Abstract:
A process of enhancing hydrocarbon production from wells previously hydraulically fractured with a polymer based fluid(s). An in-situ combustion process is initiated in the reservoir for a short duration wherein thermal and chemical processes act to reduce the viscosity of unbroken gels and other fluids retained in the propped hydraulic fracture and immediate reservoir matrix vicinity.

Description:
[0001]    This application claims priority of U.S. provisional patent application Serial No. 60/273,294 having a filing date of Mar. 1, 2001 and is incorporated herein in its entirety by reference. 
     
    
     
       FIELD OF THE INVENTION  
         [0002]    This process generally relates to a process for enhancing the recovery of hydrocarbons from a producing hydrocarbon zone. More specifically, it relates to enhancing permeability in an already propped fracture by removing unbroken or residual polymer based gel fracturing fluids. When removed, flow from previously undrained portions of the hydrocarbon reservoir is established or enhanced.  
         BACKGROUND OF THE INVENTION  
         [0003]    Many different processes have been employed to enhance the recovery of hydrocarbons (liquids and/or gases) from subterranean formations/reservoirs. This includes improving the rate of flow and/or the ultimate recovery of hydrocarbons from a producing hydrocarbon reservoir. Hydraulic fracturing is one such method known in the petroleum industry to accomplish this goal. This process if most often plied where transmissibility (kh/μ) is low, most frequently in low permeability gas formations. Typical fracturing fluids used to enhance reservoir productivity during hydraulic fracturing techniques include, but are not limited to 1) water-based systems which are normally comprised of polymer gels; 2) oil-based systems which are often gelled; 3) foam based systems; and 4) alcohol based systems.  
           [0004]    Early water and oil based systems have been extensively referenced in the literature for their ineffectiveness due to the inherent inability of the gels not to “break”, i.e., become less viscous and ultimately produced from the reservoir. In some cases, unbroken gels have been inadvertently produced from these well bores years later, long after they should have broken. The original design emphasis on these gel systems was reduced surface tension and increased viscosity to reduce friction and maximize sand carrying capacity. Unfortunately, breaking these systems was not well understood nor accomplished.  
           [0005]    Recognizing the benefits of oxidation in gel degradation, remediation attempts by injecting strong oxidizers such as chlorine bleach have previously been attempted. The outcome was usually unsuccessful, due primarily to the inability of an injected fluid phase contacting the damaged area. Thus, the petroleum industry is plagued worldwide with thousands of damaged hydrocarbon reservoirs with extensively propped hydraulic fractures that are non-productive due to residual polymer gels, thus resulting in low productivity and the inherent loss of recoverable hydrocarbon reserves and significant revenue.  
           [0006]    The prior art has generally addressed the problem of low productivity in hydrocarbon reservoirs by focusing on heavy crude oil (&lt;35 API gravity) reservoirs. Thus, attempts have previously been made to establish a combustion zone in a carbonaceous stratum by the injection of air, oxygen enriched air, or pure oxygen through an independent injection well. As the combustion supporting gas is injected, products of combustion and other heated fluids are forced away from the point of injection within the producing reservoir formation toward one or more producing wells where they are withdrawn to the surface. Associated production increases result from 1) increased pressure around a designated injection well driving reservoir fluids toward a producing well; or 2) an associated reduction in oil viscosity achieved through an increase in temperatures of the oil and the surrounding rock matrix. Examples of previous attempts at downhole combustion may be found generally in U.S. Pat. No. 4,566,536 to Holmes, U.S. Pat. No. 5,868,202 to Hsu, U.S. Pat. No. 4,274,487 to Hollingsworth, U.S. Pat. No. 4,418,751 to Emery, U.S. Pat. No. 4,042,026 to Pusch and U.S. Pat. No. 4,557,329 to Savard.  
           [0007]    Typical heavy crude oil reservoirs are generally shallow (&lt;3500 ft. depth) with low (&lt;120° F.) bottom hole temperatures. The thermodynamic properties of these viscous oils require long injection times (weeks to months) and high temperatures (&gt;700° F.) to achieve in-situ ignition. These problems were addressed in part by utilizing oxygen enriched air or pure oxygen as the injection stream, and at times used in combination with bottom-hole ignition systems. However, the injection of pure oxygen creates safety issues due to the hazardous nature of uncontrolled reactions or explosions associated with hydrocarbon products exposed to extreme heat. U.S. Pat. No. 4,598,772 to Holmes and U.S. Pat. No. 4,440,227 to Holmes are examples of attempts to mitigate unintended ignition and manage well bores within safe operating levels.  
