scholarly journals Reliability of Relative Permeability Measurements for Heterogeneous Rocks Using Horizontal Core Flood Experiments

2021 ◽  
Vol 13 (5) ◽  
pp. 2744
Author(s):  
Chia-Wei Kuo ◽  
Sally M. Benson
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Synthetic Data ◽  
Critical Value ◽  
Core Flooding ◽  
Fractional Flow ◽  
The Core ◽  
Heterogeneous Rocks ◽  
Core Flood ◽  
Relative Permeability Curves

New guidelines and suggestions for taking reliable effective relative permeability measurements in heterogeneous rocks are presented. The results are based on a combination of high resolution of 3D core-flooding simulations and semi-analytical solutions for the heterogeneous cores. Synthetic “data sets” are generated using TOUGH2 and are subsequently used to calculate effective relative permeability curves. A comparison between the input relative permeability curves and “calculated” relative permeability is used to assess the accuracy of the “measured” values. The results show that, for a capillary number (Ncv = kLpc × A/H2μCO2qt) smaller than a critical value, flows are viscous dominated. Under these conditions, saturation depends only on the fractional flow as well as capillary heterogeneity, and is independent of flow rate, gravity, permeability, core length, and interfacial tension. Accurate whole-core effective relative permeability measurements can be obtained regardless of the orientation of the core and for a high degree of heterogeneity under a range of relevant and practical conditions. Importantly, the transition from the viscous to gravity/capillary dominated flow regimes occurs at much higher flow rates for heterogeneous rocks. For the capillary numbers larger than the critical value, saturation gradients develop along the length of the core and accurate relative permeability measurements are not obtained using traditional steady-state methods. However, if capillary pressure measurements at the end of the core are available or can be estimated from independently measured capillary pressure curves and the measured saturation at the inlet and outlet of the core, accurate effective relative permeability measurements can be obtained even when there is a small saturation gradient across the core.

A Machine Learning Methodology for Rock-Typing Using Relative Permeability Curves

2021 ◽  
Author(s):  
Carlos Esteban Alfonso ◽  
Frédérique Fournier ◽  
Victor Alcobia
Keyword(s):  
Machine Learning ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Fractional Flow ◽  
Flow Curves ◽  
Rock Types ◽  
Rock Typing ◽  
Relative Permeability Curves ◽  
Permeability Data

Abstract The determination of the petrophysical rock-types often lacks the inclusion of measured multiphase flow properties as the relative permeability curves. This is either the consequence of a limited number of SCAL relative permeability experiments, or due to the difficulty of linking the relative permeability characteristics to standard rock-types stemming from porosity, permeability and capillary pressure. However, as soon as the number of relative permeability curves is significant, they can be processed under the machine learning methodology stated by this paper. The process leads to an automatic definition of relative permeability based rock-types, from a precise and objective characterization of the curve shapes, which would not be achieved with a manual process. It improves the characterization of petrophysical rock-types, prior to their use in static and dynamic modeling. The machine learning approach analyzes the shapes of curves for their automatic classification. It develops a pattern recognition process combining the use of principal component analysis with a non-supervised clustering scheme. Before this, the set of relative permeability curves are pre-processed (normalization with the integration of irreducible water and residual oil saturations for the SCAL relative permeability samples from an imbibition experiment) and integrated under fractional flow curves. Fractional flow curves proved to be an effective way to unify the relative permeability of the two fluid phases, in a unique curve that characterizes the specific poral efficiency displacement of this rock sample. The methodology has been tested in a real data set from a carbonate reservoir having a significant number of relative permeability curves available for the study, in addition to capillary pressure, porosity and permeability data. The results evidenced the successful grouping of the relative permeability samples, according to their fractional flow curves, which allowed the classification of the rocks from poor to best displacement efficiency. This demonstrates the feasibility of the machine learning process for defining automatically rock-types from relative permeability data. The fractional flow rock-types were compared to rock-types obtained from capillary pressure analysis. The results indicated a lack of correspondence between the two series of rock-types, which testifies the additional information brought by the relative permeability data in a rock-typing study. Our results also expose the importance of having good quality SCAL experiments, with an accurate characterization of the saturation end-points, which are used for the normalization of the curves, and a consistent sampling for both capillary pressure and relative permeability measurements.

