compaction is the principal agent of porosity reduction. Conversely, at deeper levels, porosity reduction is accompanied by a large increase in sonic velocity indicating pore-filling cementation. These deep changes are correlated with TTI. This indicates pore-filling cementation via an activation energy mechanism. We proposed a predictive equation for porosity reduction with burial stress. This equation is relevant for basin analysis and hydrocarbon exploration to predict porosity if sonic velocity data for subsurface chalk is available. [ABSTRACT FROM AUTHOR]

Enhanced oil recovery by CO 2 injection (CO 2 -EOR) is a tertiary oil recovery process which has a prospective for being used, at the same time, as an effective technique for carbon dioxide storage. There is a huge potential for additional oil production and CO 2 storage in the North Sea depleted chalk reservoirs. North Sea chalk is characterized by high porosity but also high specific surface causing low permeability. A high porosity provides room for CO 2 storage, while a high specific surface causes a high risk for chemical reaction and consequently for mechanical weakening. In order to address this issue we studied two types of chalk from South Arne field, North Sea: (1) Ekofisk Formation having >12% non-carbonate and (2) Tor Formation, which has less than 5% non-carbonate. We performed a series of laboratory experiments to reveal the changes in petrophysical and rock-mechanics properties due to the injection of CO 2 at supercritical state. We analyzed these changes with respect to the differences in porosity, specific surface, pore stiffness, wettability, mineralogy and mechanical strength. We observed a 2–3% increase in porosity, a minor decrease of specific surface and consequently a small increase in permeability. A decrease in elastic stiffness is indicated by an increase of Biot׳s effective stress coefficient ( α ) by 1–2%. Nuclear Magnetic Resonance (NMR) data indicated no change in wettability and the samples remained water wet. We found that the effect of CO 2 injection on both petrophysical and mechanical properties of chalk depends on carbonate content. Pure chalk with high carbonate content was found to be vulnerable to mechanical weakening due to CO 2 injection, whereas, no significant mechanical effect was observed in the impure chalk of Ekofisk Formation. It should in this context be noted that the experiments spanned only 8 days, therefore long term effects cannot be ruled out. In spite of weakening of the chalk, we expect only minor mechanical effects, because the weakening also causes a lowering of effective stress due to an increase in effective stress coefficient. Extensive time-lapse monitoring strategies are required during a CO 2 -EOR process for the measurement of changes in reservoir properties that may cause deformation of and leakage from a reservoir. Results of this study will provide data for designing future monitoring strategies based on 4D seismic. [ABSTRACT FROM AUTHOR]

Precise and fast estimation of porosity is a vital element of reservoir characterization. A new technology for fast and reliable porosity prediction of chalk samples is presented by applying machine learning methods and X-ray fluorescence (XRF) elemental analysis. Input parameters of prediction models are based on rapid and accurate elemental analysis of chalk samples obtained from Hand-held X-ray fluorescence (HH-XRF) measurements. The intelligent models, including Random Forest (RF), Multilayer perceptron (MLP), Random Forest integrated by Genetic Algorithm (GA-RF) and Multilayer Perceptron integrated by Genetic Algorithm (GA-MLP), are trained and tested based on samples consisting of outcrop chalk samples from Rørdal and Stevns Klint (ST) and core samples from Ekofisk Formation in the North Sea. Results are evaluated by sustainability index (SI), determination coefficient (R2), correlation coefficient (CC), and Willmott's Index of agreement (WI). Results indicate that the combination of GA-RF intelligent method with XRF elemental analysis successfully provides an accurate model by 0.99, 0.02, 0.995 and 0.99 respectively for CC, SI, WI and R2, respectively. • To predict the porosity of chalk samples using Machine learning techniques. • The highest prediction accuracy was owned by GA-RF for predicting the chalk porosity. • The Sensitivity analysis was performed by RReliefF algorithm for input variables. • Silicon, calcium and aluminum play the most significant role in chalk porosity prediction. [ABSTRACT FROM AUTHOR]

Abstract: Lower oil recovery is observed from sandstone cores than from chalk for synthetic dead and live oils with miscible CO2 flooding. This was attributed to the greater likelihood of developing fingers in sandstone cores and lower exposed surface areas compared to chalk. This was assessed by addressing the effect of the transverse dispersion on viscous instability. Recombined oil with C1 in chalk and sandstone cores and flooding with CO2 shows higher recovery than the case of recombination with C1/C3. A ternary diagram was constructed for the two cases in order to understand the CO2 flooding mechanisms at the different flooding conditions. [Copyright &y& Elsevier]

Abstract: 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. T 1,2 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/T 1,2 relaxation rate also appeared to correlate with the volumetric strain. The NMR signal from the partially saturated cores (S w ), however, showed no respectable change despite being loaded beyond the yield point. The T 2 signal was dominated by two relaxation rates, which we argue corresponds to the surface water film and micropores . The point that T 1,2 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. [Copyright &y& Elsevier]

