Modelling and Upscaling Unstable Miscible Displacement Processes: Characterisation of Physical Instabilities

2021 ◽  
Author(s):  
Precious Ogbeiwi ◽  
Karl Stephen
Keyword(s):  
Relative Permeability ◽  
Transport Coefficients ◽  
Miscible Displacement ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Fine Grid ◽  
Flow Models ◽  
Reservoir Models ◽  
Flood Simulations ◽  
Physical Instabilities

Abstract The compositional simulations are required to model CO2 flooding are computationally expensive particularly for fine-gridded models that have high resolutions, and many components. Upscaling procedures can be used in the subsurface flow models to reduce the high computation requirements of the fine grid simulations and accurately model miscible CO2 flooding. However, the effects of physical instabilities are often not well represented and captured by the upscaling procedures. This paper presents an approach for upscaling of miscible displacements is presented which adequately represents physical instabilities such as viscous and heterogeneity induced fingering on coarser grids using pseudoisation techniques. The approach was applied to compositional numerical simulations of two-dimensional reservoir models with a focus on CO2 injection. Our approach is based on the pseudoisation of relative permeability and the application of transport coefficients to upscale viscous fingering and heterogeneity-induced channelling in a multi-contact miscible CO2 injection. Pseudo-relative permeability curves were computed using a pseudoisation technique and applied in combination with transport coefficients to upscale the behaviour of fine-scale miscible CO2 flood simulations to coarser scales. The accuracy of the results of the pseudoisation procedures were assessed by applying statistical analysis to compare them to the results of the fine grid simulations. It is observed from the results that the coarse models provide accurate predictions of the miscible displacement process and that the fingering regimes are adequately captured in the coarse models. The study presents a framework that can be employed to represent the dynamics of physical instabilities associated with miscible CO2 displacements in upscaled coarser grid reservoir models.

scholarly journals Numerical optimisation of CO<sub>2</sub> flooding using a hierarchy of reservoir models

2021 ◽  
Vol 56 ◽  
pp. 19-31
Author(s):  
Andrey Afanasyev ◽  
Anna Andreeva ◽  
Anna Chernova
Keyword(s):  
Net Present Value ◽  
Gradient Methods ◽  
Cash Flows ◽  
Initial Guess ◽  
Co2 Injection ◽  
Global Maximum ◽  
Co2 Flooding ◽  
Present Value ◽  
Reservoir Models ◽  
Water Alternating Gas

Abstract. We present a method for accelerated optimisation of CO2 injection into petroleum reservoirs. The optimisation assumes maximisation of the net present value by coupling reservoir models with the calculation of cash flows. The proposed method is based on the construction of a hierarchy of compositional reservoir models of increasing complexity. We show that in dimensionless volumes, the optimal water and gas slugs are very close for the 1-D and 2-D areal reservoir models of the water-alternating-gas (WAG) process. Therefore, the solution to the 1-D optimisation problem gives a good approximation of the solution to the 2-D problem. The proposed method is designed by using this observation. It employs a larger number of less computationally expensive 1-D compositional simulations to obtain a good initial guess for the injection volumes in much more expensive 2-D simulations. We suggest using the non-gradient optimisation algorithms for the coarse models on low levels of the hierarchy to guarantee convergence to the global maximum of the net present value. Then, we switch to the gradient methods only on the upper levels. We give examples of the algorithm application for optimisation of different WAG strategies and discuss its performance. We propose that 1-D compositional simulations can be efficient for optimising areal CO2 flooding patterns.

Advances in Midland Basin Expand Boundaries of CO2 EOR in Marginal Pay Areas

2021 ◽  
Vol 73 (06) ◽  
pp. 65-66
Author(s):  
Judy Feder
Keyword(s):  
Oil Recovery ◽  
Large Scale ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Improved Oil Recovery ◽  
Midland Basin ◽  
The North ◽  
Production Wells ◽  
Original Oil In Place ◽  
Carbon Dioxide Co2

