ARTICLE pubs.acs.org/EF
Flow Assurance Study for Waxy Crude Oils Marcia Cristina Khalil de Oliveira,* Adriana Teixeira, Lenise Couto Vieira, Rogerio Mesquita de Carvalho, Alexandre Barbosa Melo de Carvalho, and Bruno Charles do Couto Petrobras Research Center (CENPES), Petrobras, Avenida Horacio Macedo 950, Cidade Universitaria, Q.7 Ilha do Fund~ao, 21941-598, Rio de Janeiro, Rio de Janeiro (RJ), Brazil ABSTRACT: In subsea environments, wax-phase separation, deposition, and gelling constitute an important concern in production operation/activities. Understanding the crude oil wax-phase behavior can help to avoid the high costs resulting from production reduction or stoppage in the field operations to mitigate these effects. Conversely, expenses arising from production system overdesign may also be prevented. In this context, two waxy crude oils from different Brazilian fields were selected to be characterized according to Petrobras technical specification for flow assurance requirements. These light crude oils A and B have similar chemical characteristics of saturates, aromatics, resins, and asphaltenes (SARA) analysis, but crude oil A has a wax appearance temperature 15 °C higher than crude oil B. Despite having a density around 29° American Petroleum Institute (API), for a rheological point of view, crude oil B has a viscosity about half that of crude oil A at 20 °C. In addition, crude oil B dehydrated exhibits Newtonian behavior, in the range evaluated for the shear rate and temperature, while crude oil A features a shear thinning behavior, which increases with the increase of the water content and temperature reduction.
1. INTRODUCTION Flow assurance is a critical concern during oil/gas production, especially in deep and ultradeep water conditions. It involves effectively handling many solid deposits, such as, hydrates, asphaltenes, emulsions, and waxes.111 Laboratory testing provides necessary data to assess the flow assurance risk because it defines the crude oil properties known to be principal causes of flow problems. The knowledge of fluid properties in conjunction with thermal and hydraulic analyses is used to develop strategies to control (prevent/mitigate/remediate) these flow assurance issues and problems. New discoveries in Brazil demonstrate that waxy crude oils represent a significant reserve base. In environments such as subsea tiebacks, the precipitation, deposition, and gelling of solid waxes in hydrocarbon fluids constitute critical production concerns. Understanding wax behavior can help avoid high costs resulting from output reductions or stoppages or, conversely, from system overdesign. The presence of paraffinic wax in crude oil is known to cause significant flow assurance problems related to wax deposit buildup and gel formation.1214 At low-temperature conditions, wax crystals nucleate in the bulk and form a solid crystalline network structure that changes the rheological behavior of the crude oil. Recently, we have observed that waxy crude oils can result in different gel emulsion properties because of differences between n-paraffin content.14 One possible mechanism that could be an explanation to this phenomenon is the adsorption of wax particles at the liquidliquid interface, forming pickering emulsions, increasing the interfacial film viscosity, and reducing the coalescence of the drops.13 Then, the growth of the gel network involves the droplets themselves, and the gel behavior emerges when the entire volume is spanned by a wax crystal network. However, it is not well-understood why waxy oils with similar properties have so different flow assurance properties. In this r 2011 American Chemical Society
study, two waxy crude oils were characterized according to Petrobras technical specification for flow assurance requirements. The parameters gathered include crude oil physical and chemical analysis, crude oil emulsion preparation, emulsion stability, dropsize distribution, crude oil and emulsion rheology, wax appearance temperature (WAT), and rheology of the emulsion/hydrate transition at favorable thermodynamic conditions. In this selected case, crude oil A provides the WAT 15 °C higher than crude oil B, with similar chemical characteristics from saturates, aromatics, resins, and asphaltenes (SARA) analysis. For this reason, great attention should be given to this problem. The main objective of this study was to show the significance of considering this issue in flow assurance strategies for the production of waxy crude oils.