Abstract: Chalk develops as a result of diagenesis of pelagic calcareous ooze. In a newly deposited ooze sediment, porosity ranges from 60% to 80% but porosity reduces with burial. We studied how different porosity reduction mechanisms change the strength of these deep sea carbonate-rich sediments and effect Biot''s coefficient, β. In calcareous ooze, β is one. Mechanical compaction reduces porosity, but only leads to a minor decrease in β. Recrystallization renders particles smoother, but does not lead to reduction in β unless it gives rise to pore stiffening cementation. Pore stiffening cementation causes β to fall, even when porosity remains constant. Biot''s coefficient correlates with strength-indicating properties: compressional and shear modulus, oedometer modulus, yield strength, strain from direct loading and creep strain. Our data indicate that β may be used for predicting the diagenetic process involved in porosity reduction and strengthening of chalk during burial diagenesis. [Copyright &y& Elsevier]

Abstract: Predicting properties of reservoir chalk involve testing and modelling of easily obtainable outcrop chalk. However, variations in onshore and offshore chalk properties will expectedly occur due to different diagenetic history. Understanding diagenetic mechanisms and their consequences are thus a key issue when reservoir chalk characterization is based on outcrop chalk. In chalk of the Valhall field high pore pressure and hydrocarbon presence have counteracted recrystallization and cementation and preserved high porosity despite a burial depth of c. 3km. As a consequence inter-particle connections are poorly developed and Valhall chalk is expectedly geomechanically weak. Similar high porosity and weak consolidation were observed in Danish outcrop chalk which expectedly will match the Valhall samples geomechanically. In chalk of the Dan, South Arne and Ekofisk fields recrystallization and cementation features are significantly better developed compared to the Valhall field. Calcite redistribution has strengthened particle contacts and reduced porosity, assumingly providing a geomechanically stronger chalk. Similar low porosity and well-developed recrystallization and cementation features are found in English chalk which from a geomechanical point of view may share characteristics with chalk of the Dan, South Arne and Ekofisk fields. Matrix permeability is related not only to porosity but also to specific surface area of chalk which is controlled partly by calcite recrystallization partly by type and amount of non-carbonate minerals. In onshore chalk significant mineralogical differences are reflected in varying specific surface area. In contrast, specific surface area of Upper Cretaceous reservoir chalk show little variation indicating that care must be taken when choosing an outcrop chalk as substitute for reservoir chalk during flooding experiments. [Copyright &y& Elsevier]

Fluid withdrawal and pore pressure reduction change the effective stresses around a borehole and cause borehole instability associated with progressive localization of the damaged zone as well as potential fines production. Experimentally, chalk exhibits a complex geomechanics behaviour (pore collapse, shear failure, time/rate dependency) and modelling the behaviour of the borehole under in-situ and operational conditions requires the constitutive model to be capable of capturing the observations. This study presents a workflow that integrates rock mechanics testing on cylindrical specimens as well as specimen with a single lateral hole (SLH) and a finite element code, developed for chalk. The code incorporates post-peak softening as well as the rate dependency of the pore collapse stress in order to accurately predict the wellbore stability under in-situ stress conditions. The tested SLH specimen was CT imaged before and after testing for identifying the damaged zone and its extension. Backward numerical simulations of the SLH test data improved the accuracy of the estimated rock mechanics properties (post-peak failure and dilatancy) compared to the properties estimated by back analyses of standard triaxial tests with a single element simulator. The workflow is applied to predict the stability of a small lateral borehole (2 cm) created with Radial Jet Drilling technique with two different geometries: one with circular geometry created by a rotating nozzle; another with a circular hole with wing shaped cracks likely to develop when a static nozzle is used. Results of the wellbore stability analyses applying the chalk properties from the back analyses highlighted the importance of using experimentally verified post-peak failure and dilatancy parameters, together with a modelling tool capable of simulating shear strain localization incorporating the Cosserat approach. • This study integrates rock-mechanic tests and numerical simulations for open hole stability in chalk rocks. • Back analysis of standard triaxial tests using the single element simulator is carried out. • A Design and predictive model for the Single Lateral Hole test is validated. • Study shows the significant development of breakout zone during creep phase near the hole. [ABSTRACT FROM AUTHOR]

Chalk reservoirs, due to their high storage capacity and very low permeability, are one of the most interesting cases for reservoir engineering research on carbonates. They exhibit complex fluid-rock interactions because of their chemically active porous media. This study investigates the effect of brine composition, injection scenario, and temperature on oil recovery by low salinity water-flooding in chalk core samples from a Danish North Sea reservoir. The mechanisms governing oil-brine-rock interactions were also explored. Actual reservoir chalk core samples, without any open fractures, were selected using computed tomography analyses. These cores were saturated with representative fluids (crude oil and synthetic formation brine) and aged at reservoir conditions for approximately three weeks. The role of brine chemistry has been investigated through effluent analysis by ion chromatography, and results indicate that low salinity diluted seawater promotes rock-surface reactions if left to incubate for at least 48 h. Rock dissolution, observed through the monitoring of effluent ions, increased both with increase in temperature and decrease in brine salinity. The recovery curves show that formation water and diluted seawater produce significantly more oil (of the order of 10 % more) at the secondary stage compared to seawater. Additionally, there is also some indication of an effect of low salinity brine at the tertiary stage. These experiments were performed on reservoir materials and corresponding crude oil samples and provide new data on the low salinity flooding potential for chalk, and provide further evidence for the applicability of the low salinity effect in carbonates. • DSW and FW yield 11 % additional secondary recovery compared to SW in chalk. • Evidence for the low salinity effect was observed at the tertiary stage. • Evidence of magnesium mineral precipitation in low salinity flooding experiments. • Brine analyses of major ions show a piston-like flow and confirms rock dissolution. • Effect of increased temperature on the recovery was not observed in carbonate rock. [ABSTRACT FROM AUTHOR]

