METHOD AND COMPOSITION TO DIVERT FLUIDS AT HIGH TEMPERATURES

Abstract

Methods of treating a subterranean formation as a portion of steam-assisted gravity drainage operation including providing a fluid containing a diverting agent, injecting the fluid into a first wellbore, allowing the diverting agent to divert fluid placement, performing steam-assisted gravity drainage, and producing formation fluids from a second wellbore.

Description

RELATED PATENT APPLICATION INFORMATION

This patent application claims priority to and the benefit of provisional patent application U.S. 61/383,590, filed Sep. 16, 2010, which is incorporated in its entirety herein.

BACKGROUND

The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.

Various thermal methods have been proposed for the production of heavy oils. Variation of steam flooding (direct steam flooding, cyclic steam stimulation, etc) and steam-assisted gravity drainage (SAGD); see U.S. Pat. No. 4,344,485, incorporated herein, are the two most common methods. Of the two, steam flooding has been tested in the field and has been commercially used. However, SAGD has been only recently become commercialized. With better understanding of the SAGD process and more field experience, this particular method has gained considerable attention recently. Currently, there are several producing wells using SAGD process and more than twenty five (Strategy West Inc., 2006; Alberta Economic Development, 2006, incorporated herein) SAGD projects which are under construction or approved to be online in the next decade in Canada alone. The total investments on SAGD projects alone so far exceeds 12 billion dollars (Strategy West Inc.—Alberta Economic Development, 2006, National Energy board, 2006, incorporated herein).

One challenge in using SAGD for heavy oil production is even heating of the formation and associated fluid. This challenge is relevant to both the start-up phase of the SAGD process where proper thermal & hydrodynamic communication is being established between the horizontal well pairs as well as the production phase where steam is being used to deliver heat to the reservoir, thus lowering the viscosity so that the heavy oil can be produced by gravity drainage. It has also been observed in the field that heating of the well pairs and the reservoir itself is often not uniform due to variations if fluid and reservoir properties that can lead to “blind” areas where there is no contact with steam. In the start-up phase, the influence of geology of the reservoir, SAGD well pair completion design, well pair operating conditions, and many other factors leads to long periods (up to 4-6 months) before the thermal and hydrodynamic communication between the well pairs is suitable enough for actual production. Even then, there may be regions along the length of the horizontal length that communications are not uniform. During the production phase of a SAGD operation, non-uniform injection of steam to the reservoir for the purpose of oil production is likely affecting overall efficiency of the steam injection process and the ultimate recovery. The non-uniform injection of steam and uneven steam sweep could be seen both in a SAGD well pair arrangement and in a traditional steam flooding (either continuous or cyclic) methods.

It is expected that reducing the required time for uniform well pair communication and uniform distribution of steam injection during production phase will drastically affect the economics of the any steam assisted heavy oil production project.

SUMMARY

In a first aspect, methods of treating a subterranean formation as a portion of steam-assisted gravity drainage operation are provided which include providing a fluid including fibers or other diverting agent, injecting the fluid into a first wellbore, allowing the fibers or other diverting agent to function as a diverting agent, performing steam-assisted gravity drainage, and producing formation fluids from a second wellbore.

In a second aspect, methods of treating a subterranean formation as a portion of steam-assisted operation, include providing a fluid comprising fibers or other diverting agent, injecting the fluid into a first wellbore, allowing the fibers or other diverting agent to function as a diverting agent, and performing steam-assisted production of formation fluids from a second wellbore.

Some other aspects are methods of treating a subterranean formation including providing a fluid comprising a diverting agent and adhesive, injecting the fluid into a first wellbore, allowing the diverting agent to divert fluid placement, and performing steam involved production of formation fluids from a second wellbore.

