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.

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.

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.

The Performance Characteristics of Waterdrive Gas Reservoirs off the South-East Coast of Trinidad

2014 ◽  
Author(s):  
C Welsh
Keyword(s):  
Relative Permeability ◽  
East Coast ◽  
Produced Water ◽  
The South ◽  
Fractional Flow ◽  
Gas Reservoirs ◽  
Well Completion ◽  
High Production Rate ◽  
Single Well ◽  
Condensate Blocking

Abstract Sustained production is needed to satisfy the contractual demands of both Trinidad's domestic and LNG markets. To unlock the value of existing fields on production, comprehending the case histories of produced water drive reservoirs is necessary. This study analyses production, reservoir and well data to understand trends in 12 water drive gas reservoirs from production to abandonment. These reservoirs were produced by 16 wells, from 5 fields located off the South East coast of Trinidad. From the analysis, relative permeability Corey exponents were matched to fractional flow curves in a numerical simulator. The Buckley-Leverett-Wedge (B-L-W) technique was applied to predict the flooding order of the reservoirs, but was not found to be reliable because of its inability to compensate for layering and thick reservoir intervals. Nevertheless, the shape of the relative permeability curves could be used in some cases to identify a general grain size distribution. The endpoint values of the water curves in particular were correlated with the water-wettabilities of the reservoirs. It was discovered that Recovery Factor (RF) before Water Breakthrough (WBT) was better with the high production rate reservoirs. Meanwhile improvement in RF after WBT depended on having a higher initial gas column. The pre-WBT result may have been caused by successfully outrunning the aquifer. The effect of increasing aquifer size was to lower RFs. Single well completion reservoirs' WGR profiles depended on completion orientation. Vertical completions experienced WBT between 80 and 85 percent RF compared to horizontal and deviated wells at greater than 95 percent RF. At conditions close to abandonment by water-out, phenomena such as liquid loading and condensate blocking were prevalent in a few reservoirs based on production trending. A study limitation that may have led to incorrect conclusions was the inability to keep all other variables constant whilst manipulating only one. This could be remedied by a study with a larger number of reservoirs.

scholarly journals Relative Permeability: A Critical Parameter in Numerical Simulations of Multiphase Flow in Porous Media

Energies ◽  
2021 ◽  
Vol 14 (9) ◽  
pp. 2370
Author(s):  
Nathan Moodie ◽  
William Ampomah ◽  
Wei Jia ◽  
Brian McPherson
Keyword(s):  
Multiphase Flow ◽  
Relative Permeability ◽  
Co2 Storage ◽  
Careful Consideration ◽  
Trapping Efficiency ◽  
Flow In Porous Media ◽  
Geological Co2 Storage ◽  
Relative Permeability Curve ◽  
Wide Range ◽  
Co2 Eor

Effective multiphase flow and transport simulations are a critical tool for screening, selection, and operation of geological CO2 storage sites. The relative permeability curve assumed for these simulations can introduce a large source of uncertainty. It significantly impacts forecasts of all aspects of the reservoir simulation, from CO2 trapping efficiency and phase behavior to volumes of oil, water, and gas produced. Careful consideration must be given to this relationship, so a primary goal of this study is to evaluate the impacts on CO2-EOR model forecasts of a wide range of relevant relative permeability curves, from near linear to highly curved. The Farnsworth Unit (FWU) is an active CO2-EOR operation in the Texas Panhandle and the location of our study site. The Morrow ‘B’ Sandstone, a clastic formation composed of medium to coarse sands, is the target storage formation. Results indicate that uncertainty in the relative permeability curve can impart a significant impact on model predictions. Therefore, selecting an appropriate relative permeability curve for the reservoir of interest is critical for CO2-EOR model design. If measured laboratory relative permeability data are not available, it must be considered as a significant source of uncertainty.

scholarly journals Experimental investigation of the displacement flow mechanism and oil recovery in primary polymer flood operations

2021 ◽  
Vol 3 (5) ◽  
Author(s):  
Ruissein Mahon ◽  
Gbenga Oluyemi ◽  
Babs Oyeneyin ◽  
Yakubu Balogun
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Polymer Flooding ◽  
Mobility Control ◽  
List Type ◽  
Motor Oil ◽  
Flow Mechanism ◽  
Fractional Flow ◽  
Recovery Method ◽  
Polymer Flood

