Patent Abstract:
This invention relates to enhancing hydrocarbon production from a subterranean formation via a well completed with a gravel pack. Gravel packs suffer plugging and damage over time from produced particles and other plugging materials brought into the pack as production continues. This invention relates to a chemical treatment for the gravel pack designed to remove damaging particulate matter from the pack via dissolution or displacement. Damaging material is forced sufficiently far into the producing reservoir to prevent its remigration back into the pack.

Full Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     Not applicable 
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not applicable 
     REFERENCE TO A “MICROFICHE APPENDIX” 
     Not applicable 
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates to a method of improving hydrocarbon production from a reservoir that was completed with a gravel pack, wherein fine particles that clog the gravel pack are removed from the gravel pack so that hydrocarbon production is increased. 
     2. General Background of the Invention 
     Formations that exhibit a tendency to release formation particles during hydrocarbon production (commonly called “sanding” or “fines migration”) create problems as these particles are released into the hydrocarbon stream. Particles can bridge in formation flow channels and impede production rate. Particles carried into a well bore with produced hydrocarbon can also erode well structure such as tubulars and well heads. Such particles can settle into the bottom of a well bore and impede production. 
     Common practice for completing wells drilled into high-permeability formations with sanding tendency through the early 1990&#39;s was to install a tubular wire screen into the well bore and gravel pack the space between the screen and casing or bore hole wall. Gravel packing is still a preferred completion method for many low budget wells drilled into high-permeability formations with sanding tendencies. 
     The gravel packing operation includes a transport of sand into the space between the screen and the casing, and into the perforation tunnels. The sand is sized to prevent fine particles or fines from the specific formation from passing through the pack (usually 20-40 mesh or 30-50 mesh or 40-60 mesh). The sand is deposited into the annulus behind the screen and then packed to create a filter to stop the fine particulate matter or fines from migrating into the well bore. The screen openings are further sized to act as a final filter for any fines migrating through the sand bed. Thus, the problems of producing from sanding formations are mitigated. 
     This gravel pack type of completion method always damages the permeability of the formation compared to native permeability of the reservoir rock. Additionally, as fines migrate into the well and are trapped by the gravel pack, permeability is further reduced resulting in reduced production rates. 
     BRIEF SUMMARY OF THE INVENTION 
     The present invention provides a method of removing fine particulate matter (fines) deposited into a gravel pack. Application of the invention results in removal of fines from the pack thereby increasing the conductivity of the gravel pack and the resulting productivity of the oil reservoir. 
     The method of the present invention employs both chemical and mechanical means to remove the fine particulate matter or fines. 
     A chemical wash (solvents and acids) is first injected down tubing (e.g. coiled or jointed) into the gravel pack at low matrix injection rates (e.g. ½ to 1 barrel per minute or bpm). Solvents remove hydrocarbons, and acids remove silts and clays. 
     A water-based flush follows the chemical flush. The function of the water based flush is to displace any fine particulate matter or fines not dissolved by the chemical wash and to displace reaction products from the chemical stage sufficiently far into the well bore so that any resulting precipitation will not damage the near well bore area. Injection of aqueous flush is initially at same rate as chemical flush. After half the volume of flush is placed, injection rate is increased to increase mechanical energy applied to the remaining fines. 
     One placement option is to continue increasing injection rate until a narrow hydraulic fracture is initiated. Fines swept into the fracture will be trapped when the crack closes. Care must be taken in this scenario to avoid creating a fracture with sufficient width to accept pack sand. 
     The present invention provides a fluid train pumped into the well and through the gravel pack. The fluid train consists of a chemical portion followed by an aqueous-based flush to impart further mechanical energy into the cleaning process. 
     The chemical portion employs an organic solvent, an HCL or organic acid preflush, and an HF or combination of HCL:HF acid flush to dissolve any organics, silt and clays deposited in the pack. This chemical portion of the fluid train is then pushed far back into the formation by an overflush. The overflush can be acid, treated water, or a combination of the two and is designed to fulfill two purposes. First, the overflush sweeps the chemical flush laden with reaction products far out into the surrounding formation. Volumetric design includes sufficient overflush to sweep the chemical flush a distance away from the well bore. This physical removal of reactive fluids prevents any secondary precipitation of products from the fluids to leave damaging solids in the gravel pack or near well bore. The volume of overflush is designed to sweep the chemical flush preferably about three feet (3′) or more from the well bore. Thus, if any precipitation would occur with time, the damage to permeability so far away from the well bore would be minimal. A second purpose of the overflush is to sweep from the gravel pack any fines not dissolved or removed from the pack by the chemical flush. The method of the present invention can thus include the step of increasing displacement rate of the overflush several times throughout the injection to take advantage of penetration of fluids into less permeable formation driven by increased injection pressure derived from increased overflush flow rate. 
     A methanol-water mixture is injected into the pack and left until the well is returned to production. This mixture is left in the pack to eliminate potential for any adverse reaction with the overflush and to improve wettability of sand to hydrocarbon, to reduce surface tension and to further dissolve any blocking material. 
     General fluid types and volumes (exemplary) are listed in the table below, however volumes may change depending on formation characteristics. 
     
