Elevated-Temperature Caustic/Sandstone Interaction: Implications for Improving Oil Recovery (includes associated papers 11348 and 11548 )

1982 ◽  
Vol 22 (04) ◽  
pp. 453-462 ◽  
Author(s):  
Robert D. Sydansk
Keyword(s):  
Elevated Temperature ◽  
Low Temperature ◽  
Crude Oil ◽  
Sodium Hydroxide ◽  
Oil Recovery ◽  
Mineral Dissolution ◽  
Water Soluble ◽  
Silicate Minerals ◽  
In Situ Formation

Abstract Caustic in the form of sodium hydroxide solutions is shown to interact strongly with sandstone at elevated temperature ( 185 deg. F). Such interaction has substantial influence on the success of secondary and tertiary oil-recovery sodium hydroxide floods carried out in sandstone formations of more ordinary temperatures. Caustic in the form of sodium hydroxide interacts with sandstone at elevated temperature to promotesignificant dissolution of the more susceptible silicate minerals, predominantly clay and large-surface-area silicaminerals,sandstone weight loss;increased porosity;propagation of significant concentrations of water-soluble silicates, including sodium orthosilicate;in-situ formation of new immobile aluminosilicate material;changes in permeability: andhydroxideion consumption. Caustic/sandstone interaction resulting from sodiumhydroxide dissolution of silicate minerals is limited by kinetics. The interaction increases with increasing temperature, increasing sodium hydroxide concentration, and increasing caustic/sandstone contact time. Therate and the amount of interaction are sensitive to sandstone mineralogy and lithology. Although not studied during this work, the presence of crude oil, along with crude-oil type, may affect the rate and the amount of- interaction. Based on the laboratory study of elevated temperature caustic/sandstone interaction involving silicate-mineral dissolution by sodium hydroxide, it is concluded that, atlower temperatures, the much slower dissolution interaction has implications for field application of sodiumhydroxide for improving waterflood sweep efficiency and enhancing oil recover. Specifically, during field applications, the slow interaction could deplete the active hydroxide ions. More common low-temperature field applications are especially susceptible because oflong caustic/sandstone contact times and because, ingeneral, relatively small concentrations of sodiumhydroxide have been used historically. This study points out that proper extrapolation of laboratory caustic flooding results to field conditions should account for slow kinetic phenomena. The study also helps explaindetrimental caustic/sandstone interactions and lowerthan-expected oil recoveries experienced during a number of long-duration low-temperature enhanced oil recovery (EOR) field tests and floods. On the positive side, the dissolution interaction, especially at elevated temperatures, generates in-situ significant concentrations of water-soluble silicates, including sodium or thosilicate. Water-soluble silicates have been reported as candidates for improving oil recovery and for use in pre flushes to condition formations for other EOR techniques. Other than noting their in-situ formation and propagation, we did not study the alkaline water-soluble silicates in detail, and they are not discussed. Introduction Caustic (alkaline) flooding is one of several chemical processes for EOR being studied by the petroleum industry. Caustic flooding has been reviewed by Johnson and more recently by Mayer et al and Castor. Historically, caustic-induced EOR generally has been considered to result from liquid/liquid(caustic/crude)interactions. An exception to the liquid/liquid interaction generalization is caustic EOR postulated to result under certain conditions from wetting changes. In general, wetting changes involve very minor liquid/rock interactions limited in principle to the pore walls of formation material. Field results in sandstone formations for caustic EOR to date have not been overly encouraging. Liquid/rock(caustic/sandstone) interactions often appear to contribute negatively. Caustic is consumed by sandstone both reversibly and irreversibly. Reversible consumption leads to caustic propagation at a slower rate than the aqueous flood front. SPEJ P. 453^

Mechanistic Modeling of Low-Salinity Waterflooding Through Coupling a Geochemical Package With a Compositional Reservoir Simulator

2016 ◽  
Vol 19 (01) ◽  
pp. 142-162 ◽  
Author(s):  
Aboulghasem Kazemi Korrani ◽  
Gary R. Jerauld ◽  
Kamy Sepehrnoori
Keyword(s):  
Ion Exchange ◽  
Crude Oil ◽  
Oil Recovery ◽  
Mineral Dissolution ◽  
Mechanistic Modeling ◽  
Water Soluble ◽  
Exchange Reactions ◽  
Low Salinity ◽  
Low Salinity Waterflooding ◽  
Reservoir Simulator

