Drive To Produce Heavy Crude Prompts Variety Of Transportation Methods

Storage tanks have been installed near Jose, Venezuela, to accommodate upgraded Zuata crude oil from the Orinoco Belt. Currently, the crude oil is moving in a dilution with much lighter crude oil. But when the Jose upgrader is completed in early 2000, the bitumen will be blended and transported with a 47° API naphtha that will be separated and returned to the field for more blending. The offshore loading dock is being installed upper left. (Photograph courtesy Petróleos de Venezuela S.A., Caracas)

Moving these heavy crudes and bitumens to market requires alternative pipeline transportation methods.

Those methods are discussed here, along with the general problems which industry faces in transporting and marketing heavy crudes and alternatives currently available for dealing with them. Environmental aspects are also considered.

Methods for dealing with the problems of heavy-oil transportation include the use of diluents, crude upgrading prior to transportation, and use of other types of pipeline systems, such as hot-oil pipelines, oil-in-water emulsion systems, oil/water core annular flow, and Orimulsion.

Also presented here are the advantages and disadvantages of the various technologies and how they might fit into the future of heavy oil in Venezuela.

The technologies and experiences reviewed confirm that heavy oil and bitumen pipelines can be designed and operated with confidence. Economic aspects must be considered in the ranking of technical options.

Demand drivers

For many years, research in heavy oil has been biased toward increased recovery and upgrading. This situation has made available modern lifting techniques and upgrading processes that have improved the entire value chain of heavy-oil projects, thus making them more attractive.

On the other hand, only little attention has been given to pipelining techniques, other than the classical ones of heating and dilution. Transporting hydrocarbons can be made greatly more efficient and much less costly by newer technologies for improvement and cost reduction. Such technologies are, in many instances, project enablers.

The economic development of heavy-oil resources at today's prices requires alternative pipeline methods to move the heavy crude oils and bitumens to their markets.

Transportation

Several methods are capable of achieving these characteristics. Some have been confirmed in the field and are currently being used, while others are in the process of being developed.

These methods are: heating, dilution, partial field upgrading, water-continuous emulsions, and lubricated and core-annular flow.

Heating

Most heavy-oil lines can be run economically when the oil viscosity is less than 500 cp at the outlet.

Evaluation of the temperature and pressure profiles of heavy oil flowing along pipelines is complicated and tedious and generally involves the simultaneous solution of the equations expressing the balance of mass, momentum, and energy over the entire length of pipe.

Simplified treatments adequate for practice are used in applications.²

Heat losses from flowing fluids may be calculated by determining an overall heat-transfer coefficient that, in turn, depends on the thermal conductivity of the pipe wall, surrounding soil, and ambient thermal conditions.

Packages for this type of calculation are available in the market and easily run in microcomputers.³

Profiles for several flow rates are shown in Fig. 1 [101,874 bytes]. Oil cooling in the flow direction and its associated viscosity increase result in hydraulic profiles that are not straight lines. The curvature becomes more pronounced for more viscous oils.

It is important to note that the external heating of the oil can be partially frustrated by heat losses from the pipe walls when the flow velocity is low. This cooling from heat loss can lead to the unacceptably high pressure gradients illustrated in Fig. 2 [55,826 bytes].

Heat losses will always occur and the heating method can work only when the oil is reheated in the pumping stations. Direct-fired heaters are generally used to raise the oil temperature; they can be natural gas or fuel fired.

Temperature variations induced by flow-rate changes can cause longitudinal expansions of the pipeline. For aboveground pipes, this is remedied by expansion loops. For buried lines, thicker steel is required in order to absorb axial compression stresses.

Plugging generally occurs when lines are cooled to a nonflowing threshold. In that case, displacement oil must be used during start-up and shutdown operations so that the heavy oil never stays in the pipeline for a long time.

Typical design of hot-oil pipelines involves temperature required to obtain optimum viscosity; heat losses, including consideration of insulation thickness; minimum flow to prevent plugging; pipeline expansion; coating insulation and pipeline material; number of pumping and heating stations; and start-up and shutdown considerations.

Dilution

Fig. 3 [56,883 bytes] shows typical viscosity reductions after blending.

There is an exponential relationship between the resulting mixture viscosity and the volume fraction of the diluent: small percentages of diluent can have a marked effect on the viscosity of the mixture.