Abstract: This paper addresses the effect of brines, containing sulphate and magnesium (found in sea water) and distilled water as initial saturating and flooding fluids, on relative permeability of modified chalk cores by fatty acids to more oil-wet. A model oil system (n-decane) containing different fatty acids (present in oil) such as 18-phenyloctadecanoic acid (PODA—long chain fatty acid with unsaturated ring), Stearic acid (SA—saturated straight long chain), and brines containing sulphate and magnesium ions (0.03 M SO4 2− and 0.06 M Mg2+) dissolved in distilled water are used. Fatty acids alter the wettability of chalk to more oil-wet. PODA shows higher tendency compared to SA, at the same concentration, to alter the chalk to more oil-wet. Relative permeability curves are used as indication of the modified chalk behaviour. It also addressed the effect of the temperature on the relative permeability. A shift in the relative permeability to the right side indicates more water-wet with temperature up to ≤80 °C. At a higher temperature of 130 °C, the relative permeability curves indicate more oil-wet tendency. Wettability indicated by the relative permeability curves shows the influence of initially saturated fluid composition and the flooding fluid composition, where the modified cores initially saturated with ion free water (distilled water) and flooded by fluids containing Mg2+ or SO4 2− shows a shift indicating more water-wet compared to reference core (initially saturated and flooded by ion free water). However, if the initial saturating and flooding fluids contain 0.06 M Mg2+ ions, the wettability tends to be more oil-wet compared to that if the modified cores are saturated and flooded with 0.03 M SO4 2− and distilled water. The calculated pore size distribution index (λ) using Huang and Honarpour correlation, is used to determine the corrected (actual) relative permeability for capillary end effect. A good agreement between experimental and simulated relative permeability data was also obtained by using the calculated λ. [Copyright &y& Elsevier]

Abstract: Seawater has been injected into high temperature and natural fractured North Sea chalk reservoirs to improve oil recovery with great success. Previous studies have shown that seawater will improve the water wetness and cause enhanced compaction of the matrix. The composition of the produced water will be quite similar to initial formation water at the start of the water injection. The formation water contains various amounts of divalent cations like Mg2+, Ca2+, Sr2+, and Ba2+. Later on, the composition will change due to the interaction between seawater and the chalk formation and some mixing with formation water. The fluid–rock interaction will involve dissolution of CaCO3, substitution of Ca2+ by Mg2+ at the chalk surface, precipitation of CaSO4, SrSO4 and BaSO4 depending on the reservoir temperature. Because of environmental reasons, it is desirable to re-inject produced water together with seawater. In the forthcoming research, we will study experimentally the effect of this re-injection on oil recovery and chalk compaction by using mixtures of produced water and seawater as injection fluid. Based on model studies using the OLI software package, the compatibility of mixtures of produced water and seawater has been studied at different temperatures by looking at the precipitation of CaSO4, SrSO4 and BaSO4. Also the impact of changes in the concentrations of Ca2+ and Mg2+ due to surface substitution is modelled. The results are discussed in terms of possible scale formation in the producer and injector. In addition, actual chemical equilibrium reactions in the chalk matrix are discussed in relation to variation in temperature during continuous injection of seawater. Special focus is made on wettability modification, irreversible thermodynamics, and impact on the mechanical strength of the chalk matrix. [Copyright &y& Elsevier]

Abstract: Chalk formations in the southern part of the North Sea are important oil reservoirs, where seawater injection, as an IOR fluid, has been used with great success to improve oil recovery in high temperature reservoirs. Compaction is observed due to water weakening of the chalk matrix, which has initiated an extensive research to study the mechanism of this weakening effect. In most cases, outcrop chalk was used as a model sample. In this paper, the effect of anisotropy on mechanical properties within two outcrop chalks is studied by drilling samples horizontally and vertically from the same chalk block. It is of interest when performing experimental research to have comparable test material. In that way, large test series can be performed on test material with similar mechanical properties. The results showed that all mechanical properties, except permeability and tensile strength, displayed anisotropic behaviour. The difference in compressive strength was a factor 1.20 to 1.45 for the different drilling directions, while for the bulk modulus the difference was a factor 1.45 to 1.50. Drilling direction had only minor affect on the permeability measurements, the reduction in permeability by increasing hydrostatic stress appeared however to be controlled by the total volumetric strain. These results indicate that mechanical properties from outcrop chalk are only directly comparable when the chalk samples are collected and drilled in the same direction from the same block of chalk. [Copyright &y& Elsevier]

