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US-12618591-B2 - Systems and processes for stimulating subterranean geologic formations

US12618591B2US 12618591 B2US12618591 B2US 12618591B2US-12618591-B2

Abstract

Systems and processes for stimulating subterranean geologic formations to create an artificial stress barrier. An injector well extends from surface to a subterranean geologic formation. After cementing and perforating, the injector well utilizes single-path injection through a coiled tubing and a pump. The coiled tubing is inserted into the injector well to a first stimulation zone. A first stimulation fluid is pumped through the coiled tubing at rate R1 into the first stimulation zone, spaced apart from a target stimulation zone in the formation. The coiled tubing is then inserted into the injector well to the target stimulation zone, then main stimulation treatment fluid at rate R2 is pumped through the coiled tubing at the target stimulation zone, where R2>R1. A sub-system is included that measures blocking effect on the main stimulation fluid in the target stimulation zone by the first stimulation fluid in the first stimulation zone.

Inventors

  • Jonathan Alcantar
  • Gabrijel Grubac
  • Abdel Wadood Mohamed El-Rabaa
  • Sriram Vasantharajan

Assignees

  • MAZAMA ENERGY, INC.

Dates

Publication Date
20260505
Application Date
20250422

Claims (20)

  1. 1 . A system for stimulating subterranean geologic formations, comprising: (a) an injector well extending from a surface to a subterranean geologic formation and configured to be cemented and perforated; (b) a coiled tubing rig including the coiled tubing and a pump configured to stimulate the subterranean geologic formation by: (i) injecting the coiled tubing into the injector well to a first stimulation zone; (ii) pumping through the coiled tubing one or more first stimulation fluids at a first rate R1 into the first stimulation zone in the subterranean geologic formation, the first stimulation zone spaced apart from and above a target stimulation zone in the subterranean geologic formation; (iii) injecting the coiled tubing into the injector well to the target stimulation zone; (iv) pumping through the coiled tubing one or more main stimulation treatment fluids at a second rate R2 at the target stimulation zone in the subterranean geologic formation, where R2>R1; and (c) a sub-system configured to measure blocking effect in the subterranean geologic formation by the one or more first stimulation fluids in the first stimulation zone, the blocking effect being restricting height of the one or more main stimulation treatment fluids in the target stimulation zone by the presence of the one or more first stimulation fluids in the first stimulation zone.
  2. 2 . The system of claim 1 including one or more producer wells, wherein the subterranean geologic formation is a geothermal formation, and the injector well and the one or more producer wells is in dry hot rock (DHR).
  3. 3 . The system of claim 2 wherein the one or more of the producer wells is selected from an open hole, a well comprising a cemented liner, a well comprising an uncemented liner, and a well selectively segmented by embedded cylinder pipe and sliding sleeves or pre-perforated liner.
  4. 4 . The system of claim 1 wherein the injector well is a vertical/deviated well and R1 is a rate and volume capable of tensile fracturing the subterranean geologic formation producing a stress/pressure in the subterranean geologic formation above minimum horizontal stress and introducing a net pressure increase in the subterranean geologic formation.
  5. 5 . The system of claim 1 wherein the injector well is a horizontal well at the target stimulation zone and the first stimulation zone is shallower than the target stimulation zone, and R1 is a rate and volume capable of limiting effects of intersecting natural fractures creating complex fracture geometries selected from: (i) a small tensile fracture producing a stress/pressure in the subterranean geologic formation above minimum horizontal stress in the subterranean geologic formation; and (ii) a hydroshearing fracture, the hydroshearing fracture producing a stress/pressure in the subterranean geologic formation below minimum horizontal stress in the subterranean geologic formation.
  6. 6 . The system of claim 1 wherein the sub-system measures improvement in injectivity index (Q/DP).
  7. 7 . The system of claim 1 wherein the sub-system measures pressure decline as compared by calculation of geothermal formation transmissivity (Kh/μ) improvement of existing natural fractures, where Kh is horizontal conductivity and μ is downhole fluid viscosity.
  8. 8 . The system of claim 1 wherein the pump is one or more surface pumps.
  9. 9 . The system of claim 1 wherein the one or more first stimulation fluids and the one or more main stimulation fluids are independently selected from water, brine, viscosified fluids, energizing fluids, and polymer based fluids.
  10. 10 . The system of claim 1 wherein the injector well is configured to utilize dual injection paths comprising a first injection path through the coiled tubing and a second injection path through an annulus between the coiled tubing and casing, and wherein the pump comprises a first pump for the first injection path and a second pump for the second injection path.
  11. 11 . The system of claim 10 wherein the first pump is configured to pump the one or more first stimulation fluids through the coiled tubing, and the second pump is configured to pump the one or more main stimulation fluids through the annulus, wherein the one or more first stimulation fluids and the one or more main stimulation fluids are different in one or more physical and/or chemical properties.
  12. 12 . The system of claim 1 wherein the one or more first stimulation fluids or the one or more main stimulation fluids, or both comprises a propping agent.
  13. 13 . A process for stimulating subterranean geologic formations, comprising: (a) providing an injector well extending from a surface to a subterranean geologic formation; (b) perforating the injector well at a first stimulation zone and at a target stimulation zone in the subterranean geologic formation, the target stimulation zone spaced apart from and below the first stimulation zone; (c) injecting coiled tubing into the injector well to the first stimulation zone; (d) pumping one or more first stimulation fluids through the coiled tubing at a first rate R1 into the subterranean geologic formation at the first stimulation zone; (e) injecting the coiled tubing into the injector well to the target stimulation zone; and (f) pumping one or more main stimulation fluids through the coiled tubing at a second rate R2 into the subterranean geologic formation at the target stimulation zone, where R2>R1, wherein the one or more first stimulation fluids and the one or more main stimulation fluids are the same or different, and (g) measuring blocking effect in the subterranean geologic formation by the one or more first stimulation fluids in the first stimulation zone, the blocking effect being restricting height of the one or more main stimulation treatment fluids in the target stimulation zone by the presence of the one or more first stimulation fluids in the first stimulation zone.