           [0008]    Those skilled in the art will appreciate that low temperature oxidation (“LTO”) processes cause reservoir oil to become partially oxidized and thereby form volatile oxygenated compounds and unstable hydro peroxide intermediates. Their decomposition releases significant heat. As the temperature produced by such reactions is raised, intermediate temperature reactions (“ITR”) cause distillation and thermal cracking which produces hydrogen gas and light hydrocarbons that are left as carbonaceous residue on solid matrix materials in the formation. As the reservoir temperature continues to rise to a minimum active combustion temperature (“MACT”), a high temperature oxidation (“HTO”) reaction occurs between the gaseous oxygen phase and the deposited carbonaceous residue. Ignition in heavy oils generally occurs in the HTO region wherein temperatures reach levels high enough to ignite and burn the deposited carbonaceous material. For reasons not fully understood, light oils and gas condensates will ignite and burn in the LTO region. Accelerated Rate Calorimeter tests performed on a specific light oil (50 API gravity) supported ignition within hours versus days or weeks, with a MACT of less than 500° F. These lower generated temperatures for the combustion of light oils allows In-situ combustion for most existing producing wells without requiring prohibitive surface or bottom-hole design changes.  
           [0009]    Hydrocarbon oxidation by transition metal compounds is recognized in the refining and processing of oil and gas. The addition of such compounds can significantly increase oxidation reactions, and thus shorten the time to ignition. For In-situ combustion processes, this is important where the thermodynamic qualities of the target oil and reservoir temperature would require unreasonably long periods of oxygen injection to achieve ignition. There is thus a significant need for a cost effective process for stimulating previously fractured well bores with damage caused from polymer gels in a safe, effective manner using an in-situ combustion process.  
           [0010]    Successful implementation of the process requires maintaining a combustion front through the reservoir at some distance from the injection well, a problem that has rendered a majority of heavy oil thermal recovery projects unsuccessful. The process of the present invention injects air for a short duration to achieve in-situ combustion, and advance the combustion front radially a small distance from the hydraulic fracture. The well is then shut-in for a predetermined period to allow for maximum oxygen utilization, bottom-hole temperature abatement to within safe operating levels, and CO2 miscibility with reservoir oil.  
         SUMMARY OF THE INVENTION  
         [0011]    It is thus one aspect of the present invention to employ an in-situ combustion process in a hydrocarbon reservoir to remediate production impairment in general and to improve the productivity and total recovery of produced hydrocarbons from a producing hydrocarbon reservoir. In one embodiment of the present invention the process is specifically designed to reduce the production impairment caused by the previous use of a polymer based hydraulic fracturing fluids. The formation of, and reduced conductivities created by polymer gel residues and unbroken gels are some of the more common forms of damage caused by fracture fluids. Thus, the gel residues and unbroken gels act as barriers to fluid flow in a formation that is damaged in this manner.  
           [0012]    In another aspect of the present invention, a process is provided which is preferably carried out through a single well bore that has been previously treated with any form of a polymer gel based system. One primary benefit of the process described herein is the degradation and removal of unbroken gels in the existing propped hydraulic fracture system. Combustion processes used in this application have several novel characteristics which contribute to polymer gel degradation, including but not limited to:  
           [0013]    1) Oxidation through contact by injected air;  
           [0014]    2) Elevated temperatures between 400° F. to 700° F.;  
           [0015]    3) Organic acids generated as a by-product of combustion distillation; and  
           [0016]    4) Low PH water generated as a by-product of combustion distillation.  
           [0017]    It is a further aspect of the present invention to facilitate the removal of localized connate water and/or retrograde condensation through reduced surface tensions created by elevated temperatures. Further, the treatment creates an effective fracture having higher fracture conductivity and/or which penetrates an area of higher pore pressure than the previous fracture and thus enhances productivity and the ultimate recovery from the hydrocarbon reservoir.  
