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Magnetic resonance imaging was used to monitor and quantify methane hydrate formation and exchange in porous media. Conversion of methane hydrate to carbon dioxide hydrate, when exposed to liquid carbon dioxide at 8.27 MPa and approximately 4 degrees C, was experimentally demonstrated with MRI data and verified by mass balance calculations of consumed volumes of gases and liquids. No detectable dissociation of the hydrate was measured during the exchange process.

A novel centrifuge technique to obtain the capillary pressure curve by measuring the local fluid distribution in a spinning core is presented. The Nuclear Tracer Imaging Centrifuge (NTIC) method measures the fluid saturation profile along the length of the core to directly obtain the capillary pressure curve. The proposed method is superior to conventional centrifuge techniques because (1) the capillary pressure curve is obtained at one rotational speed, (2) core plugs are not removed from the spinning centrifuge for imaging, and (3) no mathematical solution is needed to calculate the capillary pressure curve. The literature states that the various mathematical solutions used in conventional centrifuge tests are the greatest source of error, not the uncertainty in the experimental data. By eliminating the dependence of such solutions, the NTIC represents an alternative to conventional centrifuge tests, and may be used to validate the various mathematical procedures applied in conventional centrifuge capillary pressure tests. NTIC may also confirm the applicability of other imaging techniques that rely on core plug removal for saturation imaging, by verifying if there is no fluid re-distribution at static conditions.

Storage of CO2 in natural gas hydrate reservoirs may offer stable long term deposition of a greenhouse gas while benefiting from methane production, without requiring heat. By exposing hydrate to a thermodynamically preferred hydrate former, CO2, the hydrate may be maintained macroscopically in the solid state and retain the stability of the formation. One of the concerns, however, is the flow capacity in such reservoirs. This in turn depends on three factors; 1) thermodynamic destabilization of hydrate in small pores due to capillary effects, 2) the presence of liquid channels separating the hydrate from the mineral surfaces and 3) the connectivity of gas- or liquid filled pores and channels. This paper reports experimental results of CH4- CO2 exchange within sandstone pores and measurements of gas permeability during stages of hydrate growth in sandstone core plugs. Interactions between minerals and surrounding molecules are also discussed. The formation of methane hydrate in porous media was monitored and quantified with magnetic resonance imaging techniques (MRI). Hydrate growth pattern within the porous rock is discussed along with measurements of gas permeability at various hydrate saturations. Gas permeability was measured at steady state flow of methane through the hydrate-bearing core sample. Experiments on CO2 injection in hydrate-bearing sediments was conducted in a similar fashion. By use of MRI and an experimental system designed for precise and stabile pressure and temperature controls flow of methane and CO2 through the sandstone core proved to be possible for hydrate saturations exceeding 60%. publishedVersion

Summary Magnetic resonance imaging (MRI) of core samples in laboratory experiments showed that CO2 storage in gas hydrates formed in porous rock resulted in the spontaneous production of methane with no associated water production. The exposure of methane hydrate in the pores to liquid CO2 resulted in methane production from the hydrate that suggested the exchange of methane molecules with CO2 molecules within the hydrate without the addition or subtraction of significant amounts of heat. Thermodynamic simulations based on Phase Field Theory were in agreement with these results and predicted similar methane production rates that were observed in several experiments. MRI-based 3D visualizations of the formation of hydrates in the porous rock and the methane production improved the interpretation of the experiments. The sequestration of an important greenhouse gas while simultaneously producing the freed natural gas offers access to the significant amounts of energy bound in natural gas hydrates and also offers an attractive potential for CO2 storage. The potential danger associated with catastrophic dissociation of hydrate structures in nature and the corresponding collapse of geological formations is reduced because of the increased thermodynamic stability of the CO2 hydrate relative to the natural gas hydrate.

The effect of fractures on oil recovery and in situ saturation development in fractured chalk has been determined at near neutral wettability conditions. Fluid saturation development was monitored both in the matrix and in the fractures and the mechanisms of fracture crossing were determined using high spatial resolution MRI. Capillary continuity across open oil-filled fractures was verified by imaging the water bridges established within the fracture. Despite an alternate escape fracture for the water, separate water bridges were shown to be stable for the entire duration of the experiments. The established capillary contact resulted in oil recovery exceeding the spontaneous imbibition potential in the outlet-isolated cores by ca. 10% PV. This is explained by viscous recovery provided by water bridges across open fractures. The size of the bridges seemed to be controlled by the wettability of the rock and not by the differential pressure applied across the open fracture.

Reservoirs of clathrate hydrates of natural gases (hydrates), found worldwide and containing huge amounts of bound natural gases (mostly methane), represent potentially vast and yet untapped energy resources. Since CO2-containing hydrates are considerably more stable thermodynamically than methane hydrates, if we find a way to replace the original hydrate-bound hydrocarbons by the CO2, two goals can be accomplished at the same time: safe storage of carbon dioxide in hydrate reservoirs, and in situ release of hydrocarbon gas. We have applied the techniques of Magnetic Resonance Imaging (MRI) as a tool to visualize the conversion of CH4 hydrate within Bentheim sandstone matrix into the CO2 hydrate. Corresponding model systems have been simulated using the Phase Field Theory approach. Our theoretical studies indicate that the kinetic behaviour of the systems closely resembles that of CO2 transport through an aqueous solution. We have interpreted this to mean that the hydrate and the matrix mineral surfaces are separated by liquid-containing channels. These channels will serve as escape routes for released natural gas, as well as distribution channels for injected CO2.

Here we show for the first time the combined positron emission tomography (PET) and computed tomography (CT) imaging of flow processes within porous rocks to quantify the development in local fluid saturations. The coupling between local rock structure and displacement fronts is demonstrated in exploratory experiments using this novel approach. We also compare quantification of 3-D temporal and spatial water saturations in two similar CO2 storage tests in sandstone imaged separately with PET and CT. The applicability of each visualization technique is evaluated for a range of displacement processes, and the favorable implementation of combining PET/CT for laboratory core analysis is discussed. We learn that the signal-to-noise ratio (SNR) is over an order of magnitude higher for PET compared with CT for the studied processes. publishedVersion

The flow of CO2 in porous media is fundamental to many engineering applications and geophysical processes. Yet detailed CO2 flow visualization remains challenging. We address this problem via positron emission tomography using 11C nuclides and apply it to tight formations—a difficult but relevant rock type to investigate. The results represent an important technical advancement for visualization and quantification of flow properties in ultratight rocks and allowed us to observe that local rock structure in a layered, reservoir shale (K = 0.74 µdarcy) sample dictated the CO2 flow path by the presence of high-density layers. Diffusive transport of CO2 in a fractured sample (high-permeable sandstone) was also visualized, and an effective diffusion coefficient (Di = 2.2 · 10−8 m2/s) was derived directly from the dynamic distribution of CO2. During CO2 injection tests for oil recovery from a reservoir shale sample we observed a recovery factor of RF = 55% of oil in place without fracturing the sample. publishedVersion