       
         
               
               
               
               
             
               
               
               
             
           
               
                   
                   
               
             
             
               
                   
                 Tubing Pickle 
                 2000 
                 gal 
               
               
                   
                 Injection rate fluid 
                 5 
                 gal/ft 
               
               
                   
                 Solvent preflush 
                 10 
                 gal/ft 
               
               
                   
                 Preflush 
                 20 
                 gal/ft 
               
               
                   
                 Acid preflush 
                 15 
                 gal/ft 
               
               
                   
                 HF acid 
                 10 
                 gal/ft 
               
               
                   
                 Overflush 
                 40 
                 gal/ft 
               
               
                   
                 Methanol-water 
                 2 
                 gal/ft 
               
             
          
           
               
                   
                 Displacement 
                 tubing volume 
               
               
                   
                   
               
             
          
         
       
     
     The treatment of the present invention alleviates any need for extensive design. Any gravel pack with production decline over time is a candidate. Users should be aware of decline rates versus predicted production decline resulting from reservoir depletion. Any decreased production in excess of that predicted by reservoir depletion curves is assumed to be a result of increased damage to the gravel pack. Treatment design is based on height of gravel pack screen in place. The height of screen is multiplied by the specified volume per foot of each fluid to establish injection volumes. 
     The tubing pickle must be circulated down via coiled tubing and up the coiled tubing-production tubing annulus. The pickle treatment may also be performed before coiled tubing is in the well bore and can be flushed with a gas such as nitrogen. All other fluids can be injected either through the coil tubing or down the production tubing with the coil tubing removed. All aqueous fluids are freshwater based with the exception of displacement which can be a sea water or brine. The treatment procedure is outlined in the following steps: 
     1) Circulate tubing pickle; 
     2) Establish injection rate of ½ to 1 bpm; 
     3) Pump first 4 stages at established rate; 
     4) Pump first 20 gal/ft overflush at established rate; 
     5) Increase pump rate by ½ bpm and pump 2 minutes; 
     6) Continue pumping overflush increasing rate ½ bpm at 2 minute intervals until max pressure is reached or frac is initiated; 
     7) Pump remainder of overflush at max rate achieved. 
     Pumping the treatment into the well can employ a coiled tubing unit, pressure pumping unit, and fluid tanks. Treatment rates are dictated by the pressure limitations of the pump and the diameter of the coiled tubing and infectivity into pack and formation. Estimates of formation fracture gradient must be obtained and injection rates kept at or below the rate necessary to impart fracturing pressure at the formation. 
     One potential application difficulty might arise if one portion of the perforated interval takes injected fluid much more easily than the rest of the perforations. If that is the case, the gravel pack may not be completely contacted and treated by the injected fluid train. Moving the coiled tubing end up and down the length of the screen interval during the injection procedure alleviates the possibility of injecting through the pack at only one point. This practice would maximize the probability of complete pack treatment. 
    