Carbon Dioxide Sequestration and Drainage in Saline Aquifer

2021 ◽  
Author(s):  
Edward Ennin
Keyword(s):  
Pore Pressure ◽  
Relative Permeability ◽  
Produced Water ◽  
Co2 Storage ◽  
Trapping Efficiency ◽  
Core Flooding ◽  
Fractional Flow ◽  
The Core ◽  
Water Volumes ◽  
Water Trapping

Abstract Geological storage of CO2 in saline aquifers is recognized as a favorable technique that could deliver a significant decrease in CO2 emissions over the short to medium-term. However, the major risk is the possibility of leakage and injection limitation due to pore pressure. This research investigates the three major mechanisms of CO2 trapping to determine which method safely captures the most CO2, interrogates the pore pressure effect on storage, and compares traditional core flooding methods for CO2 storage with CO2 drainage which is more practical in the aquifer. A core flooding set up was built to replicate reservoir conditions of the Anadarko Basin in Texas, USA. The research involved three reservoir pay zone rocks obtained from depths of about 7687ft that were pieced together to undergo core flooding at 4400psi-5200psi and a temperature of 168°F. In the first study conducted the core was flooded with supercritical CO2 and brine of salinity 4000ppm to generate relative permeability curves to represent drainage and imbibition. For the duration of the 3rd, 4th, and 5th studies the core saturated with brine is flooded with CO2 at pressures of 4400psi, 4800psi, and 5200psi. Parameters like the volume of CO2 captured, connate water volumes, differential pressure, Ph of produced water, trapping efficiency, relative permeability, and fractional flow curves are noted. After scrutinizing the result it is observed that the highest volume of CO2 is captured by solubility trapping followed by structural trapping and residual trapping in that order. From this research, it can be concluded that CO2 trapping, at least for these reservoir rocks, is not affected by pore pressure. Also contrary to most practices CO2 storage is best replaced in the laboratory using drainage experiments instead of the widely used relative permeability approach.

Experimental Investigation of Two-Phase Flow Properties of Heterogeneous Rocks for Advanced Formation Evaluation

2021 ◽  
Author(s):  
Pierre Aérens ◽  
Carlos Hassan Torres-Verdin ◽  
D. Nicolas Espinoza
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Two Phase Flow ◽  
Time Lapse ◽  
Phase Flow ◽  
Flow Properties ◽  
Fractional Flow ◽  
Two Phase ◽  
Fluid Saturation ◽  
Heterogeneous Rocks

Abstract An uncommon facet of Formation Evaluation is the assessment of flow-related in situ properties of rocks. Most of the models used to describe two-phase flow properties of porous rocks assume homogeneous and/or isotropic media, which is hardly the case with actual reservoir rocks, regardless of scale; carbonates and grain-laminated sandstones are but two common examples of this situation. The degree of spatial complexity of rocks and its effect on the mobility of hydrocarbons are of paramount importance for the description of multiphase fluid flow in most contemporary reservoirs. There is thus a need for experimental and numerical methods that integrate all salient details about fluid-fluid and rock-fluid interactions. Such hybrid, laboratory-simulation projects are necessary to develop realistic models of fractional flow, i.e., saturation-dependent capillary pressure and relative permeability. We document a new high-resolution visualization technique that provides experimental insight to quantify fluid saturation patterns in heterogeneous rocks and allows for the evaluation of effective two-phase flow properties. The experimental apparatus consists of an X-ray microfocus scanner and an automated syringe pump. Rather than using traditional cylindrical cores, thin rectangular rock samples are examined, their thickness being one order of magnitude smaller than the remaining two dimensions. During the experiment, the core is scanned quasi-continuously while the fluids are being injected, allowing for time-lapse visualization of the flood front. Numerical simulations are then conducted to match the experimental data and quantify effective saturation-dependent relative permeability and capillary pressure. Experimental results indicate that flow patterns and in situ saturations are highly dependent on the nature of the heterogeneity and bedding-plane orientation during both imbibition and drainage cycles. In homogeneous rocks, fluid displacement is piston-like, as predicted by the Buckley-Leverett theory of fractional flow. Assessment of capillary pressure and relative permeability is performed by examining the time-lapse water saturation profiles. In spatially complex rocks, high-resolution time-lapse images reveal preferential flow paths along high permeability sections and a lowered sweep efficiency. Our experimental procedure emphasizes that capillary pressure and transmissibility differences play an important role in fluid-saturation distribution and sweep efficiency at late times. The method is fast and reliable to assess mixing laws for fluid-transport properties of rocks in spatially complex formations.

