Carlos A. Grattoni

An investigation of the effect of wettability on NMR characteristics of sandstone rock and fluid systems

Abstract Predicting reservoir wettability and its effect on fluid distribution and hydrocarbon recovery remains one of the major challenges in reservoir evaluation and engineering. Current laboratory based techniques require the use of rock–fluid systems that are representative of in situ reservoir wettability and preferably under reservoir conditions of pressure and temperature. However, the estimation of reservoir wettability is difficult to obtain from most laboratory experiments. In theory, it should be possible to determine the wettability of reservoir rock–fluid systems by nuclear magnetic resonance (NMR) due to the surface-sensitive nature of NMR relaxation measurements. Thus, NMR logs should in principle be able to give an indication of reservoir wettability, however, as yet there is no proven model to relate reservoir wettability to NMR measurements. Laboratory NMR measurements in representative and well-characterised rock–fluid systems are crucial to interpret NMR log data. A series of systematic laboratory experiments were designed using a range of sandstone core plugs with the aim of investigating the feasibility of using NMR measurements as a means to determine wettability. NMR T 2 spectrum measurements were performed in reservoir core plugs at different saturations and wettability states. The samples were first cleaned by hot solvent extraction, then saturated with brine and a drainage/imbibition cycle performed. At the lowest brine saturation the same samples were aged in crude oil and a further drainage/imbibition cycle performed. NMR transverse relaxation time, T 2 , was measured on fully saturated samples, at residual saturations and some intermediate saturation values. The wettability of the samples is evaluated using the Archies saturation exponent and by Amott-Harvey wettability index. The wettability of the cores studied ranged from mixed-wet to oil-wet. The NMR T 2 results for cleaned and aged reservoir core plugs, containing oil and water, show that fluid distribution and wettability can be deduced from such measurements. The results on aged core plugs suggest that the oil occupies a wide range of pore sizes and is in contact with the pore walls. The results presented in the paper suggest that NMR T 2 relaxation has the potential to be an alternative technique to evaluate rock wettability in the laboratory and in the reservoir.

Dimensionless groups for three-phase gravity drainage flow in porous media

Abstract The downward displacement of oil by gas (either through gas cap expansion or by gas injection) at the crest of the reservoir is an attractive method of oil recovery. The drainage of oil under gravity forces is a potentially efficient method as it can reduce the remaining oil saturation to below that obtained after waterflooding. This paper describes a series of experiments of gas invasion under gravity-dominated conditions with special attention to the effects of wettability and water saturation on three-phase flow. The experiments were performed in bead-pack models by spontaneous gas invasion at both low and high water saturations with a spreading oil. Different oil recovery rates were observed depending on the wettability of the beads and initial water saturation. At irreducible water saturation, the process appeared to be less efficient for the oil-wet conditions, while similar oil recoveries are observed for both oil-wet and water-wet media at residual oil saturation. Different recovery rates occur with different fluid morphology, which depend on the matrix wettability and the balance between gravity, viscous and capillary forces. The results have been analysed using dimensionless groups. The Bond ( N B ) and capillary numbers ( N C ) were modified to include the 3-phase effects of gas, oil and water. However, for these cases the Bond and capillary numbers alone were insufficient to fully describe the dynamics of oil recovery by gravity drainage. Therefore, a new dimensionless group combining the effects of gravity and viscous forces to capillary forces was defined as: N = N B + A ( μ d / μ g ) N C , where A is a scaling factor (in all our experiments A =−17225) and ( μ d / μ g ) is the viscosity ratio between the displaced and displacing phase. A linear relationship was found between this new group and the total recovery for all the scenarios tested. The slope was approximately 40 for three cases, i.e., water-wet case at irreducible water saturation, and water-wet and oil-wet cases at residual oil saturation. The oil-wet case at irreducible water saturation has a larger slope, probably due to the blocking effect of water. These experimental results may be used as a benchmark to test theoretical models of three-phase flow under gravity dominated conditions. The new dimensionless group should improve the understanding of the pore scale mechanisms so that these processes can be included in the development of network models and in the processes of upscaling laboratory results.

