Energy & Fuels 1996, 10, 883-889
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Down-Hole Catalytic Upgrading of Heavy Crude Oil J. G. Weissman,* R. V. Kessler, and R. A. Sawicki Texaco, P.O. Box 509, Beacon, New York 12508
J. D. M. Belgrave, C. J. Laureshen, S. A. Mehta, R. G. Moore, and M. G. Ursenbach Department of Chemical and Petroleum Engineering, The University of Calgary, 2500 University Drive N.W., Calgary, Alberta, Canada T2N 1N4 Received September 18, 1995. Revised Manuscript Received April 11, 1996X
Several processing options have been developed to accomplish near-well-bore in-situ upgrading of heavy crude oils. These processes are designed to pass oil over a fixed bed of catalyst prior to entering the production well, the catalyst being placed by conventional gravel pack methods. The presence of brine and the need to provide heat and reactant gases in a down-hole environment provide challenges not present in conventional processing. These issues were addressed and the processes demonstrated by use of a modified combustion tube apparatus. Middle-Eastern heavy crude oil and the corresponding brine were used at the appropriate reservoir conditions. In-situ combustion was used to generate reactive gases and to drive fluids over a heated sand or catalyst bed, simulating the catalyst contacting portion of the proposed processes. The heavy crude oil was found to be amenable to in-situ combustion at anticipated reservoir conditions, with a relatively low air requirement. Forcing the oil to flow over a heated zone prior to production results in some upgrading of the oil, as compared to the original oil, due to thermal effects. Passing the oil over a hydroprocessing catalyst located in the heated zone results in a product that is significantly upgraded as compared to either the original oil or thermally-processed oil. Catalytic upgrading is due to hydrogenation and results in about a 50% sulfur removal and an 8° API gravity increase. Additionally, the heated catalyst was found to be efficient at converting CO to additional H2. While all of the technologies needed for a successful field trial of in-situ catalytic upgrading exist, a demonstration has yet to be undertaken.
Introduction The world’s supply of crude oil is steadily and inexorably moving toward poorer quality. Additionally, extremely large reserves of heavy crude oil are waiting for exploitation. Producing and marketing this heavy oil remains problematic for many reasons, including low primary or enhanced recovery potential, difficulty in transportation, and inability or unwillingness of most refineries to accept heavy crude oils. Heavy crude oils can be made more acceptable if they can be upgraded prior to reaching today’s conventional refineries. This is commonly practiced in large, capitalintensive processing units, such as the Suncor and Syncrude units in Alberta, or via the H-OIL or LCFINING processes.1 Another alternative is possible, however; this is upgrading the heavy crude oil prior to production and prior to reaching the surface stock tank, either in an oil-bearing reservoir, near a producing well, or in the producing well-bore. A successful in-situ catalytic upgrading project entails several distinct technologies: placement of catalysts in an oil-bearing formation near the well; mobilization of reactants, including the native heavy oil and co-reactants, such * Corresponding author. Current address: P.O. Box 135, Glenham, NY 12527. X Abstract published in Advance ACS Abstracts, May 15, 1996. (1) Solari, R. B.; Vant, T. R. Preprints 14th World Petroleum Congress, Stavanger; John Wiley & Sons: West Sussex, England, 1994; Topic 12.
S0887-0624(95)00181-2 CCC: $12.00
as hydrogen, water, or carbon monoxide, over the catalyst bed; creation of the necessary processing conditions, including sufficient temperatures and pressures to achieve a reasonable catalytic upgrading; and finally, production of the upgraded oil. There have been some attempts reported at in-situ upgrading, taking advantage of the fact that simple thermal processing of crude oil can result in upgrading through visbreaking or thermal cracking.2 Several insitu combustion projects have resulted in production of an upgraded oil, particularly in Venezuela, but also in Louisiana.3,4 A process employing in-situ combustion and heat transfer to upgrade oil, after a soak period, has been described.5 Injection of hydrogen or hydrogen precursors in addition to a heat source has also been proposed. In addition to causing an expansion of the oil in place by dissolving into the oil, H2 can migrate into the tightest pores; as reservoir pressure is drawn down, the compressed gas and oil expands, producing more oil and, in the process, heating the oil, which (2) Speight, J. G. The Chemistry and Technology of Petroleum, 2nd ed.; Marcel Dekker, Inc.: New York, 1991. (3) Villalba, M.; Estrada, M.; Bolivar, J. U.S. Dept. of Energy DOE CONF-940450, April 1994, Paper ISC 5. (4) Dean, D. M.; Pusch, W. H. Bodcau In-Situ Combustion Project Final Report, June 1976-June 1982, U. S. Dept. of Energy ET-120579, December 1982. (5) Leaute, R. P. Recovery and Upgrading of Hydrocarbons Utilizing In Situ Combustion and Horizontal Wells. Canadian Patent Application 2,058,255 to Esso Resources Canada Limited, June 1993.