Abstract: Seawater is injected into the high temperature North Sea chalk reservoirs to improve oil recovery with great success. Increased compaction of the rock, which also is a significant contribution to the oil displacement, is observed in the water-flooded area. Very recent laboratory studies at high temperature documented that enhanced compaction took place when chalk cores were flooded by seawater under stress. The special composition of seawater, regarding reactive ions towards the chalk surface, appeared to be the reason. In this paper, two different water-weakening mechanisms are discussed: (1) Substitution of Ca2+ at the inter-granular contacts by Mg2+ and (2) Chemical dissolution. The effect of temperature is opposite for the two mechanisms. The impact of temperature on chalk compaction is studied both in a static (cores aged in water) and dynamic (cores flooded with water) way by performing hydrostatic tests by use of standard triaxial cells. Distilled water was used as a reference fluid in the static tests at 80–130 °C. The mechanical strength of chalk containing seawater was opposite to chalk containing distilled water. With seawater, the chalk became weaker as the temperature increased, while using distilled water, the chalk became stronger as the temperature increased. In the dynamic creep tests, at 50–130 °C, the cores flooded with seawater were significantly weaker than cores flooded with seawater without sulfate, but the difference in mechanical strength decreased as the temperature decreased. The mechanism for enhanced chemical induced weakening of chalk by seawater is discussed. [Copyright &y& Elsevier]

Abstract: Spontaneous imbibition (SI) of water into the matrix blocks is believed to be a very important drive mechanism for oil recovery from naturally fractured reservoirs, including the Ekofisk field in the North Sea. This work presents SI of artificial seawater containing sulfate ions at 130 °C on outcrop chalk saturated with crude oil (plus connate water) of high acid number to render the wettability of the porous medium preferential oil-wet. The results for the SI tests show that artificial seawater containing sulfate ions is able to spontaneously imbibe into preferential oil-wet chalk (at 40 °C) due to a wettability modification process towards more water-wet conditions. No imbibibition of any water took place at 40 °C. After raising the temperature to 130 °C, a water saturation change of 28% was observed during 15 days of imbibition time on two duplicated core samples (from S wi =24% to 52%). The SI taking place at elevated temperature is interpreted as a wettability modification process, where the sulfate ions in the imbibing water phase are assumed to play a very important role. One core sample was re-saturated with crude oil after the SI process had ceased and the relative permeability of oil and water was measured using the steady-state method. The high end-point relative permeability of water k rw ⁎ =0.761 indicated core surface to be close to neutral wettability. The measured relative permeability curves were then utilized to generate a capillary pressure curve by history matching oil production vs. time to the oil production measured experimentally using numerical simulations. The result showed that weak capillary forces were generated as a result of the SI process. Further fine-grid simulations after magnifying the size of the core sample up to 100 times (diameter D =350 cm and height H =691 cm) showed that weak induced capillary forces contributed significantly to the initial oil production rate even for the largest sample investigated. This result indicated that the induced capillary forces after a wettability modifying process may have effect on field oil production rates, as the matrix blocks investigated are representative for those blocks sizes (D =350 cm and H =691 cm) usually applied, when modeling fractured reservoirs by the dual-porosity scheme. [Copyright &y& Elsevier]

Abstract: Wettability, water-wetness or oil-wetness, is usually defined in terms of the method used to determine the wetting state of a porous medium. In the Amott test, which is most frequently used for porous media, the wetting indices of water and oil are determined by the extent of spontaneous imbibition of water and oil from the state of the corresponding residual fluid saturations of the core. Thus, the Amott fluid wetting index reflects the potential capillary energy associated with the spontaneous imbibition process, which results in a very insensitive way to detect wetting alterations close to neutral conditions. Unfortunately, the natural wetting state of many carbonate reservoirs is close to neutral conditions or preferential oil-wet. In this paper, the wetting state of porous chalk is characterized by the fraction of surface area covered by one of the two fluids, i.e. water or oil. As the new wettability test is based on the chromatographic separation of two water-soluble components, i.e. a tracer, SCN−, and a potential determining ion towards chalk, SO4 2−, the fraction of the surface area covered by water was decided to represent the new wetting index. Using a chalk core at residual oil saturation, the area between the effluent curves for SCN− and SO4 2− is proportional to the area contacted by water during the flooding process. The ratio between this area and the corresponding area obtained from a completely water-wet core will give a water index between 0 and 1, representing completely oil-wet and completely water-wet conditions, respectively. The method is excellent to be used close to neutral condition, which will give a wetting index of 0.5. Experimental results are presented for two different chalks at different wetting conditions. Furthermore, the change in the Zeta-potential of the chalk surface over the dispersion zone of SO4 2− is visualised by a gradient in the Ca2+ concentration in the same region. [Copyright &y& Elsevier]

Abstract: The mechanical strength of high porosity chalk is affected by using carbonate water as EOR (Enhanced Oil Recovery) fluid. The water-weakening effect is enhanced due to increased dissolution of chalk in the presence of CO2(aq). In this study, the mechanical properties of chalk were compared with and without CO2(aq) present in the injected water. By use of a standard triaxial cell, series of samples with and without pre-flooding at confining pressure of 0.5–1.0MPa were hydrostatic loaded up to yield point at room temperature or 90°C. Then a major part of the samples were exposed to subsequent creep and flooding phases at increased stress levels of about 2MPa above yield point. In all cases flooding experiments were performed without any backpressure and with flooding pressure varying between 0.2 and 0.8MPa. Injection of pure CO2 gas into water-saturated chalk resulted in only marginal weakening of the chalk material. At stress levels below the yield point, the chalk exposed to carbonate water becomes considerably weaker than chalk flooded with pure Eq. Water. At a given flooding pressure of carbonate water, an increase in temperature to 90°C improved the chalk stability. Flooding with CO2 saturated modified seawater, which contained an enhanced concentration of sulfate, increased the strain significantly due to the precipitation of CaSO4·2H2O(s). The preferential oil-wet cores at S or =0.62 experienced an increased strain of 20% compared to the water-wet test series during flooding with CO2-saturated Eq. water. Increasing the confining pressure by a factor of 10, strain values of about 10 times higher or even more were observed when flooding with carbonate water. The experimental observations are discussed in terms of chemical and pressure dissolution of chalk. [Copyright &y& Elsevier]

