An Effort to Establish Correlations between Brazilian Crude Oils

Article pubs.acs.org/EF

An Effort to Establish Correlations between Brazilian Crude Oils Properties and Flow Assurance Related Issues Marcia Cristina Khalil De Oliveira* and Marcelo Albuquerque Gonçalves Petrobras Research Center (CENPES), Petrobras, Av. Horacio Macedo 950, Cidade Universitária, Q.7 Ilha do Fundão, 21941-598, Rio de Janeiro, RJ, Brazil ABSTRACT: Flow assurance is a multidiscipline process involving sampling, laboratory analysis, and production and facilities engineering to ensure uninterrupted optimum well productivity. Laboratory testing provides necessary data to assess the flow assurance risk because it defines phase behavior and the properties of the waxes, asphaltenes, emulsions and hydrates known to be principal causes of flow problems. In deep- and ultra-deepwaters scenarios the precipitation, deposition, and gelling of organic solids in hydrocarbon fluids constitute critical production concerns. Understanding the crude oil behavior can help to avoid high costs resulting from production reductions or stoppages or, conversely, from system overdesign. This paper shows an effort to establish correlations between Brazilian crude oils properties and flow assurance related issues.

■

demands in terms of flow assurance issues. According to our laboratory results, we can anticipate that wax, inorganic scaling, and hydrate plug formation are the prevailing problems in most presalt fields. So, an integrated flow assurance strategy must be developed. A comprehensive study must be carried out to investigate chemical stability, compatibility, and deliverability as well. Hydrates often represent the most dramatic flow assurance problem for any deep offshore development. During the steady state production mode, hydrate formation can be avoided by using a better a pipeline insulation that keeps the fluid temperature above the hydrate thermodynamic envelope. However, in case of shutdown, an appropriate control procedure must be applied to prevent hydrate formation, which includes ethanol injection and/or pipeline fluid replacement. In contrast to this, lab results show that some oils may present a “nonplugging” behavior. Furthermore, simulations must be performed to evaluate the “no touch time” before eventually applying any flow assurance measures. Brazilian crude oils are relatively paraffinic. The presence of paraffinic wax in crude oil is known to cause significant flow assurance problems related to wax deposit buildup and gel formation.2,3 In contrast to hydrate plug formation, wax deposition occurs slowly, but with similar end results if not properly controlled. In most areas, the main wax control scheme relies on pipeline insulation, together with a robust pigging program. In more critical areas where the crude oil temperature falls below the wax appearance temperature, chemical inhibition can be applied to minimize wax deposition. The effectiveness of a paraffin treatment, however, is largely dependent on the crude oil composition, inhibitor chemistry, inhibitor concentration, and the production conditions. A thorough laboratory screening testing protocol must be carried out to identify the best inhibitor formulation(s) for given oil. It is useful at this point to pinpoint

INTRODUCTION Flow assurance is a critical multidisciplinary discipline for oil and gas production, especially in deepwater and ultra-deepwater scenarios. Among other things, it comprehends the effectively handling of different solid deposits during oil production, such as, hydrates, asphaltenes, wax, naphthenates, inorganic scale, corrosion products, and even formation fines and clasts. It is also well established that HSE (health, safety, and environment) problems caused by sour and acidic gases also demand flow assurance-oriented solutions. Laboratory testing provides the needed data to assess the flow assurance risks because it helps identifying the crude oil characteristics associated to flow assurance problems. These fluid properties in conjunction with thermal and hydraulic simulations help developing operational strategies to cope with the different flow assurance problems. The uninterrupted history of success that has been built by Petrobras on the Brazilian continental shelf has been supported by successive discoveries of crude oil in Tertiary loose turbidities progressively toward ultra-deepwater. By the same token, the recent huge crude oil discoveries made by Petrobras in presalt reservoirs in Southern Brazil represent another challenging scenario to the application of flow assurance-related technologies: ultra-deepwater (>2000 m), deep carbonate reservoirs (>5000 m), spread over very large areas, high gas/oil ratio (GOR) (>200 std m3/m3), high CO2 content (8−15%), highpressure, and low temperature reservoirs. To complicate matters further, the main presalt reservoirs lay immediately below a thick salt layer (2000+ m) and are located very far from the coast (300+ km) where the prevailing oceanic conditions are harsher than in other fields that have been so far exploited by Petrobras in the Brazilian coast.1 As the oil production scenarios change over time, new challenges also appear, demanding new technology developments. Sometimes state-of-the-art technologies may be pushed up to some extent to new boundary limits. However, the inescapable bottom line is that every technology has its predicates and limitations, so it is mandatory to continuously develop brand-new, tailor-made solutions to meet particular © 2012 American Chemical Society