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lowers viscosity due to heat of expansion.6 Hydrogen may also chemically upgrade oil under in-situ conditions, using metals in the oil or rock surfaces as catalysts to assist in the hydrogenation reaction. One means of achieving this is to inject liquid-phase hydrogen precursors into a steam flood;7 thus, oil can be upgraded by asphaltene removal and hydrogenation. Reactivity at reservoir temperatures has been claimed;8 one year at 35 °C was extrapolated to be equivalent to 1 h of reaction conducted at 400 °C. Downhole gasifiers have been proposed as a means to generate reactive gases and high-quality steam; in addition to beneficially increasing oil production, reactivity of H2 and CO2 with the oil, in the presence of minerals and oil containing metals, is claimed.9 A hydrogenation process employing heat remaining in a postcombustion burned region involves terminating a forward combustion process, injection of hydrogen, and then injection of a fluid into the former production well to drive the hydrogen bearing oil over the heated zone, thus effecting hydrogenation prior to production.10 A similar process calls for direct injection of heated solvent and hydrogen into a heavy crude, coal, bitumen, or oil shale deposit, shutting in for a certain time, and then producing upgraded product from the same well;11 however, the results presented are consistent with thermal upgrading and not hydrogenation. Alternately, heat can be derived from a terminated in-situ combustion completed at the base of a petroleum reservoir; after shutting in, gravity drainage into the heated zone and thermal upgrading occurs.12 A similar field project was undertaken in Venezuela. An in-situ combustion was conducted to sufficiently heat a volume of reservoir to about 450 °C, then extinguished, followed by hydrogen injection; after shutting in for 48 h, upgraded oil was produced through the injection well.13,14 Primary production produced 5% of the original oil in place, having 9.9° API and 5.88 wt % sulfur. The upgrading process produced an additional 15% of the original oil at 14° API and 5.0 wt % sulfur. The presence of a high concentration of indigenous metals (the oil contains 1260 ppm V, 105 ppm Ni, and 11 ppm Fe) is claimed to give a catalytic effect, leading to hydrogenation; but the relatively small change in sulfur suggests that the upgrading was due to processing over a heated zone and not hydrogenation. That none of these processes were successful can be attributed to inappropriate attempts at catalytic processing due to poor contacting between oil, hydrogen, or catalyst, limited supplies of heat, or the absence of (6) Magnie, R. L. Recovery of Crude Oil Utilizing Hydrogen. U.S. Patent 4,241,790, December 1980. (7) Hewgill, G. S.; Kalfayan, L. J. Enhanced Oil Recovery Technique Using Hydrogen Precursors. U.S. Patent 5,105,887 to Union Oil Co. of California, April 1992. (8) Hoffman, E. J. Energy Sources 1989, 11, 263. (9) Gondouin, M. Heavy Oil Recovery Process. U.S. Patent 4,706,751 to S-Cal Research Corp., November 1987. (10) Ware, C. H.; Rose, L. C. Recovery of Oil By In Situ Combustion Followed By In Situ Hydrogenation. U.S. Patent 4,691,771 to WorldEnergy Systems Inc., Sepember 1987. (11) Gregoli, A. A. Method of In Situ Hydrogenation of Carbonaceous Material. U.S. Patent 4,501,445 to Cities Service Co., February 1985. (12) Gregoli, A. A.; Oko, U. M.; Leder, F. Process For Converting Heavy Crudes, Tars, and Bitumens to Lighter Products in the Presence of Brine at Super Critical Conditions. U.S. Patent 4,818,370 to Cities Service Oil and Gas Co., April 1989. (13) Stine, L. O. Method for In Situ Conversion of Hydrocarbonaceous Oil. U.S. Patent 4,444,257 to UOP Inc., April 1984. (14) Stine, L. O. In Situ Conversion of Hydrocarbonaceous Oil. U.S. Patent 4,448,251 to UOP Inc., May 1984.
