Abstract:
A method and system for tertiary or enhanced oil recovery from a subterranean liquid hydrocarbon or oil wells is described. The method uses packers ( 104, 105, 204, 205, 304, 305, 305 A,  305 B) or angled wells ( 401 ) in order to force the gas down into the oil bearing strata ( 502 ) from a gas containing strata ( 501 ). The result is increased production of oil since the gas is forced downward over a large horizontal area between the gas containing strata and oil bearing strata.

Description:
BACKGROUND OF THE INVENTION 
     (1) Field of the Invention 
     The present invention relates to a process for enhanced oil recovery from subterranean liquid hydrocarbon or oil wells which usually have undergone primary liquid hydrocarbon (oil) removal and are pressure depleted. In particular the present invention relates to the injection of highly compressed cooled exhaust gas from an internal combustion engine into an injection well in a gas bearing strata so as to be directed downwardly to solubilize and drive the liquid hydrocarbons from an oil bearing strata to a separate production well. Also the present invention relates to the recycling of the exhaust gas removed from the production well with the oil into the injection well. 
     (2) Description of Related Art 
     A general discussion of enhanced oil recovery (EOR) is set forth in Kirk-Othmer Edition 17 168-174 (1982). The goal of EOR is to extract oil which is trapped in the sedimentary rock of the subterranean reservoir. The rock can be sandstone or carbonates, such as dolomite. Commonly, gases are used as a solvent and/or as a driving fluid. Carbon dioxide is usually used as the oil miscible, driving gas and nitrogen is an immiscible driving gas. 
     Prior art literature in enhanced recovery is as follows: Stoesppelwerth, George P., Oil &amp; Gas Journal, 68-69 (Apr. 26, 1993); Shelton, Jack L., et al., Journal of Petroleum Technology, 890-896 (1973); Bardon, C. P., et al., Society of Petroleum Engineers, U.S. Department of Energy, SPE/DOE 14943, 247-253 (1986); Palmer, F. S., et al., Society of Petroleum Engineers (SPE 15497), (1986); Monger, T. G., et al., SPE Reservoir Engineering, 1168-1176 (1988); Haines, H. K., et al., International Technical Meeting, Paper #CIM/SPE (1990); Johnson, H. R., et al., SPE/DOE 20269, pages 933-939 (1990); Monger, T. G., et al., SPE Reservoir Engineering, 25-32 (1991). 
     Patents which are related are U.S. Pat. No. 3,295,601 to Santourian; U.S. Pat. No. 3,411,583 to Holm et al; U.S. Pat. No. 3,547,199 to Fronina et al; U.S. Pat. No. 3,841,406 to Burnett; U.S. Pat. No. 3,995,693 to Cornelius; U.S. Pat. No. 4,465,136 to Troutman; U.S. Pat. No. 4,509,596 to Emery; U.S. Pat. No. 4,656,249 to Pebdani et al; U.S. Pat. No. 5,381,863 to Weaner; U.S. Pat. No. 5,402,847 to Wilson et al; U.S. Pat. No. 5,065,821 to Hang et al; U.S. Pat. No. 5,413,177 to Horn; U.S. Pat. No. 5,725,054 to Shays et al; and U.S. Pat. No. 5,663,121 to Moody. 
     The prior art has described the use of exhaust gases from internal combustion engines for increasing hydrocarbon production. Illustrative is a system described by Stoesppelwerth in Oil/Gas Journal, April 1993 and an Internet listing by Energy, Inc. of Tulsa, Okla. In the latter case, a single well is used and a primary purpose is to unplug the openings in the production well. U.S. Pat. No. 4,465,136 to Troutman describes the use of exhaust gas with water flooding around the injection production well. The gas pressure in the reservoir is cycled between about 150-300 pounds/m 2 , which is relatively low, and is referred to as “huff&#39;n-puff”. U.S. Pat. No. 5,381,863 to Wehner the carbon dioxide is initially immiscible in the oil at low pressures during injection and miscible at high pressures during extraction from the well. 
     U.S. Pat. No. 5,065,821 to Huana et al describes lateral drilling for gas injection. There is no use of any plugs in the wells and the well openings for injection and extraction are at the same level. U.S. Pat. No. 5,725,054 to Shayeai et al descries a method using steps of carbon dioxide injection separate from nitrogen injection. 
     There is a need for a more reliable method for the production of oil from pressure depleted reservoirs. 
     OBJECTS 
     It is therefore an object of the present invention to provide an improved method for enhanced oil recovery from a subterranean well. In particular, the present invention relates to a method which is relatively economical and reliable. Further, it is an object of the present invention to provide a method which is environmentally sound. These and other objects will become increasingly apparent by reference to the following description and the drawings. 
     SUMMARY OF THE INVENTION 
     The present invention relates to a method for enhanced recovery of hydrocarbons containing oil from a subterranean hydrocarbon bearing strata comprising the steps of: 
     (a) providing an exhaust gas from an internal combustion engine, which gas is compressed by a compressor connected to the engine motor, wherein the gas consists essentially of nitrogen and carbon dioxide; 
     (b) injecting the exhaust gas from the compressor into an injection well and from the injection well into a gas bearing strata which is above the hydrocarbon bearing strata, without injection of the exhaust gas directly into the hydrocarbon bearing strata from the injection well which increases pressure in the oil bearing strata; and 
     (c) recovering the hydrocarbons and the exhaust gas from a production well in the hydrocarbon bearing strata. 
     Further the present invention relates to an oil producing well system for enhanced recovery of hydrocarbons including oil from a subterranean bearing strata which comprises: 
     (a) an injection well for injecting a compressed exhaust gas from an internal combustion engine, which is connected to a compressor for the exhaust gas, into a gas bearing strata which is above the hydrocarbon bearing strata, without injection of the exhaust gas directly into the hydrocarbon bearing strata from injection well; 
     (b) a production well in spaced relationship to the injection well and extending into the hydrocarbon bearing strata for recovering the exhaust gas and hydrocarbons from the hydrocarbon bearing strata; and 
     (c) a separation facility above the production well for separating the hydrocarbons from the exhaust gas. 
    