Received: April 17, 2012 Revised: July 27, 2012 Published: July 29, 2012 5689

dx.doi.org/10.1021/ef300650k | Energy Fuels 2012, 26, 5689−5701

Energy & Fuels

Article

Therefore, flow assurance strategies can have a significant impact in the development of any new oil deepwater field. The implementation of prevention and remediation methods is necessary mainly due to the low temperatures, high production pressures, long tie-backs, and oils prone to organic deposition under actual field conditions.5 Previous studies showed that in some waxy crude oils the presence of water above a threshold value could promote gel formation, thereby changing significantly the viscosity of the mixture.6 Additionally, light oils from different fields may present apparently similar chemical composition by SARA analysis and API density but significant differences in their flow assurance parameters.7 In this context, some waxy crude oils from different Brazilian fields were selected to be characterized according to Petrobras technical specifications oriented to flow assurance problems. The investigated parameters include physical and chemical analysis, emulsion stability, crude oil and emulsion rheological characterization, wax appearance temperature (WAT), asphaltenes precipitation onset, and rheological measurement of the emulsion/hydrate transitions under favorable thermodynamic conditions. This paper addresses the most critical points related to flow assurance to the development of deepwater oilfields. It encompasses laboratory analysis and methods to anticipate, and how to best avoid, the presence of deposits in subsea flowlines, pipelines, and other production system equipment. The relationship between the physical and chemical propoerties of the crude oil and flow assurance-related issues was also investigated.

those chemicals for deepwater subsea injection must remain solid-free at all conditions of temperatures and pressures throughout the capillary/umbilical lines. So, they must show neither gunking nor solid precipitation at all under actual application conditions. The strategies investigated to mitigate wax problems in this specific scenario are pipeline thermohydraulic calculation tools, pigging, wax chemical inhibition, and pipeline heating/insulation. Among those, pigging has become the main preventive measure to be implemented in large scale, in both existing and new production systems. After a long shutdown period in the subsea flowline/pipeline, the originally warm crude may be cooled below its pour point and end up forming a gel structure. This gel phase, which most always gives rise to start-up problems, is formed by wax crystals dispersed in a viscous crude oil matrix. So, it is crucial to run a series of laboratory experiments to evaluate the gelled-crude strength and to come up with a feasible start-up procedure for the crude. As is always the case, water-in-crude oil (w/o) emulsions are a recurrent problem in the different stages of oil production. The stability and the high viscosity of the formed emulsions can significantly affect the performance of the production systems, especially those located in the offshore scenarios. These emulsions can be very stable due to the presence of indigenous stabilizers, such as asphaltenes or other solid materials, such as clays, or rock fines, that can adsorb onto the oil−water interface.4 In this sense, the previous knowledge of the rheological properties of oil and its emulsions is of vital importance to properly design the production facilities. A high salt concentration in the formation water, or incompatibilities between the injection and formation waters, may lead to the formation of different types of scale. Once the scales have formed, they can accumulate in different parts of the production system, thus causing production impairments, corrosion problems, and other problems. Therefore, it is highly desirable to use thermodynamic models to evaluate risk of calcium carbonate or other salts deposition problems since the early phases of the production, even though the expected water cut is rather low at this stage. Carbonate scales are formed in the wellbore because the CO2 ex-solves from the water phase, thereby increasing its pH and the saturation index of carbonate minerals. Continuous downhole injection of the scale inhibitor is often required to avoid carbonate deposition in critical areas of the production system. Despite the vast number of flow assurance technologies and strategies that can be properly applied to the development of oilfields located in deepwater and ultra-deepwater, one can not overlook the important chemical compatibility issue. Thus, chemical compatibility studies are of paramount importance to define a holistic mitigation strategy for flow assurance problems. The downhole chemical delivery system has been considered by the industry as an efficient preventive method to fight flow assurance-related problems. The use of dedicated umbilical lines and topside facilities for each chemical can be very expensive, or technically unfeasible, depending on the well completion scheme and flowline/pipeline layout. In spite of the best efforts, there might be a few uncertainties regarding flow assurance problems, which can lead eventually to unexpected problems for which no chemical solutions have been sought for during the lab evaluation tests. For instance, the effectiveness of a particular chemical addictive can be affected by the presence of an incompatible chemical injected simultaneously through a separated umbilical.