Miscible CO2 and CO2-foam laboratory injection tests were performed to study Enhanced Oil Recovery (EOR) processes in strongly water-wet fractured carbonate core material to evaluate the potential of foam for mobility control. The experimental results demonstrate a significant oil recovery potential during pure scCO2 injection in baseline unfractured cores: endpoint oil recovery was up to 98%OOIP and 80%OOIP was produced after 2PVof scCO2 injection starting at Swi. Recovery and production rates were significantly lower and slower for fractured cores where oil recovery was mainly driven by diffusion: 58-68%OOIP was recovered after 10PV injected. By switching to scCO2-foam injection after 1-2PV of pure scCO2, a viscous component was added to the oil displacement process, which increased oil recovery rates and final recoveries for all experiments. Integrated EOR (IEOR) schemes of waterfloods followed by tertiary CO2 and CO2-foam injection was also investigated for intricate fracture systems. Magnetic Resonance Imaging (MRI) provided in situ visualization of local development in oil saturations and fluid displacement fronts during waterflood and CO2 injection. It is shown that CO2 mobility control using CO2-foam significantly increase oil recovery during CO2 injection and will meet the challenges of low macroscopic sweep efficiency and the adverse water-shielding effect in CO2-EOR.

Polymer gels are frequently applied for conformance improvement in fractured reservoirs, where fluid channeling through fractures limits the success of waterflooding. Placement of polymer gel in fractures reduces fracture conductivity, thus increasing pressure gradients across matrix blocks during chase floods. A gel-filled fracture is re-opened to fluid flow if the injection pressure during chase floods exceeds the gel rupture pressure, thus channeling through the fractures resumes. The success of a polymer gel treatment therefore depends on the rupture pressure. Swelling of gels, e.g. pre-formed particle gels, due to salinity differences between the gel network and surrounding water phase has recently been observed, but the effect has been less studied in conjunction with conventional polymer gels. Using core floods, this study demonstrates that low-salinity water can swell conventional Cr(III)-acetate HPAM gels, thereby improving gel blocking performance after gel rupture. Formed polymer gel was placed in fractured core plugs and chase waterfloods were performed, using four different brine compositions of which three were low-salinity brines. The fluid flow rates through the matrix and differential pressures across the matrix and fracture were measured and shown to increase with decreasing salinity in the injected water phase. In some cores, the fractures were re-blocked during low-salinity waterfloods, and gel blocking capacity was increased above the initial level. Low-salinity water subsequently flooded the matrix during chase floods, which provided additional benefits to the waterflood. The improved blocking capacity of the gel was caused by a difference in salinity between the gel and injected water phase, which induced gel swelling. The results were reproducible through several experiments, and stable for long periods of time in both sandstone and carbonate outcrop core materials. Combining polymer gel placement in fractures with low-salinity chase floods is a promising approach in integrated EOR (IEOR).

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.

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.

Alteration of the wettability is often a part of the restoration process for core plugs or used to obtain a desired wettability in outcrop plugs. If the procedure does not provide a uniform wettability state in the plug, experimental artifacts can result. For immersion under crude oil to alter wettability, it was observed that the wettability distribution in a chalk plug was nonuniform. Capillary pressure curves by the direct measurement of saturation method were used to determine the wettability variation within the plug. This plug did not imbibe water because its exterior was rendered almost oil-wet, while the interior remained strongly water-wet. Similarly, for preparation methods that flow crude oil into a plug, the wettability could vary from the end of the sample to the interior or to the other end. The distribution of water and oil in the plug from a subsequent waterflood would then vary with the pressure imposed by the flow direction. Consequently, a forced displacement waterflood could recover different amounts of oil depending upon the direction of the waterflood. A neural net was used to capture the behavior of forced displacement for various wettabilities from measured capillary pressure curves and then used to predict waterflood results.

Summary Foam generation for gas mobility reduction in porous media is a well-known method and frequently used in field applications. Application of foam in fractured reservoirs has hitherto not been widely implemented, mainly because foam generation and transport in fractured systems are not clearly understood. In this laboratory work, we experimentally evaluate foam generation in a network of fractures within fractured carbonate slabs. Foam is consistently generated by snap-off in the rough-walled, calcite fracture network during surfactant-alternating-gas (SAG) injection and coinjection of gas and surfactant solution over a range of gas fractional flows. Boundary conditions are systematically changed including gas fractional flow, total flow rate, and liquid rates. Local sweep efficiency is evaluated through visualization of the propagation front and compared for pure gas injection, SAG injection, and coinjection. Foam as a mobility-control agent resulted in significantly improved areal sweep and delayed gas breakthrough. Gas-mobility reduction factors varied from approximately 200 to more than 1,000, consistent with observations of improved areal sweep. A shear-thinning foam flow behavior was observed in the fracture networks over a range of gas fractional flows.

The blockage performance of a Cr(III) acetate-HPAM gel was investigated using several different application regimes and gel maturities. Fractured core plugs from four outcrop core materials were used, all constituting smooth, longitudinal fractures of 1 mm aperture. Mature and immature gel was placed in the fractures, and for some application regimes in the surrounding core matrix, and the blockage performance assessed by recording rupture pressures and subsequent residual resistance factors during chase waterfloods, Frrw. Placement of mature gel in open fractures yielded consistent rupture pressures during subsequent water injections, following linear trends for given gel placement rates and throughput volumes. The rupture pressures were predictable and stable in all the core materials studied. Rupture pressures achieved after placement and in-situ crosslinking of gelant were comparable to mature gel rupture pressures, but were less predictable. When maximizing gelant saturation in the matrix, rupture pressures were measured to 12 – 53 psi/ft. The maximum achieved rupture pressure when gelant was placed without matrix taps to promote leakoff was 11.9 psi/ft. Interactions between rock material and gelant were observed when Bentheim sandstone cores were used, and gel was in some cases not formed. No such interactions were observed in experiments using formed gel. Significant permeability reduction for water was achieved when both gel and gelant were used. Residual resistance factors for cores treated with gel and gelant were initially comparable. After eight water flushes (>120 fracture volumes (FV) water injected) substantially greater pressure gradients were observed in cores treated with formed gel rather than gelant cross-linked in-situ and the permeability reduction averaged a factor 5000 for gel and 600 for gelant treated cores. The significance of these observations to field applications will be discussed.