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an effective catalyst. A more deliberate use of appropriate catalysts may result in improve in-situ upgrading. Heterogeneous catalyst compositions found effective for conventional upgrading of heavy oils, including heavy crude oil, vacuum residual oil, and similar heavy petroleum fractions, should be applicable for in-situ upgrading. Catalysts for these applications are wellknown and are used in large quantities in the refining industry, in processes including hydrotreating and hydrocracking, and in ebullated bed hydroprocessing reactors.2 However, for in-situ upgrading, these catalysts will be deployed into an environment that they were not designed for. Successful processing of heavy crude oils in water or brine, with either H2 or CO, has been demonstrated using either heterogeneous or homogeneous catalysts.15-18 A conventional sulfided NiMo/Al2O3 hydrotreating catalyst was found to be useful for processing of oils in water, but at a diminished activity;19 thus, conventional hydroprocessing catalysts may be suitable provided sufficient volumes can be provided. Several processing options can be conceived to accomplish near well-bore in-situ upgrading, in which oil is passed over a fixed bed of catalyst, the catalyst being placed by conventional gravel pack or proppant injection methods. As most heavy oil reservoirs have a matrix consisting of unconsolidated sand, gravel packing is a necessary step in order to prevent erosion and excessive sand production. Catalysts are commonly produced in size ranges similar to that used in gravel packing or proppant injection. In addition to heavy crude oil, the catalyst is exposed to formation brine. The presence of brine and the need to provide heat and reactant gases in a down-hole environment present challenges not present in conventional processing. The proposed processes are described in Figures 1, 2, and 3. In-situ processing has several advantages over conventional surface upgrading technology. Firstly, in-situ upgrading can be applied on a well-by-well basis, so that large volumes of production needed for surface processes are not required. In-situ processes can easily be adjusted to take into account declining production rates. There is no need to build large, costly pressure vessels, as the reservoir formation serves as the reactor. Insitu upgrading can be applied both on land and offshore, in remote locations, and in places where a surface upgrader would be inappropriate. In-situ processing also differs from conventional surface processes in that full-range whole crude oils are treated, and not specific boiling range fractions as is commonly done in refineries. Reactants such a hydrogen or synthesis gas can be injected into the production well, so as to pass over a catalyst bed, or generated by in-situ combustion or thermal decomposition of the heavy oil in place. Pro(15) Stapp, P. R. In Situ Hydrogenation; National Institute for Petroleum and Energy Research; IIT Research Institute, Bartlesville, OK, 1989; NIPER-434. (16) Ng, F. T. T.; Tsakini, S. K. Upgrading Crude Oil Emulsions. U.S. Patent 5,055,175 to University of Waterloo, October 1991. (17) de Bruijn, T. J. W.; Patmore, D. J.; Hogan, C. M. Upgrading Oil Emulsions with Carbon Monoxide or Synthesis Gas. Canadian Patent Appl. 2,103,508, February 1994. (18) Johnson, H. S.; Bright, A. Upgrading of Heavy Hydrocarbonaceous Oil Using Carbon Monoxide and Steam. Canadian Patent 1,195,639 to Gulf Canada Limited, October 1985. (19) Laurent, E; Delmon, B. In Catalyst Deactivation 1994; Delmon, B., Froment, G. F., Eds.; Elsevier: Amsterdam, 1994; p 459.
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Figure 1. Diagram of a “burn and turn” in-situ catalytic upgrading production scheme. In the top part of the figure, air or a combustion-supporting gas is injected and a dry or wet combustion initiated in the oil-saturated catalyst bed; as the burn proceeds, the area adjacent to the well is heated. In the lower part of the figure, the well is brought onto production, reservoir fluids and combustion gases pass over the heated catalyst, and the produced oil is upgraded. Injection/production cycling is repeated to maintain the heated catalyst bed and remove coke deposits.