2. EXPERIMENTAL SECTION 2.1. Materials. Two waxy crude oils from different Petrobras Brazilian fields, identified as A and B, were selected. Carbon disulfide and iso-octane were purchased from Tedia, and acetone, petroleum ether, and sodium chloride were purchased from Vetec. Spindle oil was provided by BR Supplier. All reagents were analytical-grade. 2.2. Crude Oil Physical and Chemical Characterization. The American Petroleum Institute (API) density value was obtained by the ISO 12185 method. The water content of crude oils was measured by coulometric Karl Fischer titration. A SARA analysis was performed in a thin-layer chromatographyflame ionization detection (TLCFID) system as reported in the literature.15 The total acid number (TAN) Special Issue: 12th International Conference on Petroleum Phase Behavior and Fouling Received: September 16, 2011 Revised: November 10, 2011 Published: November 29, 2011 2688
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was determined according to the American Society for Testing and Materials (ASTM) D664 method. 2.2.1. Separation of the Normal Paraffin from the Crude Oils. A methodology, developed with the aim of separating n-paraffin from crude oils, to obtain rich fractions of n-paraffin was used.16,17 About 1 g of each crude oil was dissolved in iso-octane and percolated in a column packaged with activated alumina to eliminate the polar compounds (non-hydrocarbons). Then, a Soxhlet extraction was performed with alumina impregnated with the polar compounds as the solid phase and iso-octane used to percolate the column as the liquid phase, with the intention of recovering any apolar compounds (non-adsorbed fraction in alumina) that may have been adsorbed on the alumina. After the
Table 1. Crude Oil Physical and Chemical Characterization crude oil analysis API (deg)
method ASTM D4052
A
B
28.4
29.8
56.2
51.1
25.7
30.9
resin
17.1
16.6
asphaltene
1.0
1.4
0.29
0.17
SARA (%) saturate aromatic
acid number (mg of KOH/g)
SFC/TLCFID/ASTM D6560
ASTM D664
pour point (°C)
ASTM D5950
9.0
36.0
viscosity (mPa s)
ASTM D2196
58.4
33.0
ASTM D4377
0.05
0.08
at 20 °C and 50 s1 water content, Karl Fisher (%, w/w)
extraction, the fraction soluble in iso-octane was evaporated and a cold mixture (approximately 21 °C) of acetone and petroleum ether was added to the residue of the fraction soluble in iso-octane (maltenes). The new mixture was sonicated for about 30 min and then cooled to 21 °C for 2 h in a thermal container with dry ice as well as the whole Millipore apparatus to be used for filtration. Thereafter, a filtration under vacuum was carried out, and the precipitate obtained was washed with a cooled mixture of acetone and petroleum ether. The material soluble in the mixture of acetone and petroleum ether, called non-paraffin, was recovered by solvent evaporation. The fraction rich in n-paraffin, retained on the 0.45 μm polytetrafluoroethylene (PTFE) membrane, was recovered by washing the membrane with boiling iso-octane. 2.2.2. Characterization of the n-Paraffinic Fraction by Gas Chromatography. For the characterization of the n-paraffinic fraction, a new methodology was developed to determine the carbon number distribution using high-temperature gas chromatography (HTGC) and hightemperature simulated distillation (HTSD). For sample analysis, it was necessary to weigh 0.2 g of the sample and prepare a solution with 7.8 g of carbon disulfide (CS2). The final concentration should be around 2% (in weight). Each sample was analyzed twice, once using HTSD and once using HTGC (carbon number distribution method). The two techniques were applied individually, using the same conditions of analysis. After the analyses, the results obtained for both were compared and the complete composition of the sample was recalculated. This procedure was the same as reported in the literature.14 2.3. Flow Assurance Characterization. The main flow assurance analyses performed were as follows. 2.3.1. WAT. Determination was measured by a differential scanning calorimeter (DSC)18 in a temperature range from 10 to 80 °C. Because crystallization will give out heat, it will show up in the DSC curve as an exothermic peak during cooling. The onset temperature is measured by the intersection point of the baseline and the tangent line of the inflection point of the exothermal peak. The calculated temperature
Figure 1. Chromatographic analysis for waxy crude oils (a) A and (b) B. 2689