           [0018]    It is a further aspect of the present invention to provide a process which can be practiced at a fraction of the cost of conventional hydraulic fracturing techniques and which utilizes equipment well known in the Petroleum Industry, and which can be effectively implemented in a period of days as opposed to weeks or months. Thus, in one aspect of the present invention, conventional compressors for the injection of high pressure air are utilized, as well as commonly used high pressure nitrogen gas.  
           [0019]    Thus, in one embodiment of the present invention, a method for restimulating a previously fractured hydrocarbon reservoir is provided, and comprises the steps of:  
           [0020]    a) shutting in a producing well bore in communication with said previously fractured hydrocarbon reservoir to prevent flow;  
           [0021]    b) displacing at least a portion of a hydrocarbon product existing in said producing well bore with a fluid;  
           [0022]    c) injecting air down said hydrocarbon well bore and into the hydrocarbon reservoir to create an in-situ combustion reaction in said previously fractured hydrocarbon reservoir;  
           [0023]    d) shutting in the hydrocarbon well bore for a period of at least about 12 hours; and  
           [0024]    e) producing the hydrocarbon products from said hydrocarbon reservoir.  
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0025]    [0025]FIG. 1 is a top plan view of a theoretical well bore which has been hydraulically fractured and identifying an effective drained area and a fracture created during the stimulation process;  
         [0026]    [0026]FIG. 2 is a top plan view of a well bore identifying the geometry of the actual hydraulic fracture and showing the effective area of drainage;  
         [0027]    [0027]FIG. 3 is a top plan view of a well bore with a pre-treatment area of drainage and a post-treatment area of drainage and depicting the subsequent improvement in productivity based on the method of the present invention;  
         [0028]    [0028]FIG. 4 is a front elevation view of a typical well bore of the present invention and identifying the flow of air into the hydrocarbon producing reservoir and showing the propagation of heat into the surrounding rock matrix;  
         [0029]    [0029]FIG. 5 is a front elevation view of the well bore shown in FIG. 4 after treatment and identifying the production of hydrocarbons into the well bore and the increase in the effective area of drainage;  
         [0030]    [0030]FIG. 6 is a top plan view of a wellhead in the present invention and identifying the flow of air and nitrogen and subsequent production of well bore fluids into a separator or flat tank; and  
         [0031]    [0031]FIG. 7 is a front elevation view of the well bore of the present invention and identifying the producing reservoir and the injection of air and nitrogen and the subsequent production of produced fluids through the production tubing.  
     
    
     DETAILED DESCRIPTION  
       [0032]    Referring now to the drawings, FIGS.  1 - 7  depict various views of a hydraulically fractured reservoir, the penetrating well bore, and the equipment associated with the present invention. More specifically, FIG. 1 depicts a top plan view of a theoretical well bore  6  and associated reservoir which has been hydraulically fractured and further showing the effective drained area  8 . FIG. 1 represents a hypothetical or ideal plan view wherein the fracture wings generated by the hydraulic treatment are shown extending horizontally into the hydrocarbon reservoir  2 . These fractures are “propped” open by materials such as sand or ceramic beads, thus increasing the permeability and transmissibility of the reservoir fluids and the rate of flow entering the well bore.  
         [0033]    [0033]FIG. 2 is a plan view of a well bore  6  and identifying the actual geometry of a typical hydraulic fracture  4  extending into a hydrocarbon reservoir  2 . The darker regions of the fracture wings  4  depict a zone damaged by residual polymers remaining after hydraulic fracturing and thus not effective for the production of hydrocarbons. More specifically, as the distance increases away from the well bore  16  the fractures become ineffective due to the presence of unbroken, highly viscous fracture fluids and residues. This creates a decreased pressure drop away from the well bore  6  which combines to make the fluids immobile and impermeable to oil and gas production past the effective fracture zone, thus resulting in reduced production outside of the effective drained area  8 .  
         [0034]    [0034]FIG. 3 depicts a plan view of the well bore  6  shown in FIG. 2 and the associated hydrocarbon reservoir  2  of the present invention and identifies an increased post treatment area of drainage  10  once the residual polymers and other well bore damage is removed from the hydraulically fractured area. Accordingly, a more effective fracture and improved permeability in the rock matrix is obtained in the treated hydrocarbon reservoir  2 .  
