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Publication numberUS3442333 A
Publication typeGrant
Publication dateMay 6, 1969
Filing dateOct 11, 1967
Priority dateOct 11, 1967
Publication numberUS 3442333 A, US 3442333A, US-A-3442333, US3442333 A, US3442333A
InventorsMeldau Robert F
Original AssigneePhillips Petroleum Co
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Wellbore visbreaking of heavy crude oils
US 3442333 A
Abstract  available in
Previous page
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Claims  available in
Description  (OCR text may contain errors)

R. F. MELDAU May 6, 1969 WELLBORE VISBREAKING OF HEAVY CRUDE OILS 1967 I of 2 Sheet Filed 001:. ll,



WELLBORE VISBREAKING OE HEAVY CRUDE OILS Filed Oct. 11, 1967 May 6, 1969 Sheet 2 of 2 I 6 4 f3 E FIG. 2

FIG. 3

INVENTOR. R. F. MELDAU A 7' TORNEYS United States Patent 3,442,333 WELLBORE VISBREAKING 0F HEAVY CRUDE OILS Robert F. Meldau, Bartlesville, 0kla., assignor to Phillips Petroleum Company, a corporation of Delaware Filed Oct. 11, 1967, Ser. No. 674,468 Int. Cl. E21b 43/24, 43/00 US. Cl. 166-272 9 Claims ABSTRACT OF THE DISCLOSURE This invention relates to a method of visbreaking and lowering of the sulphur content of heavy crude oil while the oil is passing thru the borehole.

- The desirability of upgrading and reducing the sulphur content of heavy crude oil is well recognized in the art.

It has been found that significant visbreaking and sulphur reduction occurs about 650 F.

The principal object of the invnetion is to provide a process for visbreaking and lowering the sulphur content of a heavy crude oil while traveling thru the borehole to ground level. Another object is to provide a process for upgrading a heavy crude oil in the production borehole utilizing steam for the heating medium and making additional use of the steam and hot condensate in auxiliary oil production. Other objects of the invention will become apparent to one skilled in the art upon consideration of the accompanying disclosure.

A broad aspect of the invention comprises heating a produced oil steam in the borehole either in the tubing or in the tubing-casing annulus at a temperature in the range of 550 to 700 F., for a period of at least 24 hours and up to several days, or a week, so as to visbreak and lower the sulphur content of the crude oil by passing steam in indirect heat exchange with the produced oil thru the wall of the tubing carrying the steam downhole. It is preferred to produce the oil thru the tubing-casing annulus and inject the steam thru the tubing. The rates of flow of oil and steam are controlled so as to subject the oil to a heat treatment in the range of 600 to 700 F. for at least 24 hours. The casing size and the production rate are selected to provide suflicient residence time for the oil. When utilizing a casing having an ID. of 11% inches and a tubing having an CD. of 2% inches with a well depth of about 4000 feet, the volume of oil in the tubing-casing annulus is about 400 bbl. With this arrangement, any production rate of 400 bbl. or less per day provides a 24-hour period of treating the oil in the annulus. In this type of operation, steam at a pressure of at least 2000 p.s.i.g. and at a temperature of at least 640 F. is injected into the tubing string using a choke on the lower end thereof which facilitates maintaining the pressure in the tubing string. The steam condenses at least partially to hot water due to wellbore heat loss, and finally cools to near the producing zone temperature under the counterfiow heat transfer eonditions in the well. After passing thru the choke or back-pressure valve at the bottom of the tubing, the condensate and any remainin steam are forced into a sand in one-days time at temperatures of 3 ,442,333 Patented May 6, 1969 below the producing stratum, preferably an oil sand, to effect a hot fluid drive through the oil sand to one or more offset wells.

It is economically desirable to recover heat from the oil which is produced at the wellhead at a temperature of approximately 650 F., utilizing a heat exchanger aboveground. The feed water to the steam generator is passed thru the heat exchanger to pre-heat same before introduction to the steam generator.

Insulated casing may be utilized to reduce wellbore heat loss and increase the overall heat utilization in the process. The process works more economically in wells which produce with a low water out and/or low gas oil ratio, since water or gas production lowers oil prduction and residence time for given well and given gross fluid production rate.

The invention is readily applicable to a production well leading to a formation or stratum having sufiicient pressure to force the oil up the well. It is also applicable to oil production from wells in which pumping is required but specific novel techniques are required in this type of application.