Figure 2. Diagram of a combustion-assisted in-situ catalytic upgrading production scheme. A dry or wet combustion is used to drive reservoir fluids and combustion gases over a catalyst bed located near a production well. The catalyst bed can be heated by thermal override from the combustion front or by down-hole electrical, steam, or gasification methods.
duction of CO and H2 by the latter processes has been demonstrated.9,15,20,21 While in-situ combustion with thermal override may provide sufficient heat, several electrical down-hole heating schemes have recently been successfully demonstrated from technological and economic standpoints.22-24 One drawback of electric heating, distribution of heat through an entire formation, (20) Joseph, C.; Jay, C. B.; Eslinger, E. V.; Mundis, C. J. J. Pet. Technol. 1983, 827. (21) Greidanus, J. W.; MacDonald, D. D.; Hyne, J. B. Spec. Vol.sCan. Inst. Min. Metall. 1977, 17, 162. (22) Kasevich, R. S.; Price, S. L.; Faust, D. L.; Fontaine, M. F. 69th Soc. Pet. Eng. Tech. Conf. Proc. 1994, 2, 105-118. (23) Vossoughi, S.; Sarapuu, E.; Crowther, R. H. 69th Soc. Pet. Eng. Tech. Conf. Proc. 1994, 2, 119-134.
is not an issue for in-situ catalytic upgrading, as electrical heating is ideally suited toward providing large quantities of heat close to a well, where a catalyst bed will be placed. Electrical heating has another advantage in that no heat carrying fluids need to be injected into a producing well, eliminating a possible counter-driving force toward reservoir fluid flow into the producing well. The three illustrated processes were demonstrated by use of a modified combustion tube apparatus. A heavy (24) Yu, C. L.; McGee, B. C. W.; Chute, F. S.; Vermeulen, F. E. Electromagnetic Reservoir Heating With Vertical Well Supply and Horizontal Well Return Electrodes. U.S. Patent 5,339,898 to Texaco Canada Petroleum, Inc., August 1994.
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Weissman et al. Table 1. Initial Core Pack Properties run 1
porosity (%) SO, oil satn (vol %) SW, water satn (vol %) SG, gas satn (vol %) oil loaded (g) water loaded (g)
run 2
oil satd section
entire core
oil satd section
entire core
41 64 17 19 2675 718
40 49 32 19 2675 1791
40 67 17 16 2807 726
2807 1846
Experimental Section
Figure 3. Diagram of in-situ catalytic upgrading scheme with down-hole injection processing. Hot gases or steam can be injected into a catalyst bed, or down-hole electric heating or combustion can be employed to heat the catalyst bed. Optionally, hydrogen or other upgrading gases can also be injected. Reservoir fluids pass over the heated catalyst zone and contact injected hydrogen; the oil is then upgraded prior to production.
Middle-Eastern crude oil and the corresponding brine were used as fluids. A normal dry combustion was used to generate reactive gases and to drive fluids over a heated catalyst bed. Produced gas and oil samples were periodically collected during the run and analyzed to assess the degree of upgrading. An additional run was completed, replacing the catalyst with a sand pack, to evaluate any upgrading due to thermal processing. While past experience has shown that results of laboratory combustion tube experiments can predict field combustion behavior with considerable certainty,25 how the complication that the presence of a catalyst bed and reactive zone will have on this record of laboratory modeling is uncertain. Additional aspects of this work have examined the effectiveness of conventional hydroprocessing catalysts in upgrading heavy crude oil and on the kinetics of the upgrading reactions.26 Catalysts tested using both batch and continuous flow apparatus found that sulfur removal rates, which behaved according to first-order kinetics, were primarily a function of the reactivity of the sulfur in the feed; no differentiation between catalyst compositions, in terms of upgrading effectiveness, was noted. Additionally, contact times required to achieve a reasonable degree of upgrading are feasible when considering typical heavy oil production rates and volumes of catalyst that can be injected near a production well. A more detailed analysis of the combustion process described here and analysis of the produced oil and gas has now been collected and recently reported.27 (25) Field Application of In Situ CombustionsPast Performance/ Future Application; Olsen, D., Sarathi, P., Eds.; U.S. Department of Energy, 1994; DOE CONF-940450. (26) Weissman, J. G.; Kessler, R. V. Appl. Catal. A 1996, in press. (27) Weissman, J. G.; Kessler, R. V.; Belgrave, B. D. M.; Laureshen, C. J.; Mehta, S. A.; Moore, R. G.; Ursenbach, M. G. J. Can. Pet. Technol. 1996, in press.