Summary Low-salinity waterflooding is an emerging enhanced-oil-recovery (EOR) technique in which the salinity of the injected water is substantially reduced to improve oil recovery over conventional higher-salinity waterflooding. Although there are many low-salinity experimental results reported in the literature, publications on modeling this process are rare. Although there remains some debate regarding the mechanisms of low salinity waterflooding process (LoSal EOR®)*, the geochemical reactions that control the wetting of crude oil on the rock are likely to be central to a detailed description of the process. Because no comprehensive geochemical-based modeling has been applied in this area, it was decided to couple a state-of-the-art geochemical package, IPhreeqc (Charlton and Parkhurst 2011), developed by the US Geological Survey, with UTCOMP (Chang 1990), the compositional reservoir simulator developed by The University of Texas at Austin. A step-by-step algorithm is presented for integrating IPhreeqc with UTCOMP. Through this coupling, we are able to simulate homogeneous and heterogeneous (mineral dissolution/precipitation), irreversible, and ion-exchange reactions under nonisothermal, nonisobaric, and both local-equilibrium (away from the wellbore) and kinetic (near wellbore) conditions. Consistent with the literature, there are significant effects of water-soluble hydrocarbon components—e.g., carbon dioxide (CO2), methane (CH4), and acidic/basic components of the crude—on buffering the aqueous pH value and more generally, on the crude oil, brine, and rock reactions. Thermodynamic constraints are used to explicitly include the effect of these water-soluble hydrocarbon components. Hence, this combines the geochemical power of IPhreeqc with the important aspects of hydrocarbon flow and compositional effects to produce a robust, flexible, and accurate integrated tool capable of including the reactions needed to mechanistically model low-salinity waterflooding. Different geochemical-based approaches to modeling wettability change in sandstones (e.g., interpolation on the basis of total ionic strength and multicomponent ion exchange through surface complexation of the organometallic components) were implemented in UTCOMP-IPhreeqc, and the integrated tool is then used to match and interpret a low-salinity experiment published by Kozaki (2012) and the field trial performed by BP at the Endicott field.

scholarly journals Wettability Effects on Oil-Recovery Mechanisms in Fractured Reservoirs

2001 ◽  
Vol 4 (06) ◽  
pp. 455-466 ◽  
Author(s):  
A. Graue ◽  
T. Bognø ◽  
B.A. Baldwin ◽  
E.A. Spinler
Keyword(s):  
Crude Oil ◽  
Numerical Simulations ◽  
Capillary Pressure ◽  
Oil Recovery ◽  
History Matching ◽  
Water Saturation ◽  
Fracture Network ◽  
Stock Tank ◽  
Recovery Mechanisms