The smallest viscosity that can be achieved by diluting the oil is the viscosity of the diluent; most of the viscosity reduction can be achieved at to-be-determined fractions of diluent, and further dilution should not be done.

It is recommended to prepare test blends in a laboratory and to determine viscosities experimentally.

Pressure drops can be calculated by conventional methods, assuming isothermal, single-phase flow of an homogeneous mixture with a viscosity value corresponding to the percentage of diluent in the mixture.

If condensate is unavailable in a given field, other possible schemes could be used, such as manufactured diluent, light crude, or diluent recycling. Diluents with characteristics similar to condensate can be manufactured from any light crude from fractions normally used to produce gasolines, jet fuels, and middle distillates.

Many light crudes can also be used directly as diluents. Oils in the 35-45° API range can be used, although more is usually required to do the same job as condensate.

Recycling can be achieved by recovering downstream the diluent from the mixture and reinjecting it upstream. The main difficulties with this scheme are the need to incorporate facilities to remove the diluent at the end of the pipe and the construction of a return pipe.

These add both cost and operational complexity to the diluent option and must be carefully examined in every pipelining evaluation that considers this technique.

Partial field upgrading

Recently, Pdvsa-Intevep has successfully tried a novel technology at a commercial level at the Isla refinery in Curacao (The Netherlands Antilles). This scheme, known as Aquaconversion, is based on a partial and selective steam reforming of heavy molecules which results in products with lower API gravity and improved quality.⁴

In this thermal conversion process, the cleavage of carbon-carbon bonds creates smaller paraffins and olefins, which reduces the viscosity of feedstock. As an example of the potential of this technology, consider the treatment of Cerro Negro bitumen from the Orinoco Belt. (Editor's note: See OGJ's special report on recent and current Orinoco Belt heavy-oil projects in Oct. 19, 1998.)

This bitumen has an API gravity ranging from 6 to 8.5° and a viscosity of more than 300,000 cp. When this oil is used to feed an Aquaconversion plant, the resulting fluid is upgraded up to 14° API with a viscosity around 1.5 million cp, very suitable for pipelining without any further requirement.

Oil-in-water emulsions

The viscosity of such emulsions can be much less than the viscosity for the dispersed hydrocarbon and for heavy and extra-heavy oils and bitumens, independent of the hydrocarbon viscosity. Pipelining emulsions requires reduced horsepower of the same magnitudes as dilution or heating.

Commercial pipelines for transporting emulsions have been used in Venezuela and elsewhere. A commercial line in Indonesia carries 40,000 b/d of 70% oil-water emulsion in a 238-km, 50-cm OD line.⁵

Oil-in-water emulsion technology has been mastered in Venezuela since 1980; more than 1 million cu m of emulsified oil have been transported through a 72-km, 609.6 mm (24-in.) OD pipeline.⁶ Field tests have also been conducted at Wolf Lake, Canada.⁷

Design for pipelining emulsions should consider selection of the best chemical to form a stable emulsion; dispersion mechanism (mixers and homogenizers); rheological and stability characteristics of the emulsion; pipeline diameter; and emulsion breaking.

Criteria for selecting a suitable chemical must ensure the stability of the emulsion under different conditions but in such a way as to allow breaking at the end of the pipe (discussed presently). The most relevant criteria are temperature, hydrocarbon/water ratio, water salinity, and pH.

Nonionic surfactants are the most effective in producing a more-stable emulsion because they produce a smaller mean droplet size for the same formation dynamics.

A typical effect of the volume of water on the viscosity of the emulsion is shown in Fig. 4 [56,068 bytes]: viscosity decreases exponentially as the water content increases. This curve is very useful for selecting the optimum amount of water in the emulsion.

The rheological behavior of the emulsion must be assessed in order to predict pressure losses. According to the rheological models developed by Pdvsa-Intevep, the behavior is Newtonian for oil fractions less than 65%.

For higher fractions, the emulsion behaves as a pseudo plastic fluid; for example the coal-substitute fuel Orimulsion with oil fraction exceeding 69% follows a power-law model.

Separation of the emulsion phases is ultimately required to restore the crude oil for further processing. Breaking of an emulsion requires the optimization of oil-drop coalescence.