Abstract Polymer flooding is a mature chemical enhanced oil recovery method employed in oilfields at pilot testing and field scales. Although results from these applications empirically demonstrate the higher displacement efficiency of polymer flooding over waterflooding operations, the fact remains that not all the oil will be recovered. Thus, continued research attention is needed to further understand the displacement flow mechanism of the immiscible process and the rock–fluid interaction propagated by the multiphase flow during polymer flooding operations. In this study, displacement sequence experiments were conducted to investigate the viscosifying effect of polymer solutions on oil recovery in sandpack systems. The history matching technique was employed to estimate relative permeability, fractional flow and saturation profile through the implementation of a Corey-type function. Experimental results showed that in the case of the motor oil being the displaced fluid, the XG 2500 ppm polymer achieved a 47.0% increase in oil recovery compared with the waterflood case, while the XG 1000 ppm polymer achieved a 38.6% increase in oil recovery compared with the waterflood case. Testing with the motor oil being the displaced fluid, the viscosity ratio was 136 for the waterflood case, 18 for the polymer flood case with XG 1000 ppm polymer and 9 for the polymer flood case with XG 2500 ppm polymer. Findings also revealed that for the waterflood cases, the porous media exhibited oil-wet characteristics, while the polymer flood cases demonstrated water-wet characteristics. This paper provides theoretical support for the application of polymer to improve oil recovery by providing insights into the mechanism behind oil displacement. Graphic abstract Highlights The difference in shape of relative permeability curves are indicative of the effect of mobility control of each polymer concentration. The water-oil systems exhibited oil-wet characteristics, while the polymer-oil systems demonstrated water-wet characteristics. A large contrast in displacing and displaced fluid viscosities led to viscous fingering and early water breakthrough.

scholarly journals Interpretation of Gas/Water Relative Permeability of Coal Using the Hybrid Bayesian-Assisted History Matching: New Insights

Energies ◽  
2021 ◽  
Vol 14 (3) ◽  
pp. 626
Author(s):  
Jiyuan Zhang ◽  
Bin Zhang ◽  
Shiqian Xu ◽  
Qihong Feng ◽  
Xianmin Zhang ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Coalbed Methane ◽  
History Matching ◽  
Water Saturation ◽  
Unsteady State ◽  
Core Flooding ◽  
Rock Interaction ◽  
Interaction Mechanisms ◽  
True Value ◽  
Assisted History Matching

The relative permeability of coal to gas and water exerts a profound influence on fluid transport in coal seams in both primary and enhanced coalbed methane (ECBM) recovery processes where multiphase flow occurs. Unsteady-state core-flooding tests interpreted by the Johnson–Bossler–Naumann (JBN) method are commonly used to obtain the relative permeability of coal. However, the JBN method fails to capture multiple gas–water–coal interaction mechanisms, which inevitably results in inaccurate estimations of relative permeability. This paper proposes an improved assisted history matching framework using the Bayesian adaptive direct search (BADS) algorithm to interpret the relative permeability of coal from unsteady-state flooding test data. The validation results show that the BADS algorithm is significantly faster than previous algorithms in terms of convergence speed. The proposed method can accurately reproduce the true relative permeability curves without a presumption of the endpoint saturations given a small end-effect number of <0.56. As a comparison, the routine JBN method produces abnormal interpretation results (with the estimated connate water saturation ≈33% higher than and the endpoint water/gas relative permeability only ≈0.02 of the true value) under comparable conditions. The proposed framework is a promising computationally effective alternative to the JBN method to accurately derive relative permeability relations for gas–water–coal systems with multiple fluid–rock interaction mechanisms.

Fast Upscaling of Polymer Flood Simulations Using Fractional Flow and Scaled Mobilities

2021 ◽  
Author(s):  
Hasan Al-Ibadi ◽  
Karl Stephen ◽  
Eric Mackay
Keyword(s):  
Relative Permeability ◽  
Control Method ◽  
Pressure Profile ◽  
Polymer Flooding ◽  
Mobility Control ◽  
Scale Model ◽  
Fine Scale ◽  
Fractional Flow ◽  
Water Viscosity ◽  
Flow Mobility

Abstract We introduce a pseudoisation method to upscale polymer flooding in order to capture the flow behaviour of fine scale models. This method is also designed to improve the predictability of pressure profiles during this process. This method controls the numerical dispersion of coarse grid models so that we are able to reproduce the flow behaviour of the fine scale model. To upscale polymer flooding, three levels of analysis are required such that we need to honour (a) the fractional flow solution, (b) the water and oil mobility and (c) appropriate upscaling of single phase flow. The outcome from this analysis is that a single pseudo relative permeability set that honours the modification that polymer applies to water viscosity modification without explicitly changing it. The shape of relative permeability can be chosen to honour the fractional flow solution of the fine scale using the analytical solution. This can result in a monotonic pseudo relative permeability set and we call it the Fractional-Flow method. To capture the pressure profile as well, individual relative permeability curves must be chosen appropriately for each phase to ensure the correct total mobility. For polymer flooding, changes to the water relative permeability included the changes to water viscosity implicitly thus avoiding the need for inclusion of a polymer solute. We call this type of upscaling as Fractional-Flow-Mobility control method. Numerical solution of the upscaled models, obtained using this method, were validated against fine scale models for 1D homogenous model and as well as 3D models with randomly distributed permeability for various geological realisations. The recovery factor and water cut matched the fine scale model very well. The pressure profile was reasonably predictable using the Fractional-Flow-Mobility control method. Both Fractional-Flow and Fractional-flow-Mobility control methods can be calculated in advance without running a fine scale model where the analysis is based on analytical solution even though produced a non-monotonic pseudo relative permeability curve. It simplified the polymer model so that it is much easier and faster to simulate. It offers the opportunity to quickly predict oil and water phase behaviour.

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