permeability reduction
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2021 ◽  
Author(s):  
Tormod Skauge ◽  
Kenneth Sorbie ◽  
Ali Al-Sumaiti ◽  
Shehadeh Masalmeh ◽  
Arne Skauge

Abstract A large, untapped EOR potential may be extracted by extending polymer flooding to carbonate reservoirs. However, several challenges are encountered in carbonates due to generally more heterogeneous rock and lower permeability. In addition, high salinity may lead to high polymer retention. Here we show how in-situ viscosity varies with permeability and heterogeneity in carbonate rock from analysis of core flood results and combined with review of data available in literature. In-situ rheology experiments were performed on both carbonate outcrop and reservoir cores with a range in permeabilities. The polymer used was a high ATBS content polyacrylamide (SAV10) which tolerates high temperature and high salinity. Some cores were aged with crude oil to generate non-water-wet, reservoir representative wettability conditions. These results are compared to a compilation of literature data on in-situ rheology for predominantly synthetic polymers in various carbonate rock. A systematic approach was utilized to derive correlations for resistance factor, permeability reduction and in-situ viscosity as a function of rock and polymer properties. Polymer flooding is applied to improve sweep efficiency that may occur due to reservoir heterogeneities (large permeability contrasts, anisotropy, thief zones) or adverse mobility ratio (high mobility contrast oil-brine). In flooding design, the viscosity of the polymer solution in the reservoir, the in-situ viscosity, is an essential parameter as this is tuned to correct the mobility difference and to improve sweep. The viscosity is estimated from rheometer/viscometer measurements or, better, measured in laboratory core flood experiments. However, upscaling core flood experiments to field is challenging. Core flood experiments measure differential pressure, which is the basis for the resistance factor, RF, that describes the increased resistance to flow for polymer relative to brine. However, the pressure is also influenced by several other factors such as the permeability reduction caused by adsorption and retention of polymer in the rock, the tortuosity of the rock and the viscosity of the flowing polymer solution. Deduction of in-situ viscosity is straight forward using Darcy's law but the capillary bundle model that is the basis for applying this law fails for non-Newtonian fluids. This is particularly evident in carbonate rock. Interpretation of in-situ rheology experiments can therefore be misleading if the wrong assumptions are made. Polymer flooding in carbonate reservoirs has a large potential for increased utilization of petroleum reserves at a reduced CO2 footprint. In this paper we apply learnings from an extensive core flood program for a polymer flood project in the UAE and combine this with reported literature data to generate a basis for interpretation of in-situ rheology experiments in carbonates. Most importantly, we suggest a methodology to screen experiments and select data to be used as basis for modelling polymer flooding. This improves polymer flood design, optimize the polymer consumption, and thereby improve project economy and energy efficiency.


SPE Journal ◽  
2021 ◽  
pp. 1-16
Author(s):  
Pål Østebø Andersen

Summary This work studies 1D steady-state flow of gas from compressible shale matrix subject to water blocking toward a neighboring fracture. Water blocking is a capillary end effect causing wetting phase (e.g., water) to accumulate near the transition from matrix to fracture. Hydraulic fracturing is essential for economical shale gas production. Water is frequently used as fracturing fluid, but its accumulation in the matrix can reduce gas mobility and production rate. Gas transport is considered at a defined pressure drop. The model accounts for apparent permeability (slip), compressibility of gas and shale, permeability reduction, saturation tortuosity (reduced relative permeability upon compaction), and multiphase flow parameters like relative permeability and capillary pressure, which depend on wettability. The behavior of gas flow rate and distributions of gas saturation, pressure, and permeability subject to different conditions and the stated mechanisms is explored. Water blockage reduces gas relative permeability over a large zone and reduces the gas flow rate. Despite gas flowing, strong capillary forces sustain mobile water over the entire system. Reducing drawdown gave lower driving force and higher resistance (by water blockage) for gas flow. The results show that 75% reduction of drawdown made the gas flow rate a couple orders of magnitude lower compared to if there was no blockage. The impact was most severe in more water-wetsystems. The blockage caused most of the pressure drop to occur near the outlet. High pressure in the rest of the system reduced effects from gas decompression, matrix compression, and slip-enhanced permeability, whereas rapid gradients in all these effects occurred near the outlet. Gas decompression resulted in an approximately 10 times higher Darcy velocity and pressure gradient near the outlet compared to inlet, which contributed to removing blockage, but the added resistance reduced the gas production rate. Similarly, higher gas Corey exponent associated gas flow with higher pressure drop. The result was less blockage but lower gas production. Slip increased permeability, especially toward the outlet, and contributed to increase in gas production by 16%. Significant matrix compression was associated with permeability reduction and increased Corey exponent in some examples. These effects reduced production and shifted more of the pressure drop toward the outlet. Upstream pressure was more uniform, and less compression and permeability reduction were seen overall compared to a system without water blockage.


