US20200400001A1

US20200400001A1 - Method for treating hydraulically-fractured wells in shales

Info

Publication number: US20200400001A1
Application number: US16/838,360
Authority: US
Inventors: Kenneth Kibodeaux; Ivan Edward Terez
Original assignee: Individual
Current assignee: Individual
Priority date: 2019-06-24
Filing date: 2020-04-02
Publication date: 2020-12-24

Abstract

The present invention is directed to an improved method for the production of hydrocarbons from shales. A mixture of heated water vapor and solvent gases are injected into the formation through the wellhead, and the well and fracture network are filled with steam. The injection is ceased and the heated water vapor and solvent gases are allowed to soak, allowing the rock to take in the heat of the steam in the fractures via thermal conduction. The well is then opened allowing the well to produce hydrocarbons, and pressure of fluid in the fractures to drop. Oil and gas from the reservoir will then flow into the well and to the surface.

Description

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates generally to methods and systems for production of hydrocarbons from various subsurface formations such as hydrocarbon-containing formations. More specifically, it is directed to a cyclic hot-gas well treatment of hydraulically-fractured wells in shales. It should be noted that shales is a term that refers to hydrocarbon-rich source-rock formations with ultra-low permeability which in recent years have been exploited as oil & gas reservoirs, enabled by the advent of multi-stage fracturing in horizontal wellbores. The shales upon which the invention may be employed have no restrictions on their concentrations of bitumen and kerogen.

2. Description of the Prior Art

Hydrocarbons obtained from subterranean formations such as shales are often used as energy resources, as feedstocks, and as consumer products. Concerns over depletion of available hydrocarbon resources and concerns over declining overall quality of produced hydrocarbons have led to development of processes for more efficient recovery, processing and/or use of available hydrocarbon resources. In-situ processes may be used to remove hydrocarbon materials from subterranean formations. Chemical and/or physical properties of hydrocarbon material in a subterranean formation may need to be changed to allow hydrocarbon material to be more easily removed from the subterranean formation. The chemical and physical changes may include in-situ reactions that produce removable fluids, composition changes, solubility changes, density changes, phase changes, and/or viscosity changes of the hydrocarbon material in the formation. A fluid may be, but is not limited to, a gas, a liquid, an emulsion, a slurry, and/or a stream of solid particles that has flow characteristics similar to liquid flow. Shales are attractive because they have large quantities of high quality oil. However they virtually always suffer from low recovery factors, for multiple technical reasons. First, liquid compressibility is low compared to gas, causing rapid rate decline.
Second, oil mobility is low compared to gas, leading to very small production rates. The oil-mobility term from Darcy's Law has three elements (Kro*K/μo), all three of which lead to poor oil productivity for shales. Rock permeability K is extremely low for both shales. Oil (oleic liquid) viscosity μois high compared to the vapor in shale gas. Relative permeability for oil Kro is lower than for gas (gas resides in the larger pore networks). Furthermore, eventually pressure will drop below bubble point at the fracture face. The exsolved gas will reside in largest pores, greatly reducing oil relative permeability at the fracture face, creating a flow barrier to oil production. This suggests the need for an effective stimulation/enhancement technique that allows the oil-in-place to flow to the fracture through the vapor phase. It should be noted that the term fracture, for purposes of this invention it means not only the propped fracture lobes connected directly to the horizontal well, it also refers to the unpropped network of natural microcracks in the native rock that comprises the SRV, or Stimulated Rock Volume. These microcracks are activated during the high-pressure fluid injection process known as hydraulic fracturing, which was performed prior to oil & gas production. For gas wells, since pressure is lowest at the fracture face, the dew point is often passed and liquid has built up, which restricts production into the fractures. Also, in the vapor phase large amount of methane exists adsorbed against the rock surfaces as a condensed phase. A method is needed that will take away liquid blocking at the fracture face and/or adsorbed methane in the in-situ gas. Furthermore, fluids used to create hydraulic fracture often contain polymers to improve fracture creation. However the polymers can create gels in the proppant that decreases permeability in the fractures and thereby restricts production rates. A method is needed to remove this problematic polymer from the propped fracture space.
Poor performance in shales have engendered a desperate need for production enhancement methods. There has been some recent use of gas injection in fractured shales. Since there is a small region of mobile gas close to the fracture face, some of the gas can enter the matrix. The contact of high-pressure gas with oil, both at the fracture face, and for a tiny depth-of-penetration into the matrix, allows for diffusion of gas into the oil during the injection cycle. During the production cycle, the gas is produced back, and carries with it some of the oil components. The process is somewhat effective because 1) it relies on vapor-phase flow in the matrix for carrying the initial oil components out to the fracture, and 2) because the surface area of rock face that the process acts on is enormous in a multi-stage fractured horizontal well, so a small invasion depth is sometimes adequate. However the recovery factor is still very small.
Accordingly, the present invention provides an improved method for the production of hydrocarbons from shales. A mixture of heated water vapor and solvent gases are injected into the formation through the wellhead and the well and fracture network are filled with steam. The injection is ceased and the heated water vapor and solvent gases are allowed to soak, allowing the rock to take in the heat of the steam in the fractures via thermal conduction. The well is then opened at the wellhead allowing the well to produce hydrocarbons and allowing the pressure of fluid in the fractures to drop. Oil and gas from the reservoir will then flow into the well and to the surface. The process is then repeated until a desired production goal is met. Also, when the same steam process is deployed in gas wells, it extracts the liquid blocks as well as extracts the adsorbed condensed methane via thermal desorption, therein resulting in increased production. Furthermore, the steam will decompose any blocking gels that are restricting flow of produced fluids in the fractures, thereby increasing subsequent production rates.
In furtherance of the inventive method, it is intended to use Vacuum Insulated Tubings (VIT) or centralized tubings inside the casing with the annulus space filled with natural gas, nitrogen, air, CO2 or any type of inert gas to provide thermal insulation. The purpose of providing the tubing is threefold. First, it ensures steam or steam component in the gas mixture do not condense before reaching reservoir during injection period; second it ensures vaporized oil and steam do not condense in the wellbore before reaching surface treatment facilities, thus preventing possible well loading with liquid; and it ensures wellbore integrity in the vertical section.