Summary Iterative comparison between experimental work and numerical simulations has been used to predict oil-recovery mechanisms in fractured chalk as a function of wettability. Selective and reproducible alteration of wettability by aging in crude oil at an elevated temperature produced chalk blocks that were strongly water-wet and moderately water-wet, but with identical mineralogy and pore geometry. Large scale, nuclear-tracer, 2D-imaging experiments monitored the waterflooding of these blocks of chalk, first whole, then fractured. This data provided in-situ fluid saturations for validating numerical simulations and evaluating capillary pressure- and relative permeability-input data used in the simulations. Capillary pressure and relative permeabilities at each wettability condition were measured experimentally and used as input for the simulations. Optimization of either Pc-data or kr-curves gave indications of the validity of these input data. History matching both the production profile and the in-situ saturation distribution development gave higher confidence in the simulations than matching production profiles only. Introduction Laboratory waterflood experiments, with larger blocks of fractured chalk where the advancing waterfront has been imaged by a nuclear tracer technique, showed that changing the wettability conditions from strongly water-wet to moderately water-wet had minor impact on the the oil-production profiles.1–3 The in-situ saturation development, however, was significantly different, indicating differences in oil-recovery mechanisms.4 The main objective for the current experiments was to determine the oil-recovery mechanisms at different wettability conditions. We have reported earlier on a technique that reproducibly alters wettability in outcrop chalk by aging the rock material in stock-tank crude oil at an elevated temperature for a selected period of time.5 After applying this aging technique to several blocks of chalk, we imaged waterfloods on blocks of outcrop chalk at different wettability conditions, first as a whole block, then when the blocks were fractured and reassembled. Earlier work reported experiments using an embedded fracture network,4,6,7 while this work also studied an interconnected fracture network. A secondary objective of these experiments was to validate a full-field numerical simulator for prediction of the oil production and the in-situ saturation dynamics for the waterfloods. In this process, the validity of the experimentally measured capillary pressure and relative permeability data, used as input for the simulator, has been tested at strongly water-wet and moderately water-wet conditions. Optimization of either Pc data or kr curves for the chalk matrix in the numerical simulations of the whole blocks at different wettabilities gave indications of the data's validity. History matching both the production profile and the in-situ saturation distribution development gave higher confidence in the simulations of the fractured blocks, in which only the fracture representation was a variable. Experimental Rock Material and Preparation. Two chalk blocks, CHP8 and CHP9, approximately 20×12×5 cm thick, were obtained from large pieces of Rørdal outcrop chalk from the Portland quarry near Ålborg, Denmark. The blocks were cut to size with a band saw and used without cleaning. Local air permeability was measured at each intersection of a 1×1-cm grid on both sides of the blocks with a minipermeameter. The measurements indicated homogeneous blocks on a centimeter scale. This chalk material had never been contacted by oil and was strongly water-wet. The blocks were dried in a 90°C oven for 3 days. End pieces were mounted on each block, and the whole assembly was epoxy coated. Each end piece contained three fittings so that entering and exiting fluids were evenly distributed with respect to height. The blocks were vacuum evacuated and saturated with brine containing 5 wt% NaCl+3.8 wt% CaCl2. Fluid data are found in Table 1. Porosity was determined from weight measurements, and the permeability was measured across the epoxy-coated blocks, at 2×10–3 µm2 and 4×10–3 µm2, for CHP8 and CHP9, respectively (see block data in Table 2). Immobile water saturations of 27 to 35% pore volume (PV) were established for both blocks by oilflooding. To obtain uniform initial water saturation, Swi, oil was injected alternately at both ends. Oilfloods of the epoxy-coated block, CHP8, were carried out with stock-tank crude oil in a heated pressure vessel at 90°C with a maximum differential pressure of 135 kPa/cm. CHP9 was oilflooded with decane at room temperature. Wettability Alteration. Selective and reproducible alteration of wettability, by aging in crude oil at elevated temperatures, produced a moderately water-wet chalk block, CHP8, with similar mineralogy and pore geometry to the untreated strongly water-wet chalk block CHP9. Block CHP8 was aged in crude oil at 90°C for 83 days at an immobile water saturation of 28% PV. A North Sea crude oil, filtered at 90°C through a chalk core, was used to oilflood the block and to determine the aging process. Two twin samples drilled from the same chunk of chalk as the cut block were treated similar to the block. An Amott-Harvey test was performed on these samples to indicate the wettability conditions after aging.8 After the waterfloods were terminated, four core plugs were drilled out of each block, and wettability measurements were conducted with the Amott-Harvey test. Because of possible wax problems with the North Sea crude oil used for aging, decane was used as the oil phase during the waterfloods, which were performed at room temperature. After the aging was completed for CHP8, the crude oil was flushed out with decahydronaphthalene (decalin), which again was flushed out with n-decane, all at 90°C. Decalin was used as a buffer between the decane and the crude oil to avoid asphalthene precipitation, which may occur when decane contacts the crude oil.

