Method for subsurface injection conformance improvement using micro calcium carbonate particles

1 . A method of improving subsurface injection conformance and sweep efficiency using extremely small calcium carbonate particles having a median particle size of about 1 μm to no more than 140 μm to shut off an injected fluid flow into thief zones within a subsurface reservoir and to divert the injected fluid to desired hydrocarbon, geothermal or carbon storage zones, the method comprising:

evaluating and diagnosing of the subsurface reservoir and the thief zones, thereby estimating and defining pore size and fracture width of the thief zone;

engineering and designing of a treatment plan for sealing pores and fractures of the thief zone, thereby determining the required calcium carbonate particle size, spectrum and concentration of the treatment plan;

introducing the calcium carbonate particles according to the treatment plan into the thief zones to create seals over the thief zones, wherein at least a portion of the calcium carbonate particles is non-spherical;

computing and estimating of a permeability of the created seals over the thief zone thereby predicting and defining post-treatment permeability; and

determining injection conformance improvement, injected fluid rate distribution over different zones, and estimating oil or geothermal production rate increase, and a ratio of an injection rate to a withdrawal rate.

2 . The method of claim 1 , wherein the introducing comprises injecting the calcium carbonate particles according to the treatment plan into an injection well for enhanced oil recovery in oil and gas production, or for enhanced heat exchange and production in enhanced geothermal systems, or for carbon capture, utilization and storage.

3 . The method of claim 1 , further comprising, injecting water, CO 2 , water-alternating-gas, or water mixed with surfactant or polymeric chemicals into an injection well.

4 . The method of claim 1 , further comprising, collecting of reservoir description data, subsurface injection history data and testing data for evaluating and defining the pore size and fracture width of the subsurface thief zones of fractures and high-permeability streaks.

5 . The method of claim 4 , wherein the pore size and fracture width are defined from well logs, core analysis and permeability, and combinations thereof.

6 . The method of claim 1 , wherein engineering and designing of the treatment plan further comprises engineering calcium carbonate particle size, spectrum and concentration, for shutting off injected fluid flow into the thief zones and diverting the injected fluid into desired hydrocarbon, geothermal or carbon storage zone.

7 . The method of claim 6 , wherein engineering calcium carbonate comprises one or more of calcium carbonate particle size, spectrum and concentration.

8 . The method of claim 7 , wherein the calcium carbonate particles are selected to have a size and shape spectrum that build bridges in the thief zones and create desired low-permeability seals over the thief zones.

9 . The method of claim 7 , wherein the treatment plan further comprises fibers and secondary granular materials.

10 . The method of claim 9 , wherein the secondary granular particles cause no permeability reduction in hydrocarbon or geothermal zones and the extremely small calcium carbonate particles are dissolvable using acid.

11 . The method of claim 7 , the method further comprising:

making a batch of slurry consisting of fluid, calcium carbonate particles and other optional fracture plugging agents according to the treatment plan;

pumping the slurry of fluid mixing with calcium carbonate particles into an injector;

recording a pumping rate and an injection pressure;

observing any injection pressure increase;

stopping pumping when the injection pressure reaches a pre-determined value or when the pumping of a design slurry volume is completed;

analyzing injection data to determine treatment efficiency; and

evaluating injection conformance improvement and oil or geothermal production increase.

12 . The method of claim 11 , wherein the calcium carbonate particles have an apparent bulk density of at least 0.6 g/cc to no more than 3.0 g/cc.

13 . The method of claim 11 , wherein the calcium carbonate particles have a concentration of at least 0.5 to 5% by volume or 0.2 to 50 pound per barrel.

14 . The method of claim 11 , wherein the slurry volume ranges from tens of barrels to tens of thousands of barrels, with the volume selected based on the size and severity of the thief zones.

15 . The method of claim 1 , wherein the treatment plan comprises multiple batches of treatment with at least a first batch containing calcium carbonate particles with a median size ranging from 10 μm to 140 μm for plugging large fractures of the thief zones, and a second batch containing calcium carbonate particles with a median particle size of 10 μm or less for plugging medium fractures and pores in the seals formed by the first batch, resulting in plugging and sealing the thief zones.

16 . The method of claim 1 , further comprising: computing and optimizing the porosity and permeability of the created seals over the thief zones from the treatment plan.

17 . The method of claim 1 , further comprising: computing and simulating injected fluid flow rate profiles before and after the treatment plan.

18 . The method of claim 1 , wherein the treatment plan further comprises thief-zones plugging agents selected from fibers and/or secondary granular materials.

19 . The method of claim 1 , further comprising: selecting a wettability of the extremely small calcium carbonate particles based on the reservoir.

20 . The method of claim 1 , wherein the extremely small calcium carbonate particles create three-dimensional blockages of fluid pathways over the fracture length and width, and the height of the thief zones.