SUMMARY OF THE INVENTION

It is a major object of the invention to provide a method for production of hydrocarbons from various subsurface formations.
It is another object of the invention to provide an improved method for the production of hydrocarbons from shales.
It is another object of the invention to provide an improved method for the production of hydrocarbons involving cyclic hot-gas treatment of shales.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a diagrammatic overview of the invention.

FIG. 2 depicts temperature vs time for enhanced recovery techniques as described herein.

FIG. 3 depicts a representation propagated fractures in a well bore.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The present invention is directed to a method of increasing oil and gas production from subterranean formations. The method has particular utility with hydraulically-fractured shales, but may be employed in oil wells, gas wells, and/or gas condensate wells. The invention includes all the advantages of prior art gas-injection projects, but adds numerous other effective recovery mechanisms. Introducing hot gases (heated water vapor with or without added solvent gases such as CO2, N2, and methane) will include all the advantageous recovery mechanisms of the current hot gas injection method.
The present invention is an improvement on what currently exists. It introduces heating, it is a cyclic process, it uses gases that are more effective at recovering oil, and it is designed to heat the fracture rather than injecting gases directly into the reservoir.
The invention works through exposing the entire well and fracture system to heated water vapor and other gases in a way that cycles between low and high pressures. This causes an increased and longer-lived driving force for flow from reservoir to well, it increases amount of oil removed by the gas, it increases fluid mobility for greater flow to the well, and increases penetration depth of the process into the reservoir.
The invention includes all the advantages of prior art gas-injection projects but adds numerous other effective recovery mechanisms including thermal conduction, enhanced vaporization of via steam distillation, reduced oil viscosity, thermal expansion, thermal desorption, and improved well productivity. Introducing hot gases (heated water vapor with or without added non-aqueous gases such as CO₂, N₂, and methane) will include all the advantageous recovery mechanisms of the current hot gas injection method.
Thermal Conduction—Steam does not have to enter the rock to achieve heating of rock and its resident oil and gas via thermal conduction—it only has to fill the fracture space. This is feasible for contacting a large amount of oil in a short amount of time due to the enormous surface area of rockface exposed by hydraulic fractures and their connecting natural fracture networks. Since this does not require steam to enter the rock, steam can be injected at much lower pressures, where steam is a more effective heat-transfer medium due to its increased latent heat at lower pressures. Moreover, injecting at lower pressures is not possible in conventional reservoirs, especially in deeper wells such as most shale wells, because the reservoir fluids would quickly flow in to the fractures and force the attempted low-pressure injectant to be produced. However in unconventional reservoirs the reservoir permeability is so low that fluids take so long to flow in to the fractures that fluids can be readily injected into the well at pressures much lower than reservoir pressure. Furthermore, the production cycle of this process occurs at even lower pressures, enabling steam to be an even more effective heat carrier.
Vaporization by Steam Distillation—Steam exposes the in situ oil to vapor space. Exposing a liquid to vapor always promotes vaporization, but in the case of exposure of oil to steam there are three (3) factors that further enhance vaporization: 1) Heating rock up from initial temperature to steam temperature drives some of its resident liquid water into the vapor. This increase in the amount of vapor increases the in situ vapor's capacity to vaporize oil. 2) The primary mechanism of steam distillation is driven by the fact that a vapor composed of water has a greater capacity for vaporizing oil than does a hydrocarbon vapor at the same conditions. Increased presence of water in a vapor reduces the hydrocarbon partial-pressure in the vapor, and the lower the vapor's hydrocarbon partial-pressure, the greater its capacity for vaporizing additional oil. 3) Unlike exposure of the in situ oil to a cold gas injectant, steam increases the temperature, and vaporization occurs to a much greater degree at higher temperature than it does at lower temperature.
Reduced Oil Viscosity—Some of the initial oil that exits the rock into the fractures does so in the form of hot vapor, but some also leaves the rock in the form of liquid oil. The rate at which this happens is directly proportional to the oil's viscosity, and oil viscosity is a strong function of temperature. Thus hot oil is less viscous, and exits the rock at a higher rate, which results in increased oil production for the well.