Industrial Application of Nickel Tallate Catalyst During Cyclic Steam Stimulation in Boca De Jaruco Reservoir

2021 ◽  
Author(s):  
Alexey V. Vakhin ◽  
Irek I. Mukhamatdinov ◽  
Firdavs A. Aliev ◽  
Dmitriy F. Feoktistov ◽  
Sergey A. Sitnov ◽  
...  
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Industrial Application ◽  
Laboratory Scale ◽  
Catalyst Precursor ◽  
Hydrothermal Conditions ◽  
Cyclic Steam Stimulation ◽  
Steam Stimulation

Abstract A nickel-based catalyst precursor has been synthesized for in-situ upgrading of heavy crude oil that is capable of increasing the efficiency of steam stimulation techniques. The precursor activation occurs due to the decomposition of nickel tallate under hydrothermal conditions. The aim of this study is to analyze the efficiency of in-situ catalytic upgrading of heavy oil from laboratory scale experiments to the field-scale implementation in Boca de Jaruco reservoir. The proposed catalytic composition for in-reservoir chemical transformation of heavy oil and natural bitumen is composed of oil-soluble nickel compound and organic hydrogen donor solvent. The nickel-based catalytic composition in laboratory-scale hydrothermal conditions at 300°С and 90 bars demonstrated a high performance; the content of asphaltenes was reduced from 22% to 7 wt.%. The viscosity of crude oil was also reduced by three times. The technology for industrial-scale production of catalyst precursor was designed and the first pilot batch with a mass of 12 ton was achieved. A «Cyclic steam stimulation» technology was modified in order to deliver the catalytic composition to the pay zones of Boca de Jaruco reservoir (Cuba). The active forms of catalyst precursors are nanodispersed mixed oxides and sulfides of nickel. The pilot test of catalyst injection was carried out in bituminous carbonate formation M, in Boca de Jaruco reservoir (Cuba). The application of catalytic composition provided increase in cumulative oil production and incremental oil recovery in contrast to the previous cycle (without catalyst) is 170% up to date (the effect is in progress). After injection of catalysts, more than 200 samples from production well were analyzed in laboratory. Based on the physical and chemical properties of investigated samples and considering the excellent oil recovery coefficient it is decided to expand the industrial application of catalysts in the given reservoir. The project is scheduled on the fourth quarter of 2021.

Interfacial Viscoelasticity of Crude Oil/Brine: An Alternative Enhanced-Oil-Recovery Mechanism in Smart Waterflooding

SPE Journal ◽  
2018 ◽  
Vol 23 (03) ◽  
pp. 803-818 ◽  
Author(s):  
Mehrnoosh Moradi Bidhendi ◽  
Griselda Garcia-Olvera ◽  
Brendon Morin ◽  
John S. Oakey ◽  
Vladimir Alvarado
Keyword(s):  
Crude Oil ◽  
Water Chemistry ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Interaction Mechanism ◽  
Field Trials ◽  
Wettability Alteration ◽  
Low Salinity ◽  
Injection Water

Summary Injection of water with a designed chemistry has been proposed as a novel enhanced-oil-recovery (EOR) method, commonly referred to as low-salinity (LS) or smart waterflooding, among other labels. The multiple names encompass a family of EOR methods that rely on modifying injection-water chemistry to increase oil recovery. Despite successful laboratory experiments and field trials, underlying EOR mechanisms remain controversial and poorly understood. At present, the vast majority of the proposed mechanisms rely on rock/fluid interactions. In this work, we propose an alternative fluid/fluid interaction mechanism (i.e., an increase in crude-oil/water interfacial viscoelasticity upon injection of designed brine as a suppressor of oil trapping by snap-off). A crude oil from Wyoming was selected for its known interfacial responsiveness to water chemistry. Brines were prepared with analytic-grade salts to test the effect of specific anions and cations. The brines’ ionic strengths were modified by dilution with deionized water to the desired salinity. A battery of experiments was performed to show a link between dynamic interfacial viscoelasticity and recovery. Experiments include double-wall ring interfacial rheometry, direct visualization on microfluidic devices, and coreflooding experiments in Berea sandstone cores. Interfacial rheological results show that interfacial viscoelasticity generally increases as brine salinity is decreased, regardless of which cations and anions are present in brine. However, the rate of elasticity buildup and the plateau value depend on specific ions available in solution. Snap-off analysis in a microfluidic device, consisting of a flow-focusing geometry, demonstrates that increased viscoelasticity suppresses interfacial pinch-off, and sustains a more continuous oil phase. This effect was examined in coreflooding experiments with sodium sulfate brines. Corefloods were designed to limit wettability alteration by maintaining a low temperature (25°C) and short aging times. Geochemical analysis provided information on in-situ water chemistry. Oil-recovery and pressure responses were shown to directly correlate with interfacial elasticity [i.e., recovery factor (RF) is consistently greater the larger the induced interfacial viscoelasticity for the system examined in this paper]. Our results demonstrate that a largely overlooked interfacial effect of engineered waterflooding can serve as an alternative and more complete explanation of LS or engineered waterflooding recovery. This new mechanism offers a direction to design water chemistry for optimized waterflooding recovery in engineered water-chemistry processes, and opens a new route to design EOR methods.

