Methods and materials for evaluating and improving the production of geo-specific shale reservoirs

Abstract

Diagnostic or assisting lateral wellbores can have a significant benefit for injecting and distributing treatment fluids and other materials within complex fracture networks that surpass conventional injection at the primary lateral wellbore perforations for acquiring empirical knowledge about the numerous processes that influence shale reservoir production which occur after primary shale reservoir stimulation. Injection of diagnostic treatment fluids or treating chemicals for understanding production optimization, such as water-block removal, fines migration removal, and treating chemicals for prevention of scale and paraffin deposition, can be injected along the diagnostic lateral wellbore or frac interval lateral wellbores to give broader and/or deeper distribution into the fracture network than by using mono-bore-centric diagnostic injection techniques. Diagnostic lateral treatment techniques can also improve fluid or chemical distribution, such as the use of gas injection to help energize fluid flow to the primary lateral during production optimization treatments, including reverse diversion methodology.

1 . A method of acquiring data for improving a flow of hydrocarbons from at least one primary lateral wellbore in a subsurface shale volume characterized by having at least one assisting lateral wellbore substantially adjacent to the primary lateral wellbore that has been previously stimulated and where the at least one primary lateral wellbore has a lateral length and comprises at least one fracture network along the lateral length, where the method comprises:
 a sub-method selected from the group consisting of:
 (1) ultra-high resolution imaging utilizing moderately-close to ultra-close proximity imaging instruments and processes for determining reservoir production flow within the fractured network to the primary lateral wellbore; 
 (2) introducing at least one diagnostic agent into the at least one primary lateral wellbore through the fracture network and the at least one assisting lateral wellbore; 
 (3) introducing at least one treatment fluid into the at least one lateral wellbore and the fracture network for treating the at least one lateral wellbore and/or the fracture network with the treatment fluid; 
 (4) imaging flow and changes of flow within the fracture network; and 
 (5) combinations thereof. 
   
     
     
         2 . The method of  claim 1  where the at least one primary lateral wellbore and the at least one assisting lateral wellbore are:
 within about 50 to about 600 feet (about 15 to about 183 meters) of each other, and 
 within 0° to about 70° of the same angle as each other. 
 
     
     
         3 . (canceled) 
     
     
         4 . The method of  claim 1  where the at least one assisting lateral wellbore is a diagnostic lateral wellbore, and the sub-method is sub-method (1) and in the sub-method (1) the ultra-high resolution imaging comprises the use of an array of acoustic generators positioned in the diagnostic lateral wellbore and an array of acoustic sensors positioned along the primary lateral wellbore, and the method further comprises acquiring seismic signals from the acoustic generators by the acoustic sensors. 
     
     
         5 . The method of  claim 1  where there is more than one assisting lateral wellbore, where the assisting lateral wellbores are diagnostic lateral wellbores, the sub-method is sub-method (1) and where the sub-method is (1) ultra-high resolution imaging comprising using an array of acoustic generators positioned in at least one of the diagnostic lateral wellbores, or positioned in the primary lateral wellbore, and the method further comprises acquiring the seismic signals from acoustic sensors positioned along different diagnostic lateral wellbores and/or the primary lateral wellbore. 
     
     
         6 . The method of  claim 1  where the at least one assisting lateral wellbore is a diagnostic lateral wellbore, and the sub-method is sub-method (2) and in the sub-method (2) the diagnostic agent comprises at least one tracer selected from the group consisting of organic and inorganic tracers, where the tracer is present in a fluid and where the tracer is present in the fluid in an amount ranging from about 0.001 to about 50,000 ppm. 
     
     
         7 - 8 . (canceled) 
     
     
         9 . The method of  claim 1  where the at least one assisting lateral wellbore is a diagnostic lateral wellbore, and the sub-method is sub-method (2) and in the sub-method (2) the diagnostic agent is selected from the group consisting of:
 inorganic scale removal solvents; 
 paraffin removal solvents; 
 asphaltene removal solvents; 
 polymer residue cleanup solutions; 
 water-block removal solutions; and 
 combinations thereof. 
 
     
     
         10 . The method of  claim 1  where the at least one assisting lateral wellbore is a diagnostic lateral wellbore, and the sub-method is sub-method (3) and in the sub-method (3) the at least one treatment fluid is selected from the group consisting of:
 water-block removal solutions; 
 a fluid for fines migration removal and/or fines fixation; 
 scale deposition inhibitors; 
 paraffin deposition inhibitors; 
 fluids to remove residual polymer; 
 fluids to remove inorganic scale; 
 fluids to remove organic deposits; 
 diverter materials; and 
 combinations thereof. 
 
     
     
         11 . The method of  claim 1  further comprising at least one fracture interval injection lateral wellbore extending from the at least one assisting lateral wellbore in the direction of the at least one lateral wellbore, where the at least one fracture interval injection lateral wellbore is in fluid communication with the fracture network. 
     