    
     
       BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS 
       For a further understanding of the nature, objects, and advantages of the present invention, reference should be had to the following detailed description, read in conjunction with the following drawings, wherein like reference numerals denote like elements and wherein: 
         FIG. 1  is a schematic, sectional elevation view of a well that has been completed using a gravel pack; 
         FIG. 2  is a fragmentary elevation view illustrating fines migration plugging a gravel pack; 
         FIG. 3  is a fragmentary elevation view of fines migration plugging a gravel pack and flowing into the open well bore; 
         FIG. 4  is a schematic, sectional elevation view of a step of the method of the present invention using tubing such as coil tubing to place a plug in the production tubing and circulating pickling fluid above the plug; 
         FIG. 5  is a schematic, sectional elevation view of a step of the method of the present invention illustrating circulating of pickling fluid; 
         FIG. 6  is a schematic, sectional elevation view of the method of the present invention showing solvent preflush with coil tubing fully extended through production packer and to bottom of gravel screen; 
         FIG. 7  is a transverse, sectional view showing solvent preflush flow into the producing formation; 
         FIG. 8  is a sectional elevation view of a method step of the present invention, showing solvent preflush with coil tubing extending through the production packer partially to a position next to the top of the gravel pack; 
         FIG. 9  is a sectional elevation view of the method of the present invention showing placement of a water preflush into the producing formation; 
         FIG. 10  is a transverse sectional view showing water preflush flow into the producing formation; 
         FIG. 11  is a sectional elevation view of the method of the present invention showing placement of an acid preflush on the producing formation; 
         FIG. 12  is a transverse sectional view of the method of the present invention showing placement of an acid preflush on the producing formation; 
         FIG. 13  is a sectional elevation view of the method of the present invention showing placement of hydrofluoric acid or HCL:HF blend on the producing formation; 
         FIG. 14  is a transverse sectional view of the method of the present invention showing placement of an hydrofluoric acid or HCL:HF blend on the producing formation; 
         FIG. 15  is a sectional elevation view of the method of the present invention showing placement of a water overflush in the producing formation; 
         FIG. 16  is a transverse sectional view of the method of the present invention showing placement of a water overflush in the producing formation; 
         FIG. 17  is a transverse sectional view of the method of the present invention showing placement of a water overflush in the producing formation with cross fracture flow; 
         FIG. 18  is a sectional elevation view of the method of the present invention showing placement of a methanol/water mixture; 
         FIG. 19  is a transverse, sectional view of the method of the present invention that illustrates the path of travel of fines from the gravel pack to the fracture and the fracture sealed; and 
         FIGS. 20-21  are graphical illustrations of test results that demonstrate increased hydrocarbon production for a test well after using the method of the present invention. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
       FIG. 1  shows a typical well that has been completed using a gravel pack. In  FIG. 1 , the oil and gas well  1  provides a borehole  2  that extends downwardly from the earth&#39;s surface  3 . Casing  4  can be used to line the well borehole  2  as shown in  FIG. 1 . A production tubing  5  extends internally of the casing  4  in a manner that is known in the art. The production tubing  5  extends downwardly to a position next to a producing formation  7 . A cemented annulus  6  can be formed in between producing formation  7  and casing  4 . Production packer  9  is placed in between production tubing  5  and casing  4  above the producing formation  7 . 
     A plurality of perforations  8  extend through cemented annulus  6  and communicate with the producing formation  7 . Gravel pack  10  is placed in between screen  11  and cemented annulus  6 . Oil and gas that is produced from well  1  flows from producing formation  7  through perforations  8 , then through gravel pack  10  and screen  11  to well bore  12 . Arrows  42  in  FIG. 1  schematically illustrate the flow of oil and gas from producing formation  7  to well bore  12 . 
     In  FIG. 2 , the gravel pack  10  is shown in more detail, including a number of different pieces of gravel  13  that can become clogged with fine particulate matter or fines  14 . These fines  14  flow into the perforations  8  and can clog the spaces between individual pieces of gravel  13  as indicated schematically by the arrow  15  in  FIG. 2 . The numeral  16  which indicates areas that have an accumulation of fines  14  and thus provide a flow impediment to hydrocarbon that is to be produced from formation  7  to well bore  12 . 
     In  FIG. 3 , another problem that is experienced by oil and gas wells  1  is illustrated. In  FIG. 3 , heavy particulate matter that has settled is indicated by the numeral  17 . Additionally,  FIG. 3  shows generally examples of erosion sites  18  that can be eroded by the flow of particulate matter that escapes the producing formation  7  and enters the well bore  12 . 
     In  FIGS. 4 and 5 , there is schematically illustrated the placement of pickling fluid or a “pickle”. A pickle is simply a fluid that is used to remove scale, rust, deposits or any other undesirable material or hydrocarbon (e.g. crude oil, paraffin, pipe dope, etc.) from the surface of the production tubing string  5  to expose metal surface to acid. Use of the pickle or the “pickling process” removes materials that may react undesirably with the treatment fluids that are to be used with the method in the present invention. The pickling process eliminates the possibility of creating undesirable secondary reactions or precipitates that might damage the producing formation  7 . 