The combustion tube apparatus consists of a 72-in.-long by 4-in.-diameter thin-walled tube held inside a larger pressure vessel; the pressure between the combustion tube interior and exterior is kept equalized. The tube is partitioned into 12 6-in. zones, each zone provided with an independently controlled band heater, an exterior thermocouple, and a center-line thermocouple. The center-line thermocouples are placed radially via welded fittings on the tube sides, as an axial thermowell may disrupt flow patterns. Reservoir zones ahead of the flame front were maintained at set point temperatures measured at the centerline thermocouple. As the flame front approached, temperature control for each zone was switched to an adiabatic mode in which the centerline temperatures were used to adjust the wall readings. As the flame front progressed past a zone, the difference between the wall and center temperatures was adjusted to allow for cooling. Simulated core material was 25/40 mesh silica sand from AGSCO Corp. of Wheeling, IL. Brine composition was 873 ppm Ca2+, 248 ppm Mg2+, 783 ppm Na+, 1871 ppm HCO3-, 1098 ppm Cl-, and 1750 ppm SO42-. Synthetic brine was prepared just prior to core packing. The core material was premixed by hand to the appropriate oil and water saturations, then tamped into the core holder, starting at the injection end, in 1-kg batches. Core pack properties are listed in Table 1; the water/oil ratio is about 26:100. The first and last 25 mm of the core were packed with 16 mesh silica frac sand to provide for better flow distribution. The last three zones, closest to the production end, except for the final 25 mm frac sand portion, were packed with either sand (run 1) or a 50/50 v/v mixture of sand and catalyst (run 2), in either case saturated to total core pack fluid saturation (SO + SW) with brine. The catalyst used was fresh alumina-supported nickel molybdenum 1/16-in. extrudates, specified for heavy oil hydroprocessing. The catalyst was diluted to insure better oil/catalyst contacting and to minimize wall effects. The combustion was conducted such that the produced fluids and combustion gases would pass over the heated catalyst or sand interval located in the three zones closest to the production end. A processing temperature of 325 °C was used to insure sufficient catalyst activity for observable upgrading. The burn was stopped before the flame front could enter the heated zones. Both runs were conducted identically. Initial reservoir conditions were taken to be 36 °C and 1500 psia (10.3 MPa). The core was initially pressurized with helium to 1500 psia, and the first nine zones were heated to reservoir temperature prior to continuous helium injection. Helium injection, at a rate of 202 standard L/h, occurred from about -3 to 0 h, in part to flush air out of the core. The last three zones, containing catalyst or sand, were preheated to 325 °C over about a 5-h period, reaching temperature at 0 h. The igniter heaters were raised to 400 °C starting at about -2.0 h. At 0 h, the flow of helium was stopped and flow of normal air begun, at a rate of 195 standard L/h, until about 8.2 h. Air flow was terminated and helium injected for an additional 3 h to purge the core and production lines. A summary of gas injection and production is listed in Table 2. Produced gas was analyzed by an on-line gas chromatograph. Liquid product samples were periodically collected; water was separated from
Down-Hole Catalytic Upgrading of Heavy Crude Oil Table 2. Volumetric Summary of Injected and Produced Gases run 1
run 2
time of initial helium injection (h) time of air injection (h) time of helium purge (h)
-2.92 0.0 8.35
-2.52 0.0 8.17
helium required for pressurization (std L) helium injected (std L) oxygen injected (std L) nitrogen injected (std L)
349 1187 358 1268
349 1167 325 1266
total volume, injected gas (std L) total volume, produced gas (std L) volume recovered (%)
3162 3103 98
3107 3259 105
Table 3. Summary of Stabilized Combustion Parametersa run 1
run 2
air/fuel ratio air flux (m3 (std)/m3) combustion front velocity (m/h)
10.6 25.1 0.15
10.7 25.1 0.15
air required (m3 (std)/m2h) fuel required (kg/m3)
168 15.9
163 15.3
oxygen utilization (%) conversion of reacted O2 to COx (%) (CO2+CO)/CO ratio (CO2+CO)/N2 ratio
97 71 6.1 0.21
99 87 340. 0.22
(m3 (std)/kg)
aAveraged
over the air injection time interval.