     
         12 . The method of  claim 1  the fracture network is a first fracture network and where:
 the at least one primary lateral wellbore and the at least one assisting lateral wellbore each have a heel and toe with a lateral wellbore length between the heel and toe; 
 the at least one first shale interval is near the toe of the at least one primary lateral wellbore and the at least one assisting lateral wellbore, the at least one primary lateral wellbore and the at least one assisting lateral wellbore being within the at least one first shale interval; 
 there is present a second shale interval between the first shale interval and the heel of the at least one primary lateral wellbore and the at least one assisting lateral wellbore, the at least one primary lateral wellbore and the at least one assisting lateral wellbore being within the second shale interval; 
 
       where the method further comprises:
 temporarily isolating a portion of the at least one primary lateral wellbore within the at least one first shale interval from the second shale interval; 
 temporarily isolating a portion of the at least one assisting lateral wellbore within the at least one first shale interval from the second shale interval; 
 hydraulically fracturing second shale interval from the at least one primary lateral wellbore in the direction of the at least one assisting lateral wellbore to create a second fracture network; 
 a sub-method selected from the group consisting of:
 (1) ultra-high resolution imaging utilizing moderately-close to ultra-close proximity imaging instruments and processes for determining reservoir production flow within the fractured network to the primary lateral wellbore; 
 (2) introducing at least one diagnostic agent into the at least one primary lateral wellbore through the second fracture network and the at least one assisting lateral wellbore; 
 (3) introducing at least one treatment fluid into the at least one lateral wellbore and the second fracture network for treating the at least one lateral wellbore and/or the first fracture network with the treatment fluid; 
 (4) imaging flow and changes of flow within the fracture network; and 
 (5) combinations thereof. 
 
 
     
     
         13 . The method of  claim 12  where the hydraulic fracturing comprises a stop/start-low viscosity/high viscosity staged diversion process to create complex fractures. 
     
     
         14 . The method of  claim 12  where the method further comprises creating at least one planar fracture extending from the at least one primary lateral wellbore in the direction of the at least one assisting lateral wellbore so that the first fracture network, the second fracture network, and the planar fracture are in fluid communication with each other. 
     
     
         15 . The method of  claim 1  where the at least one assisting lateral wellbore is a diagnostic lateral wellbore, and the method further comprises:
 disposing at least one diagnostic device in the at least one diagnostic lateral wellbore; 
 emitting at least one signal between the subsurface volume and the at least one diagnostic device; 
 detecting at least one received signal associated with the at least one emitted signal; and 
 analyzing the at least one received signal to ascertain at least one parameter of the at least one primary lateral wellbore and/or the subsurface volume. 
 
     
     
         16 - 17 . (canceled) 
     
     
         18 . The method of  claim 1  where the at least one primary lateral wellbore and at least one assisting lateral wellbore are in different planes of the subsurface volume. 
     
     
         19 . The method of  claim 1  where the at least one primary lateral wellbore and the at least one assisting lateral wellbore are at an angle to each other ranging from about 2° to about 70°. 
     
     
         20 . The method of  claim 15  where the at least one parameter is used to decide to refracture the subsurface shale volume and decide how to refracture the subsurface shale volume using a process selected from the group consisting of generating new fractures, injecting diverting fluids, increasing fracture complexity, improving proppant distribution in existing and new fractures, and combinations thereof. 
     
     
         21 . A method of acquiring data for improving a flow of hydrocarbons from at least one primary lateral wellbore in a subsurface shale volume characterized by having at least one assisting lateral wellbore comprising a diagnostic lateral wellbore substantially adjacent to the primary lateral wellbore that has been previously stimulated and where the at least one primary lateral wellbore has a lateral length and comprises at least one fracture network along the lateral length, where the method comprises:
 a sub-method consisting of ultra-high resolution imaging comprises using an array of acoustic generators positioned in the diagnostic lateral wellbore and an array of acoustic sensors positioned along the primary lateral wellbore, and the method further comprises acquiring seismic signals from the acoustic generators by the acoustic sensors;   
       where the at least one primary lateral wellbore and the at least one assisting lateral wellbore are:
 within about 50 to about 600 feet (about 15 to about 183 meters) of each other, and 
 within 0° to about 70° of the same angle as each other. 
 
     
     
         22 . The method of  claim 21  where:
 the at least one primary lateral wellbore and at least one assisting lateral wellbore are in different planes of the subsurface volume; and 
 the at least one primary lateral wellbore and the at least one assisting lateral wellbore are at an angle to each other ranging from about 2° to about 70°. 
 
     
     
         23 . A method of acquiring data for improving a flow of hydrocarbons from at least one primary lateral wellbore in a subsurface shale volume characterized by having at least one assisting lateral wellbore comprising a diagnostic lateral wellbore substantially adjacent to the primary lateral wellbore that has been previously stimulated and where the at least one primary lateral wellbore has a lateral length and comprises at least one fracture network along the lateral length, where the method comprises:
 a sub-method consisting of introducing at least one diagnostic agent comprising a tracer into the at least one primary lateral wellbore through the fracture network and the at least one assisting lateral wellbore, where the tracer is selected from the group consisting of organic and inorganic tracers, where the tracer is present in a fluid and where the tracer is present in the fluid in an amount ranging from about 0.001 to about 50,000 ppm   
       where the method of further comprises at least one fracture interval injection lateral wellbore extending from the at least one assisting lateral wellbore in the direction of the at least one lateral wellbore, where the at least one fracture interval injection lateral wellbore is in fluid communication with the fracture network. 
     
     
         24 . The method of  claim 23  where the at least one primary lateral wellbore and the at least one assisting lateral wellbore are:
 within about 50 to about 600 feet (about 15 to about 183 meters) of each other, and 
 within 0° to about 70° of the same angle as each other.