         [0035]    Referring now to FIG. 4, a front elevation view of a typical well bore  4  of the present invention is provided herein and which shows casing  12  penetrating a hydrocarbon reservoir  2 . In this particular schematic, the injected air is shown being introduced through the perforations  14  and into the hydrocarbon reservoir  2  to create an oxidation process which generates significant heat. The heat and combustion front is advanced and replenished by the cooler injected air, and the propagation of the heat continues along the hydraulic fracture  4  network into the surrounding rock matrix as it is propelled by the available air and oxygen. This effectively creates carbon dioxide gases, low ph water and peroxide byproducts and distillation which assist in the thermal degradation of entrained fracture fluids and the mobilization of the broken gelled fluids and the improved productivity of the hydrocarbon reservoir  2 .  
         [0036]    [0036]FIG. 5 is a depiction of the well bore  6  shown in FIG. 4, but identifies the production of hydrocarbons after the injection process and treatment of the present invention is completed. More specifically, after the air injection has been discontinued, the bottom hole temperature is allowed to cool to a specified level and the well returned to production. The rate of production is enhanced due to the increased effective fracture length, resulting from the breakdown of viscous polymer gels, which allows contact with higher reservoir pressure and improved permeabilities in the fracture and surrounding rock matrix, hence improving production rates and total recovery of hydrocarbon fluids.  
         [0037]    [0037]FIG. 6 is a top plan view identifying equipment utilized in one aspect of the present invention. More specifically, a compressor  15  used to inject the air necessary for combustion, while a nitrogen source maybe used for injection down the annulus between the production tubing  16  and casing  12  and the subsequent necessity of a separator for use during production after treatment. Further, an open top flat tank may additionally be used for sales or the removal of water or other byproducts.  
         [0038]    [0038]FIG. 7 is a front elevation view of one aspect of the present invention and further identifies the hydrocarbon reservoir  2 , well bore casing  12 , production tubing  16 , injection lines necessary for the injection of the air and nitrogen, as well as the valves and associated piping required for the present method of treatment. Additionally, a thermocoupler is shown which may be used to monitor the bottom hole temperature throughout the process of the present invention to assure temperatures do not exceed design limitations. FIG. 7 further depicts the well bore  6  extending from the surface of the earth through the overburden and extending into the target hydrocarbon producing formation from which hydrocarbons are recovered by an in-situ combustion process of the present invention.  
         [0039]    In one aspect of the present invention, the operation of the system is as follows. A predetermined amount of water is pumped down the tubing in sufficient volume to kill the well and evacuate the lower portion of oil, condensate or other hydrocarbon products. If metallic salts are required as a combustion catalyst, a predetermined volume is mixed with the water prior to injection. These metallic salts may include, but are not limited to Ammonium, Magnesium, Bismuth, Manganese, Calcium, Nickel, Cobalt, Potassium, Copper, Silver, Iron, Sodium or other transition metal complexes as identified on a periodic chart. Nitrogen is then injected down the casing  12  and production tubing  16  in sufficient quantity to over-flush the associated well bore  6  volume from surface to the base of the perforations  14 . Air or oxygen enriched air is then injected into the hydrocarbon reservoir  2  via the tubing  16  at a predetermined constant rate until ignition is indicated by a significant increase in bottom-hole temperature as indicated by the thermocoupler or sudden increases in surface injection pressures. Air injection is continued until a predetermined amount of air volume has been injected or pressures meet certain limits that exceed hydraulic fracture pressures for the Rock Matrix of the hydrocarbon reservoir  2 . It is intended that air be injected at pressures that allow diffusion down the previous hydraulic fracture  4  and into the rock matrix, but not to create additional fractures which would diminish the effectiveness of the present treatment.  
         [0040]    In one embodiment of the present invention, air injection is immediately followed by nitrogen gas in sufficient volumes to over-displace the tubing volume by at least 50%. As an inert gas, the Nitrogen gas serves to protect the well bore  6  from propagation of the combustion front back into the well bore and the inherent problems associated with excessive temperatures. As appreciated by one skilled in the art, other inert gases may also be used for the same purpose. The well bore  6  is then shut-in and bottom-hole temperatures are monitored by the thermocoupler. The well is then produced to an open top flat tank and flue gases vented until the bottom-hole temperatures have subsided to within safe operational levels, which typically occurs in a period of about 24 hours. Flue gases are additionally monitored until O2 and N2 levels are deemed to be within accepted pipeline levels, at which time the well is returned to sales.  