Natural gas hydrate is a crystallized ice-like substance, consisting of water and natural gas, with methane as the most common gas. Water molecules form cages through hydrogen bonding and encapsulate gas molecules. Natural gas hydrates are found in the earth under high pressure and low temperature where water and gas co-exist, typically in permafrost and sub- marine environments. Hydrates have been considered a nuisance in the petroleum industry, creating barriers in pipe lines, and effort has mainly been put into preventing hydrate formation. However, natural gas hydrates are in recent decades acknowledged as a potential energy resource for the future; even conservative estimates suggest 1015 m3 CH4 STP present within hydrate. Several methane production scenarios are proposed: thermal-, chemical- and pressure reduction induced dissociation is available, although depressurization is considered the least costly option. The University of Bergen has since 2002 worked on a fourth alternative: exchange of CH4 molecules with CO2. Lab scale experiments have repeatedly shown CO2-CH4 exchange within sediments. These experiments led to a field trial test in Alaska, operated by ConocoPhillips, by utilizing CO2 injection as a production method. Similar procedures as in the field test were performed in the lab, creating repetitive data for analysis on lab scale. This paper reviews results from both the laboratory and field pilot and discusses challenges and mitigating measures related to production.

The poor rock quality and matrix permeability several orders of magnitude lower than conventional oil reservoirs observed in unconventional liquid reservoirs (ULR) presents many uncertainties on the storage capacity of the rock and the possibility of enhancing recovery. The technological advances in multiple stage hydraulic fracturing and horizontal drilling have improved the overall profitability of oil shale plays by enhancing the matrix – wellbore connectivity. The combination of these technologies has become the key factor for the operators to reach economically attractive production rates in the exploitation of ULR, causing a lot of focus on their improvement. However, as the reservoir matures, primary production mechanisms no longer drive oil to the hydraulic fractures, making the improvement of matrix – wellbore connectivity insufficient to provide economically attractive production rates. Therefore, the need to develop enhanced recovery techniques in order to improve the displacement of the oil from the matrix, maintain profitable production rates, extend the life of the assets and increase ultimate oil recovery becomes evident. This study presents experimental results on the use of CO2 as an enhanced oil recovery (EOR) agent in preserved, rotary sidewall reservoir core samples with negligible permeability. To simulate the presence of hydraulic fractures, the ULR cores were surrounded by high permeability glass beads and packed in a core holder. The high permeability media was then saturated with CO2 at constant pressure and temperature during the experiment. Production was monitored and the experiment was imaged using x-ray computed tomography to track saturation changes inside the core samples. The results of this investigation support CO2 as a promising EOR agent for ULR. Oil recovery was estimated to be between 18 to 55% of OOIP. We provide a detailed description of the experimental set up and procedures. The analysis of the x-ray computed tomography images revealed saturation changes within the ULR core as a result of CO2 injection. A discussion about the mechanisms is presented, including diffusion and reduction in capillary forces. This paper opens a door to the investigation of CO2 enhanced oil recovery in ULR.

Summary Iterative comparison between experimental work and numerical simulations has been used to predict oil-recovery mechanisms in fractured chalk as a function of wettability. Selective and reproducible alteration of wettability by aging in crude oil at an elevated temperature produced chalk blocks that were strongly water-wet and moderately water-wet, but with identical mineralogy and pore geometry. Large scale, nuclear-tracer, 2D-imaging experiments monitored the waterflooding of these blocks of chalk, first whole, then fractured. This data provided in-situ fluid saturations for validating numerical simulations and evaluating capillary pressure-and relative permeability-input data used in the simulations. Capillary pressure and relative permeabilities at each wettability condition were measured experimentally and used as input for the simulations. Optimization of either Pc-data or kr-curves gave indications of the validity of these input data. History matching both the production profile and the in-situ saturation distribution development gave higher confidence in the simulations than matching production profiles only.

A reproducible method for selectively altering the wettability of outcrop chalk has been established to obtain stable wettability conditions in the range from strongly water-wet to near-neutral-wet. Aging in different oils and the response to aging in different rocks are reported. The influence of different initial water saturations on the role of wettability alterations has been evaluated. Core plugs were aged in oil, at 90°C, for different time periods in duplicate sets. Oil recovery by spontaneous room temperature imbibition, followed by a waterflood, was studied for aged cores, to obtain Amott–Harvey wettability index to water. The procedure was also performed on cores containing aged crude oil, on cores where the aged crude oil was exchanged with fresh crude oil after aging was completed, but before imbibition testing and for cores where the crude oil was exchanged with decahydronaphthalene which was then displaced by n -decane. Imbibition in water-wet cores with n -decane was used as the baseline experiment. A consistent and reproducible change in wettability, from strongly water-wet to a near-neutral-wet state, with increased aging time was observed for five different outcrop chalks. The altered wettability was stable over several flooding cycles but when the aged crude oil was exchanged by fresh crude oil or decane after aging but before imbibition, results exhibited different but consistent Amott indices. Exchanging crude oil at temperature with decalin, which in turn was exchanged with decane, was found to be the best procedure for reproducible and stable wettability alteration.

Summary A total of 41 chalk core plugs, cut with the same orientation from large blocks of outcrop chalk, have been aged in crude oil at 90 °C for different time periods, in duplicate sets. Different filtration techniques, filtration temperatures and injection temperatures were used for the crude oil. Oil recovery by spontaneous, room temperature imbibition, followed by a waterflood, was used to produce the Amott water index for cores containing aged crude oil and for cores where the aged crude oil was exchanged by fresh crude oil or decane. The main objective was to establish a reproducible method for altering the wettability of outcrop chalk. A secondary objective was to determine mechanisms involved and the stability of the wettability change. The aging technique was found to be reproducible and could alter wettability in Rordal chalk selectively, from strongly water-wet to nearly neutral-wet. A consistent change in wettability towards a less water-wet state with increased aging time was observed.

Summary The effect of embedded fractures on the movement and recovery of hydrocarbon from larger outcrop chalk blocks at different wettabilities has been measured in the laboratory. Two-dimensional (2D) nuclear tracer imaging was used to produce in situ fluid saturation distributions during oil production. Emphasis was on determining the oil recovery mechanisms by tracking the flow path of the advancing water. Two sequential waterfloods were performed on each of the three different blocks: first before fracturing, and then after fracturing. The same fracture network configuration was used for all three blocks, which were strongly water wet, moderately water wet, and near neutral wet. Waterflooding the unfractured blocks, at high initial water saturation, occurred with minimal water banking while waterflooding at low initial water saturation produced distinct water bank formation. Waterflooding of the fractured blocks showed that the "closed" fractures produced a significant effect on fluid movement in the strongly water wet block, but only minor effect for the moderately and near neutral wet blocks. The open fracture affected flow in all the blocks. Total oil recovery was higher in the strongly water-wet block than in the moderately water wet block with the lowest oil recovery observed in the near neutral wet block.