oil by centrifugation. Produced oil density was measured at 25 °C and analyzed for sulfur and metals content by X-ray fluorescence (XRF), nitrogen content by pyrolysis, asphaltene content by heptane precipitation, hydrocarbon molecular type by 13C NMR, boiling point distribution by ASTM D2887 simulated distillation, and viscosity at 40 °C.
Results The progress of the two runs was nearly identically. The combustion proceeded smoothly with excellent burn performance and relatively low air requirements. The onset of low-temperature oxidation, at 250 °C, and hightemperature oxidation, at 450 °C, occurred at nearly the same times in both runs. A summary of produced gas volumes and combustion parameters are given in Table 2 and Table 3. The excessive volume of gas recovered in run 2 may be due to gas or water vapor contained in the pores of the catalyst. Both runs ran at 1500 psi with no noticeable pressure fluctuations. The same air flux and air/fuel ratio were used in the two runs, the resulting combustion front velocities and air and fuel requirements were almost identical, as these parameters were not affected by the presence of a heated zone at the production end. However, the presence of the catalyst did have an effect on produced gases flowing over the catalyst. While oxygen utilization was slightly increased, conversion of oxygen to CO or CO2 was higher. More importantly, very little CO was produced in the second run, while the total amount of CO and CO2 was nearly constant, as referenced to the constant amount of nitrogen injected. The difference in produced gases, due to the influence of the heated catalyst bed, is more clearly evident from the average produced gas compositions, listed in Table 4. The most significant differences are the much greater amounts of hydrogen and hydrocarbons produced in run 2. Hydrogen production can be attributed, at least in part, to a water-gas shift reaction converting CO to H2; the minimal amount of CO produced in run 2 and the
Energy & Fuels, Vol. 10, No. 4, 1996 887 Table 4. Average Produced Gas Compositiona CO2 CO O2 N2 H2 H2S SO2 COS CH4 C2H4 C2H6 C3H6 C3H8 C4+ total C1-4’s aAveraged
run 1
run 2
14.14 2.77 0.65 80.04 0.24 1.90 0.00 0.00
16.71 0.05 0.27 75.88 3.08 1.81 0.00 0.00
0.12 0.00 0.04 0.04 0.04 0.02 0.26
0.84 0.01 0.47 0.01 0.47 0.39 2.19
over the air-injection time interval, in mol %.
small amount of H2 produced in run 1 supports this assertion. The increased amount of hydrocarbons produced in run 2 can be attributed to catalytic reaction byproducts and hydrocracking. The greater amounts of unsaturated hydrocarbons, particularly propene that were produced in run 1, despite increased overall hydrocarbon production in run 2, is an indication that there was minimal hydrogenation activity in run 1. Although the presence of a catalyst and an increased amount of hydrogen in run 2 should lead to increased amounts of hydrogen sulfide production due to hydrodesulfurization reactions, this was not found to be the case as both runs produced nearly the same amounts of H2S. Further insights into the difference in the gases between the two runs can be obtained by examining cumulative gas productions over the run lengths, as plotted for CO2, CO, H2S, and CH4 in Figure 4. A steady increase in the amounts of gas produced occurs except for the production of H2S in run 2. The behavior of H2S production, as shown in Figure 4, indicates that an adsorption phenomenon may be occurring; once a saturation point is reached, H2S production then occurs. As the catalyst was loaded in an oxide state, H2S is probably consumed in conversion of molybdenum and nickel oxides, contained in the catalyst, to the corresponding sulfides. Less H2S is required as this sulfiding reaction proceeds, and so more H2S is produced. H2S production levels off near the end of the run, at about 8.5 h, as air injection, oil production, and catalyst bed temperatures were all reduced. A very good accounting of both oil and water was made. In both runs 97% of the original oil and 102% of the original water placed in the core were ultimately retrieved. However, less oil was produced and more remained in the core pack in run 2, due to the presence of the highly porous catalyst. Sulfur and API gravity of the produced oil in both runs as a function of run length are plotted in Figure 5. Run 1 oil products had very little gravity change from the original feed, but some decrease in sulfur content. Run 2 oil products showed a significant increase in gravity and a significant decrease in sulfur content. Both of these changes, in run 2, can be attributed to the contacting of the oil with the heated catalyst bed and consequent hydroprocessing reactions. The reduction in sulfur content of produced oil in the first run is due to removal of liable sulfur compounds by thermal or distillative processes.