         [0041]    As one example of the present invention, the following actual procedure is described below for a hydrocarbon reservoir having a depth of 6700 ft. which was penetrated by 4.5″ casing  12  and 2⅜″ production tubing  16 :  
         [0042]    Procedure:  
         [0043]    Embodiment 1—All Perforated Intervals to Be Treated  
         [0044]    1. Shut-in Offset producing wells  
         [0045]    2. Pressure test casing to rated minimum wellhead pressure of 3000 psia.  
         [0046]    3. Flush tubing with enough water to void the well bore volume from the top of the perforations to the bottom of the hole.  
         [0047]    Note: In one preferred embodiment of the present invention, a combination of substances (chemical soups, principally comprised of various metallic salt compounds) are added to the water prior to placement in the well bore, wherein combustion ignition times from certain reservoir temperatures, pressures and air flux rates are known.  
         [0048]    4. Place wireline thermocoupler down the tubing or casing/tubing annulus to the base of the tubing to monitor bottom hole temperature.  
         [0049]    5. Inject Nitrogen down the annulus at low rates and a total volume of 1.5 times the annular tubing volume.  
         [0050]    6. Inject nitrogen down tubing at low rates and a total volume of 1.5 times the tubing volume.  
         [0051]    7. Immediately follow Nitrogen injection down tubing with air injection. Adjust air injection rates such that monitored pressures are either 1) below maximum rated wellhead pressures or 2) below fracture initiation pressures of the formation.  
         [0052]    8. Continuously monitor surface pressures for a rid rise indicative of combustion ignition.  
         [0053]    9. Periodically suspend air injection and monitor bottom hole temperatures for an increase above baseline temperatures indicating combustion ignition.  
         [0054]    Note: If bottom hole temperatures exceed 800 degrees F.; 1) immediately resume air injection and if they do not immediately subside, 2) cease air injection and immediately follow with nitrogen injection down tubing. Shut-in well until bottom hold temperatures subside to 500 degrees F.; resume air injection.  
         [0055]    10. Continue air injection for a predetermined period of time following combustion ignition (usually 3 to 48 hours).  
         [0056]    11. Inject nitrogen down tubing with a total volume of 1.5 times tubing volume.  
         [0057]    12. Shut-in the well for a predetermined period of time (usually 2-5 days).  
         [0058]    13. Pull thermocoupler from the well bore.  
         [0059]    14. Flowback well to an open top flat tank. Swab if necessary.  
         [0060]    15. Monitor oxygen and nitrogen levels of the vented gas until levels have fallen below the designated containment levels for the sales line.  
         [0061]    16. Return production to the sales line.  
         [0062]    Embodiment 2—Selected Perforated Intervals to Be Treated  
         [0063]    1. The process is as above with a packer positioned above a bridge plug to isolate the perforation target intervals. This step eliminates the annulus and the need to inject nitrogen in step 5 above.  
         [0064]    To assist in the understanding of the present invention, the following components and numberings associated with the drawings are provided herein:  
                                                   #   Component                            2   Hydrocarbon reservoir            4   Hydraulic fracture            6   Well bore            8   Area of drainage           10   Post treatment area of drainage           12   Casing           14   Perforations           16   Production tubing           18   Valves           20   Thermocoupler           22   Injection lines                      
 
         [0065]    The foregoing description of the present invention has been presented for purposes of illustration and description. Furthermore, the description is not intended to limit the invention to the form disclosed herein. Consequently, variations and modifications commenced here with the above teachings and the skill or knowledge of the relevant art are within the scope in the present invention. The embodiments described herein above are further extended to explain best modes known for practicing the invention and to enable others skilled in the art to utilize the invention in such, or other, embodiments or various modifications required by the particular applications or uses of present invention. It is intended that the dependent claims be construed to include all possible embodiments to the extent permitted by the prior art.