This paper reports on studies of two-dimensional local saturation development in a cross layered reservoir model. Numerical simulations and experimental studies have been performed on a heterogeneous reservoir model consisting of three blocks of porous material with capillary and permeability contrasts connected at a dip angle of 45°. The physical reservoir model measured 22 cm × 5 cm × 5 cm and was composed of blocks of Vosges sandstone alternating with Aerolith-10, an artificial sintered porous medium with high porosity and permeability. The physical properties, porosities, permeabilities, capillary pressures, and end-point saturations of the blocks composing the heterogeneous medium were measured independently on isolated samples. A series of oilfloods and waterfloods were performed, and dynamic two-dimensional saturation fields were measured by gamma-ray attenuation. After drainage, during a no-flow state at low water saturation, we observed a redistribution of fluids near the boundaries of permeability contrasts due to capillary pressure differences between the blocks. The two-dimensional saturation fields recorded during the low-rate waterfloods showed a different behavior in different layers due to the contrasts of permeability and capillary pressure. Recovery efficiency by waterflooding isolated samples does not necessarily predict local recovery in composite models. Good reproducibility was obtained by performing different experiments with the same boundary conditions and petrophysical properties. Two-dimensional numerical simulations performed with the full-field commercial simulator ECLIPSE confirmed the observed experimental behavior. However, the simulated recovery from each block did not match the experimental results. We concluded that two-dimensional local saturation information in larger scale three dimensional reservoir models significantly improves the interpretation of the recovery mechanisms in heterogeneous porous media.

A comparative study of numerical modelling and laboratory experiments of two-phase immiscible displacements in a 33 cm × 10 × 3 cm thick cross-bedded reservoir model is reported. Dynamic two-dimensional fluid saturation development was obtained from experiments by use of a nuclear tracer imaging technique and compared to numerical predictions using a full-field black oil simulator. The laboratory cross-bedded reservoir model was a sandpack consisting of two strongly waterwet sands of different grain sizes, packed in sequential layers. The inlet and outlet sand consisted of low permeable, high capillary, sand while the central crosslayer with a dip angle of 30° was a high permeable, low capillary, sand. Results on moderate contrasts in permeability and capillary heterogeneities in the cross-bedded reservoir model at different mobility ratios and capillary number floods temporarily showed a bypass of oil, resulting in a prolonged two-phase production. The final remaining oil saturations, however, were as for isolated samples. Hence, permanently trapped oil was not observed. Simulations of waterfloods, using a commercial software package, displayed correct water breakthrough at low flow rate and unity viscosity ratio, but failed in predicting local saturation development in detail, probably due to numerical diffusion. The simulator was used to test several cases of heterogeneity contrasts, and influence from different relative permeability curves. Further, by altering the capillary pressure at the outlet, the end effects were proven important.

This work experimentally investigates a two-step, integrated EOR technique for heavily fractured, oil-wet carbonate rocks by combining fracture mobility control and chase fluid injections for increased sweep. The combination of mobility control using a cross-linked Cr(III)-Acetate HPAM polymer gel, and three different chase fluids (water, surfactant or CO2 foam) was investigated as an integrated EOR approach. Waterflood oil recovery was low with poor sweep efficiency and oil production from the fracture volume only. Fracture conductivity was significantly reduced after polymer gel placement in the fracture, leading to increased sweep and oil recovery during chase fluid injections, with oil recoveries up to 60%OOIP.

SUMMARY The effect of micro-scale heterogeneities on front instabilities during secondary, liquid CO2 injections for enhanced oil recovery in standard-sized chalk core plugs was investigated. The rock structure and displacement process was imaged in an industrial CT-scanner to probe the effect of micro-scale heterogeneities on the flow patterns and development of plume and CO2 fingers during injections. Heterogeneities in the chalk samples include fractures, healed shear bands and remnants of burrows. A one-component mineral oil was placed in contact with CO2 at the experimental conditions to promote reproducibility between repeated tests. The chalk is considered homogeneous on a standard-sized plug level, and varies only slightly in porosity and permeability within a large number of cores. The high spatial resolution CT scanning revealed submm healed shear bands running through the length of the core which potentially can cause a permeability decrease or diversion of the injected fluid. Total oil recovery from CO2 injection was around 90% regardless of heterogeneities, and there was no visible difference in CO2 arrival at the outlet. With no permeability contrast through the length of the core, the production of oil took place with less than one pore volume (PV) of CO2 injected. With a permeability contrast through the length of the core, more than one PV of CO2 was required to reach end-point oil saturation. Imaging the dynamic properties of a CO2 flood in the industrial CT showed how micro scale heterogeneities impact the flooding characteristics of a small core sample, as the healed shear bands diverted flow to a certain degree. It is also demonstrated how a larger permeability contrast will make the recovery more dependent on diffusion, which is a slower process than viscous displacement. The results demonstrate the need for characterization of micro-scale heterogeneity, because high permeability streaks and fractures will dominate flow during CO2 injection for EOR.

Multiphase flow and fluid displacements at pore-level were visualized in two-dimensional micromodels retaining essential characteristics of porous rocks. Microvisual data during CO2 injection for enhanced oil recovery was obtained from high resolution images using UV-sensitive dye to improve contrast. The dominating mechanisms were piston-like displacement of one fluid by another, either by a stable moving interface or through Haines-like jumps. Film thickening, film drainage, snap-off mechanisms and capillary trapping of CO2 were also observed. Both stable and unstable flow regimes were identified as the front advanced through the network during two-phase flow. In the latter regime, instabilities in the displacements were manifested by capillary fingering perpendicular to the main flow direction. Oil was found to be spreading in the water-oil-gas system at the experimental conditions. This led to an efficient oil production at pore-level from CO2 gas injection, even at high water saturation. The injected gaseous CO2 contacted only oil in three-phase systems, and led to direct oil displacement, whereas water was displaced through double or multiple displacement events.

In laboratory experiments a surfactant was injected into the fracture of an oil-wet fractured limestone to alter the wettability of the fracture surface to increase waterflood oil recovery. After a short shut-in period, the system was waterflooded to study the fluid transport from the fracture to the matrix and the oil recovery. The results were compared with waterfloods without surfactant treatment to isolate the effect of wettability changes on the fracture surface during water based EOR in oil-wet, fractured carbonate reservoirs. Differential pressure across each matrix block was measured, and magnetic resonance imaging (MRI) was used to obtain dynamic in-situ fluid saturation distributions, both in the matrices and within the fracture itself. A capillary threshold pressure for water to invade the matrix blocks was observed. Waterfloods after surfactant treatment demonstrated the benefit of changing the fracture surface wettability, leading to water transport into the downstream matrix block with no need to overcome the threshold pressure. Changes in fracture surface wetting preference were also confirmed visually in-situ by MRI imaging.

Summary Experiments on the effects of capillary heterogeneities and permeability variations on local saturation distributions were conducted using a nuclear saturation imaging technique. Capillary heterogeneities were obtained in alternating sand layers with different permeabilities in the direction of displacement. The paper reports wetting-phase accumulation at the transition zones, step-like saturation profiles, various recovery efficiencies, and different local residual saturations.