A more comlete understanding of the invention may be had by reference to the accompanying schematic drawing of which FIGURE 1 is a flow scheme and arrangement of apparatus connected with a well extending to a producing formation; FIGURE 2 is a similar view of a well and downhole equipment for producing b pumping while heating the oil in the well; FIGURE 3 is a similar view to that of FIGURE 2 utilizing a different arrangement; and FIGURE 4 is also similar to FIGURE 2 but showing a different arrangement of apparatus to permit a different technique of operation.

Referring to FIGURE 1, an upper oil sand 10 and a lower oil sand 12 are penetrated by a well 14 provided with a casing 16 covered with insulation 17 and a tubing 18. Casing 16 is perforated at 20 into oil sand 10 and at 22 into oil sand 12. A packer 24 seals off the annulus 26 intermediate the two oil strata. A retrievable choke or back-pressure valve 28 is positioned on the lower end of the tubing for controlling steam pressure within the tubmg.

Above ground, an oil production line 30 connects with the annulus at the wellhead and passes thru an indirect heat exchanger 32 for pre-heating water passing to boiler 34 from line 36. The steam from boiler 34 passes via line 38 into tubing 18. Line 40 provides for withdrawal of any or all of the oil produced in line 30 without passing thru the heat exchanger. 7

Referring to FIGURE 2, well 14 passes thru stratum 10 containing the oil to be produced. Tubing string 18 is provided with a pump downhole and the annlus is sealed by packer 44 postioned above the upper level of stratum 10. Pump rod 46 within tubing 18 operates the. pump 42 and passes thru packing material 48 which seals the annulus around the pump rod. Crossover 50 is positioned in the tubing 18 intermediate packer 44'and packing material 48 to provide a flow path for the oil passing up the tubing and into the surrounding annulus thru the crossover. A separate pipe string 52 extends from the wellhead to a level adjacent packing material 48 and is connected thru a side vent with the tubing just above packing material 48. A choke or back-pressure device 54 is positioned in the lower end of pipe string 52.

In the arrangement shown in FIGURE 3, two packers are utilized, packer 24 being positioned intermediate the two oil strata 10 and 12 and packer 44 being positioned above the upper level of the upper stratum. Cnossover 50 is positioned above the upper packer so that pump 42 pumps well fluids from oil sand 10 into annulus 26 above the packer as in the structure in FIGURE 2. Steam in- 3 jection tubing 52 in the arrangement shown passes thru both packers 44 and 24 and is provided with a choke 54 for control of the pressure in the injection tubing.

In FIGURE 4 the arrangement is similar to that in FIGURES 2 and 3 except for the arrangement for injected down the annulus using a tubing-casing'packer with a choke or back-pressure valve to maintain pressure in the annulus. It is also feasible to inject condensate into a disposal sand above the oil stratum. It is also feasible to control the back pressure on the condensate or steam jecting steam. Instead of injecting steam thru a separate 5 injected into the lower sand :by adding a plugging agent tuging, stegim isc1 injected thll'lll kthel tujbing 18 containing :2 the injected stezlani1 whiclh effects partial plugging of re 46 an a si e vent or c o e ea s into pipe 60 just e stratum aroun t e we above packing material 48, any uncondensed steamand Visbreaking is ordinarily conducted at temperatures condlensate passing to rfecovecgy at the wellheald. bl above 7 I0l0liF. flIllld up to 1d200 F. vlvlith very shortbcontact T e arrangement 0 PI URE 1 is app ica e to a times. n er t ese con itions, t ere is a su stantia production well penetrating a stratus under suflicient amount of conversion to coke. The present invention utipressure to force oil up the well to the wellheag. In oplizesdtemlperzttures which require longer contact times but eration with the arrangement illustrated in PI URE 1, avoi co e ormation. oil flowing from stratum 10 is forced by stratum pressure The following specific example illustrates the invenu ggrdtd fthr anfimlus 2fl6 to plifducljiiOn line 30 lit the tion but is not to be construed as unnecessarily limiting we ea rom w ich it ow eit er t In heat exc anger it.

32 or thru line 40 to further processing. Water from line 36 is pre-heated in exchanger 32 with the hot produced EXAMPLE oil and is then introduced to boiler 34 for conversion to Tests were run on Group I and Group III Morichal steam at an elevated pressure in the range of about 1000 crude oils in a 600 ml. pressure vessel under selected conto 3000 p .s.1.g. or higher. The steam injected from boiler ditions. Run conditions and data obtained are shown in 34 thru line 38 into tubing 18 heats the oil in the surthe table below.