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 200460, “A Case Study of SACROC CO2 Flooding in Marginal Pay Regions: Improving Asset Performance,” by John Kalteyer, SPE, Kinder Morgan, prepared for the 2020 SPE Improved Oil Recovery Conference, originally scheduled to be held in Tulsa, 18–22 April. The paper has not been peer reviewed. As one of the first fields in the world to use carbon dioxide (CO2) in enhanced oil recovery (EOR), the Scurry Area Canyon Reef Operators Committee (SACROC) unit of the Kelly-Snyder field in the Midland Basin of Texas provides a unique opportunity to study, learn from, and improve upon the development of CO2 flood technology. The complete paper reviews the history of EOR at SACROC, discusses changes in theory over time, and provides a look at the field’s future. Field Overview and Development History The first six pages of the paper discuss the field’s location, geology, and development before June 2000, when Kinder Morgan acquired the SACROC unit and took over as operator. Between initial gas injection in 1972 and 2000, approximately 1 TCF of CO2 had been injected into the Canyon Reef reservoir. Since 2000, cumulative CO2 injection has sur-passed 7 TCF and yielded cumulative EOR of over 180 million bbl. The reservoir is a primarily limestone reef complex containing an estimated original oil in place (OOIP) of just under 3 billion bbl. The reservoir ranges from 200 ft gross thickness in the south to 900 ft in the north, where the limestone matrix averages 8% porosity and 20-md permeability. The Canyon Reef structure is divided into four major intervals, of which the Upper Canyon zone provides the highest-quality pay. The field was discovered in 1948 at a pressure of 3,122 psi. By late 1950, 1,600 production wells had been drilled and the reservoir pressure plummeted, settling as low as 1,700 psi. Waterflooding begun in 1954 enabled the field to continue producing for nearly 20 years, at which time the operators deter-mined that another recovery mechanism would be needed to maximize recovery and reach additional areas of the field. The complete paper discusses various CO2 injection programs that were developed and applied—including a true tertiary response from a miscible CO2 flood in 1981—along with their outcomes. Acquisition and CO2-Injection Redevelopment In June 2000 Kinder Morgan acquired the SACROC Unit and took over as operator. Approximately 6.7 billion bbl of water and 1.3 TCF of CO2 had been injected across the unit to that date, but the daily oil rate of 8,700 B/D was approaching the field’s economic limit. An estimated 40% of the OOIP had been produced through the combination of recovery methods that each previous operator had used. Expanding on the conclusions of its immediate predecessor, the operator initiated large-scale CO2-flood redevelopment in a selection of project areas. These redevelopments were based on several key distinctions differentiating them from previous injection operations.

scholarly journals Investigation of Properties Alternation during Super-Critical CO2 Injection in Shale

2019 ◽  
Vol 9 (8) ◽  
pp. 1686 ◽  
Author(s):  
Sai Wang ◽  
Kouqi Liu ◽  
Juan Han ◽  
Kegang Ling ◽  
Hongsheng Wang ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Supercritical Co2 ◽  
Indentation Test ◽  
Nitrogen Adsorption ◽  
Xrd Analysis ◽  
Bet Surface Area ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Recovery Method ◽  
Injection Process

The low recovery of oil from tight liquid-rich formations is still a major challenge for a tight reservoir. Thus, supercritical CO2 flooding was proposed as an immense potential recovery method for production improvement. While up to date, there have been few studies to account for the formation properties’ variation during the CO2 Enhanced Oil Recovery (EOR) process, especially investigation at the micro-scale. This work conducted a series of measurements to evaluate the rock mechanical change, mineral alteration and the pore structure properties’ variation through the supercritical CO2 (Sc-CO2) injection process. Corresponding to the time variation (0 days, 10 days, 20 days, 30 days and 40 days), the rock mechanical properties were analyzed properly through the nano-indentation test, and the mineralogical alterations were quantified through X-ray diffraction (XRD). In addition, pore structures of the samples were measured through the low-temperature N2 adsorption tests. The results showed that, after Sc-CO2 injection, Young’s modulus of the samples decreases. The nitrogen adsorption results demonstrated that, after the CO2 injection, the mesopore volume of the sample would change as well as the specific Brunauer–Emmett–Teller (BET) surface area which could be aroused from the chemical reactions between the CO2 and some authigenic minerals. XRD analysis results also indicated that mesopore were altered due to the chemical reaction between the injected Sc-CO2 and the minerals.

scholarly journals Experimental Investigation on the Effects of CO2 Displacement Methods on Petrophysical Property Changes of Ultra-Low Permeability Sandstone Reservoirs Near Injection Wells

Energies ◽  
2019 ◽  
Vol 12 (2) ◽  
pp. 327 ◽  
Author(s):  
Qian Wang ◽  
Shenglai Yang ◽  
Haishui Han ◽  
Lu Wang ◽  
Kun Qian ◽  
...  
Keyword(s):  
Physical Properties ◽  
Pore Size ◽  
Mineral Dissolution ◽  
Co2 Injection ◽  
Low Permeability ◽  
Co2 Flooding ◽  
Formation Water ◽  
Injection Wells ◽  
Rock Interaction ◽  
Sandstone Reservoirs