■

FLOW ASSURANCE CHARACTERIZATION Thirteen waxy crude oil (dead oil) samples from different Brazilian reservoirs were used in this study. Investigations into the characteristics of all samples were carried out, as follows: Physical and Chemical Characteristics of Crude Oils. The API density was obtained by the ISO12185 method. The water content of crude oils was measured by coulombimetric Karl Fischer titration. A saturates, aromatics, resins, and asphaltenes (SARA) analysis was performed in a thin-layer chromatography-flame ionization detection (TLC-FID) system.8 The total acid number (TAN) was determined according to the American Society for Testing and Materials (ASTM) D664 method. The separation of normal paraffin from the crude oils and characterization was performed using gas chromatography.7 Wax Appearance Temperature (WAT). The WAT was measured by differential scanning microcalorimetry (μDSC) This technique allows to determine the highest temperature at which wax crystals begin to form or precipitate from the solution. This temperature is easily identified by the exothermic peak during the sample cool-down, in a temperature range from 80 °C to −10 at a 0.8 °C/min cooling rate. The onset temperature is measured by intersection point of baseline and the tangent line of inflection point of exothermic peak.9 The calculated temperature is noted as the WAT. The total flow heat of wax precipitation is computed by the integration of the area between the DSC calorimeter signal curve and the baseline. Emulsion Preparation and Stability. Water-in-oil emulsions were prepared using synthetic brine consisting of 5.0 wt % NaCl in Milli-Q water, at two different aqueous volume fractions: 30 and 50%. The crude oils were thermally preconditioned in an oven at 60 °C for at least 1 h to redissolve any wax already 5690

dx.doi.org/10.1021/ef300650k | Energy Fuels 2012, 26, 5689−5701

Energy & Fuels

Article

system. One point that must be kept in mind when simulating any system is the uncertainty of the results. It is important to have a good knowledge and control the level of uncertainty of all data. Depending on the complexity of the project, simulators may require a large amount of data, so the uncertainty of each individual datum will be added, and eventually, it is possible that the overall uncertainty of simulation may be above the tolerated range, even if the input individual data have low uncertainty. This may happen due to the combination of all the uncertainties of the individual data. Besides the concern with input data, there is the uncertainty of the model and its implementation on the simulator. Therefore, it of paramount importance to have technical expertise to evaluate the modeling algorithms and choose the best option for a given application, besides being careful on both system description and discretization. Moreover, the uncertainty results for the same simulator are not constant for all cases and will vary according to the situation. In general, single-phase flow simulations tend to have lower uncertainties for turbulent flow than for laminar case. Under turbulent regime at high Reynolds numbers, for instance, the only fluid property needed to calculate the pressure drop is the density, as all other variables depend on the pipe characteristics (diameter, length, and roughness) and flow rate. Conversely, under laminar flow conditions, fluid properties, such as viscosity, specific heat, and thermal conductivity become important because the pressure drop is also a function of the temperature profile. For this reason, uncertainty of simulations tends to be higher for laminar flows. When dealing with multiphase flow, similar things may happen. The uncertainties tend also to be lower if the liquid flow is turbulent, but also, it depends on the flow regime. The pressure gradient can either be dominated by friction or by gravity, which are the cases when the gravitational term (basically given by average mixture gravity) is predominant over friction. In general, gravity dominated flows calculations are less reliable because they depend on the holdup, and this parameter is calculated by empirical equations only. Flow assurance problems have been modeled recently, and it is possible to simulate the main occurrences on most simulators. Wax deposition is one of these models, and its calculations are fairly often used. The most accepted model is based on the thermal diffusion of wax components though the laminar fluid layer near the pipe wall.10 The mechanism that moves paraffin components toward the wall is the concentration gradient. This gradient is caused by the radial thermal profiletaking into consideration the fact that paraffin solubility depends on the temperature. Hence, the wax buildup is related to heat flux, and as it increases, the buildup raises as well. Buildup will only occur when pipe wall temperature drops below WAT and the external temperature is lower than the internal average (positive heat flux in bulk to wall direction). Wax deposition involves several other mechanisms, such as adherence to the wall, shear effects, and aging. However, these phenomena are not taken into account in the model on the basis of the argument that the diffusion is the slowest process, so it actually defines the buildup velocity. This model provides useful results provided adequate correction factors are used. These empirical factors must be obtained experimentally and represent corrections to the diffusion coefficient, the role of shear and maybe to compensate for other mechanisms not addressed by the model, such as gelation and aggregation. Hydrate thermodynamic phase envelopes are well determined, and their calculation is very reliable for most gas compositions

