|Publication number||US3454365 A|
|Publication date||Jul 8, 1969|
|Filing date||Feb 18, 1966|
|Priority date||Feb 18, 1966|
|Publication number||US 3454365 A, US 3454365A, US-A-3454365, US3454365 A, US3454365A|
|Inventors||Lumpkin William B, Meldau Robert F|
|Original Assignee||Phillips Petroleum Co|
|Export Citation||BiBTeX, EndNote, RefMan|
|Patent Citations (5), Referenced by (54), Classifications (19)|
|External Links: USPTO, USPTO Assignment, Espacenet|
y 3, 1969 w. B. LUMPKIN ET AL 3,454,365
ANALYSIS AND CONTROL OF IN SITU COMBUSTION OF UNDERGROUND CARBONACEOUS DEPOSIT Filed Feb. 18, 1966 KMQKOUMI OP a 255 m0 SE28 v F a .r mwtizou mm N NE 3.x J v9 2 mm. jwudzou 5-5 z w 3 25mg 2856 H mm wl L ow omgz m mm 2 P2w OF INVENTORS w. B. LUMPKIN R. F. MELDAU United States Patent US. Cl. 23-230 8 Claims ABSTRACT OF THE DISCLOSURE A method and apparatus for analyzing a gas stream from an underground in situ combustion process to provide one or more parameters for indicating the conditions in the combustion zone and facilitating control of the combustion operation.
This invention relates to an arrangement of apparatus and a process for analyzing the efiluent gas from the in situ combustion of an underground carbonaceous deposit and to the control of the in situ combustion process in response to the analysis obtained.
The production of oil from underground carbonaceous deposits by in situ combustion is an accepted practice in the petroleum industry. In this type of process, a combustion zone is established around an ignition well by any suitable method and the resulting combustion zone is caused to move thru the deposit either by direct injection of air thru the ignition well or by injection of air thru one or more ofiset wells to move the combustion zone countercurrently to the flow of air thru the deposit. One application of the process of producing oil by in situ combustion is in a sand containing a highly viscous crude oil, although the in situ combustion is applicable to either primary, secondary, or tertiary recovery operations in practically any type of stratum including tar sands, shale, and oil reservoirs.
In most applications, in situ combustion operation upgrades the crude oil or other carbonaceous material by in situ cracking. The instant invention provides an arrangement of apparatus and a process for determining the character of the effiuent gas from an in situ combustion operation and monitoring or controlling the process in response to the character of the product efiluent.
Accordingly, it is an object of the invention to provide a process and system for analyzing a produced gas stream from a carbonaceous deposit undergoing in situ combustion in order to provide one or more parameters for indicating the conditions in the combustion zone and facilitating control of the in situ combustion operation. Another object is to provide a process and arrangement of apparatus for determining selected characteristics of 21 produced gas stream from the in situ combustion of subterranean carbonaceous material. A further object is to provide a process and apparatus for determining the concentration of at least one of oxygen, carbon dioxide, hydrogen, and hydrocarbons in the effluent gas from the in situ combustion of a carbonaceous deposit as an indication of the nature of the in situ combustion. 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 withdrawing a small sample stream from the produced hot effluent from in situ combustion of a carbonaceous deposit, treating the sample stream to reduce the temperature and pressure thereof, remove condensed liquids, and dry the 3,454,365 Patented July 8, 1969 same, and metering a portion of the treated sample to one or more instruments including an oxygen analyzer, thermal conductivity cell, and a chromatographic analyzer to obtain parameters which indicate the characteristics of the combustion. A hydrogen detector may also be utilized to determine the H concentration in the eflluent as an indication of the extent of cracking. The oxygen concentration is, of course, determined by an oxygen analyzer as an indication of the amount of 0 bypassing the combustion zone or appearing in the eflluent gas due to a low combustion rate. The concentration of hydrocarbons and CO in the produced efiluent is determined by the thermal conductivity cell and chromatograph in known manner. Also, the chromatograph is used to determine the C -C hydrocarbon concentration in the production stream.
