A Chemical Theory for Linear Alkaline Flooding

Abstract A simple equilibrium chemical model is presented for continuous, linear, alkaline waterflooding of acid oils. The unique feature of the theory is that the chemistry of the acid hydrolysis to produce surfactants is included, but only for a single acid species. The in-situ produced surfactant is presumed to alter the oil/water fractional flow curves depending on its local concentration. Alkali adsorption lag is accounted for by base ion exchange with the reservoir rock. The effect of varying acid number, mobility ratio, and injected pH is investigated for secondary and tertiary alkaline flooding. Since the surface-active agent is produced in-situ, a continuous alkaline flood behaves similar to a displacement with a surfactant pulse. This surfactant-pulse behavior strands otherwise mobile oil. It also leads to delayed and reduced enhanced oil recovery for adverse mobility ratios, especially in the tertiary mode. Caustic ion exchange significantly delays enhanced oil production at low injected pH. New, experimental tertiary caustic displacements are presented for Ranger-zone oil in Wilmington sands. Tertiary oil recovery is observed once mobility control is established. Qualitative agreement is found between the chemical displacement model and the experimental displacement results. Introduction Use of alkaline agents to enhance oil recovery has considerable economic impetus. Hence, significant effort has been directed toward understanding and applying the process. To date, however, little progress has been made toward quantifying the alkaline flooding technique with a chemical displacement model. Part of the reason why simulation models have not been forthcoming for alkali recovery schemes is the wide divergence of opinion on the governing principles. Currently, there are at least eight postulated recovery mechanisms. As classified by Johnson and Radke and Somerton, these include emulsification with entrainment, emulsification with entrapment, emulsification (i.e., spontaneous or shear induced) with coalescence, wettability reversal (i.e., oil-wet to water-wet or water-wet to oil-wet), wettability gradients, oil-phase swelling (i.e., from water-in-oil emulsions), disruption of rigid films, and low interfacial tensions. The contradictions among these mechanisms apparently reside in the chemical sensitivity of the crude oil and the reservoir rock to reaction with hydroxide. Different crude oils in different reservoir rock can lead to widely disparate behavior upon contact with alkali under varying environments such as temperature, salinity, hardness concentration, and pH. The alkaline process remains one of the most complicated and least understood. It is not surprising that there is no consensus on how to design a high-pH flood for successful oil recovery. One theme, however, does unify all present understanding. The crude oil must contain acidic components, so that a finite acid number (i.e., the milligrams of potassium hydroxide required to neutralize 1 gram of oil) is necessary. Acid species in the oil react with hydroxide to produce salts, which must be surface active. It is not alkali per se that enhances oil recovery, but rather the hydrolyzed surfactant products. Therefore, a high acid number is not a sufficient recovery criterion, because not all the hydrolyzed acid species will be interfacially active. That acid crude oils can produce surfactants upon contact with alkali is well documented. The alkali technique must be distinguished from all others by the fundamental basis that the chemicals promoting oil recovery are generated in situ by saponification. SPEJ P. 245^

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Role of Intermolecular Forces on Surfactant-Steam Performance into Heavy Oil Reservoirs

SPE Journal ◽

10.2118/201513-pa ◽

2021 ◽

pp. 1-6

Author(s):

Lee Yeh Seng ◽

Berna Hascakir

Keyword(s):