precipitated, and after that, the aqueous phase was added. Emulsification was performed using a homogenizer at 8000 rpm for 3 min at 25 °C. Subsequently, bottle tests were performed at 60 °C to visually determine emulsion stability. Rheological Analysis. Rheometric measurements were performed by using a controlled-stress rheometer. Crude oil and emulsion dynamic viscosity was measured using concentric cylinders geometry at a programmed cooling rate (1 °C/min) from the starting temperature (60 °C) to the hold final temperature (4 °C). The shear rate range used in the study was 20−250 s−1. The viscosity of an emulsion (ηE) shows a proportional relationship with the viscosity of its external phase (ηEP). Thus, the viscosity of an emulsion can be expressed as the relative viscosity (ηR), calculated by eq 1. ηR =

ηE ηEP

(1)

To define the crude oil yield stress, oscillatory rheology studies are performed using plate−plate geometry. A sample is heated to 45 °C and sheared for 15 min at shear rate of 10 s−1. Shortly afterward, the sample was cooled down to 4 at 1 °C/min cooling rate and was kept at a standstill for 15 min. An oscillation stress sweep was performed at 1 Hz, applying stress values ranging from 0.01 to 1000 Pa. Yield stress was established as a crossover point between loss and storage modulus. Hydrate. The rheology of the transition emulsion/hydrate suspension is obtained for the water−oil emulsion with 30% of water content at 4 °C and 100 bar, using a standard natural gas (87% methane). Tests were performed using the pressure cell of a controlled-stress rheometer and the dynamic viscosities were measured using the vane geometry. After the emulsion preparation, the cell is then pressurized and stays at 40 °C for 12 h to incorporate the gas. Afterward, the system is cooled to 4 °C (0.5 °C/min), under constant shear (50 s−1) and pressure (100 bar), remaining at this temperature for 6 h. If a blockage happens to occur, the test is promptly interrupted. Asphaltene Flocculation Onset. Asphaltene stability is a function of crude composition, temperature, and pressure. In the procedure adopted here, dead crude oil is titrated at ambient conditions with normal heptane to find the first appearance of asphaltene aggregates. The onset is detected with a near-infrared (NIR) spectrometer at 1600 nm wavelength as the minimum absorbance, as a function of the titrated volume of n-heptane/g crude oil. This test protocol enables one to quantify the crude oil's tendency to flocculate its asphaltenes as a function of the volume of titrant (n-heptane) necessary to achieve the onset of flocculation, as follows: oils with less than 0.5 mL n-heptane/g crude oil are very unstable crude oil, and there is great possibility of precipitation of asphaltenes; oils with between 0.5 and 1.0 mL of n-heptane/g crude oil are unstable, and there is a real possibility of precipitation of asphaltenes; oils with between 1.0 and 2.0 mL of n-heptane/g crude oil are stable, but the precipitation may be induced by blending the crude with lighter crudes or condensate, CO2, CH4 injection, miscible rich gas flooding, acidification, etc.; oils with onset values greater than 2.0 mL of n-heptane/g crude oil are very stable, and there is no possibility of asphaltenes precipitation. Simulation. The measured fluid properties are used as input data in flow simulators with the aim of designing the producing 5691

dx.doi.org/10.1021/ef300650k | Energy Fuels 2012, 26, 5689−5701

Energy & Fuels

Article

Table 1. Waxy Crude Oil Characterization crude oil samp.