Temperature, water pH, water salinity, and surfactant concentration affect the emulsion-breaking process. The use of nonionic surfactants at greater than certain temperatures promotes the breaking of the emulsion.

Lubricated, core flows

Water-lubricated transport of heavy viscous oils is based on a gift of nature in which the water migrates into the region of high shear at the wall of the pipe where it lubricates the flow.

Since the pumping pressures are balanced by wall-shear stresses in the water, the lubricated flows require pressures comparable to pumping water alone at the same throughput.

In core flow, water and heavy oil are pumped simultaneously in a line. The water fractions are typically in the range of 10-30% and there is an optimum fraction, depending on flow speed, for the reduction of pumping power.

The power saved is proportional to the ratio of the viscosities; this can be even greater than 100,000 for crudes with viscosities greater than 1,000 poise. Lubricated flow in an oil core is called "core-annular flow" (CAF).

Typically, waves appear on the surface of the oil core and seem to be necessary for levitation of the core off the wall when the densities are different and for centering the core when the densities are matched. These flows are known as "wavy core-annular flows" (WCAF).

Perfect core-annular flows (PCAF) of density-matched fluids in horizontal pipes, and generally in vertical pipes, are possible but are rarely stable.^8-10

The science behind CAF has given rise to a large literature which has been variously reviewed.^{8 11 12} This literature reports, among other information, models for levitation, empirical studies of energy efficiency of different flow types, empirical correlations giving the pressure drop vs. mass flux, stability studies, and industrial experiences.

Heavy crudes are very viscous and usually somewhat lighter than water, although crudes heavier than water are not unusual. Typical crudes might have a viscosity of 1,000 poise and density of 990 Kg/cu m at 25° C. Light oils with viscosities less than 5 poise do not give rise to stable lubricated flows unless they are processed into water-oil emulsions and stiffened.

Oil companies have shown intermittent interest in water-lubricated transport of heavy oil since 1904 when researchers proposed to stabilize water lubrication of lighter oils by centripetal acceleration created by rifling the pipe.¹³

For stratified flow, a method was patented for conveying oils by passing them over an array of water traps at the bottom of the pipe.^{8 14} In fact, the patent history of the subject starts in 1949 with Socony Vacuum Oil Co. whose researchers used additives to reduce density differences between oil and water and an ionic surfactant to reduce emulsification of water into oil.¹⁵

Researchers at Shell Development proposed to prevent emulsification of oil at pumps by removing water before pumping and reinjecting it afterwards.¹⁶

In fact, values for water-in-oil emulsion viscosities can be orders of magnitude higher than for oil alone. In general, lubricated flows are more effective when the oil is more viscous: the water-oil emulsion is effectively thickened oil whose density is closer to water.

Exxon patented a CAF process for pumping heavy oils and water-in-oil emulsions, surrounded by water, with the purpose of fracturing subterranean formations to increase oil and gas production.¹⁷ Later, Exxon produced a concentrated water-in-oil emulsion with 7-11 times more water than oil, which it successfully transported in CAF.¹⁸

Shell pipeline

When lubricated by water at a flow rate of 30 vol % of the total, the pressure drop varied between 900 psi and 1,100 psi at a flow rate of 24,000 b/d. The larger pressure represents a threshold of unacceptability which called for cleaning the oil off the pipe wall.

After 6 years of operation, the fresh water was replaced with water produced at the well site that contained various natural chemicals leached from the reservoir, including sodium metasilicate in minute 0.6 wt % amounts.

After that, the pressure drop never varied much from the acceptable 900 psi value, the CAF was stable as long as the flow velocity was at least 1 m/sec. Industrial experience suggests that inertia is necessary for successful CAF.

Lubed pipelining-Venezuela

Typically at a pumping station, the Bachaquero crude contains 16% produced water. As much as 24% more water is added to keep the pressure drops low. The system has been running this way for more than 30 years.

Whenever fouling or blockage cause a pressure buildup, it is washed away by addition of more water, suggesting a robustly stable lubricated flow.

The superficial velocities in the tributaries are low, 0.006-0.023 m/sec. The viscosity of the Bachaquero Pesado ranges 4,800-1,200 cp at 30° C. and 2,000-3,000 cp at 60° C.