Analytical Solutions for Spontaneous Imbibition: Fractional-Flow Theory and Experimental Analysis

SPE Journal ◽  
2016 ◽  
Vol 21 (06) ◽  
pp. 2308-2316 ◽  
Author(s):  
K. S. Schmid ◽  
N.. Alyafei ◽  
S.. Geiger ◽  
M. J. Blunt
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Analytical Solutions ◽  
Flow Theory ◽  
Spontaneous Imbibition ◽  
Fractional Flow ◽  
Matrix Block ◽  
Relative Permeability Curves ◽  
Fractional Flow Theory ◽  
Saturation Profiles

Summary We present analytical solutions for capillary-controlled displacement in one dimension by use of fractional-flow theory. We show how to construct solutions with a spreadsheet that can be used for the analysis of experiments as well as matrix-block-scale recovery in field settings. The solutions can be understood as the capillary analog to the classical Buckley-Leverett solution (Buckley and Leverett 1942) for viscous-dominated flow, and are valid for cocurrent and countercurrent spontaneous imbibition (SI), as well as for arbitrary capillary pressure and relative permeability curves. They can be used to study the influence of wettability, predicting saturation profiles and production rates characteristic for water-wet and mixed-wet conditions. We compare our results with in-situ measurements of saturation profiles for SI in a water-wet medium. We show that the characteristic shape of the saturation profile is consistent with the expected form of the relative permeabilities. We discuss how measurements of imbibition profiles, in combination with other measurements, could be used to determine relative permeability and capillary pressure.

History Matching Heterogeneous Coreflood of CO2/Brine by Use of Compositional Reservoir Simulator and Geostatistical Approach

SPE Journal ◽  
2014 ◽  
Vol 20 (02) ◽  
pp. 267-276 ◽  
Author(s):  
Xianhui Kong ◽  
Mojdeh Delshad ◽  
Mary F. Wheeler
Keyword(s):  
High Resolution ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Mean Value ◽  
Heterogeneous Distribution ◽  
Compositional Model ◽  
The Core ◽  
The Mean ◽  
Relative Permeability Curves ◽  
Reservoir Simulator

Summary Numerical modeling and simulation are essential tools for developing a better understanding of the geologic characteristics of aquifers and providing technical support for future carbon dioxide (CO2) storage projects. Modeling CO2 sequestration in underground aquifers requires the implementation of models of multiphase flow and CO2 and brine phase behavior. Capillary pressure and relative permeability need to be consistent with permeability/porosity variations of the rock. It is, therefore, crucial to gain confidence in the numerical models by validating the models and results by use of laboratory and field pilot results. A published CO2/brine laboratory coreflood was selected for our simulation study. The experimental results include subcore porosity and CO2-saturation distributions by means of a computed tomography (CT) scanner along with a CO2-saturation histogram. Data used in this paper are all based on those provided by Krause et al. (2011), with the exception of the CT porosity data. We generated a heterogeneous distribution for the porosity but honoring the mean value provided by Krause et al. (2011). We also generated the permeability distribution with the mean value for the whole core given by Krause et al. (2011). All the other data, such as the core dimensions, injection rate, outlet pressure, temperature, relative permeability, and capillary pressure, are the same as those in Krause et al. (2011). High-resolution coreflood simulations of brine displacement with supercritical CO2 are presented with the compositional reservoir simulator IPARS (Wheeler and Wheeler 1990). A 3D synthetic core model was constructed with permeability and porosity distributions generated by use of the geostatistical software FFTSIM [Jennings et al. (2000)], with cell sizes of 1.27×1.27×6.35 mm. The core was initially saturated with brine. Fluid properties were calibrated with the equation-of-state (EOS) compositional model to match the measured data provided by Krause et al. (2011). We used their measured capillary pressure and relative permeability curves. However, we scaled capillary pressure on the basis of the Leverett J-function (Leverett 1941) for permeability, porosity, and interfacial tension (IFT) in every simulation grid cell. Saturation images provide insight into the role of heterogeneity of CO2 distribution in which a slight variation in porosity gives rise to large variations in CO2-saturation distribution in the core. High-resolution numerical results indicated that accurate representation of capillary pressure at small scales was critical. Residual brine saturation and the subsequent shift in the relative permeability curves showed a significant impact on final CO2 distribution in the core.