     In  FIG. 4 , a pressure pump  19  can be used in combination with a coil tubing unit  20  to place the fluid that comprises the “pickle”. Such a coil tubing unit  20  is known in the art and utilizes an elongated coil tubing  26  having a lower end portion  27  that is lowered into the well  1 . Flow of the pickle is illustrated schematically by the arrows  28  for injecting the selected fluid and by the numeral  29  for removing it from the well. The pickle or pickling fluid is a combination of an acid, usually HCL and an organic solvent, usually Xylene. During this process of  FIGS. 4 and 5 , a plug  34  can be placed in the production tubing  5  at an elevation that is near the bottom of the production tubing  5  as shown in  FIGS. 4 and 5 . After the tubing is pickled, the remainder of the treatment can be placed into the gravel pack via the coiled tubing after removing the bridge plug and lowering the coil into position with the tubing end adjacent to the gravel pack screen. Alternatively, the remainder of the treatment fluids may be injected down the production tubing after retrieving the coiled tubing. The remainder of the illustrations show treatment through coiled tubing. 
       FIGS. 6 and 7  illustrate a solvent preflush. In  FIGS. 6 and 7 , a number of tanks  21 ,  22 ,  23 ,  24 ,  25  can be provided, each tank supplying a different fluid that can be used as part of a fluid train employed with the method of the present invention. The first tank  21  can contain the solvent preflush  30 . The solvent preflush  30  of tank  21  can be Xylene or methanol or other organic liquid capable of dissolving paraffin. This organic preflush is treated with a non-emulsifying surfactant to prevent emulsion blocks. The solvent preflush  30  is used to remove hydrocarbons (e.g. crude oil, paraffin, etc.). Solvent preflush also acts as a barrier between formation fluids. The solvent preflush  30  is injected into the well bore below production packer  9 . A sufficient volume of the solvent preflush  30  is injected into the well (using pump  19 , coil tubing unit  20  and its coil tubing  26 ) so that the solvent preflush  30  extends into the gravel pack  10 , perforations  8 , and a part of the producing formation  7 . Arrows  32  in  FIG. 7  illustrate schematically the flow of solvent preflush  30  into the surrounding formation  7 . 
     Tank  22  can contain a water based preflush  33  which is injected using coil tubing unit  20  and its coil tubing  26 . This fluid consists of water, NH 4 Cl for clay stabilization, a water-wetting surfactant, and a non-emulsifying surfactant. As shown in  FIG. 8 , the water based preflush  33  is transmitted via the coil tubing  26  immediately behind the solvent preflush  30 . In  FIGS. 8 and 9 , the water based preflush  33  pushes the solvent preflush  30  further into the surrounding producing formation  7 . The water based preflush  33  maintains compatibility with clays before and after ion exchange occurs. The water based preflush also acts as barrier between formation fluids and treating fluids.  FIG. 9  shows the relative positions of the solvent preflush  30  and the water based preflush  33 , the interface being indicated as solvent/preflush interface  31 . 
     In  FIGS. 9-10 , an acid preflush  36  of tank  23  is pumped into the well bore using coil tubing unit  20  and its coil tubing  26 .  FIG. 10  shows a sectional view with arrows  35  illustrating the radial flow of acid preflush through the gravel pack  10  and into the surrounding formation  7 . The acid preflush  36  removes any carbonates present. This fluid consists of HCL, a combination of HCL and an organic acid such as acetic or formic for clay protection, or just the organic acid combined with wetting agents, non-emulsifying surfactant, and corrosion inhibitors. 
     In  FIGS. 10-12 , the relative positions of the solvent/preflush  30 , water based preflush  33  and acid preflush  36  are shown. The numeral  37  illustrates the acid/water based preflush interface in  FIG. 11 . 
     After the placement of the acid preflush  36 , a hydrochloric acid, a hydrofluoric acid blend  39  from tank  24  can be added to the well. As with the other fluids, the hydrofluoric acid blend  39  can be transmitted into the well using coil tubing unit  20  and its coil tubing  26 . Arrows  38  in  FIG. 12  illustrate the radial movement of the hydrofluoric acid  39  through the gravel pack  10  and into the surrounding formation  7 . 
     The hydrofluoric acid blend  39  removes hydrofluoric soluble damage. After the hydrofluoric acid blend  39  is added to the well, an overflush  43  consists of either water, HCL followed by water or an organic acid solution followed by water, can be placed into the formation as illustrated in  FIGS. 13-14 . Overflush  43  pushes the hydrofluoric acid blend (HF) through the gravel pack  10  and into the formation  7  to spend the acid and remove damage. 
       FIGS. 15-16  show the overflush in formation matrix flow. In this step, fine particulate matter or fines  14  are swept from the gravel pack  10  into the matrix/producing formation  7 . 
       FIG. 17  illustrates that a hydraulic fracture  41  can be formed. Fine particulate matter  14  can be transported into the fracture with overflush fluid. In  FIG. 17 , the flow of fine particulate matter  14  into fracture  41  is illustrated schematically by arrow  45 . 
     In  FIG. 18 , the method of the present invention has been completed. A methanol water mixture  44  is added to the well bore using the coil tubing unit  20  and its coil tubing  26 . The methanol/water mixture (e.g. a 50:50 mix) is a displacement fluid that pushes the overflush  43  through the gravel pack  10 .  FIG. 18  is a sectional view that illustrates a sweeping of the fine particulate matter from the gravel pack into the surrounding formation and fracture. In  FIG. 19 , the fracture has closed, trapping fine particulate matter  14 . The closed fracture is indicated as numeral  46 . 
       FIGS. 20-21  are laboratory test results that illustrate increased flow rate after simulated treatment of a test well using the method and apparatus of the present invention. 
     The following is a list of part numbers and corresponding descriptions as used herein. 
     