I

II

III

IV

V

VI

VII

VIII

IX

X

XI

XII

XIII

saturate (%) aromatic (%) resin (%) asphaltenes (%) resin/asphaltene saturate/aromatic resin/aromatic (Sat + Arp)/(Res + Asph) TAN (mgKOH/g) pour point (°C) wax (% w/w) API water content (% w/w) asphaltene on-set (mL n-heptane/g oil) crude oil viscosity, 60 °C at 50 s−1 crude oil viscosity, 20 °C at 50 s−1 relative viscosity, 30% wc 60 °C/50 s−1 relative viscosity, 30% wc 20 °C/50 s−1 relative viscosity, 50% wc 60 °C/50 s−1 relative viscosity, 50% wc 20 °C/50 s−1 WAT (°C) yield stress (Pa) hydrate blockage−emulsion, 30% water

51.2 24.2 23.1 1.5 15.4 2.1 1.0 3.1 0.23 23.0 10.6 26.6 0.67 3.6 20.1 483.0 3.2 2.1 12.1 5.8 46.1 5970 no

54.5 23.0 22.0 0.5 44.0 2.4 1.0 3.4 0.37 6.0

57.1 24.5 18.0 0.4 45.0 2.3 0.7 4.4 0.26 12.0 5.6 27.8 1.00 3.9 12.8 74.2 2.4 2.3 7.7 9.4 35.2 260 no

53.8 22.0 23.7 0.5 47.4 2.4 1.1 3.1 0.25 6.0 7.1 28.3 1.00 3.5 9.4 42.2 3.4 4.4 10.1 9.8 35.1 284 no

56.2 25.7 17.1 1.0 34.2 2.2 0.7 4.5 0.29 9.0 15.4 28.4 0.05 4.5 8.1 56.2 4.9 6.4 11.0 12.2 41.1 51 no

54.0 24.0 22.0 0.5 44.0 2.3 0.9 3.5 0.27 6.0 24.8 28.6 0.07 3.7 7.9 55.6 2.4 1.5 8.4 4.2 35.5 123 no

57.7 24.2 17.4 0.7 26.4 2.4 0.7 4.5 0.06 6.0

52.7 33.6 12.6 1.1 11.5 1.6 0.4 6.3 0.1 −27.0

56.6 24.4 19.0 0.5 38.0 2.3 0.8 4.2 0.45 −2.0

61.3 24.7 13.9 0.5 27.8 2.5 0.6 6.0 0.05 8.0

29.0 0.50

6.3 32.6 2.7 2.1 14.2 11.9 37.4 145 no

5.7 25.5 3.3 4.5 17.3 12.1 26.5 0 no

29.5 0.32 4.70 5.4 41.5 2.6 1.6 2.8 2.8 34.5 37 yes

57.2 26.2 14.7 2.0 7.4 2.2 0.6 5.0 0.05 15.0 10.8 31.1 0.82 0.92 5.6 38.5 3.0 4.2 18.2 10.0 36.5 98 no

66.7 20.1 12.8 0.4 33.7 3.3 0.6 6.6 0.13 17.3

28.8 0.20

51.1 30.9 16.6 1.4 11.9 1.7 0.5 4.6 0.17 −36.0 7.1 29.8 0.08

SARA

27.4 0.60 5.8 11.2 103.0 2.6 1.7 8.6 6.6 39.7 67

8.3 36.0 2.9 2.2 8.0 9.8 26.9 0 no

30.6 0.26 3.3 5.4 31.3 2.7 2.2 10.0 8.9 39.8 185 no

33.9 0.76 1.80 4.5 34.9 6.0 1.8 13.5 3.7 45.7 yes

Figure 1. SARA and API data for 13 Brazilians waxy crude oils.

There are several attempts to model deposition, but there is no commercial model available in the market at this time. However, considering the progress some research groups have been experienced lately, such models shall be available to the project engineer in the near future. To conclude, it is important to stress that the simulator must be regarded as a tool to help the design and shall never replace the laboratory evaluation and responsibilities of the engineer.

(except with unusually high amount of contaminants). Recently, a kinetic model has been developed and tested and shows promising results.11 This model allows calculating the required time for actually start to form a blockage, and then, the design of the system can be done by taking into account the cool-down time and hydrate kinetics. This approach is less conservative than the traditional one, which is to avoid hydrate formation in any circumstance; therefore, it may allow a much lower Capex. Asphaltene precipitation and deposition are still very much unanswered phenomena that both demand efforts to understanding and model. The thermodynamic models yet demand an extensive set of experimental data, so they are not practical to use.