Crude Oil ◽

Oil Recovery ◽

Heavy Oil ◽

Intermolecular Forces ◽

Immiscible Fluids ◽

Reservoir Rock ◽

Crude Oils ◽

Head Group ◽

Polar Head Group ◽

Polar Head

Summary This study investigates the role of polar fractions of heavy oil in the surfactant-steamflooding process. Performance analyses of this process were done by examination of the dipole-dipole and ion-ion interactions between the polar head group of surfactants and the charged polar fraction of crude oil, namely, asphaltenes. Surfactants are designed to reduce the interfacial tension (IFT) between two immiscible fluids (such as oil and water) and effectively used for oil recovery. They reduce the IFT by aligning themselves at the interface of these two immiscible fluids; this way, their polar head group can stay in water and nonpolar tail can stay in the oil phase. However, in heavy oil, the crude oil itself has a high number of polar components (mainly asphaltenes). Moreover, the polar head group in surfactants is charged, and the asphaltene fraction of crude oils carries reservoir rock components with charges. The impact of these intermolecular forces on the surfactant-steam process performance was investigated with 10 coreflood experiments on an extraheavy crude oil. Nine surfactants (three anionic, three cationic, and three nonionic surfactants) were tested. Results of each coreflood test were analyzed through cumulative oil recovery and residual oil content. The performance differences were evaluated by polarity determination through dielectric constant measurements and by ionic charges through zeta potential measurements on asphaltene fractions of produced oil and residual oil samples. The differences in each group of surfactants tested in this study are the tail length. Results indicate that a longer hydrocarbon tail yielded higher cumulative oil recovery. Based on the charge groups present in the polar head of anionic surfactants resulted in higher oil recovery. Further examinations on asphaltenes from produced and residual oils show that the dielectric constants of asphaltenes originated from the produced oil, giving higher polarity for surfactant-steam experiments conducted with longer tail length, which provide information on the polarity of asphaltenes. The ion-ion interaction between produced oil asphaltenes and surfactant head groups were determined through zeta potential measurements. For the most successful surfactant-steam processes, these results showed that the changes on asphaltene surface charges were becoming lower with the increase in oil recovery, which indicates that once asphaltenes are interacting more with the polar head of surfactants, then the recovery rate increases. Our study shows that the surfactant-steamflooding performance in heavy oil reservoirs is controlled by the interaction between asphaltenes and the polar head group of surfactants. Accordingly, the main mechanism that controls the effectiveness of the process is the ion-ion interaction between the charges in asphaltene surfaces and the polar head group of crude oils. Because crude oils carry mostly negatively charged reservoir rock particles, our study suggests the use of anionic surfactants for the extraction of heavy oils.

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Interrelation of Crude Oil and Rock Properties With the Recovery of Oil by Caustic Waterflooding

Society of Petroleum Engineers Journal ◽

10.2118/5830-pa ◽

1977 ◽

Vol 17 (04) ◽

pp. 263-270 ◽

Cited By ~ 39

Author(s):

Robert Ehrlich ◽

Robert J. Wygal

Keyword(s):

Crude Oil ◽

Reservoir Rock ◽

Rock Properties ◽

Core Material ◽

Crude Oils ◽

Active Materials ◽

Interfacial Tensions ◽

X Ray ◽

Recovery Mechanisms ◽

Surface Active

Abstract This paper describes a series of laboratory caustic (NaOH) waterfloods and related measurements using crude oils from 19 oil reservoirs. These were light (mostly,>30 degrees API) crudes mainly from South Louisiana and Texas, although crude oils from other areas also were tested. The waterfloods held core material (Berea sandstone), connate water (2-percent-NaCl brine) and other conditions (temperature, flow rate, aging time before flood) constant, and determined increased production due to NaOH injection for each crude oil. Relative permeability end-points before and after flooding were used to estimate initial and final wettabilities and, together with crude-oil acid numbers and interfacial tensions against NaOH solution, to infer the probable mechanism by which increased recovery was obtained. A series of laboratory NaOH depletion measurements by static and dynamic methods in core material from several oil-producing formations and in Berea sandstone is also described. Results are compared with those from similar measurements using pure clays and other minerals and with X-ray diffraction analysis of the core material. The following are observations from these tests.Crude oils with acid numbers greater than about 0.1 to a 0.2 mg KOH per gm of oil or interfacial tension against 0.1 percent NaOH less than about 0.5 dyne/cm gave significant caustic-waterflood increased production. There was no further correlation of increased production at higher acid numbers or lower interfacial tensions nor was there a correlation with the apparent initial rock wettability.Regardless of initial wettability or increased production, the cores are indicated to be water-wet production, the cores are indicated to be water-wet following NaOH waterflooding to a high water-oil ratio (WOR).Caustic consumption by reservoir rock is predictable from the formation mineral composition predictable from the formation mineral composition as determined by X-ray methods. Exceptions are noted where clay content is high and where trace amounts of gypsum are present. Introduction Crude oils containing naturally occurring organic acids will react with aqueous caustic solution to produce surface-active materials. These surfactants, produce surface-active materials. These surfactants, when generated during a caustic waterflood, can improve oil recovery over that of a normal waterflood by a number of mechanisms related to changes occurring at the oil-water and liquid-solid interfaces: interfacial-tension lowering, wettability change, changes in interface rheology, etc. The extent to which any of these mechanisms will be operative and the recovery improvement obtainable depends on, among other things, the amount and type of acids present, the initial formation wettability, the reservoir-rock pore geometry, and the extent to which it consumes caustic. The available literature describing mechanisms proposed for caustic-waterflooding improved recovery, proposed for caustic-waterflooding improved recovery, the conditions required for applicability, and the results of various laboratory and field studies have been surveyed most recently by Johnson. Some common currents of thought or implication in this literature and some common areas of uncertainty related to the effects of crude oil and reservoir rock properties on recovery mechanisms are listed below. properties on recovery mechanisms are listed below.The presence of acids in crude oil at some minimum level is an obvious necessary condition for improved recovery. Where emulsification is involved, minimum acid numbers ranging from 0.5 to 1.5 mg KOH per gm of oil have been suggested. No minimum has been stated for other recovery mechanisms. One might not expect such minimum requirements to be absolute since the quality of surfactants generated from these acids can vary widely among crude oils.Improved recovery by wettability alteration generally has been discussed in terms of a reversal from oil-wet to water-wet or vice versa. It has been implied that wettability reversal is required since capillary forces trapping oil are eliminated as the neutral wettability condition is traversed. SPEJ P. 263