The win-win situation of CO2 storage in natural gas hydrate reservoirs is attractive for several reasons in addition to the associated natural gas production. Since both pure CO2 and pure methane form structure I hydrate there is no expected volume change by replacing the in situ methane with CO2, and there is not net production of associated water which requires extra handling. The geo-mechanical implication of the first of these may be a very important issue since hydrates in unconsolidated sediments are the most promising targets for exploitation of natural gas. The stability of CO2 stored in the form of hydrate is probably one of the safest options today, even though also this option relates to safety of sealing cap-rock or clay layer. The stability of hydrates in a reservoir depends on many factors, including the interactions between minerals, surrounding fluids and hydrate. The natural level of salinity increases with depth in a reservoir. In addition formation of hydrate will lead to increased salinity of the fluids surrounding the formed hydrate. This may lead to liquid pockets of residual aqueous solution with increased salinity as well as very non-uniform hydrate. The latter due to the fact that hydrate composition and stability relates to properties of surrounding fluids. In the work presented here methane hydrates were formed in several sandstone cores. The cores were all partially saturated with brine of different salinities in order to identify the effect salinity has on the fill fraction, the amount of methane per available structural site in hydrates. The results indicate that salinities lower than regular sea water composition has no significant impact on the fill fraction of methane hydrate in porous media. When the salinity surpasses regular sea water composition there is a significant drop in fill fraction. The methane hydrate fill fraction is dominated by total brine salinity rather than brine distribution in the core. publishedVersion

Capillary pressure is an important parameter in the study of immiscible flow in porous media, where the capillary forces, in interaction with viscous and gravitational forces, control the microscopic fluid distributions. The initial migration of oil into

Summary Sulfate-reducing bacteria (SRB) have been isolated from hot oilfield watersfrom subsea oil reservoirs in the North Sea. Experiments with these bacteria ina reservoir simulator indicate that SRB may maintain their activity in theconditions found in most North Sea reservoirs and, if precautions are nottaken, may contribute to souring of the oil and gas. precautions are not taken, may contribute to souring of the oil and gas. Introduction Water flooded hydrocarbon reservoirs may offer good conditions for growth ofthe anaerobic SRB that produce toxic and give H2S. This is particularly thecase for offshore oil fields where oxygen-scavenged seawater with high sulfateconcentration (28 mM) is injected and mixed with the in-situ reservoir porewater containing different kinds of short-chained organic acids. For continuingmicrobial activity, however, both chemical and physical requirements must bemet. Hence, the SRB must be able to grow and generate H2S at the in-situpressures and temperatures in the reservoir. Reservoir conditions weresimulated with a flow rig and investigated with respect to SRB growth andactivity. This flow rig may simulate conditions in a reservoir down to 15,000ft [4.6km], corresponding to a geostatic pressure of 15,000 psi [100 MPa] and atemperature up to 248 degs F [120 degs C]. Spore-forming thermophilic SRB ofthe genus Desulfotomaculum were isolated from hot produced water on different North Sea oil platforms. The bacteria were injected into brine-saturatedsandstone cores inside the rig's pressure vessel. Thereafter, the cores withbacteria were gradually exposed to increasing temperature and pressure, and the SRB activity at the various combinations of high temperature and pressure wasmeasured as sulfate reduction rate. Results showed that the bacteria wereactive and produced H2S to a temperature of 176 degs F [80 degs C] and apressure of 4,500 psi [30 MPa]. Electron micrographs revealed bacterial growthon mineral surfaces. Slimy extracellular material was observed in connectionwith the settlement of the bacteria. Seawater injection often is used in therecovery of hydrocarbons from subsea oil reservoirs. To obtain a successfulrecovery, the microbiological aspects of the waterflood must also beconsidered. Failure to do so may result in severe production problems. Bacterial activity downhole and in the reservoir formation results in formationdamage by loss of reservoir production performance, by a reduction in oilquality, by souring of the off, and by the development of major corrosionproblems, in both injection and production wells. H2S also is poisonous ifinhaled and may present a health hazard for platform personnel. Naturalseawater contain several types of platform personnel. Natural seawater containseveral types of slime-forming and filamentous bacteria, among them SRB andiron-oxidizing bacteria. Under favorable conditions, it is likely that theseorganisms will colonize the huge surface of the reservoir matrix. Theavailability of nutrients is important in the development of a microbialcommunity. The best nutrient conditions for SRB are expected to occur in themixing zone between the injection and formation water. This mixing zonecontains a high concentration of sulfate from seawater and soluble organiccompounds from the formation water. If chemical and physical requirements aremet in such an anaerobic environment, the bacteria will be active and produce H2S. Although SRB activity has been known for decades, little is known abouttheir ability to be active under the extreme pressure and temperatureconditions found in oil reservoirs.. In North Sea reservoirs, pressure commonlyranges from 3,000 to 7,500 psi [20 to 50 MPa] and temperatures from 140 to 212degs F [60 to 100 degs C]. The highest at which biological sulfate reductionhas been observed so far is 199 degs F [93 degs C] by the bacteria Archaeoglobus fulgidus. Other thermophilic SRB are Thermodesulfobacteriummobile and Thermodesulfobacterium commune, with maximum temperature of 180 degsF [85 degs C], and Desulfotomaculum nigrificans, with a maximum temperature of158 degs F [70 degs C]. In this study, we simulated an oil reservoir in alaboratory flow rig, using realistic temperatures and pressure. Representativethermophilic SRB, isolated from hat produced water on North Sea oil platforms, are used to study the effect of these bacteria on the platforms, are used tostudy the effect of these bacteria on the reservoir. Technical Procedure Core Preparation. The cores used in this study were drilled from a matrixblock of the eolic Hopeman sandstone. The block was obtained from an outcrop at Elgin in Scotland, the Clashach quarry. Petrographic and mineralogical studiesof the sandstone indicate Petrographic and mineralogical studies of thesandstone indicate a rather pure (91 %) quartz composition and only traceamounts of clay (muscovite). Grain sizes are on the order of 0.25 mm, with onlysmall variations. The average porosity is 18%, and the permeability ranges from700 to 800 md. Average pore diameter (26 m) was measured by mercury injection. Cylindrical cores 2.0 in. [5.1 cm] in diameter were drilled with length from 4to 30 in. [10 to 80 cm]. All cores were air dried at 176 degs F [80 degs C] for24 hours before cooling and weighing. End caps were mounted and the coresepoxy-coated. The cores were flushed with oxygen-free nitrogen and thenevacuated. This procedure was repeated several time to remove oxygen from themicropores. Several PV's of anaerobic brine containing nutrients for thebacteria were flushed through the cores before they were mounted in the flowrig. To establish a systematical approach, only brine was used to saturate thecore in these experiments. In later experiments, both oil and water wereused. Flow Rig. Fig. 1 illustrates the experimental flow rig. The main componentof the rig is a 3-ft [1-m] -long cylindrical steel pressure vessel with an IDof 2.8 in. [7.1 cm) and a 0.4-in. [1.0-cm] wall thickness. A core prepared asdescribed was pressurized in transformer oil inside the vessel. The rig cansimulate pressure conditions in a reservoir down to 15,000 ft [4 km], corresponding to a geostatic pressure of 15,000 psi [100 MPa]. Pressuretransducers monitored the simulated overburden pressure, water injectionpressure, and the differential pressure across the core. Pumping the fluidagainst a backpressure regulator gave pore pressures up to 10,500 psi [70 MPa]. Experimental flow rates ranged from 0.01 to 9.99 mL/min. A heating cable heatedthe pressure vessel and a thermostat regulated the temperature. Three standardthermocouple K-elements were placed at the inlet, in the middle, and at theoutlet end of the rig. Temperatures up to 248 degs F [120 degs C] could bemaintained with an accuracy of 1.8 degs F [1.0 degs C]. Porosity and Permeability measurements. Average porosity was measured Porosity and Permeability measurements. Average porosity was measured with a Boyle's law porosimeter and checked by measuring the volume of the fluidsaturating the core Dual-piston pumps operating with pulseless constant flowrate were used to inject fluids from a piston-type accumulator cell. Aprogrammable liquid sampler was attached to the outlet end of the programmableliquid sampler was attached to the outlet end of the rig. The differentialpressure across the core, flow-rate measurements, and fluid and corecharacteristics were used in Darcy's equation to calculate permeability.