Abstract: The Yibal field, the largest oil field in Oman, comprises 15% of the oil production of the country. The field has had a high ultimate recovery factor and in order to maintain the current recovery trend, different management strategies have been sought. One of the options is the injection of a dilute surfactant in addition to the current waterflooding. The cores from the chalky Shuaiba formation were saturated with brine and oilflooded to restore the initial reservoir condition after cleaning. Nineteen samples were waterflooded followed by dilute surfactant injection. Eight samples were flooded with dilute surfactant. The reason for this scheme is that some parts of the reservoir under study were totally watered out while others are still untouched. In addition to these experiments, nine capillary (static) imbibition experiments were conducted to treat fractured zones where recovery by capillary imbibition during injection is a possibility. Twelve different surfactants (at different concentrations) were tested. Five surfactants were non-ionic, two cationic, four anionic, and one was a mixture of anionic and non-ionic. The selection of the optimum concentrations was based on IFT values at different concentrations. The results were evaluated in terms of the final oil recovery. The average waterflooding recovery was found to be 75.1% of OOIP (out of 19 experiments) whereas surfactant injection yielded an average of 69.9% of OOIP (out of 8 experiments). This indicates that the surfactant injection is not preferable and not recommended over waterflooding for the untouched portion of the reservoir where the rock matrix dominates the flow (unfractured portions). An additional recovery by surfactant solution injection succeeding waterflooding was obtained and found to vary between 0% and 7.4% of OOIP. The surfactant injection is, therefore, recommendable in the pre-waterflooded unfractured zones as long as the proper surfactant type is selected. Half of the surfactant solutions yielded higher and faster capillary imbibition recovery than brine. For the untouched fractured zones of the chalky reservoir, it is more effective to start the injection with surfactant addition rather than waterflooding alone. Surfactant types and concentrations yielding the best performances were identified and listed in this paper. [Copyright &y& Elsevier]

Abstract: Chalk petroleum reservoirs are characterized as fragmentary parts of calcite skeletons produced by plankton algae, known as coccolithophorids. As water injection into chalk reservoirs is an important method for improved oil recovery, chalk–water interactions have received considerable attention during the decades due to reservoir compaction. In the present study the mechanical properties of high porosity outcrop chalk (>40%) were studied with mixtures of water and glycol. The objective was to test the hypothesis that the activity of water is the key parameter in water-weakening of chalk. This hypothesis is based on experiments with brine-saturated chalk of different salinities. The fact that water and glycol are fully miscible fluids allows variation of water activity from unit to zero. Four types of tests were used: (1) triaxial tests at low confining pressure to assure shear failure conditions, (2) triaxial tests at higher confining pressure to assure a stress path passing through the end-cap, (3) hydrostatic tests to determine the hydrostatic yield stress and (4) “Brazilian” tests. The tests showed increasing strength with decreasing water activity. Compared with the results from brines, there was good agreement, confirming the hypothesis. Previously results using water–methanol mixtures resulted in the same conclusion. A water weakening mechanism is proposed which involves an additional pressure exerted on the grains by attraction of water molecules to the chalk surface. This adsorption pressure acts like an increase in pore pressure, decreasing the cohesion of the chalk. Evaluation of different mechanisms in chalk–water interactions, indicate that pressure solution and adsorption pressure may be the two most important ones. [Copyright &y& Elsevier]

Abstract: The objective of the present study is to provide a better understanding about the mechanism for weakening of chalk reservoirs when injecting large quantities of seawater to improve the oil recovery. The mechanical stability of chalk has often been related to capillary forces, which is known to induce an apparent cohesion between chalk grains, although several researchers have pointed out that other mechanisms need to be considered as well. In the present study, the experimental conditions have been designed to quantify the weakening of the chalk in a chemical dissolution/precipitation process, when one of the common ions, Ca2+ or CO3 2−, was chemically removed from the solution at 130 °C during an aging time of 6 weeks. Removal of one of the common ions enhances the dissolution of chalk. Three different saturating fluids were used: (1) artificial Ekofisk formation brine (EF-brine), (2) artificial seawater (SSW), and (3) modified seawater containing 4 times the sulphate concentration with respect to artificial seawater (SSW1). At the aging conditions, CaSO4(s) was about to precipitate from the SSW1 solution, causing dissolved Ca2+ ions from the chalk to be precipitated/removed as CaSO4(s) from the solution. No removal of common ions took place using EF-brine and SSW. Mechanical tests (Brazilian tests, hydrostatic yield, and K-modulus) at room temperature of the chalk cores saturated with the actual fluids showed that the strength of chalk saturated with SSW1 was 20–25% weaker than cores saturated with EF-brine and SSW. No difference in chalk strength was detected using EF-brine and SSW. The greater water weakening of cores saturated with SSW1 was discussed in terms of a chemical dissolution/precipitation process and the chemistry of the thin water film close to the intergranular contacts. [Copyright &y& Elsevier]

