Steady-State Liquid Permeability Measurements in Samples from the Bakken Formation, Williston Basin, USA

2021 ◽  
Author(s):  
Sebastian Ramiro-Ramirez ◽  
Peter B. Flemings ◽  
Athma R. Bhandari ◽  
Oluwafemi Solomon Jimba
Keyword(s):  
Steady State ◽  
Confining Pressure ◽  
Hysteresis Effect ◽  
Bakken Formation ◽  
Pore Throat ◽  
Confining Stress ◽  
Well Production ◽  
Matrix Permeability ◽  
The Matrix ◽  
Middle Member

Abstract We measured steady-state liquid (dodecane) permeability in four horizontal core plugs from the middle member of the Bakken Formation at multiple effective stress conditions to investigate how permeability evolves with confining stress and to infer the matrix permeability. Three of the four tested samples behaved almost perfectly elastically as the hysteresis effect was negligible. In contrast, the fourth sample showed a permeability decrease of ~40% at the end of the test program. Our interpretation is that the closure of open artificial micro-fractures initially present in the sample (based on micro-CT imaging) caused that permeability hysteresis. The matrix permeability to dodecane (oil) of the tested samples is between ~50 nD and ~520 nD at the confining pressure of 9500 psi. The 520 nD sample exhibited the lowest porosity, the highest calcite content, and the largest dominant pore throat radii. In contrast, the 50 nD sample was more porous, and exhibited the highest dolomite content and the smallest dominant pore throat radii. This study shows that our multi-stress testing protocol allows the study of the permeability hysteresis effect to interpret the matrix permeability. We also document the presence of middle Bakken lithologies with permeabilities up to one order of magnitude greater than others. These permeable lithologies may have a significant contribution to well production rates.

The Influence of Drying and Stress on the Permeability of Texas Lignite

1977 ◽  
Vol 99 (4) ◽  
pp. 634-640
Author(s):  
T. W. Thompson ◽  
S. Sen ◽  
K. E. Gray ◽  
T. F. Edgar
Keyword(s):  
Applied Stress ◽  
Significant Influence ◽  
Confining Pressure ◽  
Fracture Permeability ◽  
Gasification Process ◽  
Matrix Permeability ◽  
The Matrix ◽  
Order Of Magnitude ◽  
Permeability Increase

Tests have been carried out to quantify the variation in permeability of Texas lignite with drying and with applied stress. It has been shown that the matrix permeability of lignite may be increased from effectively zero to the order of 10 darcies by removing about 20 percent by weight of water. In addition, an increase of confining pressure after drying will reduce the permeability, but only by about one order of magnitude. Drying of the matrix thus may produce matrix permeabilities of the same order as the undried field fracture permeability. The permeability increase of the matrix is initially greater parallel to the bedding than perpendicular, but after further drying the two orientations show similar final permeabilities. This drying effect could have a significant influence on the operation of an in-situ gasification process by increasing the transmissivity and injectivity of the producing seam. Drying of the seam could occur by the flow of unsaturated gas and will be enhanced by combustion.

scholarly journals Effects of Supercritical CO2 on Matrix Permeability of Unconventional Formations

Energies ◽  
2021 ◽  
Vol 14 (4) ◽  
pp. 1101
Author(s):  
Arash Kamali-Asl ◽  
Mark D Zoback ◽  
Arjun H. Kohli
Keyword(s):  
Pressure Dependence ◽  
Carbonic Acid ◽  
Confining Pressure ◽  
Initial Permeability ◽  
Carbonate Content ◽  
Scattered Electron ◽  
Matrix Permeability ◽  
The Matrix ◽  
Order Of Magnitude ◽  
Flow Pathways