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Figure 4. Cumulative production, in standard L, of carbon dioxide, carbon monoxide, hydrogen sulfide, and methane, for run 1 (O) and run 2 (b). Table 5. Summary of Combustion Tube Run Resultsa production end pack sulfur (wt %) nitrogen (wt %) asphaltenes (wt %) paraffinic carbon (mol %) aromatic carbon (mol %) viscosity at 40 °C (cP) gravity at 25 °C (°API) sim.-dis. midpoint (°C) Fe + V + Ni (wppm)
crude oil
run 1
run 2
6.33 0.22 10.7 30. 27. 490. 15.3 516 105
sand 4.75 0.20 10.8 33. 29. 269. 15.7 501 113
sand/catalyst 3.09 0.14 3.0 43. 23. 20. 23.2 373 23
27 9 +0.4
51 36 +7.9
sulfur removal (%) nitrogen removal (%) gravity increase (°API)
aValues are weighted averages of samples collected over the air injection time interval.
Figure 5. API gravity and sulfur content of liquid oil products and crude oil feed (solid line) for run 1 (O) and run 2 (b).
Table 5 compares the results of the two runs and corresponding feed properties. While the oil produced in the first run showed some upgrading, due to thermal
changes brought on by contacting with the heated sand pack, the oil produced in the second run was significantly upgraded as compared to both the crude oil feed and the oil produced in the second run. Besides 50% sulfur reduction and 36% nitrogen reduction, API gravity was increased 8°, asphaltene content was significantly reduced, viscosity was greatly lowered, metal content was lowered, more material boiled at a lower temperature, and the amount of aromatic carbon decreased while the amount of paraffinic carbon increased. These last two changes, in particular, strongly indicate that hydrogenation was occurring and that hydrogen addition is the primary underlying mechanism of the changes brought on by contacting the oil with the heated catalyst bed and combustion gases. Conclusions This particular heavy crude oil is amenable to in-situ combustion at anticipated reservoir conditions, such as
Down-Hole Catalytic Upgrading of Heavy Crude Oil
1500 psi total pressure, and at a relatively low air requirements. Forcing the oil to flow over a heated zone prior to production results in some upgrading of the oil, as compared to the original oil, due to thermal effects. Passing the oil over a hydroprocessing catalyst located in the heated zone results in a product that is significantly upgraded as compared to either the original oil or thermally-processed oil. Catalytic upgrading is due to hydrogenation and results in about a 50% sulfur removal and an 8° API gravity increase. Reactive hydrogen is supplied by gases produced by the combustion process, either as hydrogen or carbon monoxide. The heated catalyst was found to be efficient at converting CO to additional H2. The combination of appropriate catalysts and hydrogenative processing conditions results in heavy crude
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oil upgrading that is substantially improved over prior laboratory or field attempts.3-15 In these prior attempts at least one of the necessary processing ingredients, thermal energy, a hydrogen source, catalysts, or efficient oil-catalyst contacting, was absent. We have shown that a correctly deployed combination of ingredients is effective. Use of in-situ combustion to produce reactive gases alleviates the need to inject high-pressure hydrogen or syn-gas into the near-well-bore environment of the producing well. All of the technologies needed for a successful in-situ catalytic upgrading have been demonstratedswhat remains to be done is for these technologies to be brought together into a field pilot project. EF9501814