Reaction Kinetics of In-Situ Combustion: Part 1-Observations

1984 ◽  
Vol 24 (04) ◽  
pp. 399-407 ◽  
Author(s):  
Mohammad Reza Fassihi ◽  
William E. Brigham ◽  
Henry J. Ramey
Keyword(s):  
Porous Medium ◽  
Porous Media ◽  
Reaction Mechanism ◽  
Crude Oil ◽  
Oil Recovery ◽  
Burning Front ◽  
Burning Zone ◽  
Different Temperatures ◽  
Air Compression

Abstract Continuous analysis of produced gases from a small packed bed reactor, at both isothermal and linearly increasing temperatures, has shown that combustion of crude oil in porous media follows several consecutive reactions. Molar carbon dioxide/carbon monoxide (CO2/CO) and apparent hydrogen/carbon (H/C) ratios were used to observe the transition between these reactions at different temperature levels. A new kinetic model for oxidation of crude oil in porous media is presented in Part 2 of this paper (Page 408) Introduction The quantity of fuel consumed and the reaction rate within the burning zone have been studied intensively for two reasons. First, the maximum oil recovery is the difference of the original oil in place (OOIP) at the start of the operation and the oil consumed as fuel. Second, one of the most important factors in the economic evaluation of any in-situ combustion project is the cost of air compression. Excessive fuel deposition causes a slow rate of advance of the burning front and large air compression costs. However, if the fuel concentration is too low, the heat of combustion will not be sufficient to raise the temperature of the rock and the contained fluids to a level of self-sustained combustion. This may lead to combustion failure. Thus, it is necessary to understand the reactions occurring at different temperatures as the combustion front moves in the porous medium. The most crucial and yet least understood zone of insitu combustion oil recovery is the burning front, where temperature reaches a maximum value. The velocity of the burning front is controlled by the chemical reactions involved. However, since crude oil is a mixture of hydrocarbons, it is necessary to consider a global description of the reaction mechanism. Reaction Mechanism The reaction between fuel and oxygen in a forward combustion process is a heterogeneous flow reaction. Injected oxidant gas must pass through the burning zone to make the burning front move. Within the burning zone, four known transport processes occur:oxygen diffuses from the bulk gas stream to the fuel interface; then, perhaps,the oxygen absorbs and reacts with the fuel;then combustion products desorb; andproducts finally transfer into the bulk gas stream. If any of these steps is inherently much slower than the remaining ones, the overall rate will be controlled by that step. Also, the rate of each series of steps must be equal in the steadystate condition. However, there are no useful correlations for computing absorption and desorption of oxygen in a porous medium. Consequently, consideration of these phenomena becomes extremely difficult for even simple reactions. Theoretical expressions for postulated mechanisms often contain 10 or more arbitrary constants. Because of the large number of arbitrary constants, sever-al expressions developed for widely different mechanisms often will match experimental data equally well. In general, the combustion rate, Rc, of crude oil in a porous medium can be described as dCm m nRc = - ------ = kpo2 Cm,............................(1)dt whereCm = instantaneous concentration of fuel, k = rate constant, Po2 = partial pressure of oxygen, andm, n = reaction orders. The reaction constant, k, is often a function of temperature, T, as expressed by k=w exp(– E/RT).......................................(2) where E is the activation energy, w is the Arrhenius constant, and R is the universal gas constant. For heterogeneous reactions, the constant w is a function of the surface area of the rock. Early studies of crude oil oxidation in a porous medium were mostly qualitative. Differential thermal analysis (DTA) was performed on samples of crude oil, and the resulting thermograms represented the thermal history of each sample as it was heated at a uniform rate (usually 18 degrees F/min [10 degrees C/min]) in a constant air flow (usually 277 mL/min [277 cm3/min]). These thermograms indicated the presence of a number of exothermic reactions. Another method of analysis is thermogravimetric analysis (TGA). Here, a sample of crude oil is weighed continuously as it is heated at a constant rate. The resulting curve of weight change vs. time or temperature indicates the occurrence of at least two reactions at different temperatures. SPEJ P. 399^