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Experimental Analysis of Alkali-Brine-Alcohol Phase Behavior with High Acid Number Crude Oil

SPE Reservoir Evaluation & Engineering ◽

10.2118/201369-pa ◽

2021 ◽

pp. 1-19

Author(s):

D. Magzymov ◽

T. Clemens ◽

B. Schumi ◽

R. T. Johns

Keyword(s):

Crude Oil ◽

Phase Behavior ◽

Oil Recovery ◽

Complex Mixture ◽

Acid Number ◽

Field Application ◽

Water Interface ◽

Total Acid ◽

Oil Water

Summary A potential enhanced oil recovery technique is to inject alkali into a reservoir with a high-total acid number (TAN) crude to generate soap in situ and reduce interfacial tension (IFT) without the need to inject surfactant. The method may be cost-effective if the IFT can be lowered enough to cause significant mobilization of trapped oil while also avoiding formation of gels and viscous phases. This paper investigates the potential field application of injecting alkali to generate in-situ soap and favorable phase behavior for a high-TAN oil. Oil analyses show that the acids in the crude are a complex mixture of various polar acids and not mainly carboxylic acids. The results from phase behavior experiments do not undergo typical Winsor microemulsion behavior transition and subsequent ultralow IFTs below 1×10−3 mN/m that are conventionally observed. Instead, mixing of alkali and crude/brine generate water-in-oil macroemulsions that can be highly viscous. For a specific range of alkali concentrations, however, phases are not too viscous, and IFTs are reduced by several orders of magnitude. Incremental coreflood recoveries in this alkali range are excellent, even though not all trapped oil is mobilized. The viscous phase behavior at high alkali concentrations is explained by the formation of salt-crude complexes, created by acids from the crude oil under the alkali environment. These hydrophobic molecules tend to agglomerate at the oil-water interface. Together with polar components from the crude oil, they can organize into a highly viscous network and stabilize water droplets in the oleic phase. Oil-soluble alcohol was added to counter those two phenomena at large concentrations, but typical Winsor phase behavior was still not observed. A physicochemical model is proposed to explain the salt-crude complex formation at the oil-water interface that inhibits classical Winsor behavior.

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Smackover Nacatoch Crude Oil Separation of Surfactant Precursors and Their Effect on the Crude

Society of Petroleum Engineers Journal ◽

10.2118/8733-pa ◽

1981 ◽

Vol 21 (04) ◽

pp. 493-499 ◽

Cited By ~ 1

Author(s):

J.H. Runnels ◽

C.J. Engel

Keyword(s):

