FLUID DISTRIBUTION IN TRANSITION ZONES (Using a New Initial-Residual Saturation Correlation)

ABSTRACT The fluid distribution as a function of height in transition zones is often very complex. This may be due to movement of water-oil contact, tilting of the reservoir at some point in time, leak of fluid out of the reservoir zone or complex inflow during secondary migration. The resultant fluid distribution seen in saturation logs may be difficult to model. In this paper we address the changes in fluid distribution versus height, inferred by changes of fluid distribution due to the movement of water-oil contact only. The experimental procedures for determining capillary pressure are based on fluid saturation monitoring by gamma absorption from centrifuge experiments. An analytical capillary pressure-saturation model was fit to the bounding imbibition capillary pressuresaturation data. The drainage-imbibition hysteresis curves were then constructed assuming that these curves have similar shape to that of the bounding imbibition curve. The imbibition hysteresis model proposed may be used to calculate fluid saturation in the reservoir due to the movement of water-oil contact. We also proposed necessary auxiliary equations to solve the new linear and four-parameter (sigmoidal type) initial-residual fluid saturation equations. Thus once the shape of the bounding-imbibition capillary pressuresaturation curve and maximum non-wetting fluid saturation are known one can easily construct any imbibition hysteresis curves that may be required

FLUID DISTRIBUTION IN TRANSITION ZONES (Using a New Initial-Residual Saturation Correlation)

ABSTRACT The fluid distribution as a function of height in transition zones is often very complex. This may be due to movement of water-oil contact, tilting of the reservoir at some point in time, leak of fluid out of the reservoir zone or complex inflow during secondary migration. The resultant fluid distribution seen in saturation logs may be difficult to model. In this paper we address the changes in fluid distribution versus height, inferred by changes of fluid distribution due to the movement of water-oil contact only. The experimental procedures for determining capillary pressure are based on fluid saturation monitoring by gamma absorption from centrifuge experiments. An analytical capillary pressure-saturation model was fit to the bounding imbibition capillary pressuresaturation data. The drainage-imbibition hysteresis curves were then constructed assuming that these curves have similar shape to that of the bounding imbibition curve. The imbibition hysteresis model proposed may be used to calculate fluid saturation in the reservoir due to the movement of water-oil contact. We also proposed necessary auxiliary equations to solve the new linear and four-parameter (sigmoidal type) initial-residual fluid saturation equations. Thus once the shape of the bounding-imbibition capillary pressuresaturation curve and maximum non-wetting fluid saturation are known one can easily construct any imbibition hysteresis curves that may be required

FLUID DISTRIBUTION IN TRANSITION ZONES (Using a New Initial-Residual Saturation Correlation)

ABSTRACT The fluid distribution as a function of height in transition zones is often very complex. This may be due to movement of water-oil contact, tilting of the reservoir at some point in time, leak of fluid out of the reservoir zone or complex inflow during secondary migration. The resultant fluid distribution seen in saturation logs may be difficult to model. In this paper we address the changes in fluid distribution versus height, inferred by changes of fluid distribution due to the movement of water-oil contact only. The experimental procedures for determining capillary pressure are based on fluid saturation monitoring by gamma absorption from centrifuge experiments. An analytical capillary pressure-saturation model was fit to the bounding imbibition capillary pressuresaturation data. The drainage-imbibition hysteresis curves were then constructed assuming that these curves have similar shape to that of the bounding imbibition curve. The imbibition hysteresis model proposed may be used to calculate fluid saturation in the reservoir due to the movement of water-oil contact. We also proposed necessary auxiliary equations to solve the new linear and four-parameter (sigmoidal type) initial-residual fluid saturation equations. Thus once the shape of the bounding-imbibition capillary pressuresaturation curve and maximum non-wetting fluid saturation are known one can easily construct any imbibition hysteresis curves that may be required

Permeability Prediction in Tight Carbonate Rocks using Capillary Pressure Measurements

The prediction of permeability in tight carbonate reservoirs presents ever more of a challenge in the hydrocarbon industry today. It is the aim of this paper to ascertain which models have the capacity to predict permeability reliably in tight carbonates, and to develop a new one, if required. This paper presents (i) the results of laboratory Klinkenberg-corrected pulse decay measurements of carbonates with permeabilities in the range 65 nD to 0.7 mD, (ii) use of the data to assess the performance of 16 permeability prediction models, (iii) the development of an improved prediction model for tight carbonate rocks, and (iv) its validation using an independent data set. Initial measurements including porosity, permeability and mercury injection capillary pressure measurements (MICP) were carried out on a suite of samples of Kometan limestone from the Kurdistan region of Iraq. The prediction performance of sixteen different percolation-type and Poiseuille-type permeability prediction models were analysed with the measured data. Analysis of the eight best models is included in this paper and the analysis of the remainder is provided in supplementary material. Some of the models were developed especially for tight gas sands, while many were not. Critically, none were developed for tight gas carbonates. Predictably then, the best prediction was obtained from the generic model and the RGPZ models (R2 = 0.923, 0.920 and 0.915, respectively), with other models performing extremely badly. In an attempt to provide a better model for use with tight carbonates, we have developed a new model based on the RGPZ theoretical model by adding an empirical scaling parameter to account for the relationship between grain size and pore throat size in carbonates. The generic model, the 28 new RGPZ Carbonate model and the two original RGPZ models have been tested against independent data from a suite of 42 samples of tight Solnhofen carbonates. All four models performed very creditably with the generic and the new RGPZ Carbonate models performing well (R2 = 0.840 and 0.799, respectively). It is clear from this study that the blind application of conventional permeability prediction techniques to carbonates, and particularly to tight carbonates, will lead to gross errors and that the development of new methods that are specific to tight carbonates is unavoidable