In one aspect of the invention, the signal from various instruments are rationalized thru a control computer which puts out a control signal and/or a print out for use in controlling the air injection rate and/or the production rate at the production well head to maintain an optimum utilization of the oxygen in the air stream and to optimize the in situ cracking process. In instances in which the combustion rate drops below a desired level as indicated by the monitoring instruments, a secondary signal may be used to inject supplementary fuel (such as methane, propane, or LP gas) to raise the combustion rate and temperature level within the carbonaceous deposit to restore optimum concentrations of the various constituents in the production stream.
A more complete understanding of the invention may be had by reference to the accompanying schematic drawing which is a flow and arrangement of apparatus in accordance with the invention.
Referring to the drawing, a carbonaceous stratum 10 is penetrated by a production well 12 and an injection well 14. Air is injected into well 14 thru line 16 and tubing stream 18 under the impetus of blowers or compressors 20. Well 12 is provided with production tubing 22, which connects with production line 24, and with water injection line 26 for controlling the temperature within the production well below ignition temperature of the produced hydrocarbons at the oxygen concentration existing in the produced gases. Usually, the temperature is maintained below about 550 or 600 F.
Production line 24 leads into sand trap 28, which drops out any sand in the produced stream thru line 30 and removes any liquid product thru line 32, the overhead gas stream passing thru line 34 to recovery equipment not shown.
A small sample stream is recovered at sample point 36 and is passed thru line 38 and condenser 40 therein to line 42, from which a selected portion passes to separator 44 and the remaining portion passes to line 34 via line 45. Condensed liquids in condenser 40, such as light oils and water, are recovered thru line 46. The cooled gas is metered at a selected rate thru meter 48 in line 50, the remaining gas being passed thru line 52 into line 34.
The sample gas stream from line passes into line 54, a portion of this stream being passed thru pressure regulator 56 to reduce the pressure to a selected value suitable for the downstream instruments and the remaining portion being passed via line 57 to line 34. The gas in line 54 passing thru pressure regulator 56 also passes thru a cooler or condenser 58 and a filter and liquid trap 60 from which liquid is vented thru line 62. The filtered gas stream is metered by meter 64 to provide a predetermined flow rate of gas for passage to the downstream instruments. This stream of metered gas is passed thru dryer 66 before passing to the downstream instruments. Any excess gas in line 54 downstream of meter 64, when any one of the downstream instruments is not in operation, is returned to line 34 via line 68.
Usually, two or more dryers 66 are positioned in the gas line to provide for regeneration of one dryer while another dryer is on stream. A portion of the dry gas is fed thru meter 70 in line 72 to oxygen analyzer 74 for determination of the oxygen concentration in the sample gas stream. Analyzer 74 is a conventional instrument, commercially, available (such as Beckman O analyzer), and emits a signal thus line 76 which is proportional to the oxygen concentration. In conventional manner, a standard reference gas is passed from any one of cylinders 78, line 80 and branch line 82 into the sample gas stream in line 72 upstream of meter 70. Nitrogen from cylinder 84 may alternatively be passed thru line 86 into the sample gas stream in line 72 in conventional manner.
Another portion of the dry sample gas stream is passed via line 88 and branch line 90 thru meter 92 into thermal conductivity cell 93 along with a standard reference gas introduced thereto from lines 80 and 94. Carrier gas such as helium is passed from storage cylinder 96 thru lines 98 and 100 either into line 90 upstream of meter 92 or thru line 102 directly into thermal conductivity cell 93.
Thermal conductivity cell 93 is a commercially available, conventional instrument, such as a Beckman, and emits a signal thru line 104 proportional to the concentration of CO or hydrocarbons in the sample gas stream, depending upon the reference gas being utilized.