■

RESULTS AND DISCUSSION The main properties of the 13 waxy crude oils are reported in Table 1. As one can see, these crude oils have medium API values 5692

dx.doi.org/10.1021/ef300650k | Energy Fuels 2012, 26, 5689−5701

Energy & Fuels

Article

Figure 2. Saturates/aromatic and resin/aromatic ratio versus API density for 13 Brazilians waxy crude oils.

Figure 3. Ratio of the cumulative content of saturates and aromatics to the cumulative content of resins and asphaltenes versus API density for 13 Brazilians waxy crude oils.

Figure 4. Crude oil viscosity (20 and 60 °C at 50 s−1 shear rate) for 13 Brazilian waxy crude oils.

(between 26 and 33° API) and low acidity index (total acid number). In the SARA analysis, the crude oil components are grouped into four chemical classes based on differences in solubility and polarity (saturates, aromatics, resins, and asphaltenes). Figure 1 illustrates respective correlations between the contents of saturates, aromatics, resins, and asphaltenes, and the API. The

crude oil's physical and chemical properties can be considered typical of many waxy crude oils with around 50% of saturated compounds and 1% of asphaltenes. The database analysis shows there is not a correlation between SARA content and API value. It can also be observed that crude oils VIII and X have the highest aromatic content. 5693

dx.doi.org/10.1021/ef300650k | Energy Fuels 2012, 26, 5689−5701

Energy & Fuels

Article

Figure 5. Relative viscosity of emulsion at 30% of water phase (20 and 60 °C at 50 s−1 shear rate) for 13 Brazilian waxy crude oils.

Figure 6. Relative viscosity of emulsion at 50% of water content (20 and 60 °C at 50 s−1 shear rate) for 13 Brazilian waxy crude oils.

of solid wax crystals in the crude oil medium is responsible for the viscosity increasing. It is clear that crude oil viscosity exhibits a fairly good correlation with API density. Crude oils were also tested for emulsion forming tendency. Here, the idea was to evaluate how the water-in-oil emulsion viscosity can be affected by the shearing, resulting from pumping and lifting mechanisms. The vast majority of crude oils are keen to form emulsions that show quite different rheological behaviors. That is why it is important to determine the emulsion rheological behavior in the lab. Figures 5 and 6 show the relative viscosity, as defined by eq 1, of emulsions with 30% and 50% water content at 20 °C and shear rate of 50 s−1. The salient conclusion is that all 13 crudes form stable emulsions. The results obtained also show the emulsion viscosity with 30% of water can be 2 to 6 times higher than the original crude oil viscosity. It is also possible to observe that the emulsion viscosity is almost constant with API increment. On the other hand, when the water content in the emulsion is 50%, the increase in crude oil viscosity can be up to 15 times higher than that of the original crude oil viscosity. In this case, the relative viscosity data reveals a weak correlation with the crude oil's API density. Another point worth noting is that crude oils I and XII form the most viscous emulsions of all crude samples. It was also observed that relative viscosity changes with temperature. In the case of emulsion with 50% of water, phase higher values of relative viscosity were observed at 60 °C instead of 20 °C for most crude oils. It is widely accepted that indigenous crude oil components do contribute to the formation of a viscoelastic film on the crude

Figure 2 shows that these crude oils cannot be easily differentiated by their saturates to aromatics and resins to aromatics ratios. The highest API crude oil (crude XIII) has the highest saturate/aromatic ratio, but this is not a rule for all crudes. A useful indicator of oil alteration due to biodegradation is the ratio of the cumulative content of saturates and aromatics to the cumulative content of resins and asphaltenes.12 In Figure 3, the ratios (Sat + Aro)/(Res + Asph) are plotted against API. An easily observed feature of our database is that crude oils with a ratio between 3 and 5 are singled out by higher occurrence, but in this case, it is not possible to correlate with biodegradation as geochemistry results for these crude oils. Furthermore, the results in Table 1 show that although some crude oils, for instance, samples II and III, IV and V, present similar API density and chemical composition, they significantly differ in their flow assurance related properties, such as WAT, pour point, yield stress, and viscosity. Waxy crudes fluids normally present shear-thinning behavior below the WAT.7 They also present other complex rheological phenomena that must be properly quantified to completely optimize the design of waxy crude flowlines. The measurement results presented herein shall be regarded as comparative, only because they were carried out by using the same standard procedure. However, it is well-known that several crude oil properties are dramatically affected by pressure, thermal history, cooling rate, and temperature range, to name a few. The crude oil viscosity at 60 and 20 °C, respectively, is showed in Figure 4. As expected, a viscosity increase during the cooling process is observed for all the crude oil samples. The formation and growth 5694