Pore-scale study of counter-current imbibition in strongly water-wet fractured porous media using lattice Boltzmann method

Oil recovery from naturally fractured reservoirs with low permeability rock remains a challenge. To provide a better understanding of spontaneous imbibition, a key oil recovery mechanism in the fractured reservoir rocks, a pore-scale computational study of the water imbibition into an artificially generated dual-permeability porous matrix with a fracture attached on top is conducted using a recently improved lattice Boltzmann color-gradient model. Several factors affecting the dynamic countercurrent imbibition processes and the resulting oil recovery have been analyzed, including the water injection velocity, the geometry configuration of the dual permeability zones, interfacial tension, the viscosity ratio of water to oil phases, and fracture spacing if there are multiple fractures. Depending on the water injection velocity and interfacial tension, three different imbibition regimes have been identified: the squeezing regime, the jetting regime, and the dripping regime, each with a distinctively different expelled oil morphology in the fracture. The geometry configuration of the high and low permeability zones affects the amount of oil that can be recovered by the countercurrent imbibition in a fracture-matrix system through transition of the different regimes. In the squeezing regime, which occurs at low water injection velocity, the build-up squeezing pressure upstream in the fracture enables more water to imbibe into the permeability zone closer to the fracture inlet thus increasing the oil recovery factor. A larger interfacial tension or a lower water-to-oil viscosity ratio is favorable for enhancing oil recovery, and new insights into the effect of the viscosity ratio are provided. Introducing an extra parallel fracture can effectively increase the oil recovery factor, and there is an optimal fracture spacing between the two adjacent horizontal fractures to maximize the oil recovery. These findings can aid the optimal design of water-injecting oil extraction in fractured rocks in reservoirs such as oil shale

The Effect of Wettability and Flow Rate on Oil Displacement Using Polymer-Coated Silica Nanoparticles: A Microfluidic Study

Polymer-coated silica nanoparticles (PSiNPs) have been experimentally investigated in core- and micro-scale studies for enhanced oil recovery (EOR). Wettability and flow rate have a considerable effect on oil displacement in porous media. This work investigates the efficiency of PSiNPs for oil recovery on micro-scale at three wettability states (water-wet, intermediate-wet, and oil-wet). In addition, a cluster mobilization regime is considered in all experiments. A microfluidic approach was utilized to perform flooding experiments with constant experimental settings such as flowrate, pore-structure, initial oil topology, porosity, and permeability. In this study, the wettability of the microfluidic chips was altered to have three states of wettability. Firstly, a micro-scale study (brine-oil-glass system) of each wettability condition effect on flow behavior was conducted via monitoring dynamic changes in the oleic phase. Secondly, the obtained results were used as a basis to understand the changes induced by the PSiNPs while flooding at the same conditions. The experimental data were extracted by means of image processing and analysis at a high spatial and temporal resolution. Low injection rate experiments (corresponding to ~1.26 m/day in reservoir) in a brine-oil-glass system showed that the waterflood invaded with a more stable front with a slower displacement velocity in the water-wet state compared to the other states, which had water channeling through the big pores. As a result, a faster stop of the dynamic changes for the intermediate- and oil-wet state was observed, leading to lower oil recoveries compared to the water-wet state. In a cluster mobilization regime, dynamic changes were noticeable only for the oil-wet condition. For the aforementioned different conditions, PSiNPs improved oil displacement efficiency. The usage of PSiNPs showed a better clusterization efficiency, leading to a higher mobilization, smaller remaining oil clusters, and lower connectivity of the residual oil. The knowledge from this experimental work adds to the understanding of the behavior of polymer-coated silica nanoparticles as a recovery agent at different wettability states and a cluster mobilization regime

Investigating residual trapping in CO2 storage in saline aquifers – application of a 2D glass model, and image analysis

Two-dimensional glass model experiments are used to investigate the residual trapping mechanism of CO2 stored in saline aquifers. For this purpose, two proxy fluids are chosen to simulate the CO2-brine behavior under reservoir conditions. The first set of experiments is carried out by flooding n-heptane in a mixture of glycerol and water inside a glass bead porous media. Fluids and porous materials are designed so that the dimensionless groups are in the range of real storage sites. Another set of proxy fluid consists of dodecane and a different mixture of glycerol and water, representing the second wettability condition for the system. The size of the glass beads chosen was fine (70–110 μm) in order to investigate residual trapping phenomena. For each set, after complete drainage process, an imbibition process is performed and in each time step, images are taken from the phenomena. The images are processed using a red, green, blue (RGB) color concept using a Matlab code that was developed for this study. By using this process, it is possible to measure the residual trapping of CO2 proxy fluid for each test and to determine the saturation profile in the model. Tests are carried out at various imbibition and drainage rates to study the effect of the rate on the results. Fine-scale numerical simulation models are constructed for comparison with experimental results. Good agreement is obtained between the simulation results and the image processing estimations, as well as the readings from the material balances during the experiments. This study could provide a framework for modeling different reservoir conditions for residual trapping mechanism and the impact of different parameters in future studies

Methods for the study of clustering and precipitation in Al-based alloys by APT

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