Simulation Protocol for Core Flooding: Relative Permeability and Capillary Pressure Analysis

2014 ◽  
Author(s):  
S Kumar ◽  
Mariyamni Awang ◽  
Ghulam Abbas ◽  
Khurram Farouque ◽  
Sheraz Ahmed
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Core Flooding ◽  
Simulation Protocol ◽  
Pressure Analysis

Core Effective and Relative Permeability Measurements for Conventional and Unconventional Reservoirs by Saturation Monitoring in High Frequency 3d Gradient NMR

2021 ◽  
Author(s):  
Brian Chin ◽  
Safdar Ali ◽  
Ashish Mathur ◽  
Colton Barnes ◽  
William Von Gonten
Keyword(s):  
Relative Permeability ◽  
Oil And Gas ◽  
Spontaneous Imbibition ◽  
Tuning Parameter ◽  
Core Flooding ◽  
Hydrocarbon Gases ◽  
Flowing Fluid ◽  
The Core ◽  
Difficult Time ◽  
Saturation Front

Abstract A big challenge in tight conventional and unconventional rock systems is the lack of representative reservoir deliverability models for movement of water, oil and gas through micro-pore and nano-pore networks. Relative permeability is a key input in modelling these rocks; but due to limitations in core analysis techniques, permeability has become a knob or tuning parameter in reservoir simulation. Current relative permeability measurements on conventional core samples rely on density contrast between oil/water or gas/water on CT (Computed Tomography) scans and recording of effluent volumes to determine relative fluid saturations during the core flooding process. However, tight rocks are characterized by low porosities (< 10 %) and ultra-low permeabilities (< 1 micro-Darcy), that make effective and relative permeability measurements very difficult, time-consuming, and prone to high errors associated with low pore volumes and flow rates. Nuclear Magnetic Resonance (NMR) measurements have been used extensively in the industry to measure fluid porosities, pore size characterization, wettability evaluation, etc. Core NMR scans can provide accurate quantification of pore fluids (oil, gas, water) even in very small quantities, using T2, T1T2 and D-T2 activation sequences. We have developed a novel process to perform experiments that measure effective and relative permeability values on both conventional and tight reservoirs at reservoir conditions while accurately monitoring fluid saturations and fluid fronts in a 12 MHz 3D gradient NMR spectrometer. The experimental process starts by acquiring Micro-CT scans of the cylindrical rock plugs to screen the samples for artifacts or microcracks that may affect permeability measurements. Once the samples are chosen, NMR T2 and T1T2 scans are performed to establish residual fluid saturations in the as-received state. If a liquid effective permeability test is required, the samples are then saturated with the given liquid through a combination of humidification, vacuum-assisted spontaneous imbibition, and saturation under pressure and temperature. After saturation, NMR scans are obtained to verify the volumes of the liquids and determine if the samples have achieved complete saturation. The sample is then loaded into a special core-flooding vessel that is invisible to the NMR spectrometer to minimize interference with the NMR signals from the fluids in the sample. The sample is brought up to reservoir stress and temperature, and the main flowing fluid is injected from one side of the sample while controlling the pressures on the other side of the sample with a back pressure regulator. The saturation front of the injected fluid is continuously monitored using 2D and 3D gradient NMR scans and the volumes of different fluids in the sample are measured using NMR T2 and T1T2 scans. The use of a 12 MHz NMR spectrometer provides very high SNR (signal-to-noise ratio); and clear distinction of water and hydrocarbon signals in the core plug during the entire process. The scanning times are also reduced by orders of magnitude, thereby allowing for more scans to properly capture the saturation front and changes in saturation. Simultaneously, the fluid flowrates and pressures are recorded in order to compute permeability values. The setup is rated to 10,000 psi confining pressures, 9000 psi of pore pressure and a working temperature of up to 100 C. Flowrates as low as 0.00001 cc/min can be recorded. These tests have been done with brine, dead and live crudes, and hydrocarbon gases. The measured relative permeability values have been used successfully in both simulation and production modelling studies in various reservoirs worldwide.