    
     DESCRIPTION OF DRAWINGS 
     FIGS. 1 to  4  are front partial cross-sectional views of wells  100 ,  200 ,  300  and  400  for liquid hydrocarbon production. FIG. 1A and 1B are cross-sections along lines  1 A— 1 A and  1 B— 1 B of FIG. 1, respectively. 
     FIG. 5 is a schematic view of the unit  10  which generates the internal combustion engine exhaust. 
    
    
     DESCRIPTION OF PREFERRED EMBODIMENTS 
     The present invention provides a method and system for the enhancement of oil recovery from mature, pressure depleted, subterranean formations via re-pressurization utilizing a gas stream mixture of nitrogen and carbon dioxide produced by an internal combustion engine. The exhaust gas is preferably has reduced acid and corrosion properties by the addition of neutralizing agents and cooled. 
     The recovery of the oil is from the subterranean formation containing oil, gas and/or water, penetrated by vertical or angled production and injection well bores, through reservoir repressurization. The subterranean formation is initially depleted of its natural pressure drive. Exhaust gases are preferably produced on-site by a mobile internal combustion engine(s), usually fueled by either diesel fuel or propane. 
     The method comprises the steps of injecting via the injector well bore a stream of an inert gas mixture produced by said internal combustion engines and with the reduced acid and corrosion characteristics prior to the injection. The inert gas is a mixture of nitrogen and carbon dioxide and contains trace amounts of other associated gases; carbon monoxide, hydrogen, oxygen, argon, hydrocarbons and other similar gases. The temperature of the gas at the well head is preferably between about 80° and 150° F. The gas is injected via a compressor into the injection well bore (s) in an amount and under pressures sufficient to establish either miscible, near-miscibility or immiscible conditions. 
     The injection well alone or with the production well is shut-in for a period of time to allow for reservoir stabilization, produced during the re-pressurization phase or produced immediately upon the completion of the injection phase. The oil is removed through the production well. 
     Gases produced through production well bore(s) are re-injected into subterranean formation via compressor and the injection well bore until such time as deemed uneconomical by the operator. Additional makeup gas may be used during the course of operation to maintain a desired bottom hole pressure. 
     FIGS. 1 to 4 show various types of well systems  100 ,  200 ,  300  or  400  which can be used. Referring to FIG. 1, a strata  500  which has reduced production is injected with the gas from the unit  10  through injection well  101  in a casing  102 . The well  101  is closed with cap  101 A. The injection well  101  leads to the gas section  501  of a strata  500  above the oil section  502 . The casing  102  leads to the bottom of the well, usually just above the water level below the strata  500 . Adjacent to the injection well  101  in the casing  102  is a production well  103  which leads to the oil production section  502  below the gas section  501 . In Michigan, the strata  500  is comprised of dolomite and limestone. The casing  102  is provided with retrievable packings  104  and  105  which are on either side of the gas section  501 . A lateral well  106  for injection the gas into the gas section  501  is provided from the casing  102  above the packing  105  and below the packing  104 . An oil production lateral well  107  is provided below the packing  105 . The well is provided with a cement top  108  (about 500 feet above the strata  500 ). An outer casing  109  shields the ground water and generally extends in Michigan down below the fresh water table. A secondary inner casing  110  extends down to adjacent the formation at the level of the cement top  108 . The annulus  113  between the casing  102  and wells  101  and  103  is optimally filled with fluid to prevent corrosion of the wells  101  and  103 . The production well  103  is connected to a production facility  111  which processes the oil and recycles the exhaust gas extracted through a recycling compressor  112  into the injection well  101 . 