Dynamic 3D MRI in-situ fluid saturation images during laboratory waterfloods of fractured carbonate rocks provided useful insights to the oil recovery mechanisms at water-wet and oil-wet conditions. The high spatial resolution imaging data formed the basis for a numerical representation of the experiment, and the numerical model was validated by history matching the experimentally observed results. Experimentally measured multiphase functions were used to match the in-situ fluid flow propagation during waterfloods of fractured rock, improving the confidence in the simulations beyond simply relying on material balance. A numerical sensitivity analysis of the effects from variations in fracture properties identified the impacts on sweep efficiency and oil recovery in waterfloods of fractured rock.

During waterfloods of a total of six outcrop chalk core plug samples prepared at various wettabilities, simultaneous local pressures and in situ fluid saturation from Magnetic Resonance Imaging (MRI) intensities were measured. Complementary use of high spatial resolution fluid saturation imaging and phase pressure measurements allowed calculations of the relative permeability to water and the dynamic capillary pressure curves for the imbibition process. One objective was to validate the theory for relative permeability calculations based on data from the fluid phase pressures measured separately using semi-permeable discs and local in situ fluid saturation measurements. A second objective was to identify fluid saturation changes due to spontaneous imbibition and viscous displacement, respectively, to determine the local recovery mechanism and allowing local recovery factors and in situ Amott-Harvey indices to be measured. The analysis of the experimental data from three of the core samples shows that the presented theory only applies for the saturation interval when the pressures are measured in the same phase. A new and improved experimental setup is therefore introduced for the remaining three cores in order to measure each of the dynamic phase pressure gradients separately using semi-permeable discs located at fixed pressure ports. The obtained data contributes to improved description and understanding of multi-phase fluid flow in porous media, including in situ measurements of relative permeabilities, capillary pressure curves, wettability distribution and local oil recovery mechanisms.

Summary Fluid saturation development in long-core flood experiments is investigated. Information on 1D fluid saturation distributions is obtained by labeling the fluid phases with nuclear tracers and detecting radiation with a movable detector. Various flood experiments were done on 2.5-ft [76-cm] -long sandstone cores. In miscible displacements where radioactive brine is displacing inactive brine, dispersion and ion adsorption are evaluated. Imaging saturation profiles during drainages and waterfloods gives information on saturation-front velocity and time development of local saturation variations. Experimental results are compared with numerical results from a 1D front-tracking black-oil simulator that incorporated inhomogeneities and capillary effects. Surfactant floods were investigated to test the applicability for EOR studies further.

Recovery mechanisms in fractured carbonate rocks have been investigated by comparing laboratory experiments with numerical simulations. The experimental data include waterfloods in blocks of carbonate rock with 2D, in-situ fluid saturation of the advancing waterfronts. The waterfloods were initially performed on the whole block, and then repeated on the same block with a fracture network containing both closed and open fractures to isolate the effect from fractures. The primary objective for the experiments was to investigate how the presence of fractures altered the dynamics of the propagating waterfront. A numerical, grid based model of the block was created and a sensitivity study of the representation of fractures was carried out. Especially the impact of the degree of capillary contact over fractures was studied. Matrix capillary pressure and relative permeability curves were determined by history matching both average oil production and the in-situ fluid saturation profiles from the unfractured block experiment. These were in turn used as input for the matrix properties in the fractured block simulations. The results show how the degree of capillary contact between matrix blocks controlled fluid saturation development and influenced the waterflood oil recovery in fractured limestone. Sensitivity studies on the degree of capillary contact over fractures showed this to be the most significant parameter for the frontal propagation during waterfloods. Numerical simulations together with experimental data gave increased understanding of the waterflood oil recovery mechanisms in fractured carbonate rock.

The ratio between the viscous and capillary forces, commonly denoted the Capillary Number Nc, is crucial in determining the remaining oil saturation. The impact on residual oil saturation by a systematic increase in Nc is determined in homogeneous chalk at wettabilities varying from nearly neutral-wet to strongly-water-wet conditions. In fractured chalk reservoirs waterflood residual oil saturation is strongly dependent on the wettability. The current results provide assistance in determining the potential target for tertiary oil recovery by measuring the amount of mobile oil at various Nc. A series of displacements of oil by water injection at increasing constant pressures were carried out to determine the relation between remaining oil and applied capillary number in waterfloods at different wettability conditions. Various uniform distributed mixed wettability conditions were established and quantified by the Amott test for 21 core plug samples. Minimum remaining oil at constant Nc occurred at wettability conditions reflecting an Amott Index to water at 0.3. The residual oil saturation decreased with increasing capillary number and significant trapped oil after completed spontaneous water imbibition was mobilized at moderately water-wet to nearly neutral-wet conditions. Similar results as reported in the literature for waterflooding residual oil saturations as function of wettability and PV water injected in sandstone were found for chalk at increasing capillary number. Distinct dome shaped curves of oil recovery as function of wettability, with consistent increase in oil recovery with increasing capillary number, reflected similarities to earlier results on waterflooding oil recovery.