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Energy & Fuels will be noted as the WAT. The total flow heat of wax precipitation is computed by the integration of the area between the DSC signal curve and the baseline. 2.3.2. Emulsion Preparation and Stability. Water-in-oil emulsions were prepared using synthetic brine consisting of 5.0 wt % NaCl in MilliQ water, at aqueous volume fractions of 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 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. 2.3.3. Rheological Analysis. Rheometric measurements were performed using a controlled-stress rheometer. Dynamic viscosity was measured using concentric cylinder geometry, while the emulsion was cooled at a programmed cooling rate (1 °C/min) from the starting temperature (60 °C) to the hold temperature (4 °C). The range of shear rate applied was 20250 s1. To define the crude oil yield stress, oscillatory rheology studies are performed using plateplate geometry. The sample is heated to 45 °C and sheared for 15 min at a shear rate of 10 s1. After this, the sample is cooled to 4 °C and kept static for 15 min. 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 the loss and storage modulus. 2.3.4. Droplet Size Distribution. The drop size distribution of the watercrude oil emulsion type was determined using the laser diffraction technique. The light produced when a laser beam passes through an emulsion is diffracted as a function of the particle size. The emulsion was diluted in spindle oil, and the droplet size distribution was determined considering the volume of droplets. The average diameter of the particles was determined as a function of the total volume of the droplets. The study was based on the comparison of the mean diameter characterizing 50% of the total particles, named D(0.5). 2.3.5. Hydrate. The rheology of the transition emulsion to hydrate suspension is obtained for the wateroil emulsion at 4 °C and 100 bar, using a standard natural gas (composition: 87% methane, 10% ethane, 2% propane, 0.05% isobutane, 0.04% n-butane, 0.01% isopentane, 0.4% carbon dioxide, and 0.5% nitrogen). Tests were performed using the pressure cell of a controlled-stress rheometer, and the dynamic viscosities were measured using vane geometry. The experiment can be performed in a range of shear rate between 10 and 100 s1. After emulsion preparation, the cell is pressurized and kept at 40 °C and 50 s1 for 12 h, to solubilize the gas within the emulsion. Then, the system is cooled to 4 °C (0.5 °C/min), with constant shear (50 s1) and pressure (100 bar), remaining at this temperature for at least 6 h. During this step, hydrates are formed and the viscosity increase is evaluated. If a plug is formed, the test is interrupted by the sensor movement blockage. After this first part of the hydrate test, the system is kept on a static condition (without shear) at 4 °C for, at least, 24 h. Then, a growing shear stress is applied to the system. Using this procedure, it is possible to evaluate qualitatively restart problems when hydrates are present.
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Table 2. Distribution by Carbon Atoms of the n-Paraffin Fraction Isolated from the Crude Oils carbon number
3. RESULTS AND DISCUSSION
sample A (%)
sample B (%)
C16
0.02
C17 C18
0.23 0.62
0.04 0.27
C19
1.11
0.88
C20
1.36
1.35
C21
1.58
1.57
C22
1.90
1.62
C23
2.06
1.72
C24
2.19
1.65
C25 C26
2.26 2.50
1.49 1.48
C27
2.60
1.57
C28
2.60
1.63
C29
2.72
1.59
C30
2.26
1.57
C31
1.98
1.61
C32
1.85
1.58
C33 C34
1.89 1.59
1.65 1.48
C35
1.57
1.62
C36
1.80
1.48
C37
1.42
1.31
C38
1.37
1.24
C39
1.31
1.26
C40
1.31
1.25
C41 C42
1.26 1.22
1.16 1.19
C43
1.13
1.15
C44
1.17
1.15
C45
1.15
1.04
C46
1.19
1.00
C47
1.14
1.06
C48
1.06
1.06
C49 C50
1.03 1.14
1.01 1.04
C51
1.07
0.96
C52
1.08
0.98
C53
1.11
0.94
C54
1.08
0.97
C55
1.00
1.04
C56
1.11
0.75
C57 C58+
0.81 38.00
0.94 49.64
total
100.00
100.00
3.1. Crude Oil Physical and Chemical Characterization.
The main properties of the crude oils A and B are reported in Table 1, with the first column showing the analysis, the second column showing the method applied, and the third column showing the results. As we can see, these crude oils have a medium API value (around 29° API) and low acidity index. The values of physicalchemical properties can be considered typical of many waxy crude oils, with around 50% saturated compounds and 1% asphaltenes. The total of the resin plus asphaltene content is similar for both crude oils.
Furthermore, the results revealed that, although the crude oils present similar API density and chemical composition, they significantly differ in their flow assurance parameters as pour point and viscosity. The crude oil A pour point is 9.0 °C, while the crude oil B pour point is 36 °C. 3.1.1. Separation and Characterization of n-Paraffin from Crude Oils. The wax content is assumed to represent the total amount of n-paraffin in each crude oil. The wax content obtained 2690
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Figure 2. Crystallization enthalpy evaluation for waxy crude oils (a) A and (b) B.