TABLE Reaction conditions Oil viscosity, Sulfur content. up. at 122 F. weight percent ime Temp. Pressure 011 used (hr.) F.) (p.s.i.g.) Original Treated Original Treated Group I 336 550 1,730 632 1.6 336 600 2,10 1.7 Group II.-. 312 600 2, 000 8850 3. 5 .312 600 15 3.1 168 600 15 3.1

rounding annulus thru the wall of the tubing with ade- The vest improvement in viscosity and substantial requate back pressure maintained by choke 28 at the lower duction in sulfur content were produced without any end of the tubing. Condensate and uncondensed steam coking of the oil. egress from the bottomof the tubing and enter oil sand In the various arrangements shown in the various fig- 12 thru perforation 22. The rate of steam injection can ures of the drawings, an expansion joint (not shown) is be suflicient to effect a hot fluid drive in oil sand 12 to used between the packer and the tubing extending thru a ring of surrounding product on wells. The temperature 40 the packer. I t of the in ected steam is sufliciently elevated to heat the Certain modlfications of the invention will become apoil in the surrounding annulus to a temperature in the parent to those skilled in the art and the illustrative derange of about 600 to 700 F. The flow of oil thru line tails disclosed are not to be construed as imposing un- 30 is regulated to provide the required heating period of necessary limitations on the invention. at least 24 hours of the oil ascending well 14. I claim:

The arrangements illustrated in FIGURES 2, 3, and 4 1. A process for producing and visbreaking crude oil are utilized in production wells in which the formation from an oil stratum penetrated by a production well propressure 1s insuflicient to force the oil to the wellhead. vided with a casing and a tubing extending substantlally In the arrangement of FIGURE 2 oil is pumped by to said stratum which comprises the steps: means of pump 42 positioned below packer 44 upwardly (a) producing liquid crude oil from said stratum thru thru a short section of tubing to crossover thru which 50 one of said tubing and the casing-tubing annulus; the oil passes into the annulus between the casing and (b) passing steam. thru the other of said tubing and tubing. As the oil ascends the annulus, it is heated by said annulus from the wellhead at an elevated temsteam injected thru separate tubing 52 and vented into perature and pressure sufficient to heat said oil to tubing 18 above packing 48 thru choke 54. This arrangea temperature in the range of 550 to 700 F; ment avoids mixing the steam and condensate with the 55 (c) regulating the flow rate of said oil and said steam produced oil, the steam and condensate being produced so as to hold said oil at said temperature within said thru the tubing at the wellhead. well for at least 24 hours to eflect substantial vis- With the arrangement illustrated in FIGURE 3, the breaking thereofand Oil is P P in the Same manner in R (d) recovering the upgraded oil from the preceding ascending the annulus 26 around tubing 18 containing Steps the pump rod and also around slteam in ection tu 2. The process of claim 1 including the step of:

52 A ii g g l dc g k (e) passing hot aqueous fluid comprising said steam g z g i f p a and water condensed therefrom from the lower end a o nve 1S emg on u o r mg of said well into a second stratum.

Operation with the arrangement illustrated in FIG- iii i f clam 2 i 2 second iratum URE 4 is similar to that in FIGURE 2, the difference be 15 01 Pi i 6 Steps 0 ing in the injection of steamthru tubing 18 carrying (f) dnvmg aqueous fimd toward offset Well the pump rod and recovery of the condensate and unconto saldsecond Stratum on P g -$1 t p 1 t g i g g 1 g (gzvgelcovering said second stratum oil from said oflset easl e o simp y ven con ensa e an unc n ense steam thru a choke in the wall of tubing 18 above pack- 4. The process of claim 1 wherein oil produced thru ing 48 and produce these fluids with the produced oil. said annulus in step (a), said annulus is packed off inter- In another arrangement not shown, hot oil and conmediate said stratum and a second lower permeable stradensed water are pumped up the tubing and steam is inturn, and passing from said tubing aqueous fluid comprising said steam and water condensed therefrom into said second stratum.

5. The process of claim 4 wherein said second stratum contains oil and said aqueous fluid from the lower end of said tubing passing into said second stratum drives second stratum oil into an offset well.

6. The process of claim 1 wherein said oil requires pumping, the tubing-casing annulus is packed off adjacent the upper level of said stratum, said tubing is provided with a rod and pump and with a crossover above the packed-oft area, and oil is pumped from below said packed-oil area thru the lower end of said tubing thru said crossover into and up said annulus, said steam being injected thru a separate tubing to a level adjacent said crossover thence into said first-mentioned tubing above said crossover and passed therethrough to the Wellhead.