  14. 14 . The process of claim 13 including producing geothermal heat through one or more producer wells, wherein the subterranean geologic formation is a geothermal formation, and the injector well and the one or more producer wells is in dry hot rock (DHR).
  15. 15 . The process of claim 14 wherein the one or more producer wells are selected from an open hole, a well comprising a cemented liner, a well comprising an uncemented liner, and a well selectively segmented by embedded cylinder pipe and sliding sleeves or pre-perforated liner.
  16. 16 . The process of claim 13 wherein the measuring of blocking effect comprises measuring improvement in injectivity index (Q/DP), where Q is volume flow rate and DP is pressure drop.
  17. 17 . The process of claim 13 wherein the measuring of blocking effect comprises measuring pressure decline as compared by calculation of geothermal formation transmissivity (Kh/μ) improvement of existing natural fractures, where Kh is horizontal conductivity and μ is downhole fluid viscosity.
  18. 18 . The process of claim 13 wherein the pumping is provided by one or more surface pumps.
  19. 19 . The process of claim 13 wherein the one or more first stimulation fluids and the one or more main stimulation fluids are independently selected from water, brine, viscosified fluids, energizing fluids, and polymer based fluids.
  20. 20 . The process of claim 13 wherein the injector well is selected from vertical/deviated injector wells and horizontal injector wells.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS This application is entitled to and claims the benefit of earlier filed provisional application No. 63/662,142, filed Jun. 20, 2024, under 35 U.S.C. § 119(e), and nonprovisional application Ser. No. 18/802,048, filed Aug. 13, 2024, which earlier filed provisional and nonprovisional applications are incorporated by reference herein in their entirety. BACKGROUND INFORMATION Technical Field The present disclosure relates to systems and processes for stimulating subterranean geologic formations to create an artificial stress barrier, and more particularly to systems and processes for stimulating subterranean geologic formations to create an artificial stress barrier between injector and producer wells in enhanced geothermal systems. Background Art A naturally occurring geothermal system, known as a hydrothermal system, is defined by three key elements: heat, fluid, and permeability at depth. An Enhanced Geothermal System (EGS) is a man-made reservoir, created where there is hot rock but insufficient or little natural permeability or fluid saturation. In an EGS, fluid is injected into the subsurface under carefully controlled conditions, which cause pre-existing fractures to re-open, creating permeability. What is an Enhanced Geothermal System (EGS)? U. S. Dept. of Energy, DOE/EE-0785 September 2012. A different approach, closed-loop geothermal systems (CLGS), overcomes permeability issues by circulating a working fluid through a sealed downhole heat exchanger to absorb and transport heat. CLGS is a versatile technology that can be implemented in a wide variety of different well pipe configurations using a choice of working fluids (such as water and sCO2) to optimize site specific costs and performance. Muir, New Opportunities and Applications for Closed-Loop Geothermal Energy Systems, Geothermal Rising Bulletin, December 2020, Vol. 49, No. 4. Extraction of heat from Dry Hot Rock (DHR) presents several efficiency and power advantages over other EGS or CLGS approaches for geothermal energy recovery. To efficiently extract DHR heat, it is necessary to create a network of fractures to connect an injector well with one or more producer wells. However, in contrast with stimulation and extraction from hydrocarbon-bearing formations, stress barriers in geothermal reservoirs are not as prevalent in containing a fracture in terms of height during stimulation. In fact, fracture geometries grow in height more than compared to length. Moreover, dry hot rock formations are typically more homogenous than shales and stress barriers are weak. The geometry of a fracture produced by stimulation depends on the stress contrast between overburden (vertical stress, or Sv) and minimum horizontal stress (Shmin). During the propagation of the fracture, it will be easier to break through formations (overburden) than to create more length as energy is lost in at the tip of the fracture. To address these problems, geothermal projects have started to use stimulation techniques that have shown successes in the O&G (oil and gas) industry to stimulate hydrocarbon-bearing formations, such as use of slickwater fracs, crosslinked fluids, limited entry, and completion designs using devices such as sleeves. These technologies have started to become prevalent in geothermal wells but do not address the height control of a fracture, which remains an unsolved problem. As may be seen, current practices may not be adequate for all circumstances, and do not address the noted problems with respect to extracting heat from DHR. There remains a need for more robust systems and processes for stimulating subterranean geologic formations, and in particular geothermal formations. The systems and processes of the present disclosure are directed to these needs. SUMMARY In accordance with the present disclosure, systems and processes are described which reduce or overcome many of the faults of previously known systems and processes. The systems and processes of the present disclosure create an artificial stress barrier prior to the main stimulation to provide the fracture propagation to be contained in the target interval. This method can be applied in vertical, deviated and horizontal wells, regardless of temperature of the formation and regardless of the completion of the well. A first aspect of the disclosure are systems for stimulating subterranean geologic formations (in certain embodiments for stimulating subterranean geologic formations between injector and producer fractures in DHR wells) to create an artificial stress barrier comprising (or consisting essentially of, or consisting of): (a) an injector well extending from a surface to a subterranean geologic formation and configured to be perforated;(b) a pump configured to stimulate the subterranean geologic formation by: (i) forming an artificial stress barrier at a first position in the subterranean geologic formation by pumping one or more first fluids at a