Rapid porosity and permeability changes of calcareous sandstone due to CO2‐enriched brine injection

Reservoir injectivity and storage capacity are the main constraints for geologic CO2 sequestration, subject to safety and economic considerations. Brine acidification following CO2 dissolution leads to fluid-rock interactions that alter porosity and permeability, thereby affecting reservoir storage capacity and injectivity. Thus, we determined how efficiently CO2-enriched brines could dissolve calcite in sandstone cores and how this affects the petrophysical properties. During computerized tomography monitored flow-through reactor experiments, calcite dissolved at a rate largely determined by the rate of acid supply, even at high flow velocities which would be typical near an injection well. The porosity increase was accompanied by a significant increase in rock permeability, larger than that predicted using classical porosity-permeability models. This chemically driven petrophysical change might be optimized using injection parameters to maximize injectivity and storage.

Petrophysical properties of greensand as predicted from NMR measurements

ABSTRACT Nuclear magnetic resonance (NMR) is a useful tool in reservoir evaluation. The objective of this study is to predict petrophysical properties from NMR T2 distributions. A series of laboratory experiments including core analysis, capillary pressure measurements, NMR T2 measurements and image analysis were carried out on sixteen greensand samples from two formations in the Nini field of the North Sea. Hermod Formation is weakly cemented, whereas Ty Formation is characterized by microcrystalline quartz cement. The surface area measured by the BET method and the NMR derived surface relaxivity are associated with the micro-porous glauconite grains. The effective specific surface area as calculated from Kozenys equation and as derived from petrographic image analysis of backscattered electron micrographs (BSE), as well as the estimated effective surface relaxivity, is associated with macro-pores. Permeability may be predicted from NMR by using Kozenys equation when surface relaxivity is known. Capillary pressure drainage curves may be predicted from NMR T2 distribution when pore size distribution within a sample is homogeneous.

Gas and oil production from waterflood residual oil: effects of wettability and oil spreading characteristics

Abstract In the depressurisation of reservoirs already produced to waterflooded residual oil, solution gas is released when the reservoir pressure drops to below the bubble point. This gas becomes mobilised when the critical gas saturation has been reached. Additionally, the oil itself can become mobile from its residual state and can also be produced under suitable physical conditions. The critical gas saturation, the rate of saturation change, and the gas saturation remaining at the end of the depressurisation process (unrecoverable gas) are important parameters in determining the overall economic performance when depressurising a reservoir. In this, and previous work, we are demonstrating that these quantities depend additionally upon other factors which affect the fluid distribution and the rate of gas generation, particularly the surface and interfacial properties. For instance, earlier visual experiments in glass micromodels suggested that wettability and oil spreading coefficient could substantially influence both the value of the critical gas saturation and the growth pattern for the developing gas bubbles, and thus the gas flow. In order to confirm these observations and to provide quantitative data, further experiments in large sintered packs, with different matrix wettability and with oils having different spreading coefficients (e.g. oil spreading onto a gas–water interface), have been carried out and are reported here. These new experiments show that the magnitude of the critical gas saturation for a water-wet system is about the same irrespective of whether the oil is spreading or non-spreading, but it is much higher than for the oil-wet case. In addition, oil is also produced but the rate of production is dependent upon the rock wettability and the oil characteristics. We find that in a water-wet medium, for spreading oils, the physical form of the oil becomes transformed from being immobile ganglia into mobile oil films, which can then be transported by the gas. For non-spreading oils, oil has to be pushed out by the gas as discontinuous ganglia so less is oil produced. In contrast, in an oil-wet system, the oil phase already exists as a continuous film on the surface of the solid so that the generation of gas effectively expands the oil phase, enabling the oil to be produced in larger quantities even at lower gas saturations. These new experiments give further evidence that rock wettability has an important influence on the performance of gas production from residual oil. Additionally, significant amounts of oil may be recovered after waterflooding from the residual condition, which could have a beneficial impact on the economics of the depressurisation.