dx.doi.org/10.1021/ef300650k | Energy Fuels 2012, 26, 5689−5701

Energy & Fuels

Article

Figure 7. Correlation between relative viscosity of emulsion at 30% of water content at 60 °C (50 s−1 shear rate) for 13 Brazilian waxy crude oils and total acid number (TAN).

Figure 8. Correlation between relative viscosity of emulsion at 50% of water content at 60 °C (50 s−1 shear rate) for 13 Brazilian waxy crude oils and the total acid number (TAN).

oil−water interface. The ability of asphaltenes and resins to form elastic crude oil−water interfaces has been emphasized by several authors as an important factor regarding emulsion stability. The interfacial elasticity has been proposed as a very determining factor for emulsion stability. It was found that there is no direct relationship between this interfacial elasticity and the amounts of interfacial active material in a crude oil, resins, and asphaltenes.13,14 An comprehensive modeling of the stabilization mechanism and knowledge of the factors that affect this stabilization is a major concern of several authors.15−18 It is shown that the stability of water in crude oil emulsion depends mainly on a rigid protective film encapsulating the water droplets. It is believed that this interfacial film is composed predominantly by natural surfactants contained in crude oil (i.e. asphaltenes, resins, and fatty acids).19,20 These substances may accumulate at the water− oil interface and hinder the droplets' ability to coalesce and separate. Among these components, asphaltenes are believed to be the major culprits of the emulsion stabilization processes. Indeed, in most cases, the fatty acids and resins can not produce stable emulsions in the absence of asphaltenes.21 Moreover, these families of compounds may associate to asphaltene molecules and affect emulsion stability.

The correlation between relative viscosity and total acid number for emulsions with 30% and 50% water content is presented in Figures 7 and 8, respectively. These results suggest a possible correlation with relative viscosity decreasing as the TAN increases. This seems to be more pronounced for the emulsion with 50% water phase. The influence of TAN on the emulsion relative viscosity is not fully understood yet. Further studies, especially the interaction between fatty acids and paraffin molecules, are required to cast some light on this matter. The sodium naphthenate soaps are postulated to be formed by the reaction of acids in oil (C16−C36 fatty acids) with produced waters rich in sodium-bicarbonate. The pH rise of water during depressurization and the cooling of the produced fluids both favor these acids−bicarbonate reactions. As it is impossible to avoid depressurization and cooling of the produced fluids during oil production, the methods for inhibiting or dissolving soaps shall include acidification and heating. A theory holds that the grouping of large paraffin molecules with the fatty acid ones is responsible for increasing the crystallinity or amorphicity of the (naphthenate) soap, hence affecting the emulsion stability.22 A suite of experiments with sodium carboxylate soaps and a structure proposed for metallic soap that includes bicarbonate 5695

dx.doi.org/10.1021/ef300650k | Energy Fuels 2012, 26, 5689−5701

Energy & Fuels

Article

Figure 9. Wax appearance temperature (WAT) versus API density for 13 Brazilian waxy crude oils.

Figure 10. Pour point versus API density for 13 Brazilian waxy crude oils.

ion complexation is described in the literature.23 The author also suggested that water droplets in the oil continuous phase of metallic soaps were protected against coalescence (emulsion breakage) by a mixed film formed by paraffins, fatty acids, and bicarbonate with incorporated metallic soaps. Regardless of whether bicarbonate complexation takes place or not, further studies on this matter might provide valuable insight with respect to the contribution of naphthenates to emulsion stability. In fact, the nature of this complexation phenomenon is still a matter of conjecture; perhaps, it is promoted by hydrogen bonding. The group of soaps referred to as sodium emulsion soaps have a tendency to be formed from lighter oils with API gravities typically in the range from 32 to 41, with low total acid numbers (TANs) of 0.05−0.60 mg KOH/g oil) and low sulfur contents (typically from 0.03 wt % to