Author(s):  
Iskander Sh Gussenov ◽  
Sarkyt E. Kudaibergenov

PLoS ONE ◽  
2021 ◽  
Vol 16 (7) ◽  
pp. e0254676
Author(s):  
Adharsh Rajasekar ◽  
Charles K. S. Moy ◽  
Stephen Wilkinson ◽  
Raju Sekar

Microbially Induced Carbonate Precipitation (MICP) is currently viewed as one of the potential prominent processes for field applications towards the prevention of soil erosion, healing cracks in bricks, and groundwater contamination. Typically, the bacteria involved in MICP manipulate their environment leading to calcite precipitation with an enzyme such as urease, causing calcite crystals to form on the surface of grains forming cementation bonds between particles that help in reducing soil permeability and increase overall compressive strength. In this paper, the main focus is to study the MICP performance of three indigenous landfill bacteria against a well-known commercially bought MICP bacteria (Bacillus megaterium) using sand columns. In order to check the viability of the method for potential field conditions, the tests were carried out at slightly less favourable environmental conditions, i.e., at temperatures between 15-17°C and without the addition of urease enzymes. Furthermore, the sand was loose without any compaction to imitate real ground conditions. The results showed that the indigenous bacteria yielded similar permeability reduction (4.79 E-05 to 5.65 E-05) and calcium carbonate formation (14.4–14.7%) to the control bacteria (Bacillus megaterium), which had permeability reduction of 4.56 E-5 and CaCO3 of 13.6%. Also, reasonably good unconfined compressive strengths (160–258 kPa) were noted for the indigenous bacteria samples (160 kPa). SEM and XRD showed the variation of biocrystals formation mainly detected as Calcite and Vaterite. Overall, all of the indigenous bacteria performed slightly better than the control bacteria in strength, permeability, and CaCO3 precipitation. In retrospect, this study provides clear evidence that the indigenous bacteria in such environments can provide similar calcite precipitation potential as well-documented bacteria from cell culture banks. Hence, the idea of MICP field application through biostimulation of indigenous bacteria rather than bioaugmentation can become a reality in the near future.


2021 ◽  
Vol 290 ◽  
pp. 123228
Author(s):  
Jiandong Huang ◽  
Yi Zhang ◽  
Yuantian Sun ◽  
Jiaolong Ren ◽  
Zedong Zhao ◽  
...  

2021 ◽  
pp. 1-8
Author(s):  
Arley S. Carvalhal ◽  
Gloria M. N. Costa ◽  
Silvio A. B. Vieira de Melo

Summary Uncertainties regarding the factors that influence asphaltene deposition in porous media (e.g., those resulting from oil composition, rock properties, and rock/fluid interaction) strongly affect the prediction of important variables, such as oil production. Besides, some aspects of these predictions are stochastic processes, such as the aggregation phenomenon of asphaltene precipitates. For this reason, a well-defined output from an asphaltene-deposition model might not be feasible. Instead of this, obtaining the probability distribution of important outputs (e.g., permeability reduction and oil production) should be the objective of rigorous modeling of this phenomenon. This probability distribution would support the design of a risk-based policy for the prevention and mitigation of asphaltene deposition. In this paper we aim to present a new approach to assessing the risk of formation damage caused by asphaltene deposition using Monte Carlo simulations. Using this approach, the probability-distribution function of the permeability reduction was obtained. To connect this information to a parameter more related to economic concepts, the probability distribution of the damage ratio (DR) was also calculated, which is the fraction of production loss caused by formation damage. A hypothetical scenario involving a decision in the asphaltene-prevention policy is presented as an application of the method. A novel approach to model the prevention of asphaltene aggregation using inhibitors has been proposed and successfully applied in this scenario.


SPE Journal ◽  
2021 ◽  
pp. 1-21
Author(s):  
M. R. Fassihi ◽  
E. Turek ◽  
M. Matt Honarpour ◽  
D. Peck ◽  
R. Fyfe

Summary As part of studying miscible gas injection (GI) in a major field within the Green Canyon protraction area in the Gulf of Mexico (GOM), asphaltene-formation risk was identified as a key factor affecting a potential GI project. The industry has not conducted many experiments to quantify the effect of asphaltenes on reservoir and well performance under GI conditions. In this paper we discuss a novel laboratory test for evaluating the asphaltene effect on permeability. The goals of the study were to define the asphaltene-precipitation envelope using blends of reservoir fluid and injection gas, and measure permeability reduction caused by asphaltene precipitation in a core under GI. To properly analyze the effect of GI, a suite of fluid-characterization studies was conducted, including restored-oil samples, compositional analysis, constant composition expansion (CCE), and differential vaporization. Miscibility conditions were defined through slimtube-displacement tests. Gas solubility was determined through swelling tests complemented by asphaltene-onset-pressure (AOP) testing. The unique procedure was developed to estimate the effect of asphaltene deposition on core permeability. The 1-ft-long core was saturated with the live-oil and GI mixture at a pressure greater than the AOP, and then pressure was depleted to a pressure slightly greater than the bubblepoint. Several cycles of charging and depletion were conducted to mimic continuous flow of oil along the path of injected gas and thereby to observe the accumulation of asphaltene on the rock surface. The test results indicated that during this cyclic asphaltene-deposition process, the core permeability to the live mixture decreased in the first few cycles but appeared to stabilize after Cycle 5. The deposited asphaltenes were analyzed further through environmental scanning electron microscopy (ESEM), and their deposition was confirmed by mass balance before and after the tests. Finally, a relationship was established between permeability reduction and asphaltene precipitation. The results from the asphaltene-deposition experiment show that for the sample, fluids, and conditions used, permeability is impaired as asphaltene flocculates and begins to coat the grain surfaces. This impairment reaches a plateau at approximately 40% of the initial permeability. Distribution of asphaltene along the core was measured at the end by segmenting the core and conducting solvent extraction on each segment. Our recommendation is numerical modeling of these test results and using this model to forecast the magnitude of the permeability impairment in a reservoir setting during miscible GI.


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