Abstract The ratio between the viscous and capillary forces, commonly denoted the Capillary Number Nc, is crucial in determining the remaining oil saturation. The impact on residual oil saturation by a systematic increase in Nc is determined in homogeneous chalk at wettabilities varying from nearly neutral-wet to strongly-water-wet conditions. In fractured chalk reservoirs waterflood residual oil saturation is strongly dependent on the wettability. The current results provide assistance in determining the potential target for tertiary oil recovery by measuring the amount of mobile oil at various Nc. A series of displacements of oil by water injection at constant pressure were carried out to determine the relation between oil recovery and applied capillary number in waterfloods at different wettability conditions. Maximum oil recovery at constant Nc occurred at wettability conditions reflecting an Amott Index to water at 0.3. The remaining oil decreased with increasing capillary number and significant trapped oil after completed spontaneous water imbibition was mobilized at moderately water-wet to nearly neutral-wet conditions. Similar results as reported in the literature for waterflooding residual oil saturations as function of wettability and PV water injected in sandstone were found for chalk at increasing capillary number. Distinct dome shaped curves of oil recovery as function of wettability, with consistent increase in oil recovery with increasing capillary number, reflected similarities to earlier results on waterflooding oil recovery. Introduction The opportunity window for implementing IOR schemes for a given reservoir in production is limited when reaching the tail production. It is vital that the amount of potential target oil for EOR is determined as early as possible, and in this respect that the ultimate immobile or residual oil saturation for the rock/crude/brine system at the wettability conditions present in the reservoir is determined. Oil recovery depends strongly on the wettability condition and the interaction between the capillary and viscous forces will accordingly change with wettability [1, 2]. This study emphasizes the impact from wettability on the residual oil saturation during increasing differential viscous pressure drops at various wettabilities. Capillary forces are responsible for fluid entrapment during an immiscible displacement in porous media. Laboratory studies have shown that more of the remaining oil may be recovered in immiscible displacements if increased viscous displacement is applied. By exceeding the capillary forces trapped residual oil may be mobilized [3]. The capillary forces are determined by the wettability conditions and the oil/water interfacial tension (IFT). The potential to mobilize capillary trapped oil depends on the pore geometry. The required viscous force needed to mobilize trapped oil is determined by the fluid dynamics of the displacing phase. Thus an important parameter determining mobilization of capillary trapped oil during immiscible fluid displacements is the capillary number; exhibiting the ratio of viscous forces to the capillary forces.

The fracture/matrix transfer and fluid flow behavior in fractured carbonate rock was experimentally investigated using magnetic resonance imaging (MRI). Viscous oil-water displacements in stacked carbonate core plugs were investigated at wettability conditions ranging from strongly water-wet to moderately oil-wet. The impact of wettability and was investigated in a series of flooding experiments. The objective was to determine the impacts on fluid flow from different types of fractures at various wettability conditions. A general-purpose commercial core analysis simulator was used to simulate the flood experiments and to perform a parameter sensitivity study. The results demonstrated how capillary continuity across open fractures may be obtained when wetting phase bridges were established. A viscous component over the open fractures was provided when the wetting preference between the injected fluid and the rock surface allowed the formation of stable wetting phase bridges. The combination of high spatial resolution imaging and rapid data acquisition revealed how the transport mechanisms for oil and water were governed by the wetting affinity between the rock surface and the fluids in the fracture; both at moderately water wet conditions and at moderately oil wet conditions.

Formation and growth of methane hydrates in porous sandstone was monitored using Magnetic Resonance Imaging (MRI). A series of 3-D MRI images collected during these experiments illustrated patterns of hydrate growth. Calibrated MRI intensity changes that occured during the hydrate growth correlated with methane gas consumption and gave dynamic and quantitative in-situ information on hydrate formation rate and spatial distribution of the hydrate formed. Gas permeability was measured at various hydrate saturations and during hydrate growth. Experimentally it was verified that methane hydrate in porous sandstone spontaneously converted to CO2 hydrate when exposed to liquid CO2 at high pressure and low temperature. It has experimentally been determined that without heating, an exchange process between CO2 and methane occured allowing the injected CO2 to be stored as hydrate resulting in spontaneous production of methane, with no associated water production. The MRI images provided quantitative information on the methane production rates and amounts of methane released during the CH4-CO2 hydrate exchange reaction. Thermodynamic simulations based on Phase Field theory supported the measured results and predicted similar methane production rates observed in several reproduced experiments.

The mechanism of wetting phase flow into and across fractures was determined for stacked core plugs using highly water-wet and less water-wet chalk and several fracture widths and flow rates. Magnetic resonance imaging (MRI) was used to measure 2D saturation distributions in the matrix along the flow axis and 2D spatial distributions of the wetting and nonwetting phases in the fracture. For the strongly water-wet system, even at high flow rates, the inlet plug reached its spontaneous imbibition endpoint water saturation before the water entered the fracture. When water entered the fracture, gravity segregation resulted in the displacement of oil from the bottom of the fracture and upward. The rate of displacement was determined by the water injection rate. At less-water-wet conditions, the water produced a dispersed front that allowed water; at both high and low flow rates, to flow across the fracture and into the outlet plug as if there was no fracture. MRI images showed that water droplets formed on the outlet face of the inlet plug, formed bridges across the fracture and provided a path for water movement into the outlet plug while the oil phase was still being produced from the inlet plug. With time the bridges grew in size, coalesced and dropped to the bottom of the fracture eventually filling the fracture with water. At wider fracture widths the coalescence occurred earlier and the fracture was filled sooner. The capillary continuity provided by the bridges suggested a viscous component contributing to the total oil recovery in the fractured system for less than highly water-wet conditions.

The impact of fracture permeability on oil recovery from moderately-water-wet chalk has been determined. Nuclear Tracer Imaging was used to measure local fluid movement and to identify locations of trapped oil resulting from waterflooding a sleeved, fractured chalk block. Increasing the confinement pressure between experiments decreased the permeability of an interconnected fracture network for each sequential waterflood. The experiments showed that the dominant oil recovery mechanism was spontaneous imbibition, however, viscous oil recovery added significantly to the total oil production when the permeability ratio between the fractured system and the matrix was less than 20. The amount of oil viscously recovered increased as the fracture permeability decreased.

At three different wettabilities, two stacked outcrop core plugs, separated by a 1 mm fracture, were waterflooded. During the experiment in-situ fluid saturations were monitored with Magnetic Resonance Imaging (MRI). The sequence of 2D MRI images corroborated earlier lower resolution, larger scale experimental results on the effect of fractures during waterflooding at various wettabilities. The MRI images of oil saturation development in the fracture clearly revealed two distinct transport mechanisms for the wetting phase, water, across the fracture at several wettability conditions. When strongly-water-wet, the first core reached its spontaneous imbibition endpoint before water left the matrix and entered the fracture. The displaced water flowed down the exit face to the bottom of the fracture and displaced the oil upward at the rate of water injection. At less-water-wet conditions water droplets formed on the exit face of the first plug and grew large enough to form individual bridges between the two plugs. This happened well before the first plug reached its spontaneous imbibition endpoint. Under these conditions, the fracture filled slowly, as the bridges increased in diameter and additional bridges formed. Due to the capillary continuity of the wetting phase, a viscous pressure drop was established across the stacked core plugs, providing a viscous component to the total oil recovery.