Similarly, a stream of sample gas is passed from line 88 thru line 106 in admixture with a standard reference gas from line 80 thru meter 108 and a constant volume regulator 110 to chromatographic analyzer 112. Helium, as a carrier gas, is also introduced to instrument 112 by line 98, meter 114, and constant volume regulator 116 for admixture with the sample gas in instrument 112. The chromatograph is provided with injection points 118 and 120 for use when injecting a bomb sample or a syringe sample. Vent line 122 contains a sample point 124 for obtaining a syringe sample and sample point 126 for obtaining a bomb sample when such samples and operation are desired.
Chromatographic analyzer 112 is a conventional instrument such as Model 109 manufactured by Phillips Petroleum Company and commercially available. This instrument emits a signal thru line 128 which is proportional to the concentration of hydrocarbons broadly or of a specific range of hydrocarbons in the gas sample, depending upon the reference gas fed to this instrument.
Hydrogen detector 130 is fed a gas sample thru line 132 and nitrogen thru line 134 for determination of the H content of the sample gas. When utilized in the system, a signal proportional to the H content is emitted thru line 136 and may be fed to computer 138 along with the signals from the other instruments. However, this hydrogen detector may be utilized independent of the other analytical instruments.
Any one or all of the signals from instruments 74, 93 and 112 may be fed to computer 138 for obtaining a control signal for operation of the in situ combustion process being effected in stratum 10. The computer may also provide a printout for use in manual control of the in situ combustion process.
Control of the in situ combustion process may be effected by increasing the air input from blowers or compressors 20 as by regulating the valve in line 16 to vary the injection pressure and/or by varying the back pressure in well 12 as by regulating the valve in line 22. It is also feasible to regulate the rate of introduction of water as a coolant in well 12 of regulating the valve in line 26.
Methane may be introduced .thru line 140 when desired to increase the combustion temperature in response to a need for a higher combustion temperature as indicated by the parameters provided by the analytical instruments.
Since the response to a change in air injection pressure and/or back pressure (changing the air injection rate) in the system is relatively slow, it is usually preferred to space the control signals at certain intervals or to bypass the generated signals until the process has responded to the previous control signal and adjustment as indicated by the monitoring instruments. In an in situ combustion operation in which the response to a change in air injection rate is particularly slow, a printed read out of the parameter combination in line 142 may be provided for an operator who manually adjusts the control valves or other control elements in the apparatus arrangement. The information provided by the several instruments of the disclosed system is particularly useful in the initial phases of the in situ combustion operation when regulation of conditions, particularly of the rate of injection of air, is of primary importance.
In a typical operation, hot production fluid at a temperature of about 500 F. and a pressure of about 1000 p.s.i.g. is passed thru line 24 to the system shown at a rate of about 360,000 standard cubic feet per hour (s.c.f.h.). A small sample of this stream is taken off at point 36. This sample is cooled to a temperature of about 70 F., or roughly room temperature, and reduced in pressure to below about 20 p.s.i.g. downstream of cooler or condenser 58. This cooling and pressure reduction is preferably effected step-wise but may be done in one operation. The sample gas stream is then dried in dryer 66 and passed at a rate of 0.018 to 0.021 standard cubic feet per minute (s.c.f.m.) thru line 72. Of this dry sample gas stream, 0.006 to 0.007 s.c.f.m. is passed to oxygen analyzer 74 in admixture with carrier gas and a standard reference gas. A comparable stream of the sample gas is also passed to thermal conductivity cell 93 in admixture with a carrier gas and a standard reference gas. The fiow rate of sample gas to chromatographic analyzer 112 is controlled within the range of 0.004 to 0.007 s.c.f.m. and this sample gas in admixed with carrier gas and a standard reference gas.
Standard reference gases comprise a combustion gas prepared by burning a sample of the reservoir carbonaceous material or crude oil and recovering the resulting combustion gas as the standard reference gas. Other reference gases comprise normally gaseous hydrocarbons and/or standard mixtures thereof.
Instruments 74 and 93 utilized in one arrangement are Beckman instruments, the chromatograph being a Phillips Model 109 instrument.
Certain modifications of the invention will become apparent to those skilled in the art and the illustrative details disclosed are not to be construed as imposing unnecessary limitations on the invention.