Navier-Stokes Simulations of Fluid Flow Through a Rock Fracture

A surface profilometer was used to measure fracture profiles every 10 microns over the surfaces of a replica of a fracture in a red Permian sandstone, to within an accuracy of a few microns. These surface data were used as input to two finite element codes that solve the Navier-Stokes equations and the Reynolds equation, respectively. Numerical simulations of flow through these measured aperture fields were carried out at different values of the mean aperture, corresponding to different values of the relative roughness. Flow experiments were also conducted in casts of two regions of the fracture. At low Reynolds numbers, the Navier-Stokes simulations yielded transmissivities for the two fracture regions that were closer to the experimental values than were the values predicted by the lubrication model. In general, the lubrication model overestimated the transmissivity by an amount that varied as a function of the relative roughness, defined as the standard deviation of the aperture divided by the mean aperture. The initial deviations from linearity, for Reynolds numbers in the range 1-10, were consistent with the weak inertia model developed by Mei and Auriault for porous media, and with the results obtained computationally by Skjetne et al. in 1999 on a two-dimensional self-affine fracture. In the regime 10 < Re < 40, both the computed and measured transmissivities could be fit very well to a Forchheimer-type equation, in which the additional pressure drop varies quadratically with the Reynolds number.

Photographic observations showing spreading and non- spreading of oil on gas bubbles of relevance to gas flotation for oily wastewater cleanup

Abstract Gas flotation is widely used for oily wastewater cleanup. The crux for flotation is the adhesion of the gas bubble to the oil drop. A spreading stage of oil onto the gas is vital for efficient bubble–oil rise. Thus spreading and non-spreading oils will present different fluid configurations and stabilities for bubble rise and a positive oil on a water–gas interface spreading coefficient is needed for spreading to occur. This paper provides photographic evidence of the spreading of the oil around the gas bubble. The importance of a positive spreading coefficient of the oil around the gas bubble for gas flotation is clear.

The effect of halides on the lower critical solution temperature of the 2,6-lutidine-water system

Abstract Seah, C.Y., Grattoni, C.A. and Dawe, R.A., 1993. The effect of halides on the lower critical solution temperature of the 2,6-lutidine-water system. Fluid Phase Equilibria 89: 345-350. The lower critical solution temperatures of 2,6-lutidine (2,6-dimethyl pyridine) in brine have been measured for a range of halide solutions. The effect of the anion is significant with iodide having a raising effect compared with lutidine in distilled water (34°C) and bromide, chloride and fluoride having a depressing effect. The effect of different cations is not so significant. The implications of such observations are wide ranging for both theoretical and industrial application.

Two-phase fluid flow properties of cataclastic fault rocks: Implications for CO2 storage in saline aquifers

Fault rocks can function as barriers to subsurface fluid flow and affect the storage of CO 2 in geological structures. Even though flow across faults often involves more than one fluid phase, it is typically modeled using only single-phase functions due to a lack of fault rock relative permeability data and complexities in incorporating two-phase flow properties into flow simulations. Here we present two-phase fluid flow data for cataclastic fault rocks in porous sandstone from the 90-Fathom fault (northeast England). The study area represents a field analogue for North Sea saline aquifers of Permian–Triassic age that are currently being considered for CO 2 storage. We use the experimental data to populate a synthetic model of a faulted saline aquifer to assess the impact of these fault rocks on CO 2 injection. We show that even fault rocks with low clay contents and very limited quartz cementation can act as major baffles to the flow of a non-wetting phase if realistic two-phase properties are taken into account. Consequently, pressure may increase far more rapidly in the storage compartment during CO 2 injection than anticipated based on models that only incorporate absolute fault rock permeabilities. To avoid high pressures, which may lead to hydrofracturing and CO 2 leakage, either more complex injection strategies need to be adopted or seismic data acquired to ensure the absence of faults in aquifers selected for CO 2 storage.

Coalbed methane reservoir data and simulator parameter uncertainty modelling for CO2 storage performance assessment

Abstract Laboratory studies and a number of field pilots have demonstrated that CO 2 injection into coal seams has the potential to enhance coalbed methane (CBM) recovery with the added advantage that most of the injected CO 2 can be stored permanently in coal. The concept of storing CO 2 in geologic formations as a safe and effective greenhouse gas mitigation option requires public and regulatory acceptance. In this context it is important to develop a good understanding of the reservoir performance, uncertainties and the risks that are associated with geological storage. The paper presented refers to the sources of uncertainty involved in CO 2 storage performance assessment in coalbed methane reservoirs and demonstrates their significance using extensive digital well log data representing the Manville coals in Alberta, Canada. The spatial variability of the reservoir properties was captured through geostatistical analysis, and sequential Gaussian simulations of these provided multiple realisations for the reservoir simulator inputs. A number of CO 2 injection scenarios with variable matrix swelling coefficients were evaluated using a 2D reservoir model and spatially distributed realisations of total net thickness and permeability.