Iterative comparison between experiments and numerical simulation has been used to predict oil recovery mechanisms in fractured chalk as a function of wettability. Selective alteration of wettability, by aging in crude oil at elevated temperature, produced chalk blocks which were strongly-water-wet and moderately-water-wet, but with similar pore geometry and mineralogy. Larger scale, nuclear-tracer, 2D-imaging experiments monitored fluid distributions while waterflooding blocks of chalk, first whole then fractured. This data provided in-situ fluid saturation development for validating numerical simulation and evaluating capillary pressure- and relative permeability input data used in the simulations. Capillary pressure and relative permeability at each given wettability were experimentally measured and used as input for the simulations. Optimization of either Pc-data or kr-curves gave indications of which of these input data could be more trusted. History matching both the production profile and the in-situ saturation distribution development gave higher confidence in the simulation. Labelling the injection water differently from the in-situ water made it possible to determine the degree of water mixing during the waterfloods. Mixing of injection water and in-situ water during waterfloodng was determined for both unfractured and fractured blocks. Reduced water wettability resulted in less oil recovery by spontaneous imbibition. Interconnected fractures did not significantly impact the final oil production when the permeability increase after fracturing was low, for both strongly-water-wet and moderately-water-wet conditions. However, in-situ saturation distributions were significantly affected by the wettability conditions. For higher permeability increase after fracturing significant reduction in oil recovery was experienced at less water wet conditions, while oil recovery at strongly-water-wet conditions was not reduced, even at high permeability increase after fracturing. The overall best match between the simulations and the experiments was obtained using the experimentally obtained capillary pressure curves and optimizing the experimentally measured relative permeabilities.

Iterative comparison between experimental work and numerical simulations has been used to predict oil recovery mechanisms in fractured chalk as a function of wettability. Selective and reproducible alteration of wettability, by aging in crude oil at elevated temperature, produced chalk blocks which were strongly-water-wet and moderately-water-wet, but with identical minerology and pore geometry. Large scale, nuclear-tracer, 2D-imaging experiments monitored waterflooding these blocks of chalk, first whole, then fractured. This data provided in-situ fluid saturations for validating numerical simulations and evaluating capillary pressure- and relative permeability input data used in the simulations. Capillary pressure and relative permeabilities at each given wettabilities were experimentally measured and used as input for the simulations. Optimization of either Pc- data or kr-curves gave indications of which of these input data could be trusted. History matching both the production profile and the in-situ saturation distribution development gave higher confidence in the simulations.

Abstract A total of 41 chalk core plugs, cut with the same orientation from large blocks of outcrop chalk, have been aged in crude oil at 90 C for different time periods, in duplicate sets. Different filtration techniques, filtration temperatures and injection temperatures were used for the crude oil. Oil recovery by spontaneous, room temperature imbibition, followed by a waterflood, was used to produce the Amott water index for cores containing aged crude oil and for cores where the aged crude oil was exchanged by fresh crude oil or decane. The main objective was to establish a reproducible method for altering the wettability of outcrop chalk. A secondary objective was to determine mechanisms involved and the stability of the wettability change. The aging technique was found to be reproducible and could alter wettability in Rordal chalk selectively, from strongly water wet to near neutral wet. A consistent change in wettability towards a less water wet state with increased aging time was observed. P. 193

Abstract The effect of embedded fractures on the movement and recovery of hydrocarbon from larger outcrop chalk blocks at different wettabilities has been measured in the laboratory. 2-D nuclear tracer imaging was used to produce in-situ fluid saturation distributions during oil production. Emphasis was on determining the oil recovery mechanisms by tracking the flow path of the advancing water. Two sequential waterfloods were performed on each of the three different blocks: first before fracturing, and then after fracturing. The same fracture network configuration was used for all three blocks, which were strongly water wet, moderately water wet and near neutral water wet. Waterflooding of the unfractured blocks, at high initial water saturation, occurred with minimal water banking while waterflooding at low initial water saturation produced distinct water bank formation. Waterflooding of the fractured blocks showed that the "closed" fractures produced a significant effect on fluid movement in the strongly water wet block, but only minor effect for the moderately and near neutral water wet blocks. The open fracture affected flow in all the blocks. Total oil recovery was higher in the strongly water wet block than in the moderately water wet block with the lowest oil recovery observed in the near neutral wet block. Introduction In fractured chalk reservoirs it is generally believed that oil production results from spontaneous imbibition of water from the fracture network and subsequent movement of the expelled oil through the fractures to the producing wells. However. if there were a significant amount of capillary continuity between adjacent blocks, viscous displacement of oil could also play a role and the matrix pore network could provide an alternate path for oil movement toward the production wells. Viscous displacement in a fractured chalk should be most important near water injection wells, during waterfloods and in reservoirs which are less than strongly water-wet. Previous experimental work which are pertinent to the assessment of fluid flow in fractured chalk include:The monitoring of saturation distribution during spontaneous axial imbibition in stacked cores using both horizontal and vertical configurations.Measuring saturation distributions as a function of time for the spontaneous imbibition and waterflooding of cores of different length and the area and configuration of exposed faces.The saturation distributions produced by gravitational drainage andfree gas. 2-dimensional saturation distributions have been monitored in larger strongly water-wet chalk blocks with several fracture orientations. Techniques have been developed which reproducibly alter the wettability of outcrop chalk to mimic the less than strongly water-wet chalk in a reservoir. This study was conducted to follow fluid movement and investigate hydrocarbon recovery mechanisms in fractured chalk at less than strongly water-wet conditions. The fracture network for these larger chalk blocks is similar to previously reported experiments on strongly water-wet fractured chalk. Experimental Three blocks, approximately 20 cm × 12 cm × 5 cm thick, were cut from large pieces of Roerdaloutcrop chalk obtained from the Portland quarry near Alborg, Denmark. This chalk material had never been contacted by oil and was strongly water-wet. The blocks were oven dried for three days at 90 C, end pieces were mounted and the whole assembly was epoxy coated. Each end piece contained three fittings so that entering and exiting fluids were evenly distributed with respect to height. The blocks were vacuum evacuated and saturated with brine containing 5 wt% NaCl + 5 wt% CaCl2. Porosity was determined from weight measurements and the permeability was measured across the epoxy coated blocks, see Table 2. P. 559^