     In operation the unit  10  generates gas which is injected via well  101  and lateral well  106  into the gas section  501 . This causes pressure in the oil section  502  forcing the oil into production well  103  which is collected in production facility  111 . The gas to the compressor  112  from the facility  111  is recycled into the injection well  101 . The result is better production of oil from the well. The unit  10  may have been returned to a lessor prior to production of the oil, thus reducing the cost of producing the oil. 
     FIG. 2 is similar to FIG. 1 except that an injection well  201  and production wells  203  are spaced a significant distance from the injection well  201 . Injection well  201  is provided in the casing  202  which can extend only to above the oil section  502 . Packings  204  and  205  are provided in the casing  202  above and between an opening from the well  201 A. A lateral injection well  206  is provided from the casing  202 . The outer casing  209  and inner casing  210  around casing  202  are provided as in FIG.  1 . Well caps  201 A and  203 A are provided to close the wells  201  and  203 . Around the injection well  201  and casing  202  are provided production wells  203 . These cement wells  203  include the packings  205 A and  205 B in the oil section  502  in casing  202 A. Production wells  203  are provided in casings  202 A. A cement cap  208  is provided as in FIG. 1 as are inner and outer casings  209 A and  210 A. 
     In operation gas from the unit  10  is injected through a lateral well  206  into the gas section  501 . The oil is forced out the production well  203 . The oil is collected in facility  211  and the gas is recompressed by compressor  212  for reintroduction into the injection well  201 . 
     The wells  301  and  303  in FIG. 3 are identical to FIG. 2 except there are no lateral wells  206  and  207  and instead openings  306  and  307  are included. Included are the following common parts:  301 —injection well;  301 A—well cap;  302 —casing;  303 —production well;  303 A—well cap;  304 —packing;  305 —packing;  308 —cement top;  309 —casing;  309 A—outer casing;  310 —inner casing;  310 A—outer casing;  311 —facility; and  312 —compressor. 
     This construction is not preferred since there is lower oil production without the lateral wells  206  and  207 . 
     FIG. 4 schematically represents the most preferred embodiment of the present invention. FIG. 4 shows an injection well  401  in gas section  501  and a production well  403  in the oil bearing strata  502 . The arrows show the direction of fluid flow. The gas generation unit  10  produces the gas which is injected at well cap  401 A. The tank  11  preferably contains propane to fuel the generation unit  10 . The production well  403  is below the gas injection well  401  and lateral drilling is used so that the injected gas is dispensed in the gas section  501  and the oil is collected in the oil section  502 . In any event, the wells  401  and  402  can have multiple openings along the horizontal sections. The oil is removed at well cap  403 A to a separator  416  wherein some exhaust gas is removed and sent to the recycle compressor  412  for injection into well cap  401 A. A heater  413  is used to separate gas, oil and water. Gas is also sent to the compressor  412 . Oil is sent to tank  414  and water to tank  415 . 
     The separator  416  is standard in the oil industry and is also available from NATCO (Houston, Tex.). The heater  413  is also available from NATCO, for instance. The oil tank  414  is also available from NATCO. The recycle compressor is available from Gas Compressor Services (Traverse City, Mich.) on lease. Preferred is model #JGR/2 from Ariel Compressors (Mount Vernon, Ohio). The gas generation unit  10  is also available on lease from Northland Energy Corporation, Houston, Tex. and is mounted on a wheeled flatbed for over-the-road hauling. The specifications of two available units are shown in Table 1. 
     