It should be noted that different well clusters give oils with different viscosities, and the density of the oil from different wells ranges 11.2-15.2° API (or 991-964 kg/cu m). This is a lighter-than-water oil which must be levitated by waves off of the top of the pipe.

It is unknown if the efficiency of Maracaibo lubricated pipelines can be improved by reducing the amount of lubricating water or by increasing the volume flow rate of oil.

Self-lubrication

The froth itself is a stable water-in-oil emulsion with typical water fractions ranging 10-30%. The water produced in the extraction is laced with clay platelets that readily form a colloidal dispersion in water.

This clay dispersion plays a major role in the self-lubrication of bitumen froth because it sticks to the bitumen, forming a protective coating which keeps the bitumen from sticking to itself. Thus, the water droplets may coalesce under shear at the pipe wall where the shear is greatest.

This released water collects in an annulus around the froth, forming the lubricating layer associated with "self-lubrication" in which no water is added.

Several experiments established the main features of self-lubrication: in a 47-m, 2-in. (50-mm) OD pipeloop facility in Edmonton; in a 6-m, 1-in. (25-mm) OD return loop at the University of Minnesota; and in 1,000-m, 24-in. (0.6-m) pilot loop at the oil sands.19 More-recent experiments have been carried out at Syncrude's Edmonton Research Center on a 40-m, 4-in. (100 mm) OD pipe loop.

The pressure gradients in all of the experiments are for turbulent flow and follow the Blasius law for turbulent pipe flow with Reynolds numbers and friction factors based on the pipe diameter.

The experiments revealed that the pressure gradient is proportional to the ratio of the 7/4 power of the flow velocity (U^1.75) to the 5/4 power of the pipe radius (r_o^1.25), but the constant of proportionality is about 10-20 times larger than for water alone (Fig. 5 [50,934 bytes]).

A definite reason for the increase of the ratio of the friction of froth over water has not been established. But it appears the result of an equilibrium in which froth is deposited on the pipe wall and at the same time the fouled froth on the wall is washed off by running clay water.

In fact, running clay water can clean the fouled walls; pigging is never required. The balance of fouling and cleaning could not be achieved without sacrificing pumping power, and this increase of friction is seen in the increased value of the Blasius constant.

In some sense, a pipe wall fouled by bitumen can work as an antifouling film because a layer of clay protects the wall.

Frictional heating also plays an important role in the self-lubrication of bitumen froth. There is a substantial rise of temperature with flow speed U, proportional to U²; the froth temperature increases from 46° C. at U= square root 2 m/sec to 54° C. at U= square root 6 m/sec.

The ratio of Blasius constants for froth to water decreases with increasing temperature, from 20 to 10 as the temperature is increased 10° C. This means that friction heating benefits lubricated pipelines by reducing viscosity and weakening froth which may have fouled the wall.

Lubricated froth lines will not run at low speeds; there is a critical velocity, between 0.3 m/sec and 0.7 m/sec, for the start-up and maintenance of self-lubrication.

A high-speed limit for successful self-lubrication of bitumen froth has not been found; the froth was run in a self-lubricated mode in the 1-in. line at 4 m/sec, the limit of speed obtainable in this system.

At high speeds, the flow becomes "super lubricated." Large increases in flow rate can be induced by the most modest increase in the pressure gradient.²⁰

Syncrude's operations are located in northern Alberta, about 400 km north of Edmonton. There are four huge deposits of oil sands, with Syncrude's operation in the Athabasca region. Syncrude extracts oil sand from open pit mines.

The oil sand contains 10% bitumen, which is extracted using the Clark hot water process. The bitumen is then thermally cracked and hydrotreated to make a synthetic crude.

After 25 years of operation, the newly available oil sand is located at increasing distances from Syncrude's upgrading facilities at Mildred Lake. The next ore body to be mined is 35 km northeast of the upgrading facilities, prompting the requirement for a bitumen-froth pipeline. The plan to mine this remote ore body is referred to as the Aurora project.

An economic and technical screening of available froth-transfer technologies reduced the options to heating, emulsified froth, naphtha dilution, and self-lubrication. Further screening reduced the options to diluted froth, judged to have the best chance for technical success.

Separability is an issue in diluted froth (naphtha dilution), but not for self-lubrication. In fact, self-lubrication appeared to have better economics than diluted froth, but there was insufficient research to verify it this application.