Interfacial Tension ◽

Crude Oil ◽

Sodium Hydroxide ◽

Aqueous Phase ◽

Oil Recovery ◽

Crude Oils ◽

Gel Chromatography ◽

Active Materials ◽

Tertiary Oil Recovery ◽

Surface Active

Abstract An procedure is given for separating surfactant precursors that occur in some crude oils. The effect of the precursors on the properties of the oils are described also. The separations were made by silica gel chromatography on crude oil from which the asphaltenes had been removed. The effect of the precursors on the properties of the crude was evaluated by blending the surfactant precursors into the original oil, a modified oil, or a hydrocarbon solvent such as benzene. Precursors activated and converted to surface active materials by a strong base such as sodium hydroxide are effective in reducing the interfacial tension between the oil and aqueous phase. Occurrence of precursors in crude oils is essential for improved oil recovery by the causticflood process. The procedure for separating the precursors should provide a viable means for evaluating the applicability of a causticflood tertiary oil recovery process to a particular crude or reservoir. Introduction Tertiary oil recovery by the causticflood process is inherently dependent on naturally occurring surfactant precursors in the crude. The surfactant precursors react with the caustic (base) in the floodwater to form surface active compounds that reduce the interfacial tension between the crude and aqueous phase, alter the wettability of the mineral surfaces, or reduce rigid film formation at the crude/aqueous interface. In laboratory oil-recovery tests, these mechanisms stimulate oil production characterized by increased production at caustic breakthrough and a high oil/water ratio after breakthrough. An early effort to identify the surfactant precursors in a Rio Bravo (CA) crude concluded that the surfactant precursors were related closely to the asphaltene and resin fractions of the crude. Subsequent studies using an Eichlingen Niedersachen (West German) crude and a Ventura (CA) crude concluded that the surfactant precursors were acids and phenols, respectively. The extensive work of Seifert established that the surfactant precursors of a Ventura crude were carboxylic acids and that the phenolic components of the crude were interfacially inactive. The purpose of our study was to develop a simple and practical method of separating surfactant precursors from crude oil and to evaluate their effect on the interfacial tension, acid number, and other properties of the crude. The separation technique was developed using Smackover Nacatoch crude and the surfactant precursors evaluated were obtained from the same crude. Description of Smackover Nacatoch Crude The Smackover reservoir is located in southern Arkansas, and the Nacatoch pay zone is the shallowest of five pay zones. The crude has an API gravity of 21 degrees, a viscosity of 160 cp at room temperature, and is produced from an unconsolidated sand formation about 2,000 ft deep. Preliminary studies showed that the interfacial tension between the crude and an aqueous phase was reduced from about 12 to 0.02 dyne/cm when the pH of the aqueous phase was increased from 7.0 to 12.5 with sodium hydroxide. The significant reduction in interfacial tension at higher pH's indicated that the crude contained a relatively high concentration of surfactant precursors that were converted to surface active materials by sodium hydroxide. SPEJ P. 493^

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Effect of Oil Composition on Miscible-Type Displacement by Carbon Dioxide

Society of Petroleum Engineers Journal ◽

10.2118/8814-pa ◽

1982 ◽

Vol 22 (01) ◽

pp. 87-98 ◽

Cited By ~ 84

Author(s):

LeRoy W. Holm ◽

Virgil A. Josendal

Keyword(s):

Carbon Dioxide ◽

Crude Oil ◽

Oil Recovery ◽

Reservoir Rock ◽

Crude Oils ◽

Co2 Flooding ◽

Oil Composition ◽

Extraction Mechanism ◽

Minimum Miscibility Pressure ◽

Displacement Front

Abstract This paper presents additional data related to the correlation between minimum miscibility pressure (MMP) for CO2 flooding and to the composition of the crude oil to be displaced. Yellig and Metcalfe have stated that there is little or no effect of oil composition on the MMP. However, their conclusion was based on experiments with one type of reservoir oil that was varied in C through C6 content and in the amount of C7 + present but not varied in composition of the C7 + fraction. We have found that the Holm-Josendal correlation, which is based on temperature and C5 + molecular weight, predicts the general trend of the MMP's required for CO2 flooding of various crude oils. MMP's were predicted with this correlation and then tested for several crude oils using oil recovery of 80% at CO2 break through and 94% ultimate recovery as the criteria. We now have data showing that miscible-type displacement is also correlatable with the amount of C5 through C3O hydrocarbons present in the crude oil and with the solvency of the CO2 as indicated by its density. Variations from such a correlation are shown to be related to the C5 through C 12 content and to the type of these hydrocarbons. The MMP data were obtained from slim-tube floods with crude oils having gravities between 28 and 44 degrees API (0.88 and 0.80 g/cm3) and C5 + molecular weights between 171 and 267. The crude oils used varied in carbon residue between 1 and 4 wt% and in waxy hydrocarbon content between 1 and 17%. The required MMP for these crude oils at 165 degrees F (74 degrees C) varied between 2,450 and 4,400 psi (16.9 and 30.3 MPa) for an oil recovery of 94% OIP. The MMP was found to be a linear function of the amount of C5 through C30 hydrocarbons present and of the density of the CO2. Introduction Our 1974 paper, "Mechanisms of Oil Displacement by Carbon Dioxide," discussed the various mechanisms by which oil is displaced from reservoir rock using CO2. One conclusion of this study was that multiple-contact, miscible-type displacement of oil occurs through extraction of C5 through C30 hydrocarbons from the reservoir oil by COB when a certain pressure is maintained at a given flood temperature. The mechanism of oil recovery was described as follows. The CO2 vaporizes or extracts hydrocarbons from the reservoir oil until a sufficient quantity of these hydrocarbons exists at the displacement front to cause the oil to be miscibly displaced. At that point, the vaporization or extraction mechanism stops until the miscible front that has been developed breaks down through the dispersion mechanism. When miscibility does not exist, the vaporization or extraction mechanism again occurs to re-establish miscibility. The miscible bank is formed, dispersed, and reformed throughout the displacement path; a small amount of residual oil remains behind all along the displacement path. Also, an optimal flooding pressure at a given temperature for a given oil was defined in that paper as when oil recovery of about 94% OIP was achieved and above which point essentially no additional oil was recovered. This pressure has since been termed the "minimum miscibility pressure" by others. We further determined in our previous study thatthis miscible-type displacement does not depend on the presence of C2 through C4 in the reservoir oil and thatthe presence of methane in the reservoir oil does not change the MMP appreciably. Those findings have been confirmed by Yellig and Metcalfe with the qualification that the CO2 MMP must be greater than or equal to the bubble-point pressure of the reservoir oil. SPEJ P. 87^