This study investigates two cases of velocity predictions for North Sea chalk: fluid substitution of compressional velocity (vP) and estimation of shear velocity (vS). Both high frequency laboratory and intermediate frequency logging data are included. We test five rock physics methods and two empirical relations that have been established or tested for other lithologies. The predicted velocities are tested against measured velocities or velocities estimated from Gassmann''s relations, which are confirmed to give good velocity estimates for water-saturated chalk from data on dry samples. In one case, we test predicted fluid effects on compressional velocity without knowing shear velocity. The fluid substitution effect on the compressional velocity is well estimated from all the four methods: the bound averaging method (BAM), the isoframe method, the method of replacing bulk modulus in the Gassmann''s relations with P-wave modulus and the method of decomposition of measured P-wave modulus into shear and bulk modulus. In the other case, we test shear velocity estimated from compressional velocity. We recommend the isoframe method for shear wave estimation for saturated chalk. All methods tend to underestimate shear velocity in dry chalk. For water-saturated chalk, also the empirical second-order polynomial relation between compressional and shear velocity of water-saturated limestone of Castagna et al. [Castagna, J.P., Batzle, M.L., Kan, T.K., 1993. Rock physics—the link between rock properties and AVO response. In: Castagna, J.P., Backus, M.M. (eds.), Offset-Dependent Reflectivity-Theory and Practice of AVO Analysis, Investigations in Geophysics, no. 8. Society of Exploration Geophysicists, 135–171.] gives good shear velocity estimates. The empirical constant ratio between compressional and shear velocity of water-saturated limestone of Pickett [J. Pet. Technol. 15 (1963) 650.] overestimate low shear velocities for high porosity chalk and the shear velocity is systematically underestimated by the method of decomposing P-wave modulus. [Copyright &y& Elsevier]

It is possible to improve the oil recovery from low temperature, oil-wet/neutral-wet, fractured carbonate reservoirs by spontaneous imbibition of water using nontoxic low-cost primary amines, R–NH2, as wettability alteration chemicals added to the injection water. The present paper discusses possible limitations in the performance of the chemicals such as solubility, pH, carbonate dissolution, and temperature effects. It was observed that C10-amine was compatible with high salinity brine at pH<7 in the temperature range of 20–70 °C, but C12-amine was insolvable at similar conditions. C10-amine (1.0 wt.%) was dissolved in brine at pH=6.5 and imbibed spontaneously into oil-wet reservoir dolomite cores at 20 and 40 °C. The oil recovery varied between 50% and 75% of original-oil-in-place (OOIP) depending on the core properties. The mechanism for the wettability alteration using C10-amine is believed to be similar to the previously studied C12TAB system, i.e., desorption of strongly adsorbed carboxylates from the carbonate surface by the formation of ion-pairs. At 70 °C, C10-amine appeared to fail as a wettability-modifying chemical, probably due to the dissolution of carbonate rock. The concentration of the active component C10NH3+ in the aqueous phase of the pores decreases in this dissolution process. Advancing contact angle measurements on oil-treated calcite crystals confirmed the potential of the C10-amine solution to make the surface strongly water-wet at pH=6.5 in the temperature range of 20–90 °C. [Copyright &y& Elsevier]

This paper reports an investigation of in situ wettability distribution and wetting stability of moderately water-wet and nearly neutral-wet outcrop chalk cores, aged in crude oil at elevated temperature.In this paper, in situ wettability measurements by magnetic resonance imaging (MRI) tomography are shown to give Amott indices that agree well with the standard wettability indices based on average saturations. The in situ method provides information concerning Amott index distribution radially and along the length of the core plugs.Applying multidirectional crude oil flooding during aging, uniform wettability distributions, both radially and axially, were obtained.Tests of wetting stability confirmed that stable wettability alterations for repeated waterfloods and Amott tests were established. The results showed that the core plugs should not be dried or cleaned because this will render the core plugs strongly water-wet. Stable wettability conditions were measured for cores subjected to storage in brine at 90 °C. [Copyright &y& Elsevier]

Systematic studies involving stochastic reconstruction, geometric and topological characterization, and network modeling of chalk, aiming at computation of petrophysical properties, are reported. The numerical chalk models are constructed exclusively from limited morphological information obtained from 2D backscatter scanning electron microscope images of the microstructure. Two different stochastic reconstruction methods are considered: conditioning and truncation of Gaussian random fields (GRF), and simulated annealing (SA). The potential of initializing the simulated annealing reconstruction with input generated using the Gaussian random fields method is evaluated and found to accelerate significantly the rate of convergence of simulated annealing reconstruction. This finding is important because the main advantage of simulated annealing method, namely its ability to impose a variety of reconstruction constraints, is usually compromised by its very slow rate of convergence.A detailed description of the chalk microstructure in the form of 3D volume data is essential for the prediction of petrophysical properties from first principles. The prediction of absolute permeability and formation factor directly from such information are considered first. The prediction of absolute permeability, formation factor and mercury–air capillary pressure curves are then considered using approximate network models constrained by information (pore- and throat-size distributions, coordination number) obtained from geometric and topological analysis of the reconstructed pore networks. Such information is extracted from the 3D volume data using morphological skeletonization and pore space partitioning methods. Very good agreement between the predicted and measured data is found for samples of North Sea chalk. On the basis of this study, it is concluded that (a) stochastic reconstruction from limited morphological information reproduces the essential features of pore geometry and connectivity of chalk, and (b) network modeling techniques can be used to predict petrophysical properties of chalk based on geometric and topological information of the stochastically reconstructed media. [Copyright &y& Elsevier]