for crude oils A and B was 15.6 and 7.14% (by weight percent), respectively. It was observed that, the higher the content of n-paraffin in the crude oil, the more viscous the crude oil and the emulsion formed. Analysis of the fraction rich in n-paraffin, using HTGC associated with HTSD, showed differences in the distribution by the carbon number for the crude oils A and B, which is shown in Figure 1. When the size carbon distribution is compared, you can see in crude oil A a higher percentage of C20 and C35 than in crude oil B. After this range, the distribution is quite similar. A high content of long-chain paraffin (C58+) for these crude oils can be seen in Table 2. The C58+ fraction content is higher in crude oil B than in crude oil A. It means that the high content of normal paraffin of high molecular weight in crude oil B does not compromise its flow properties. 3.2. Flow Assurance Characterization. 3.2.1. WAT. Figure 2 shows crystallization enthalpy evaluation for crude oils A and B. The WAT occurs at 41.1 °C, and the second crystallization occurs at 20.8 °C, for crude oil A. As observed in these two graphs and Table 3, the WAT for the samples is significantly different. Crude oil A presents a WAT 15 °C higher than crude oil B, and greater attention to wax deposition problems must be drawn in relation to this crude oil. To ensure the flow of crude oil A production, it is necessary to maintain high flow temperatures. Then, to prevent wax deposition, thermal methods including heating or insulating the pipeline have to be considered in the project plan. 3.2.2. Rheological Analysis. Rheological properties of the waxy crude oils, such as viscosity, depending upon the temperature, shear rate, and water content were measured. In Figure 3, the viscosity experimental data for each crude oil and emulsion were plotted for different water contents. As the temperature drops, the viscosity increases, specially below WAT. The results show that crude oil A has viscosity twice the viscosity of crude oil B in all ranges of the temperature. Also, it is observed that the inflection of the viscosity curve is greater for crude oil A, indicating that temperature has a significant effect on this crude production. Analyzing the viscosity curves of the emulsions with 3050%, a viscosity increment of 310 times is observed, respectively. Figures 4 and 5 display the crude oil and emulsion viscosity according to the shear rate. Crude oil A and its emulsions exhibited a shear-thinning behavior below WAT. Waxy crude oil B showed Newtonian flow behavior, and its emulsions exhibited a Newtonian flow behavior at 30% water cut and shear-thinning
Table 3. WAT for Crude Oils A and B sample
WAT (°C)
second WAT (°C)
crude oil A
41.1
20.8
crude oil B
26.9
12.6
behavior at 50% water cut at this range of the shear rate and temperature. Despite both samples having densities around 29° API and producing stable emulsions, their rheological behavior is quite different. At 20 °C, crude oil B has a viscosity about half that of crude oil A. The same behavior is observed comparing emulsion rheology. Figure 6 shows how the elastic modulus, G0 , and the viscous modulus, G00 , vary as the sample is submitted to stress values ranging at 4 °C after 15 min at static conditions. For crude oil A, there is a crossover point at 51 Pa, but for crude oil B, we cannot see the crossover. This behavior seems to be caused by the formation of a gel structure in crude oil A, thus raising the flowing pressure drop. During long shutdowns, the fluid will achieve equilibrium with the ambient temperature. If the environment temperature is below the pour point then a gel consisting of wax crystals in a viscous matrix will form. Therefore, a minimum pressure will be needed to break the gel and then to resume flow of crude oil A. Furthermore, crude oil A produces stable and viscous emulsions that increase gel strength and hinder way pipeline restart. The yield stress of crude oil A emulsion with 50% water content is 198 Pa at 4 °C. It is 4 times higher than crude oil without water (less than 1%). On the basis of these results, the differences observed in flow assurance properties can be attributed to the amount of n-paraffin in crude oil. In previously studies,14 the results indicate a relation between the increase in the viscosity and n-paraffin content. When all of these crude oil characterizations are compared, this relation is not evident. Then, other parameters, such as paraffin type and molecular size, and the presence of polar compounds should be considered. Some studies4,9 show that the degree of dispersion of asphaltenes in crude oil influences the wax crystallization and yield stress value. For these reasons, more studies have been performed to explain these results. 3.2.3. Droplet Size Distribution. The analyses of the particle size distribution show that crude oil emulsions A and B have a similar polydispersive distribution size and confirmed the presence of tight emulsions, with an average droplet size of 8.4 and 9.7 μm at 50% water cut (Figure 7). Although the emulsion 2691
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Figure 3. Dynamic viscosity versus temperature for waxy crude oils (a) A and (b) B at different water contents at 50 s1.
Figure 4. Dynamic viscosity versus temperature for (a) waxy crude oil A and emulsions with (b) 30% and (c) 50% water content at different shear rates.