Questions of applicability of self-lubrication were successfully resolved by the test and pilot studies reviewed previously. Based on these results, Syncrude's management authorized construction of a 35-km, 36-in. self-lubricated pipeline to start into operation in the year 2000.

Lubed oil-in-water emulsions

The same kind of lubrication occurs in shear flows of concentrated suspensions of solid particles with the caveat that the migration of particles away from regions of high shear near the wall actually creates a high viscosity region away from the wall.

In all these cases, it is probable that lubrication forces of the kind that keep single particles off walls, like the Segr?-Silberberg effect, provide the mechanism which levitates the high-viscosity constituents off the wall.

Formation of a slip layer or lubrication layer at the walls of a pipe leads to substantially greater drag reduction than the already significant ones achieved by emulsification.^{21 22}

It is apparently unknown under what conditions a flowing concentrated oil-in-water emulsion will lubricate or lose lubrication. For example, an emulsified Wyoming crude did not slip in a concentric cylinder rheometer, but two different emulsions of Venezuelan crudes did slip.²²

The strong reductions of drag on emulsions of a very viscous heavy crude, observed in the laboratory, did not carry over to test in the field.²²

For lubricated pipe flows of Orimulsion, formation of the emulsion with Intan 100, a non-ionic surfactant, will enter into lubricated flow in stainless steel capillary tubes at flow speeds greater than critical.16 A tube development length is required for the formation of lubrication.

A new formulation of Orimulsion based on a mixture of natural surfactants in crude oil and other additives enters a lubrication regime in stainless steel capillaries at much lower values of the velocity.

This seems to suggest that the emulsion formulation has an important effect on the propensity of the fluid to enter a lubricated regime. This is probably related to the degree to which water wets the pipe wall covered by surfactant.

In view of the foregoing, lubricated transport of oil-continuous emulsions represents a viable alternative for transporting heavy oil provided there is an effective formulation and a comparative economic assessment in favor of this scheme.

Principles, problems

• Any arrangement of a dispersion of heavy oil in water is lubricated when the dispersion does not attach to the solid; examples are core flow and dispersed oil in water.
• Lubricated arrangements of two fluids are stable. There is a tendency for the low-viscosity constituent to migrate to the region of high shear, to the pipe wall.
• Even when lubricated flows are hydrodynamically stable, they are at risk to fouling. Fouling involves adhesion and chemistry, not hydrodynamics.
• Additives such as sodium silicate can enhance the tendency towards wettability on a carbon-steel pipeline's wall.
• Surfactants naturally or artificially present in an oil or emulsion will interact with solid walls and change their hydrophilicity, that is the water wettability of the pipe wall.
• Know your oil. A given oil may foul a pipe wall without a buildup of fouling; you may run a core flowing in a fouled pipe provided the fouling doesn't build up.

• Accumulation of fouling may be prevented by the shear of lubricating water tearing away some of the fouled oil; this equilibrium between deposition and removal produces oil droplets.
• A fouled wall may be an excellent wall-preparation system, provided that the oil doesn't stick to itself when being pipelined. Syncrude's froth is protected by a clay coating. Protection against coalescence could be promoted by surfactants.
• There is a lower limit of speed for which core flow will stratify or undergo capillary instability, depending on the density difference and the core diameter.
• There is an optimum amount of water in a lubricated system that leads to the smallest pumping power. More water is needed for faster flows.
• Oil cores cannot persist at high speed if starved of water; they will invert to water-oil emulsions with high pressure drops. If there is ample water, they will be torn apart and form an oil-water dispersion which could be well lubricated.

Given current and prospective prices for heavy oil, there is a need to reduce the technological uncertainty associated with novel schemes, in order to increase profitability and make the development of heavy oil a reality.