We report the stochastic reconstruction of chalk pore networks from limited morphological information that may be readily extracted from 2D backscatter electron (BSE) images of the pore space. The reconstruction technique employs a simulated annealing (SA) algorithm, which can be constrained by an arbitrary number of morphological descriptors. Backscatter electron images of a high-porosity North Sea chalk sample are analyzed and the morphological descriptors of the pore space are determined. The morphological descriptors considered are the void-phase two-point probability function and lineal path function computed with or without the application of periodic boundary conditions (PBC). 2D and 3D samples have been reconstructed with different combinations of the descriptors and the reconstructed pore networks have been analyzed quantitatively to evaluate the quality of reconstructions. The results demonstrate that simulated annealing technique may be used to reconstruct chalk pore networks with reasonable accuracy using the void-phase two-point probability function and/or void-phase lineal path function. Void-phase two-point probability function produces slightly better reconstruction than the void-phase lineal path function. Imposing void-phase lineal path function results in slight improvement over what is achieved by using the void-phase two-point probability function as the only constraint. Application of periodic boundary conditions appears to be not critically important when reasonably large samples are reconstructed. [Copyright &y& Elsevier]

This paper emphasizes how wettability may be altered for special core analysis purposes and by which processes this occurs. Studies of how the imbibition characteristics change after aging core plugs in crude oil are reported, focusing on imbibition rate and endpoint saturations and on the induction time.Imbibition characteristics after wettability alteration by aging core plugs submerged in crude oil at elevated temperature are compared to the effects from aging procedures, where crude oil is continuously flushed through the core plugs during the aging and after simply leaving the plug at connate water saturation under static, i.e. no flow conditions, shows different significant results. The results show that: (1) continuously introducing fresh crude oil boosts the aging process and (2) a significant impact on the wettability alteration as a function of core length is observed, reflecting the absorption of active components for the wettability alteration process. In an integrated study consisting of experiments and numerical simulation, this paper also demonstrates the importance of close interaction between how to alter the wettability, applications of the technique in core analysis and numerical simulations of the latter. Finally, the significance of some sensitive parameters is demonstrated. [Copyright &y& Elsevier]

A first and detailed study of the geochemistry and mineralogy characterizing the North Sea reservoir and non-reservoir chalk is provided in this work. The study is based on 185 cores from exploration and development wells in the North Sea. The cores related to reservoir development have different flooding status – unflooded or waterflooded at various temperatures – and are directly sampled from the Ekofisk field. Optical petrography shows a micritic carbonate matrix, with grains represented by various microfossils such as foraminifers and sponge spicules. Scanning electron microscopy (SEM) reveals post-depositional calcite precipitation and cementation. Dolomite is found only in the reservoir samples, but it is discussed as a diagenetic feature, unrelated to the hydrocarbon content or EOR exposure. The non-carbonate minerals observed with BSE-SEM and XRD include mostly quartz but also smectite, illite, kaolinite, mica, and pyrite. The abundance of clastic input varies, and there is a clear decrease in porosity stratigraphically downwards, with stronger cementation and higher compaction. δ13C reflects primary trends for Upper Cretaceous stages while δ18O in all samples is lower than the secular global isotopic values for this period. However, the δ18O values are not sufficiently low to imply a strong diagenetic overprint, but rather suggest the influence of a secondary fluid. This fluid cannot be a hydrocarbon-rich one, nor EOR fluids, as non-reservoir samples, as well as flooded and unflooded reservoir samples show very similar stable isotope values. • Mineralogical and geochemical characterization of broad North Sea chalk sample set. • Comparison between flooded and unflooded reservoir chalk and non-reservoir chalk. • The diagenetic overprint is low in all lithotypes. • The presence of hydrocarbons is not responsible for geochemical alterations. • The geochemical effect of EOR flooding of reservoir chalk is not obvious. [ABSTRACT FROM AUTHOR]