The petrophysical properties of ultra-low permeability sandstone reservoirs near the injection wells change significantly after CO2 injection for enhanced oil recovery (EOR) and CO2 storage, and different CO2 displacement methods have different effects on these changes. In order to provide the basis for selecting a reasonable displacement method to reduce the damage to these high water cut reservoirs near the injection wells during CO2 injection, CO2-formation water alternate (CO2-WAG) flooding and CO2 flooding experiments were carried out on the fully saturated formation water cores of reservoirs with similar physical properties at in-situ reservoir conditions (78 °, 18 MPa), the similarities and differences of the changes in physical properties of the cores before and after flooding were compared and analyzed. The measurement results of the permeability, porosity, nuclear magnetic resonance (NMR) transversal relaxation time (T2) spectrum and scanning electron microscopy (SEM) of the cores show that the decrease of core permeability after CO2 flooding is smaller than that after CO2-WAG flooding, with almost unchanged porosity in both cores. The proportion of large pores decreases while the proportion of medium pores increases, the proportion of small pores remains almost unchanged, the distribution of pore size of the cores concentrates in the middle. The changes in range and amplitude of the pore size distribution in the core after CO2 flooding are less than those after CO2-WAG flooding. After flooding experiments, clay mineral, clastic fines and salt crystals adhere to some large pores or accumulate at throats, blocking the pores. The changes in core physical properties are the results of mineral dissolution and fines migration, and the differences in these changes under the two displacement methods are caused by the differences in three aspects: the degree of CO2-brine-rock interaction, the radius range of pores where fine migration occurs, the power of fine migration.

Wettability measurements on two sandstones: an experimental investigation before and after CO2 flooding

2020 ◽  
Vol 60 (1) ◽  
pp. 117
Author(s):  
Cut Aja Fauziah ◽  
Emad A. Al-Khdheeawi ◽  
Ahmed Barifcani ◽  
Stefan Iglauer
Keyword(s):  
Contact Angle ◽  
Co2 Storage ◽  
Contact Angle Measurement ◽  
Contact Angles ◽  
Angle Measurement ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Berea Sandstone ◽  
Before And After ◽  
Carbon Dioxide Co2

Wettability of rock–fluid systems is an important for controlling the carbon dioxide (CO2) movement and the capacities of CO2 geological trapping mechanisms. Although contact angle measurement is considered a potentially scalable parameter for evaluation of the wettability characteristics, there are still large uncertainties associated with the contact angle measurement for CO2–brine–rock systems. Thus, this study experimentally examined the wettability, before and after flooding, of two different samples of sandstone: Berea and Bandera grey sandstones. For both samples, several sets of flooding of brine (5 wt % NaCl + 1 wt % KCl in deionised water), CO2-saturated (live) brine and supercritical CO2 were performed. The contact angle measurements were conducted for the CO2–sandstone system at two different reservoir pressures (10 and 15 MPa) and at a reservoir temperature of 323 K. The results showed that both the advancing and receding contact angles of the sandstone samples after flooding were higher than that measured before flooding (i.e. after CO2 injection the sandstones became more CO2-wet). Moreover, the Bandera grey samples had higher contact angles than Berea sandstone. Thus, we conclude that CO2 flooding altered the sandstone wettability to be more CO2-wet, and Berea sandstone had a higher CO2 storage capacity than Bandera grey sandstone.

Changes in multi-phase flow properties of carbonate porous media during CO2 injection

2020 ◽  
Vol 60 (2) ◽  
pp. 672
Author(s):  
Mojtaba Seyyedi ◽  
Ausama Giwelli ◽  
Cameron White ◽  
Lionel Esteban ◽  
Michael Verrall ◽  
...  
Keyword(s):  
Porous Media ◽  
Pore Structure ◽  
Relative Permeability ◽  
Carbonate Rock ◽  
Trapping Potential ◽  
Co2 Injection ◽  
Phase Flow ◽  
Residual Trapping ◽  
Multi Phase Flow ◽  
Multi Phase