Thermal Expansion—The fluids in the reservoir rock fill the void volume available in the rock. Therefore if the fluid's volume can be increased by some means, their volume becomes too much for the rock to hold and they will flow into the fractures to be produced from the well. Advantageously, this is precisely what happens when oil is heated—its volume expands, and by that mechanism some of it is driven to exit the rock and be produced. Furthermore, the rock grains adjacent to the fluids become heated as well, and they swell and expand in volume also. This reduces the amount of void volume available to hold the fluids, and further drives even more oil to the fractures to be produced.
Thermal Desorption—It is well known in unconventional reservoirs that there are large amounts of light oil components (mostly methane) that are adsorbed against the rock grain surfaces inside the pores of the rock. It is also well known that only a small amount of these adsorbed components are desorbed by decreasing pressure to the levels realized during production of the wells. It is well known also that these adsorbed components would be readily released via thermal desorption if the rock could somehow be heated. By introducing hot steam, steam desorption is enabled as a recovery mechanism, and these fluids that are otherwise left behind can be readily produced.
Improved Well Productivity—In some wells, hydraulic fractures were generated using a fluid that containing polymers. While potentially advantageous for making fractures, the polymers can create a gel that is left behind, which in turn can create very viscous blockages in the fractures that impair flow of fluids from the reservoir rock to the wellbore, leading to reduced production. However at elevated temperatures (such as that of steam), these blocking gels decompose into new compounds that have low viscosity and can readily flow, and which no longer block flow, leading to improved performance in terms of wells productivity. Furthermore, for all wells, the presence of a greater amount of liquid in its vertical section leads to lower production rates, due to the weight of this dense liquid pushing down on the otherwise non-dense fluid column. The increased temperature that results from steam causes more of the well stream to be in the vapor phase rather than liquid and this increases production rates in the well.
The present inventive methods expose the entire well and fracture system to heated water vapor, or steam, and other gases in a way that cycles between low and high pressures. During the high pressure cycles steam fills the wellbore, the man made propped fractures, and the connected system of unpropped natural fractures, and immediately begins to conduct heat into the adjacent rock and its resident oil and gas via thermal conduction. This heating enables multiple recovery mechanisms, including thermal expansion, reduced oil viscosity, enhanced vaporization from steam distillation, and thermal desorption. During the low-pressure cycles: fluids flow energetically towards the surface, owing to the expansion of the hot fluids caused by the reduction in pressure. Also steam continues to heat the formation. The high and low pressure cycles cause an increased and longer-lived driving force for flow from reservoir to well, an increased amount of oil removed by the gas, an increase in the fluid mobility for greater flow to the well, and an increase in the penetration depth of the process into the reservoir.
Benefit of increased driving force. Given the amount of oil in place, it is produced at higher production rates when the driving force for flow is higher.
Benefit of increased oil removed by gas. This causes more oil to be produced by the process for a given amount of gas injected. This means a greater oil production rate for the well.
Benefit of increase in fluid mobility for greater flow to the well. For a given amount of driving force, higher fluid mobility means fluid will flow at a greater flow rate. This means a greater production rate for the well.
Benefit of increased penetration depth. The greater depth of penetration that a process can achieve, the more reservoir rock that is exposed to enhanced recovery mechanisms. This results in more oil exiting the rock, which means more oil production for the well.
In accordance with the inventive method, there are a number of steps to provide for extracting an increased amount of hydrocarbons from the well bore.