Seawater injection for Enhanced Oil Recovery (EOR) purposes can increase the hydrocarbon recovery factor in carbonate reservoirs but are also responsible for weakening their mechanical strength. This study investigates the geomechanical behavior of oil-bearing reservoir chalk subject to reactive flow at reservoir conditions. The obtained results are compared with previous results from experiments on water-saturated outcrop chalks. Two unwashed oil-bearing reservoir chalk cores from the Eldfisk Field in the North Sea are mechanically tested in a triaxial cell. The cores are saturated with NaCl brine prior to testing, in addition to residual oil. The cores' axial and radial deformations were monitored during hydrostatic stress loading and creep under constant 50 MPa stress, at 130 °C. During the test, the cores were flooded with 0.657 M NaCl, 0.219 M MgCl 2 , 0.219 M MgCl 2 + 0.130 M CaCl 2 and synthetic seawater (SSW). The average creep strain increased from 0.03% to 0.04% per day radially and from 0.03% to 0.06% axially after changing from the NaCl brine to SSW brine. Flooding MgCl 2 brine after NaCl increased the average compaction rate from 0.05% to 0.09% per day radially and from 0.04% to 0.07% per day axially. Adding CaCl 2 to the MgCl 2 brine reduced the average compaction rate from 0.05% per day during MgCl 2 injection to 0.02% per day both radially and axially, comparable to reports from outcrop chalk experiments. The brine composition-dependent creep compaction in the core flooding experiments was explained by dissolution of primary calcite, confirmed by Ion Chromatography, and precipitation of secondary Mg-bearing minerals, seen by Scanning Electron Microscopy (SEM) analytics. Generally, the aforementioned results describing geomechanical behaviors of oil-bearing reservoir chalk cores under hydrostatic stress and thermochemical influence in this study are comparable to those from previous studies on outcrop chalk, thus supporting many years of laboratory research as applicable in the reservoir chalk context. • Mechanical and chemical compaction study of actual reservoir chalk cores. • Comparison between compaction behavior of reservoir chalk and outcrop chalk. • Creep deformation rate depends on the flooding brine composition. • Excess calcium in flooding water inhibits compaction of reservoir chalk. • Compaction results are comparable to previous water-wet outcrop chalk tests. [ABSTRACT FROM AUTHOR]

Laboratory core restoration procedures include different core cleaning solvents, establishment of initial water saturation (S wi) by diverse techniques and processes of crude oil exposure that influence the final core wetting properties.In carbonate reservoirs, the acidic Polar Organic Components (POC) in crude oil are the main components dictating the wettability of the carbonate surface. Negatively charged carboxylates strongly attach to the positively charged CaCO 3 surface, thus acting as anchor molecules for the oil phase.During core cleaning with organic solvents, some of the adsorbed POC will be detached from the mineral surfaces, thereby changing the wetting conditions. However, cores are not expected to become completely water-wet even when using strong solvents.The main aim of this paper is to develop core cleaning and core restoration procedures to reproduce initial core wettability.Fractional-wet outcrop chalk cores were exposed to two different core cleaning procedures, (1) mild kerosene-heptane cleaning, or (2) standard toluene-methanol cleaning. Chromatographic wettability tests showed that both cleaning methods increased the fraction of water-wet surface area to a similar extent, but neither of them removed all adsorbed POC from the rock surface. Wettability tests by spontaneous imbibition showed that the kerosene-heptane cleaned core behaved slightly water-wet, while the toluene-methanol cleaned core behaved very water-wet, even though the cores had similar fractions of water-wet surface areas. Increased amount of crude oil exposure during core restoration reduced the water wetness below the initial fractional core wetting.Initial core wettability was successfully reproduced by combining mild cleaning solvents preserving initial adsorbed POC, and minimizing the amount of crude oil exposure during core restoration. Only a 1.5–3.6 %OOIP variation in ultimate recovery during spontaneous imbibition in four different core systems was observed. • The toluene-methanol cleaned core behaved more water-wet than the kerosene-heptane-cleaned core in spontaneous imbibition tests. • Reproduction of wetting after mild cleaning was attempted by only introducing (1-Swi) PV crude oil by vacuum-saturation. • Initial wetting reproduction was successful, with a difference of +1.5–3.6% OOIP between first and second restorations. • By this procedure, only a minimum volume of crude oil is therefore needed to reproduce the carbonates wettability. • The original reservoir oil can be different in composition to the in-situ reservoir oil today, thus, this procedure could result in a more representative reservoir core wettability than that obtained in standard routine SCAL analyses. [ABSTRACT FROM AUTHOR]

The organic-rich Late Cretaceous carbonates of the Ghareb and Mishash formations are potentially both self-sourced unconventional reservoirs and high quality source rocks for conventional petroleum systems in the eastern Mediterranean region. In this study we use cores from depths ranging from 340 to 1290 m in the Shefela and Golan Heights basins in Israel, which records the diagenesis and transformation phases of organic-rich chalk into limestone. Understanding such source rocks is complicated by the fact that each formation is unique and heterogeneity is common within each formation. Moreover, in situ samples at various stages of maturation are rarely available. We apply the three-plug measuring technique for a vertical transversely isotropic (VTI) medium to investigate the ultrasonic wave velocity and permeability anisotropies of organic-rich chalks (ORC) within the tested sequence. We propose that in ORC diagenesis, the characteristics and distribution of the organic matter in the rock matrix change significantly throughout burial and thermal maturation, strongly affecting the velocities. Measuring the velocity hysteresis under varying confining pressures revealed that development of soft porosity with preferred orientation plays a crucial role in the early maturation stage (TMAX of 428–434°C), particularly under low effective stresses, while it is absent in the immature stage (TMAX of 403–415°C). The sensitivity of the wave velocities at low effective stresses results in variations in velocity anisotropy, which may potentially be utilized in seismic exploration to delineate the highly-pressured 'sweet spots' in unconventional organic-rich carbonates. • Evolution of organic-rich carbonates during diagenesis and early thermal maturation. • Porosity, permeability, and velocity laboratory analysis of native state cores. • Significant changes in wave velocity and permeability anisotropies with maturation. • Changes in velocity hysteresis generated by confining pressure with maturation. • Results are analyzed and discussed using the Iso-Frame effective medium model. [ABSTRACT FROM AUTHOR]