       
         
               
               
               
             
               
               
               
             
           
               
                   
                 TABLE 1 
               
               
                   
                   
               
               
                   
                 Large Unit 
                 Standard Unit 
               
               
                   
                 Configuration 
                 Configuration 
               
               
                   
                   
               
             
             
               
                   
               
             
          
           
               
                 Unit Size 
                 Two Tri Axle Trailers, 
                 One 11.5′ by 50′ 
               
               
                   
                 10′ by 53, each 
                 skid unit 
               
               
                 Fuel Trailer 
                 35,000 litres 
                 35,000 litres 
               
               
                 Capacity 
               
               
                 Discharge 
                 2000 p.s.i. (13,800 
                 1,400 psi (9,600 
               
               
                 Pressure 
                 kPa) 
                 kPa) 
               
               
                 Flow Rate 
                 2000 s.c.f.m. (57 
                 1,425 s.c.f.m. (41 
               
               
                   
                 m 3 /min.) 
                 m 3 /min.) 
               
               
                 First Stage 
                 Frick Screw 
                 Fuller-Kovako 
               
               
                 Compressor 
                   
                 Rotary vane 
               
               
                   
                   
                 compressor 1   
               
               
                 Reciprocating 
                 Ariel 2  Four Stage 
                 Gardner Denver 3  WB 
               
               
                 Compressor 
                   
                 14, 4 stage, Radial 
               
               
                 (Booster) 
                   
                 reciprocating 
               
               
                   
                   
                 compressor 
               
               
                 Engine (First 
                 Caterpillar 4  3412 
                 Cummins 5  G.T.A. 12 
               
               
                 Stage) 
                 (propane) 
                 (propane) 
               
               
                 Engine (Booster) 
                 Caterpillar 3412 
                 Cummins G.T.A. 28 
               
               
                   
                 (propane) 
                 (propane) 
               
               
                 Gen Set Capacity 
                 (2) 80 kVa Continuous 
                 100 kVa Continuous 
               
               
                 480 Volt 3 Phase 
               
               
                 Oxygen Content of 
                 0.02% or less 
                 0.02% or less 
               
               
                 Gas 
               
               
                 Oxygen Monitoring 
                 Teledyne 6  Continuous 
                 Teledyne (Model 326 
               
               
                 System 
                 Read Out 
                 RA) 
               
               
                 Corrosion Rate 
                 Less than 2.0 
                 Less than 2.0 
               
               
                   
                 pounds/ft 2  per yr. 
                 pounds/ft 2  per yr. 
               
               
                   
               
               
                   1 SCS-Screw Compression Systems Catoosa, OK  
               
               
                   2 Ariel Compressors Mt. Vernon, OH  
               
               
                   3 Gardner Denver Quincy, IL  
               
               
                   4 Caterpillar Peoria, IL  
               
               
                   5 Cummins Columbus, IN  
               
               
                   6 Teledyne Brown Engineering Hunt Valley, MD  
               
             
          
         
       
     
     As shown in FIG. 5, the gas generation unit  10  of FIGS. 1 to  4  includes a fuel (propane) in a tank  11  which is provided to a motor  12  which produces the exhaust in a conduit  20 A. A catalytic converter  13  from the conduit  20 A leads to a conduit  20 B. A cooler body  14  leads to conduit  20 C. A corrosion inhibitor injector unit  15  leads to conduit  20 D, compressor heads  16 A and  16 B of compressor  16 . A shaft  17  from the motor  12  drives the compressor  16 . The outlet through conduit  20 E from the compressor  16  is fed into the well of FIGS. 1 to  4 . A unit of this type is shown in U.S. Pat. No. 5,663,121 to Moody. 
     As shown in FIGS. 1 to  4 , the tank  11  provides gas to the gas generation unit  10  and to the recycle compressor  112 ,  212 ,  312  or  412 . The gas generation unit  10  is only on line during the injection to reduce the cost of the project. 
     The following is a list of vendors and their related services: 
     (1) Nitrogen-CO/2 Gas Generation Unit: Northland Energy Corporation, 1115 Goodnight Trail, Houston, Tex. 77060-1112; 
     (2) Packers: Baker Hughes, Inc. (Houston, Tex.); 
     (3) Cement/Tools: Halliburton Energy Services (Houston, Tex.); 
     (4) Weatherford International (Houston, Tex.); 
     (5) Corrosion Inhibitor: M-1 Drilling Fluids (ConQuor 404; phosphate ester salt (Houston, Tex.); 
     (6) Corrosion Inhibitor: Magnesia, (use as a weight 10% by volume) Martin Marietta (Hunt Valley, M.d.). 
     It will be appreciated that over time additional gas can be added through the injection well to maintain the desired pressure. This can be done with the recycle compressor. Also corrosion inhibitors can be added to the injection and/or production well over time to prevent corrosion in the injection well. 
     It is intended that the foregoing description be only illustrative of the present invention and that the present invention be limited only by the hereinafter appended claims.