1. A process for analyzing a high temperature and high pressure effluent stream from in situ combination of an oil bearing stratum recovered thru a production well therein which comprises the steps of:
(1) withdrawing a 52111111316 stream from said effluent stream, cooling said sample stream and reducing the pressure thereof to a value siutable for the analyzer instruments mentioned hereinafter;
(2) separating the stream of step (1) into a gaseous stream and a liquid stream;
(3) recovering a minor portion of the gas stream of step (2) as a sample stream;
(4) further cooling the sample gas stream of step (3) to about room temperature, filtering same, and removing resulting liquid therefrom;
(5) drying a selected portion of the sample gas stream of step (4) to remove vapor therefrom;
(6) passing a first portion of the resulting dry gas stream of step (5) to an O analyzer to determine the 0 concentration therein;
(7) passing a second portion of the gas stream of step (5) to a thermal conductivity cell to determine the concentrations of CO and hydrocarbons therein; and
(8) passing a third portion of the gas stream of step (5) to a chromatographic analyzer to determine the concentration of C to C hydrocarbons therein.
2. The process of claim 1 including the steps of passing signals representing the values obtained in steps (6), (7) and (8) to a computer to obtain one of a control signal and a print out.
3. The process of claim 2 wherein said in situ combination is effected in said stratum by moving a combustion zone therethru between said production well and an oifset injection well by injecting air thru said injecting well as a combustion-supporting gas, and including the step of controlling the air injection rate in response to one of said control signal and print out.
4. The process of claim 1 wherein at least one of the values determined in steps (6), (7), and (8) is used to control the rate of air injection to said in situ combustion.
5. In combination, apparatus comprising:
(a) a production line from a well for supplying a high pressure and high temperature stream of gas from an in situ combustion oil production process maintained by an injected stream of air;
(b) a sample line connected with said production line having means therein for cooling and pressure reduction of a sample gas stream;
(c) means in said sample line downstream of the means of (b) for separating from said gas stream liquids resulting from said cooling;
((1) filtering means in said sample line downstream of the means of (c);
(e) means for drying said sample gas stream;
(1?) an oxygen analyzer connected with said 5311111316 line downstream of the several aforesaid means by a first branch sample line having a flow meter therem;
(g) a thermal conductivity cell connected with said sample line downstream of the several aforesaid means by a second branch sample line having a flow meter therein; and
(h) a chromatographic analyzer connected with said sample line downstream of the several aforesaid means by a third branch sample line having a flow meter therein.
6. The apparatus of claim 5 including:
(i) a computer operatively connected with said oxygen analyzer, with said thermal conductivity cell, and with said chromatographic analyzer and adapted to provide one of a control signal and a print out of the parameter combination from the aforenamed instruments.
7. The apparatus of claim 6 including:
(j) a hydrogen detector operatively connected with said computer and provided with a gas sample inlet.
8. The apparatus of claim 5 including:
(k) means for passing a stream of a standard reference gas into each of the instruments of (f), (g), and
(1) means for passing a stream of nitrogen to said oxygen arialyzer; and
(111) means for passing a stream of carrier gas to said thermal conductivity cell and to said chromatographic analyzer.
References Cited UNITED STATES PATENTS 2,762,568 9/1956 Sullivan.
3,096,157 7/l963 Brown et al. 23-232 3,097,518 7/ 1963 Taylor et al.
3,236,603 2/1966 Durrett et a1. 23232 XR 3,285,701 11/1966 Robertson 23-254 XR MORRIS O. WOLK, Primary Examiner.
R. E. SERWIN, Assistant Examiner.
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|U.S. Classification||436/133, 166/251.1, 436/137, 436/141, 166/66, 208/427, 422/62, 422/89, 201/15, 208/401, 422/98|
|International Classification||G01N33/22, G01N33/24, E21B43/243, E21B43/16|
|Cooperative Classification||G01N33/241, E21B43/243|
|European Classification||G01N33/24A, E21B43/243|