Acknowledgment

References

1. Meyer, R.F., "World Heavy Crude Oil Resources," presented to the 15th World Petroleum Congress, Beijing, 1997.
2. Guevara, E., Gonz lez, J., and Núñez, G., "Highly viscous oil transportation methods in the Venezuela oil industry," presented to the 15th World Petroleum Congress, Beijing, October 1997.
3. Urquhart, R.D., "Heavy oil transportation-present and future," JPT, Mar-Apr. 1986, p. 68.
4. Marzin, R., "The aquaconversion process a new approach to residue processing," presented to the NPRA Annual Meeting, San Francisco, 1998.
5. Land, J.M., and Simpson, W.C., "Pipeline Transportation of Wax-laden Crude Oil as a Water Suspension," proceedings of the 6th World Petroleum Congress, October 1963, Frankfurt, Section VII, Paper 13, pp. 23-33.
6. Núñez, G.A., Brice?o, M., Mata, C., Rivas, H., and Joseph, D.D., "Flow characteristics of concentrated emulsions of very viscous oil in water," Journal of Rheology, Vol. 40, No. 3, pp. 405-23.
7. Hardy, W.A., and Sit, S.P., "Field trials of Transoil Technology for emulsion pipelining of bitumen," proceedings of the Fourth Unitar Conference, August 1988, Vol. 5, No. 222, p. 491.
8. Joseph, D.D., and Renardy, Y.Y., Fundamentals of Two-Fluid Dynamics. New York: Springer-Verlag, 1993.
9. Preziosi, L., Chen, K., and Joseph, D.D., "Lubricated pipelining: stability of core-annular flow," Journal of Fluid Mechanics, Vol. 201 (1989), pp. 323-56.
10. Chen, K, Bai, R., and Joseph, D.D., "Lubricated pipelining. Part 3. Stability of core-annular flow in vertical pipes," Journal of Fluid Mechanics, Vol. 214 (1990), pp. 251-86.
11. Oliemans, R.V.A., and Ooms, G., "Core-annular flow of oil and water through a pipeline," in Multiphase Science and Technology, G.F. Hewitt, J.M. Delhaye, and N. Zuber, eds. Vol. 2. Washington: Hemisphere, 1986.
12. Joseph, D.D., Chen, K.P., and Renardy, Y.Y., "Core-Annular Flows." Annual Review of Fluid Mechanics, Vol. 29 (1997), pp. 65-90.
13. Isaacs, J.D., and Speed, J.B, 1904. U.S. Patent No. 759,374.
14. Looman, M.D., 1916. U.S. Patent No. 1,192,438.
15. Clark, A.F., and Shapiro, A., 1949. U.S. Patent 2,533,878.
16. Clifton, E.G., and Handley, L.R., 1958. U.S. Patent No. 2,821,205.
17. Keil, O.M., 1968. U.S. Patent 3,378,047.
18. Ho, W.S., and Li, N.N., Core-annular flow of liquid membrane emulsion, AIChE Journal, Vol. 40 (1994), No. 12, pp. 1961-68.
19. Neiman, O., "Froth pipelining tests-Syncrude," Canadian Research & Development Progress Report, Vol. 15 (1986), No. 1, pp. 373-407.
20. Joseph, D.D., Bai, R., Mata, C., Surry, K. and Grant, C., "Self-Lubricated Transport of Bitumen Froth," accepted for publication in the Journal of Fluid Mechanics, 1999.
21. Zhang, J., Yan, D. Chen, Yang, X., and Shen, Ch., "Pipelining of Heavy Crude Oil as Oil-in-Water Emulsions," SPE No. 21733 (1991), pp. 911-18.
22. Pileharvi, A., Saaokuandi, B., Haluaci, M., and Clark, P.E., "Emulsions for Pipeline Transport of Viscous Crude Oils, "SPE No. 18218 (1988)

The Authors

Gustavo A. Núñez has been leader of the rheology and scale-up team in the emulsion technology program at Pdvsa-Intevep in Los Teques, Venezuela. He has been with Pdvsa-Intevep since 1986. He has been manager of the Orimulsion business unit and currently is the corporate planning manager at Pdvsa-Intevep.

Núñez holds a BS from the University Simón Bolívar, Caracas, and MS and PhD from the University of Minnesota, Minneapolis, all in mechanical engineering.

Hercilio J. Rivas has been with Pdvsa-Intevep since 1982. Previously, he was professor of chemistry and physical chemistry at the Universidad Central de Venezuela and Universidad Metropolitana, Caracas. Rivas holds a BS in chemistry from the Universidad Central de Venezuela and a PhD in physical chemistry from the University of London.

Daniel D. Joseph is Russell J. Penrose and Regent Professor of Aerospace Engineering and Mechanics at the University of Minnesota in Minneapolis. He is a member of the National Academy of Sciences and of the National Academy of Engineering.

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