Impacts of fluid–rock geochemical reactions occurring during CO2 injection into underground formations, including CO2 geosequestration, on porosity and single-phase permeability are well documented. However, their impacts on pore structure and multi-phase flow behaviour of porous media and, therefore, on CO2 injectivity and residual trapping potential, are yet unknown. We found that CO2-saturated brine–rock interactions in a carbonate rock led to a decrease in the sweep efficiency of the non-wetting phase (gas) during primary drainage. Furthermore, they led to an increase in the relative permeability of the non-wetting phase, a decrease in the relative permeability of the wetting phase (brine) and a reduction in the residual trapping potential of the non-wetting phase. The impacts of reactions on pore structure shifted the relative permeability cross-point towards more water-wet condition. Finally, calcite dissolution caused a reduction in capillary pressure of the used carbonate rock. For CO2 underground injection applications, such changes in relative permeabilities, residual trapping potential of the non-wetting phase (CO2) and capillary pressure would reduce the CO2 storage capacity and increase the risk of CO2 leakage.

scholarly journals Relative Permeability Characteristics During Carbon Capture and Sequestration Process in Low-Permeable Reservoirs

Materials ◽  
2020 ◽  
Vol 13 (4) ◽  
pp. 990
Author(s):  
Mingxing Bai ◽  
Lu Liu ◽  
Chengli Li ◽  
Kaoping Song
Keyword(s):  
Relative Permeability ◽  
Carbon Capture ◽  
Oil And Gas ◽  
Co2 Flooding ◽  
Two Phase ◽  
Permeability Characteristics ◽  
Gas Recovery ◽  
Miscible Flooding ◽  
Relative Permeability Curves ◽  
Carbon Dioxide Co2

The injection of carbon dioxide (CO2) in low-permeable reservoirs can not only mitigate the greenhouse effect on the environment, but also enhance oil and gas recovery (EOR). For numerical simulation work of this process, relative permeability can help predict the capacity for the flow of CO2 throughout the life of the reservoir, and reflect the changes induced by the injected CO2. In this paper, the experimental methods and empirical correlations to determine relative permeability are reviewed and discussed. Specifically, for a low-permeable reservoir in China, a core displacement experiment is performed for both natural and artificial low-permeable cores to study the relative permeability characteristics. The results show that for immiscible CO2 flooding, when considering the threshold pressure and gas slippage, the relative permeability decreases to some extent, and the relative permeability of oil/water does not reduce as much as that of CO2. In miscible flooding, the curves have different shapes for cores with a different permeability. By comparing the relative permeability curves under immiscible and miscible CO2 flooding, it is found that the two-phase span of miscible flooding is wider, and the relative permeability at the gas endpoint becomes larger.

The Effect of Phase Equilibria on the CO2 Displacement Mechanism

1979 ◽  
Vol 19 (04) ◽  
pp. 242-252 ◽  
Author(s):  
R.S. Metcalfe ◽  
Lyman Yarborough
Keyword(s):  
Carbon Dioxide ◽  
Phase Equilibria ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Miscible Displacement ◽  
Co2 Flooding ◽  
Recovery Method ◽  
Two Fluids ◽  
Reservoir Conditions

Abstract Carbon dioxide flooding under miscible conditions is being developed as a major process for enhanced oil recovery. This paper presents results of research studies to increase our understanding of the multiple-contact miscible displacement mechanism for CO2 flooding. Carbon dioxide displacements of three synthetic oils of increasing complexity (increasing number of hydrocarbon components) are described. The paper concentrates on results of laboratory flow studies, but uses results of phase-equilibria and numerical studies to support the conclusions.Results from studies with synthetic oils show that at least two multiple-contact miscible mechanisms, vaporization and condensation, can be identified and that the phase-equilibria data can be used as a basis for describing the mechanism. The phase-equilibria change with varying reservoir conditions, and the flow studies show that the miscible mechanism depends on the phase-equilibria behavior. Qualitative predictions with mathematical models support our conclusions.Phase-equilibria data with naturally occurring oils suggest the two mechanisms (vaporization and condensation) are relevant to CO2 displacements at reservoir conditions and are a basis for specifying the controlling mechanisms. Introduction Miscible-displacement processes, which rely on multiple contacts of injected gas and reservoir oil to develop an in-situ solvent, generally have been recognized by the petroleum industry as an important enhanced oil-recovery method. More recently, CO2 flooding has advanced to the position (in the U.S.) of being the most economically attractive of the multiple-contact miscibility (MCM) processes. Several projects have been or are currently being conducted either to study or use CO2 as an enhanced oil-recovery method. It has been demonstrated convincingly by Holm and others that CO2 can recover oil from laboratory systems and therefore from the swept zone of petroleum reservoirs using miscible displacement. However, several contradictions seem to exist in published results.. These authors attempt to establish the mechanism(s) through which CO2 and oil form a miscible solvent in situ. (The solvent thus produced is capable of performing as though the two fluids were miscible when performing as though the two fluids were miscible when injected.) In addition, little experimental work has been published to provide support for the mechanisms of multiple-contact miscibility, as originally discussed by Hutchinson and Braun.One can reasonably assume that the miscible CO2 process will be related directly to phase equilibria process will be related directly to phase equilibria because it involves intimate contact of gases and liquids. However, no data have been published to indicate that the mechanism for miscibility development may differ for varying phase-equilibria conditions.This paper presents the results of both flow and phase-equilibria studies performed to determine the phase-equilibria studies performed to determine the mechanism(s) of CO2 multiple-contact miscibility. These flow studies used CO2 to displace three multicomponent hydrocarbon mixtures under first-contact miscible, multiple-contact miscible, and immiscible conditions. Results are presented to support the vaporization mechanism as described by Hutchinson and Braun, and also to show that more than one mechanism is possible with CO2 displacements. The reason for the latter is found in the results of phase-equilibria studies. SPEJ P. 242