viscosities from crude oils A and B are so different, we cannot see differences between drop size distribution measurements in the same experimental conditions. The droplet size distribution in an emulsion depends upon the interfacial tension, shear rate, nature of emulsifying agents, presence of solids, and bulk properties of oil and water. For these reasons, it cannot be expected that the differences observed between the behavior of these crude oils are related to interfacial or polar compounds in the interface. It can probably be related to the bulk properties of oil. 3.2.4. Hydrate. Viscosity curves of hydrate formation tests for crude oils A and B are shown in Figures 8 and 9, respectively. The viscosity increase is due to hydrate formation, and it is possible to observe that this event occurs in different ways in each emulsion. (i) For the same crude oil, the higher the water content,
the higher the viscosity increment. (ii) For the same water content, hydrate formation promotes a sudden viscosity increase and reaches higher viscosity values for crude oil B than for crude oil A. Induction times (time before hydrate formation) are quite similar. (iii) For each crude oil, viscosity tends to decrease during continuous shear for crude oil B hydrate suspensions and reach almost stable values until the end of tests. The same observation can be made for crude oil A 30% water cut suspension, but for suspension with 50% water cut, viscosity increases slowly during all of the test. This behavior can be due to an agglomeration process between hydrate particles or even hydrate particles and wax. On the basis of these results, we can observe the plugging tendency for each oil. The hydrate suspension formed is generally more viscous than the original emulsion, and in some 2692
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Figure 5. Dynamic viscosity versus temperature for (a) waxy crude oil B and emulsions with (b) 30% and (c) 50% water content at different shear rates.
Figure 6. Viscous and elastic modulus versus stress for waxy crude oils (a) A and (b) B.
cases, the flow can be blocked by hydrate particle agglomeration and/or the high viscosity achieved. Considering the continuous viscosity increase of the crude oil A suspension at 50%, this behavior can be more critical than the sudden increase of the same suspension of crude oil B, because in this case, viscosity values decrease with a continuous shear rate. Therefore, it was concluded that crude oil A showed a higher hydrate blockage risk than crude oil B during the emulsion production, which should thus require more stringent design criteria to prevent flow lines and subsea equipment blockages. The blockage risks for crude oil B are also expected but at higher water cuts. As described earlier, at the end of each test, hydrate suspensions were kept at 4 °C for 24 h. Then, performing a raising shear stress, it is possible to observe qualitatively the presence of a yield stress considering hydrates in the system. For both crude oils, it
was not possible to restart the flow using 1120 Pa (the higher value tested), neither for 30% suspension nor for 50% suspension. This behavior is an indication of possible problems with restart operations when hydrates are present. The plug formed during the shutdown test with suspension 50% of crude oil A is shown in Figure 10. The plug was kept stable for a few minutes at atmospheric pressure and ambient temperature (after depressurization of the pressure cell). It means that the hydrate was dissociated in this environmental condition but the wax network kept plug stability. This kind of stable plug was not observed with a similar suspension of crude oil B, showing the importance of individual analysis for each crude oil. These results mean an additional concern for pipeline flow startup because the oil gelation process may turn an initial hydrate blockage after a period of shutdown into a much more severe problem. 2693
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Figure 10. Hydrate plug observed at the end of the test with emulsion 50% of crude oil A (after depressurization of the system).
Figure 7. Particle size distribution analysis for waxy crude oils (a) A and (b) B at 50% water content.
Figure 8. Natural gas hydrate formation tests with crude oil A emulsions at 30 and 50% water content.
4. CONCLUSION Flow assurance is a key issue when economically developing offshore crude oil fields in deep and ultradeep water scenarios in Brazil. Light oils from different fields may present apparently almost similar chemical composition by SARA analysis and API density but significant differences in their flow assurance parameters. The crude oil A pour point is 9.0 °C, while the crude oil B pour point is 36 °C. The differences observed in chemical composition (SARA) are not enough to explain so different pour point and viscosity data. Furthermore, crude oil A has a high WAT and large amount of wax, raising the concerning for wax deposition and gelling. These results mean an additional concern for pipeline flow startup because the oil gelation process may turn an initial hydrate blockage after a period of shutdown into a much more severe problem. Because the amount and type of wax contained in a crude oil sample varies, depending upon the geographic source of the crude, specific and accurate fluid characterization is an important component of any development, production, or intervention strategy for handling waxy crude oils. Normal paraffin content is still the reason for the differences of results obtained. However, the importance of isoparaffin, microcrystalline, and macrocrystalline paraffin contents in the crude has to be studied. The study shows the need for more detailed compositional analysis rather than merely relying on SARA, WAT, API, and water content to preview flow assurance challenges. In the future, even more accurate wax characterization analysis will be performed to promote an increased understanding of the mechanisms involved in wax deposition and gelation and interactions between waxasphaltene and waxhydrate in flow assurance properties. ’ AUTHOR INFORMATION Corresponding Author
*E-mail:
[email protected].
’ ACKNOWLEDGMENT The authors thank Petrobras for permission to publish this work. ’ REFERENCES
Figure 9. Natural gas hydrate formation tests with crude oil B emulsions at 30 and 50% water content.
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