       
         
               
             
               
               
             
               
               
             
           
               
                   
               
               
                 PARTS LIST 
               
             
          
           
               
                 Part Number 
                 Description 
               
               
                   
               
             
          
           
               
                 1 
                 oil and gas well 
               
               
                 2 
                 borehole 
               
               
                 3 
                 earth&#39;s surface 
               
               
                 4 
                 casing 
               
               
                 5 
                 production tubing 
               
               
                 6 
                 cemented annulus 
               
               
                 7 
                 producing formation 
               
               
                 8 
                 perforation tunnel 
               
               
                 9 
                 production packer 
               
               
                 10 
                 gravel pack 
               
               
                 11 
                 screen 
               
               
                 12 
                 well bore 
               
               
                 13 
                 gravel 
               
               
                 14 
                 fine particulate matter (fines) 
               
               
                 15 
                 arrow indicating flow path 
               
               
                 16 
                 flow impediment from bridged fine 
               
               
                 17 
                 settled heavy particulate matter 
               
               
                 18 
                 erosion site 
               
               
                 19 
                 pump 
               
               
                 20 
                 coil tubing unit 
               
               
                 21 
                 tank 
               
               
                 22 
                 tank 
               
               
                 23 
                 tank 
               
               
                 24 
                 tank 
               
               
                 25 
                 tank 
               
               
                 26 
                 coil tubing 
               
               
                 27 
                 lower end 
               
               
                 28 
                 arrow 
               
               
                 29 
                 arrow 
               
               
                 30 
                 solvent preflush 
               
               
                 31 
                 solvent preflush interface 
               
               
                 32 
                 arrow indicating fluid injection path 
               
               
                 33 
                 water based flush/overflush 
               
               
                 34 
                 plug 
               
               
                 35 
                 arrow 
               
               
                 36 
                 acid preflush 
               
               
                 37 
                 acid preflush interface 
               
               
                 38 
                 arrow 
               
               
                 39 
                 hydrofluoric acid 
               
               
                 40 
                 HF acid interface 
               
               
                 41 
                 fracture 
               
               
                 42 
                 arrow 
               
               
                 43 
                 water overflush 
               
               
                 44 
                 methanol/water mixture 
               
               
                 45 
                 arrow indicating flow into fracture 
               
               
                 46 
                 closed fracture 
               
               
                   
               
             
          
         
       
     
     All measurements disclosed herein are at standard temperature and pressure, at sea level on Earth, unless indicated otherwise. All materials used or intended to be used in a human being are biocompatible, unless indicated otherwise. 
     The foregoing embodiments are presented by way of example only; the scope of the present invention is to be limited only by the following claims.

Technology Classification (CPC): 2