We studied the effects of supercritical carbon dioxide (scCO2) on the matrix permeability of reservoir rocks from the Eagle Ford, Utica, and Wolfcamp formations. We measured permeability using argon before exposure of the samples to scCO2 over time periods ranging from days to weeks. We measured permeability (and the change of permeability with confining pressure) when both argon and scCO2 were the pore fluids. In all three formations, we generally observe a negative correlation between initial permeability and carbonate content—the higher the carbonate content, the lower the initial permeability. In clay- and organic-rich samples, swelling of the matrix resulting from adsorption decreased the permeability by about 50% when the pore fluid was scCO2 although this permeability change is largely reversible. In carbonate-rich samples, dissolution of carbonate minerals by carbonic acid irreversibly increased matrix permeability, in some cases by more than one order of magnitude. This dissolution also increases the pressure dependence of permeability apparently due to enhanced mechanical compaction. Despite these trends, we observed no general correlation between mineralogy and the magnitude of the change in permeability with argon before and after exposure to scCO2. Flow of scCO2 through μm-scale cracks appears to play an important role in determining matrix permeability and the pressure dependence of permeability. Extended permeability measurements show that while adsorption is nearly instantaneous and reversible, dissolution is time-dependent, probably owing to reaction kinetics. Our results indicate that the composition and microstructure of matrix flow pathways control both the initial permeability and how permeability changes after interaction with scCO2. Electron microscopy images with Back-Scattered Electron (BSE) and Energy Dispersive Spectroscopy (EDS) revealed dissolution and etching of calcite minerals and precipitation of calcium sulfide resulting from exposure to scCO2.

Application of machine learning algorithms to predict permeability in tight sandstone formations

Nafta-Gaz ◽  
2021 ◽  
Vol 77 (5) ◽  
pp. 283-292
Author(s):  
Tomasz Topór ◽  
Keyword(s):  
Machine Learning ◽  
Oil And Gas ◽  
Learning Algorithms ◽  
Confining Pressure ◽  
Machine Learning Algorithms ◽  
Core Material ◽  
Confining Stress ◽  
Tight Sandstone ◽  
Oil And Gas Exploration ◽  
Better Than

The application of machine learning algorithms in petroleum geology has opened a new chapter in oil and gas exploration. Machine learning algorithms have been successfully used to predict crucial petrophysical properties when characterizing reservoirs. This study utilizes the concept of machine learning to predict permeability under confining stress conditions for samples from tight sandstone formations. The models were constructed using two machine learning algorithms of varying complexity (multiple linear regression [MLR] and random forests [RF]) and trained on a dataset that combined basic well information, basic petrophysical data, and rock type from a visual inspection of the core material. The RF algorithm underwent feature engineering to increase the number of predictors in the models. In order to check the training models’ robustness, 10-fold cross-validation was performed. The MLR and RF applications demonstrated that both algorithms can accurately predict permeability under constant confining pressure (R2 0.800 vs. 0.834). The RF accuracy was about 3% better than that of the MLR and about 6% better than the linear reference regression (LR) that utilized only porosity. Porosity was the most influential feature of the models’ performance. In the case of RF, the depth was also significant in the permeability predictions, which could be evidence of hidden interactions between the variables of porosity and depth. The local interpretation revealed the common features among outliers. Both the training and testing sets had moderate-low porosity (3–10%) and a lack of fractures. In the test set, calcite or quartz cementation also led to poor permeability predictions. The workflow that utilizes the tidymodels concept will be further applied in more complex examples to predict spatial petrophysical features from seismic attributes using various machine learning algorithms.

Allocation of fracturing intervals and justification of fracture parameters in the pre-Jurassic deposits

2021 ◽  
pp. 9-19
Author(s):  
P. A. Boronin ◽  
N. V. Gilmanova ◽  
N. Yu. Moskalenko
Keyword(s):  
Permeability Coefficient ◽  
Complex Structure ◽  
High Flow ◽  
Well Testing ◽  
Rock Matrix ◽  
Unconventional Reservoir ◽  
Flow Rates ◽  
Matrix Permeability ◽  
The Matrix ◽  
Standard Set

The object of research in this article is the productive deposits of the pre-Jurassic complex. The pre-Jurassic complex is of great interest, this is an unconventional reservoir with a complex structure and developed fractured zones. High flow rates cannot be determined by the rock matrix, since the matrix permeability coefficient is on average 2−3 md. In this regard, there is the problem of separation of fractured intervals according to a standard set of well testing.

