Jairam Kamath

Characterization of Core Scale Heterogeneities Using Laboratory Pressure Transients

In this paper, the authors construct a novel, state-of-the-art laboratory setup that captures several hundred pressure readings per second to study the response of cores to pressure disturbances. The authors used their new experimental setup to measure accurately and rapidly permeability of homogeneous cores, matrix and fractured properties of a fractured rock, and the individual segment properties of a butted core sample.

Critical Gas Saturation and Supersaturation in Low-Permeability Rocks

The laboratory methodology for determining critical gas saturation, S{sub gc}, in field depletion processes is still uncertain. Through measurements on low-permeability rocks, the authors explore some of the key issues affecting laboratory determination of S{sub gc}. Differences between laboratory depletion and external gas drive experiments are measured and analyzed. They also investigate the relationship between average S{sub gc} from material balance and true S{sub gc}, source of supersaturation, gas nucleation conditions, and dynamics of gas bubble growth in depletion drive experiments. They assess the use of low-bubble point oils to reduce experiment time. Finally, they suggest some improvements to laboratory procedures.

Evaluation of Accuracy of Estimating Air Permeability From Mercury-Injection Data

Published theoretical and correlative models and extensions developed during this study were examined to evaluate the accuracy of predicting air permeability from mercury-injection data. A recently developed statistical technique, bootstrapping, was used to compare different variables for correlation with permeability and to demonstrate that correlations by lithology or by field often are not statistically different

Water/Oil Relative Permeability Endpoints of Intermediate-Wet, Low-Permeability Rocks

The relative permeability endpoints of low-permeability, intermediate-wet mudstones increased with flow rate. This was because of both a decrease in capillary end effect and an increase in capillary number. Hence, conventional analysis will incorrectly describe field behavior. The authors recommend an improved methodology. They imaged steady-state saturation profiles at the end of different rate floods on one sample. They analyzed these profiles, which were axially nonuniform, to obtain capillary-end-effect-corrected data for each flow rate. The saturation distributions were also radially nonuniform. They characterized core-scale heterogeneity using a miscible flow test and examined the influence of heterogeneity. They conducted long-term tests on three short samples to study the higher-capillary-number regime. These tests displayed the existence of a critical capillary number, where the water relative permeability endpoint increased dramatically. The corresponding rate was over a magnitude smaller than flow rate traditionally recommended to eliminate capillary end effects.

Use of pore network models to interpret laboratory experiments on vugular rocks

Laboratory evaluation of recovery behavior in vugular rocks is unreliable because pore features are relatively large. 3-d Computed Tomography (CT) images of the porosity and of multi-rate waterfloods in a vugular sample show that conventional analysis is inadequate. Through parametric studies, we determine whether our large pore network models contain characteristics observed in the core floods. We then calibrate our models to laboratory inputs to improve quantitative interpretation.

Modeling Fluid Flow in Complex Naturally Fractured Reservoirs

We use a new numerical code to calculate single phase fluid flow in naturally fractured reservoirs. Our code is unique in that it can handle both complex fracture patterns and the coupling of the matrix and fracture flow fields. Our results show that details of the fracture statistics can become less important as the matrix becomes more permeable. We also find that the coupling of the matrix and fracture flow fields is very strong. We demonstrate the application of our code to develop grid block permeability values for use in continuum reservoir simulators. Mapping subsurface fracture distributions for use in our code is a key challenge. We briefly present the results of a new methodology that uses physical models and geostatistical techniques to generate such data.

Pore Network Modeling of Laboratory Experiments on Heterogeneous Carbonates

Many carbonate rocks have pore features that are large at the core plug scale. Laboratory assessment of recovery behavior in such carbonates can be unreliable. We review 3-D Computed Tomography (CT) images of the porosity distribution and of multi-rate waterfloods on a dolomite sample. These clearly show conventional analysis is inadequate, and we investigate use of large pore network models to improve our evaluation. Through parametric studies, we determine whether our large pore network models contain characteristics observed in the core floods. We then calibrate our models to laboratory inputs to improve quantitative interpretation. The model inputs are distributions of pore body and throat radii, throat length, coordination number, wettability, and degree of local and spatial correlation. The laboratory inputs are porosity, permeability, thin section analyses, scanning electron microscopy images, mercury injection, and centrifuge capillary pressure. Finally we compare model predictions of miscible and water flood behavior to experimental data.

Determining Relative Permeability Exponents Near the Residual Saturation

In a recent study 1 it was shown that the ratio of the flow rates of the produced fluids in an immiscible displacement can be used to identify geometrical and petrophysical characteristics of a reservoir. In this paper we develop an extended version of this approach and apply it to displacements in 1-D laboratory cores. Because of the possible importance of capillary effects, we pay attention to the capillary end effect at the outlet and to late times. It is shown that the exponent in the power-law dependence of the relative permeability to saturation, near its residual value, can be determined from a segment of the curve of the outlet fractional flow sometime after breakthrough. The asymptotic predictions are verified by obtaining an analytical solution to the full problem, including end-effects, for a model case corresponding to Burgers’ equation. Experimental results for the high-rate displacement of some gas-liquids pairs are reported. In agreement with the theoretical predictions, a power-law segment in the outlet fractional flow curve can be identified, before capillary effects set in. The exponents obtained are discussed in terms of pore-scale models for gasliquid displacement.

Laboratory Investigation of Injectivity Losses During WAG in West Texas Dolomrites

This study reports injectivity data for the different flow zones present during a Water-Alternating-Gas (WAG) flood. The experiments were carried out on four rock types sampled from the Grayburg dolomite formation in West Texas. We used liquid CO 2 -water, toluene-liquid CO 2 -water and crude oil-liquid CO 2 -water systems to isolate mechanisms and to address wettability concerns. We found that the injectivity of the chase water zone was comparable to the initial waterflood injectivity, and increased as the trapped CO 2 dissolved. The injectivity of the CO 2 -rich zone was significantly higher than the initial waterflood injectivity. Ambient condition toluene tests and reservoir condition crude tests gave similar results for the water and CO 2 zones. However the crude oil, even prior to any CO 2 injection, exhibited a strong tendency to plug the core samples. We were unable to restore permeability in the plugged up core samples by continuous flushing of different solvents.

Time Scaling of the Rates of Produced Fluids in Laboratory Displacements

In this report, the use of an asymptotic method, based on the time scaling of the ratio of produced fluids, to infer the relative permeability exponent of the displaced phase near its residual saturation, for immiscible displacements in laboratory cores was proposed. Sufficiently large injection rates, the existence of a power law can be detected, and its exponent inferred, by plotting in an appropriate plot the ratio of the flow rates of the two fluids at the effluent for some time after breakthrough.