In accordance with the inventive method, first, a steam generator is set up at the surface near the wellhead of a horizontal well that penetrates a shale and has been hydraulically fractured through the shale. Next, a liner is installed in the well using known techniques. The next step is a flow-in cycle where the steam generator flows in a mixture of heated water vapor with or without solvent gases (including CO2, N2, and/or other gases) through the wellhead to fill the well and the fracture network with steam. The rate, temperature, and duration requires some trial and error to achieve a desired rate of production for each individual well as would be apparent to one of skill in the art. Steam may be injected at a plurality of spaced locations along the horizontal well. It is potentially beneficial to pack-off the horizontal well a section at a time, and administer steam treatment starting at the toe and moving later to the heel. Some other variables include administering steam at different temperatures and pressures, and at different steam qualities, as well as co-injecting other gases such as CO2, N2, air, hydrocarbon gases, flue gases, etc., along with the hot water vapor.
The next step, in a key aspect of the invention, is a soak period. During this step, steam from the steam generator is shut off and the well is sealed off using conventional means. The trapped and heated steam is then allowed to soak for a period, the duration of which will vary depending upon how much oil production is desired. This heating process sets up a temperature profile of hot rock and fluids out into the reservoir to an increasing penetration depth with time. In other words, the oil shales are conductively heated for an extended period of time. The amount of time for this step is also variable and would be optimized for a given production goal using trial-and-error techniques as would be apparent to one of skill in the art.
The next step is to open the well, allowing the well to produce oil & gas, and causing the pressure of fluid in the fractures to drop. Oil and gas from the reservoir will flow into the well and to the surface during this period. This process is then repeated cyclically to maximize production.
FIG. 1 shows the apparatus for the invention. Fuel (A) powers a steam generator (B) which (B) heats up feed water CD until it is a hot high-pressure vapor. During the flow-in stage of the process described above, steam flows in through the wellhead (D), down through the liner centralized tubings (I), which are placed using a thermal packer (J) inside the casings located in the well's vertical (E) and horizontal (F) sections, and fills the fractures (G). During the soak period the wellhead (D) is closed and the well is shut-in while the reservoir takes in the steam's heat. During the flow-out period, the wellhead (D) is open to the aerial cooler (K) and production system (H) to accept flow of downhole fluids. Vacuum Insulated Tubings (VIT) or centralized tubings (I) inside the well casing with the annulus space (K)filled with natural gas, nitrogen, air, CO2 or any type of inert gas to provide required thermal insulation. The steam injection or flow in stage is preferably done at the maximum flow rate possible with the equipment used, which rate would be apparent to one of skill in the art. The max flow technique protects existing casing (I) from excess (prolonged) heating, and to keep produced fluids hot so that they flow as vapor and increase well deliverability (i.e., hydrocarbon production). The casings I may be slotted to release excess heat and minimize the possibility of collapse from overheating. Slotting would be done in horizontal sections of the casing I. Alternatively, low pressure low flow rate steam may be injected into the well. The techniques of swabbing and N2 foam injection may also be used to increase production. Swabbing the well, to reduce the pressure of fluids in the fracture network, and/or remove extant liquids from the fracture network is a well known technique which may be used in conjunction with the inventive method. Injecting other gases along with the steam may also increase production. An aerial cooler (must be shown) near the wellhead to prepare the hot produced fluids for existing surface production equipment in the field. A thermal packer may also be used.
FIG. 2 depicts temperature vs time for enhanced recovery techniques as described herein. It should be noted that as soon as one day of steam exposure, rock up to 1 ft away from the fracture face has been heated substantially higher than its initial reservoir temperature, which in this example is 80° C.
FIG. 3 depicts a representation of propagated fractures in a well bore, where A represents the horizontal wellbore, B represents a single fracture lobe held open by proppant, and C represents the network of unpropped natural fractures that emanate out from the man-made fracture. Steam injected into wellbore A fill flow to fill the void space in fracture B and the proceed to fill the network of natural fractures C Note that there are dozens of fractures like B created in a single horizontal wellbore A.
It should be noted that in accordance with an aspect of the invention, the inventive method may be used in neighboring wells simultaneously. That is, steam may be cyclically injected in two or more neighboring wells whose fracture networks are connected, as is known to happen occasionally in the industry.
It is to be understood that the present invention is not limited to the sole embodiment described above, but encompasses any and all embodiments within the scope of the following claims:

Claims

I claim:

1. A method of increasing hydrocarbon production from a well bore formed in subterranean rock formations, the method comprising the steps of:

generating steam and injecting said steam into the well bore;

sealing said well to trap said steam, and maintaining the seal for a predetermined amount of time to affect conductive heating of said rock formations; and

releasing said seal to allow the flow of hydrocarbons.

2. The method of claim 1 wherein heat loss from injecting said steam to well bore is minimized by lining said well with thermal insulation.

3. The method of claim 1 wherein heat loss from steam to well bore is minimized by injecting said steam at maximum flow rates.

4. The method of claim 1 wherein said steam is injected via one or more conduits, each of said conduits having an inner and outer annulus, said outer annulus containing a low pressure gas for insulation.

5. The method of claim 4 wherein said inner annulus is formed from a slotted tube.

6. The method of claim 4 wherein a thermal packer is positioned within the conduits to reduce steam loss.

7. The method of claim 1 wherein said steam is injected at low pressures.

8. The method of claim 1 wherein N2 foam is used before said steam injection to increase said hydrocarbon production.

9. The method of claim 1 wherein swabbing is used before said steam injection to increase said hydrocarbon production.

10. The method of claim 1 wherein other gases are injected along with said steam.

11. The method of claim 1 wherein an aerial cooler is positioned near the wellhead to prepare hot produced fluids for existing surface production equipment.

12. The method of claim 1 wherein said method is employed in a shale in an oil window.

13. The method of claim 1 wherein said method is employed in a shale in a gas window.

14. The method of claim 1 wherein said method is employed in oil wells, gas wells, or gas condensate wells.

15. The method of claim 1 wherein additives are injected along with the steam, said additives comprising at least one of salts, surfactants, chemically reactive agents, pH-altering agents, nanoparticles, gases, and solvents.

16. The method of claim 1 wherein agents are injected intermittently with steam injection, said agents comprising at least one of surfactants, chemically reactive agents, pH-altering agents, nanoparticles, gases, and solvents.

17. The method of claim 1 wherein steam is generated downhole in said wellbore, where said steam may be generated by either downhole steam generators, electromagnetic heating, downhole electrical heater cables, or exothermically reactive injectants.

18. The method of claim 1 wherein steam is cyclically injected in two or more neighboring wells having connected fracture networks.