Research of Lifting Technology of Combustion In Situ

2011 ◽  
Vol 347-353 ◽  
pp. 3219-3222
Author(s):  
Xi Shun Zhang ◽  
Xiao Dong Wu ◽  
Shu Qin Ma
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Gas Production ◽  
Technical Support ◽  
Recovery Ratio ◽  
Heavy Component ◽  
In Situ Combustion ◽  
Dynamic Displacement

In-situ combustion (fire flooding) is one of important methods to improve heavy oil recovery ratio, utilizing the reservoir itself heavy component burning as dynamic displacement of crude oil, improving the crude oil character, flooding efficiency is high, applicability is extensive, and other recover techniques can not match. But the technical support is difficult and broad, and is the key in restricting the effect of in-situ combustion, especially for the effectiveness of development. With the increase of fire flooding development, flowing wells turns to artificial lifting wells, the gas production increases deeply, and the lifting technology faces a lot of new problems. Aiming at the problems of combustion in-situ, the relevant technologies were researched, then some methods and measures suiting to heavy oil fire flooding technology were proposed. And it provided reference for researching of deep heavy oil fire flooding lifting technology in the future.

scholarly journals Chemical Compositions in Modified Salinity Waterflooding of Carbonate Reservoirs -- Experiment

2021 ◽  
Author(s):  
Maxim Yutkin ◽  
Clayton J. Radke ◽  
Tadeusz Patzek
Keyword(s):  
Calcium Carbonate ◽  
Ion Exchange ◽  
Crude Oil ◽  
Oil Recovery ◽  
Carbonate Rock ◽  
Single Phase ◽  
Theoretical Framework ◽  
Mineral Dissolution ◽  
High Dispersion ◽  
Carbonate Dissolution

<br>Modified or low-salinity waterflooding of carbonate oil reservoirs is of considerable economic interest because of potentially inexpensive incremental oil<br>production. The injected modified brine changes the surface chemistry of the carbonate rock and crude oil interfaces and detaches some adhered crude oil.<br>Composition design of the modified brine to enhance oil recovery is determined by labor-intensive trial-and-error laboratory corefloods. Unfortunately, limestone,<br>which predominantly consists of aqueous-reactive calcium carbonate, alters injected brine composition by mineral dissolution/precipitation. Accordingly, the rock reactivity<br>hinders rational design of the tailored brine to improve oil recovery. <br>Previously, we presented a theoretical analysis of 1D, single-phase brine injection into calcium carbonate-rock that accounts for mineral dissolution, ion<br>exchange, and dispersion (Yutkin et. al 2021). Here we present the results of single-phase waterflood-brine experiments that verify the theoretical framework. We show that concentration histories eluted from Indiana limestone cores possess features characteristic of fast calcium<br>carbonate dissolution, 2:1 ion exchange, and high dispersion. The injected brine reaches chemical equilibrium inside the porous rock even at<br>injection rates higher than 1000 ft/day. Ion exchange results in salinity waves observed experimentally, while high dispersion is responsible for long<br>concentration history tails. <br>Using the verified theoretical framework, we briefly explore how these processes modify aqueous-phase composition during the injection of designer brines into a calcium-carbonate reservoir. Because of high salinity of the initial and injected brines, ion exchange affects injected concentrations only in<br>high surface area carbonates/limestones, such as chalks. Calcium-carbonate dissolution only affects aqueous solution pH. The rock surface composition is affected by all processes.<br><br>

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