A Novel Coreflood Test to Evaluate EOR Potential of Wettability-Altering Surfactants in Oil-Wet Heterogeneous Carbonate Reservoirs

2021 ◽  
Author(s):  
Yue Shi ◽  
Kishore Mohanty ◽  
Manmath Panda
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Wettability Alteration ◽  
Low Permeability ◽  
High Permeability ◽  
Matrix Permeability ◽  
Rock Heterogeneity ◽  
The Matrix ◽  
Flow Through ◽  
Main Factors

Abstract Oil-wetness and heterogeneity (i.e., existence of low and high permeability regions) are two main factors that result in low oil recovery by waterflood in carbonate reservoirs. The injected water is likely to flow through high permeability regions and bypass the oil in low permeability matrix. In this study, systematic coreflood tests were carried out in both "homogeneous" cores and "heterogeneous" cores. The heterogeneous coreflood test was proposed to model the heterogeneity of carbonate reservoirs, bypassing in low-permeability matrix during waterfloods, and dynamic imbibition of surfactant into the low-permeability matrix. The results of homogeneous coreflood tests showed that both secondary-waterflood and secondary-surfactant flood can achieve high oil recovery (>50%) from relatively homogenous cores. A shut-in phase after the surfactant injection resulted in an additional oil recovery, which suggests enough time should be allowed while using surfactants for wettability alteration. The core with a higher extent of heterogeneity produced lower oil recovery to waterflood in the coreflood tests. Final oil recovery from the matrix depends on matrix permeability as well as the rock heterogeneity. The results of heterogeneous coreflood tests showed that a slow surfactant injection (dynamic imbibition) can significantly improve the oil recovery if the oil-wet reservoir is not well-swept.

scholarly journals Calculating the Energy Spectrum of Complex Low-Dimensional Heterostructures in the Electric Field

2013 ◽  
Vol 2013 ◽  
pp. 1-7
Author(s):  
Svetlana N. Khonina ◽  
Sergey G. Volotovsky ◽  
Sergey I. Kharitonov ◽  
Nikolay L. Kazanskiy
Keyword(s):  
Steady State ◽  
Electric Field ◽  
Ground State ◽  
State Energy ◽  
Airy Functions ◽  
Piecewise Constant ◽  
Matrix Rank ◽  
The Matrix ◽  
Constant Potential ◽  
Low Dimensional

An algorithm for solving the steady-state Schrödinger equation for a complex piecewise-constant potential in the presence of theE-field is developed and implemented. The algorithm is based on the consecutive matching of solutions given by the Airy functions at the band boundaries with the matrix rank increasing by no more than two orders, which enables the characteristic solution to be obtained in the convenient form for search of the roots. The algorithm developed allows valid solutions to be obtained for the electric field magnitudes larger than the ground-state energy level, that is, when the perturbation method is not suitable.

Exploring Low-IFT Foam EOR in Fractured Carbonates: Success and Particular Challenges of Sub-10-md Limestone

SPE Journal ◽  
1900 ◽  
Vol 25 (02) ◽  
pp. 867-882
Author(s):  
Pengfei Dong ◽  
Maura Puerto ◽  
Guoqing Jian ◽  
Kun Ma ◽  
Khalid Mateen ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Surfactant Solution ◽  
Mineral Dissolution ◽  
Mobility Control ◽  
Matrix Permeability ◽  
Geochemical Properties ◽  
Remaining Oil ◽  
The Matrix ◽  
Incremental Oil Recovery ◽  
Foam Flooding