7. The process of claim 1 wherein said oil requires pumping, the tubing-casing annulus is packed off adjacent the upper level of said stratum and intermediate said stratum and a subjacent permeable stratum, said tubing is provided with pumping means on its lower end intermediate the packed-oif areas and with a crossover above the upper packed-off area to pump oil into and thru said annulus to the wellhead, and steam is passed thru a separate tubing extending from the wellhead thru both packedolf areas to said subjacent stratum.

8. The process of claim 1 wherein said oil requires pumping, a packer is set on said tubing above said stratum sealing off the casing-tubing annulus, a crossover is positioned in said tubing above said packer, pumping means including a rod and pump are positioned on the lower end of said tubing to pump oil up said tubing thru said crossover and up said annulus to wellhead; rod packing is positioned in said tubing to seal the rod-tubing annulus above said crossover and a side vent and choke are positioned above said packing, steam being passed down said tubing to said side vent and thru said choke for returning to the wellhead thru the tubing-casing annulus in admixture with said produced oil.

9'. The process of claim 1 wherein said crude oil contains a substantial concentration of sulfur and said concentration is materially reduced by said process.

References Cited UNITED STATES PATENTS Re. 25,918 11/1965 Craig et a1 16640 56,989 8/1966 Phleger et a1. 16640 3,284,281 11/1966 Thomas 166-11 X 3,294,167 12/1966 Vogel 166-11 3,323,590 6/1967 Gilchrist et al.- 166-1l 3,379,247 4/ 1968 Santourian 166-l1 CHARLES E. O CONNELL, Primary Examiner. IAN A. CALVERT, Assistant Examiner.

US. Cl. X.R. 166315

Patent Citations
Cited PatentFiling datePublication dateApplicantTitle
US56989 *Aug 7, 1866 Improvement in obtaining oil from wells
US3284281 *Aug 31, 1964Nov 8, 1966Phillips Petroleum CoProduction of oil from oil shale through fractures
US3294167 *Apr 13, 1964Dec 27, 1966Shell Oil CoThermal oil recovery
US3323590 *Oct 28, 1964Jun 6, 1967Phillips Petroleum CoMultiple zone production drive process
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Referenced by
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US4778586 *Jun 5, 1987Oct 18, 1988Resource Technology AssociatesViscosity reduction processing at elevated pressure
US4818371 *Jun 5, 1987Apr 4, 1989Resource Technology AssociatesViscosity reduction by direct oxidative heating
US4913236 *Feb 3, 1989Apr 3, 1990Chevron Research CompanyMethod for inhibiting silica dissolution using phase separation during oil well steam injection
US5008085 *Mar 31, 1989Apr 16, 1991Resource Technology AssociatesApparatus for thermal treatment of a hydrocarbon stream
US5520247 *Mar 10, 1995May 28, 1996Shell Oil CompanyMethod of producing a fluid from an earth formation
US7793716 *Mar 15, 2007Sep 14, 2010Bj Services Company, U.S.A.Apparatus and methods for limiting debris flow back into an underground base pipe of an injection well
US8240374Aug 10, 2010Aug 14, 2012Superior Energy Services, L.L.C.Apparatus and methods for limiting debris flow back into an underground base pipe of an injection well
US8973658Mar 2, 2012Mar 10, 2015Conocophillips CompanyHeat recovery method for wellpad SAGD steam generation
US20070246226 *Mar 15, 2007Oct 25, 2007Bj Services CompanyApparatus and methods for limiting debris flow back into an underground base pipe of an injection well
US20100300692 *Aug 10, 2010Dec 2, 2010Bj Services Company, U.S.A.Apparatus and methods for limiting debris flow back into an underground base pipe of an injection well
WO2012122041A2 *Mar 2, 2012Sep 13, 2012Conocophillips CompanyHeat recovery method for wellpad sagd steam generation
WO2012122041A3 *Mar 2, 2012Aug 15, 2013Conocophillips CompanyHeat recovery method for wellpad sagd steam generation
U.S. Classification166/272.3, 166/369
International ClassificationE21B36/00, E21B43/24, E21B43/16
Cooperative ClassificationE21B36/00, E21B43/24, E21B36/003
European ClassificationE21B43/24, E21B36/00C, E21B36/00