Carbon Dioxide Displacement of a West Texas Reservoir Oil

1982 ◽  
Vol 22 (06) ◽  
pp. 805-815 ◽  
Author(s):  
William F. Yellig
Keyword(s):  
Mass Transfer ◽  
Phase Equilibria ◽  
Oil Recovery ◽  
Miscible Displacement ◽  
Pilot Test ◽  
Co2 Flooding ◽  
Process Data ◽  
Analytical Technique ◽  
West Texas ◽  
Pilot Tests

Yellig, William F., SPE, Amoco Production Co. Abstract This paper presents results of an extensive study to understand CO2 displacement of Levelland (TX) reservoir oil. The work was conducted to support Levelland CO2 pilots currently in progress. Experimental displacement tests were conducted at various pressures, core lengths, and CO2 frontal advance rates. The experimental system included a novel analytical technique to obtain effluent compositional profiles within the oil-moving zone at test conditions. The results of this study show that at pressures greater than the CO2 minimum miscibility pressure (MMP), a multicontact miscible displacement mechanism predominates. Miscibility is developed in situ by vaporization or extraction-type mass transfer. The laboratory lengths required for CO2 to develop miscibility and exhibit miscible displacement efficiency were found dependent on the phase equilibria of the CO2/Levelland oil system. Displacements requiring the greatest length to develop miscibility were at pressures where single-contact mixtures of CO2 and Levelland oil form two liquid phases. A companion paper demonstrates the use of the analytical technique developed in this study to obtain process data from a CO2 field pilot test. In addition, the mechanistic information obtained from this study is used to interpret the process data from the pilot test. The results have application to other reservoir oils whose phase equilibria with CO2 are similar to the CO2/ Levelland oil system. Introduction Miscible CO2 flooding is developing rapidly as a commercial enhanced oil-recovery process. The successful design and interpretation of CO2 pilot tests and fieldwide floods are dependent on a good knowledge of the reservoir and the CO2 displacement process. The overall CO2 displacement process is shown schematically in Fig. 1. The main focus of this study concerned the oil moving zone (OMZ) and particularly the mechanisms by which this zone formed and by which CO2 displaced Levelland oil. Levelland oil was chosen because it is typical of many west Texas reservoir oils being considered for CO2 flooding. In addition, the CO2 pilot tests currently conducted in the Levelland field provide a direct application of this research. Several authors have discussed the displacement of reservoir oil by CO2. These discussions have centered around three primary displacement mechanisms: immiscible, multicontact or developed miscible, and contact miscible. In addition, two basic types of mass transfer have been postulated as responsible for the development of miscibility in a multicontact process: transfer of hydrocarbons from the in-place oil to the displacing CO2 (i.e., vaporization or extraction) and transfer of CO2 to the in-place oil (i.e., condensation). Vaporization and extraction are the same basic mass-transfer process. Vaporization refers to mass transfer from a liquid oil phase to a CO2-rich vapor phase and extraction refers to mass transfer from a liquid oil phase to a CO2-rich liquid phase. The distinction between vaporization and extraction is somewhat arbitrary in describing the CO2 process since it reflects the types of phases present only on first contact. One purpose of this paper is to present results of a comprehensive study to determine the mechanism by which CO2 displaces Levelland oil at reservoir conditions. SPEJ P. 805^

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