Summary The high formation heterogeneity in naturally fractured limestone reservoirs requires mobility control agents to improve sweep efficiency and boost oil recovery. However, typical mobility control agents, such as polymers and gels, are impractical in tight sub-10-md formations due to potential plugging issues. The objective of this study is to demonstrate the feasibility of a low-interfacial-tension (low-IFT) foam process in fractured low-permeability limestone reservoirs and to investigate relevant geochemical interactions. The low-IFT foam process was investigated through coreflood experiments in homogeneous and fractured oil-wet cores with sub-10-md matrix permeability. The performance of a low-IFT foaming formulation and a well-known standard foamer [alpha olefin sulfonate (AOS) C14-16] were compared in terms of the efficiency of oil recovery. The effluent ionic concentrations were measured to understand how the geochemical properties of limestone influenced the low-IFT foam process. Aqueous stability and phase behavior tests with crushed core materials and brines containing various divalent ion concentrations were conducted to interpret the observations in the coreflood experiments. Low-IFT foam process can achieve significant incremental oil recovery in fractured oil-wet limestone reservoirs with sub-10-md matrix permeability. Low-IFT foam flooding in a fractured oil-wet limestone core with 5-md matrix permeability achieved 64% incremental oil recovery compared to waterflooding. In this process, because of the significantly lower capillary entry pressure for surfactant solution compared to gas, the foam primarily diverted surfactant solution from the fracture into the matrix. This selective diversion effect resulted in surfactant or weak foam flooding in the tight matrix and hence improved the invading fluid flow in the matrix. Meanwhile, the low-IFT property of the foaming formulation mobilized the remaining oil in the matrix. This oil mobilization effect of the low-IFT formulation achieved lower remaining oil saturation in the swept zones compared with the formulation lacking low-IFT property with oil. The limestone geochemical instability caused additional challenges for the low-IFT foam process in limestone reservoirs compared to dolomite reservoirs. The reactions of calcite with injected fluids—such as mineral dissolution and the exchange of calcium and magnesium—were found to increase the Ca2+ concentration in the produced fluids. Because the low-IFT foam process is sensitive to brine salinity, the additional Ca2+ may cause potential surfactant precipitation and unfavorable over-optimum conditions. It, therefore, may cause injectivity and phase-trapping issues especially in the homogeneous limestone. Results in this work demonstrated that despite the challenges associated with limestone dissolution, the low-IFT foam process can remarkably extend chemical enhanced oil recovery (EOR) in fractured oil-wet tight reservoirs with matrix permeability as low as 5 md.

scholarly journals Improved Method for Measuring the Permeability of Nanoporous Material and Its Application to Shale Matrix with Ultra-Low Permeability

Materials ◽  
2019 ◽  
Vol 12 (9) ◽  
pp. 1567 ◽  
Author(s):  
Taojie Lu ◽  
Ruina Xu ◽  
Bo Zhou ◽  
Yichuan Wang ◽  
Fuzhen Zhang ◽  
...  
Keyword(s):  
High Pressure ◽  
Fluid Transport ◽  
Effective Means ◽  
Clean Energy ◽  
Nanoporous Materials ◽  
Environmental Research ◽  
Low Permeability ◽  
Matrix Permeability ◽  
Wide Range ◽  
The Matrix

Nanoporous materials have a wide range of applications in clean energy and environmental research. The permeability of nanoporous materials is low, which affects the fluid transport behavior inside the nanopores and thus also affects the performance of technologies based on such materials. For example, during the development of shale gas resources, the permeability of the shale matrix is normally lower than 10−3 mD and has an important influence on rock parameters. It is challenging to measure small pressure changes accurately under high pressure. Although the pressure decay method provides an effective means for the measurement of low permeability, most apparatuses and experiments have difficulty measuring permeability in high pressure conditions over 1.38 MPa. Here, we propose an improved experimental method for the measurement of low permeability. To overcome the challenge of measuring small changes in pressure at high pressure, a pressure difference sensor is used. By improving the constant temperature accuracy and reducing the helium leakage rate, we measure shale matrix permeabilities ranging from 0.05 to 2 nD at pore pressures of up to 8 MPa, with good repeatability and sample mass irrelevance. The results show that porosity, pore pressure, and moisture conditions influence the matrix permeability. The permeability of moist shale is lower than that of dry shale, since water blocks some of the nanopores.

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