scholarly journals Improved method for complete gas-brine imbibition relative permeability curves

2020 ◽  
Vol 146 ◽  
pp. 03003
Author(s):  
M. Ben Clennell ◽  
Cameron White ◽  
Ausama Giwelli ◽  
Matt Myers ◽  
Lionel Esteban ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Gas Permeability ◽  
Test Methods ◽  
Standard Test ◽  
High Rate ◽  
Fractional Flow ◽  
Gas Reservoirs ◽  
Data Gap ◽  
Small Increments ◽  
Relative Permeability Curves

Standard test methods for measuring imbibition gas-brine relative permeability on reservoir core samples often lead to non-uniform brine saturation. During co-current flow, the brine tends to bank up at the sample inlet and redistributes slowly, even with fractional flow of gas to brine of 400:1 or more. The first reliable Rel Perm point is often only attained after a brine saturation of around Sw=40% is achieved, leaving a data gap between Swirr and this point. The consequent poor definition of the shape of the Rel Perm function can lead to uncertainty in the performance of gas reservoirs undergoing depletion drive with an encroaching aquifer or subjected to a water flood. We have developed new procedures to pre-condition brine saturation outside of the test rig and progress it in small increments to fill in the data gap at low Sw, before continuing with a co-current flood to the gas permeability end-point. The method was applied to series of sandstone samples from gas reservoirs from the NW Shelf of Australia, and a Berea standard. We found that the complete imbibition relative permeability curve is typically ‘S’ shaped or has a rolling over, convex-up shape that is markedly different from the concave-up, Corey Rel Perm curve usually fitted to SCAL test data. This finding may have an economic upside if the reservoir produces gas at a high rate for longer than was originally predicted based on the old Rel Perm curves.

scholarly journals Uncertainty span for relative permeability and capillary pressure by varying wettability and spatial flow directions utilizing pore scale modelling

2020 ◽  
Vol 146 ◽  
pp. 01002
Author(s):  
Thomas Ramstad ◽  
Anders Kristoffersen ◽  
Einar Ebeltoft
Keyword(s):  
Continental Shelf ◽  
Pore Structure ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Phase Flow ◽  
Pore Scale ◽  
Full Field ◽  
Scale Modelling ◽  
Relative Permeability Curves ◽  
Norwegian Continental Shelf

Relative permeability and capillary pressure are key properties within special core analysis and provide crucial information for full field simulation models. These properties are traditionally obtained by multi-phase flow experiments, however pore scale modelling has during the last decade shown to add significant information as well as being less time-consuming to obtain. Pore scale modelling has been performed by using the lattice-Boltzmann method directly on the digital rock models obtained by high resolution micro-CT images on end-trims available when plugs are prepared for traditional SCAL-experiments. These digital rock models map the pore-structure and are used for direct simulations of two-phase flow to relative permeability curves. Various types of wettability conditions are introduced by a wettability map that opens for local variations of wettability on the pore space at the pore level. Focus have been to distribute realistic wettabilities representative for the Norwegian Continental Shelf which is experiencing weakly-wetting conditions and no strong preference neither to water nor oil. Spanning a realistic wettability-map and enabling flow in three directions, a large amount of relative permeability curves is obtained. The resulting relative permeabilities hence estimate the uncertainty of the obtained flow properties on a spatial but specific pore structure with varying, but realistic wettabilities. The obtained relative permeability curves are compared with results obtained by traditional SCAL-analysis on similar core material from the Norwegian Continental Shelf. The results are also compared with the SCAL-model provided for full field simulations for the same field. The results from the pore scale simulations are within the uncertainty span of the SCAL models, mimic the traditional SCAL-experiments and shows that pore scale modelling can provide a time- and cost-effective tool to provide SCAL-models with uncertainties.

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