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Laboratory Investigation of Low-Tension-Gas Flooding for Improved Oil Recovery in Tight Formations

SPE Journal ◽

10.2118/159841-pa ◽

2013 ◽

Vol 18 (05) ◽

pp. 851-866 ◽

Cited By ~ 28

Author(s):

S.M.. M. Szlendak ◽

N.. Nguyen ◽

Q.P.. P. Nguyen

Keyword(s):

Crude Oil ◽

Oil Recovery ◽

Mobility Control ◽

Fractional Flow ◽

Tight Sandstone ◽

Secondary Recovery ◽

Gas Flooding ◽

Tertiary Recovery ◽

Low Tension

Summary This paper establishes low-tension gas (LTG) as a method for submiscible tertiary recovery in tight sandstone and carbonate reservoirs. The LTG process involves the use of surfactant and gas to mobilize and then displace residual crude after waterflood at a greatly reduced oil/water interfacial tension (IFT). This method allows extending surfactant enhanced oil recovery (EOR) in sub-20-md formations in which polymer is impractical because of plugging, shear, or the requirement to use a low-molecular-weight polymer. The proposed strategy is tested through the coinjection of nitrogen and a slug/drive surfactant solution. Results indicate favorable mobilization and displacement of residual crude oil in both tight-carbonate and tight-sandstone reservoirs. Tertiary recovery of 75−90% of residual oil in place (ROIP) was achieved for cores with 2- to 15-md permeability. High LTG tertiary recovery is contrasted with results from reference surfactant (no gas) flooding (28% ROIP tertiary recovery) and immiscible gas coinjection (no surfactant) flooding (13% ROIP tertiary recovery). In addition, high initial oil saturation was tested to determine the process tolerance to oil and to evaluate the potential for application during secondary recovery. Under such conditions, this method achieved a recovery of 84% of oil originally in place (OOIP), suggesting the potential application of this process at secondary recovery. To better understand the physical mechanisms that affect mobilization and displacement, the early production of an elongated oil bank at reduced fractional flow of oil was shown to be an attribute of high crude-oil relative mobility and low pore volume (PV) available to mobile oil. This should favorably affect economics during chemical flooding by accelerating the production of an oil bank. Next, by application of salinity as a conservative tracer and oil material balance, gas saturation during LTG floods was calculated to be 18 to 22%. By comparing effluent salinity profiles across floods, a qualitative understanding of in-situ fluid dispersion associated with macroscopic displacement stability is developed. The results indicate that in-situ foaming was present, which enabled mobility control, and that stable displacement of in-situ fluids was achieved during flooding.

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Synergetic effect between in-situ mobility control and micro-displacement for chemical enhanced oil recovery (CEOR) of a surface-active nanofluid

Journal of Petroleum Science and Engineering ◽

10.1016/j.petrol.2021.108983 ◽

2021 ◽

pp. 108983

Author(s):

Rui Liu ◽

Jiayue Lu ◽

Wanfen Pu ◽

Quan Xie ◽

Yuanyuan Lu ◽

...

Keyword(s):

Enhanced Oil Recovery ◽

Oil Recovery ◽

Synergetic Effect ◽

Mobility Control ◽

Surface Active

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Wettability Effects on Oil-Recovery Mechanisms in Fractured Reservoirs

SPE Reservoir Evaluation & Engineering ◽

10.2118/74335-pa ◽

2001 ◽

Vol 4 (06) ◽

pp. 455-466 ◽

Cited By ~ 19

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.

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

10.2118/206419-ms ◽

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.

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