Some embodiments of this invention provide a composition, method and process to optimize the production and stimulation of SAGD well pairs with fluids that contain solid state diverting agents—fibers in particular. In particular, we use composition, method and processes that:

• 1) Selectively plug or block a high permeability zone during steam injection for the purpose of heavy oil production i.e. either during start up or production phase, in order to evenly distribute the flow of steam to the formation.
• 2) Plug naturally occurring or steam induced fractures in the formation. Fibers are very effective at this.
• 3) As a plastering agent to cover the surface of a high permeability region of the wellbore.
• 4) As a plug, plaster, film or fabric forming particulate agent that selectively plugs screens or ports on the liner in the steam injection wellbore. The ports and particulate agent can be co-designed to work together similar to a lock and key. That is, some particles can block off some ports but not others.
• 5) As a temporary plug in the wellbore (i.e. you form a temporary bridge plug).
• 6) As a diverting agent in stimulation and workover treatments on SAGD wells—both on the steam injector well, and on the producing well. to allow the removal of scale from the production tubulars.

The artificial plug can be designed to be long lived or it can be designed to collapse or degrade, possibly over a short period of time, to open up the high permeability zones for complete steam sweep during production. The objectives are achieved by:

• Identifying low permeability/low fluid mobility areas (zones) or equally high permeability/high fluid mobility areas (zones) around the injector and producer wells through appropriate downhole tools.
• Temporarily plug a specified part of the formation by the high temperature fiber composition by either active or passive placement methods.

DESCRIPTION

At the outset, it should be noted that in the development of any such actual embodiment, numerous implementation—specific decisions must be made to achieve the developer's specific goals, such as compliance with system related and business related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. In addition, the composition used/disclosed herein can also comprise some components other than those cited. In the summary of the invention and this detailed description, each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context. Also, in the summary of the invention and this detailed description, it should be understood that a concentration range listed or described as being useful, suitable, or the like, is intended that any and every concentration within the range, including the end points, is to be considered as having been stated. For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10. Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to only a few specific, it is to be understood that inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that inventors possessed knowledge of the entire range and all points within the range.

Stimulation and remediation of SAGD well pairs (both injector and producer) requires novel fluid diversion technologies as well. Cracks and high permeability streaks will form in the formation during SAGD production, and can act as thief zones for scale inhibitors, acidizing and other workover fluids during remediation treatments. However, often the productive formation (steam affected region) is still at very high temperatures (in excess of 300-400° F.). High temperature may also include any temperature point in the range from about 200° F. to about 500° F. It is possible there is a strong economical incentive to intervene in the SAGD completion at as high as temperature as possible. By intervening at high temperatures: 1) it takes less time to cool down, 2) less of the energy spent to heat up the formation is lost, 3) the viscosity of the bitumen is lower—facilitating displacement and surface reactions, and 4) the intervention occurs at a physical and chemical environment that is closer to operation conditions (less thermal cycling of the rock).

Although fluid diversion techniques including viscous pills, self-diverting acids, and viscoelastic diverting acids (VDA) have been practices in conventional reservoirs, they may not be reliable at these high temperatures. Solid state diverting agents are thus required, but many of the traditional additives, such as benzoic acid flakes, rock salt, and the like, may not be practical at these high temperatures. Benzoic acid melts at 122.4° C., and rock salt can cause corrosion issues on expensive wellbore completion tubing, screens and hardware.

Methods to speed up communications in SAGD well pair arrangement are proposed. The majority of these inventions and proposed methods are based on heating the reservoir matrix between the two horizontal well pairs, and thus reducing the viscosity of the heavy oil trapped between the two wells and mobilizing it to the producer well. A common method is steam circulation in the well pair. One of the main difficulties during the steam circulation and production phase is even distribution of steam. Blocking of the thief zones (zones with high permeability) may be used as a method to target the low permeability zone in the early stages of steam injection. High permeability blocking methods have been traditionally used to divert formation treatment fluids to desired location—but as discussed above they are not particularly useful for SAGD interventions. One of the main challenges in applying the same methodology in a steam injection scenario is the capability of traditional methods to withstand very high temperatures experienced in steam injection heavy oil production methods.

In well stimulation industry, mechanical and chemical methods can be used to divert fluids to the desired zones. Mechanical methods tend to be more expensive and time consuming and their implementation requires multiple phases. The chemical methods can involve either injection of particulate laden fluids to form an impervious cake around the wellbore or using foaming, emulsifying, or gelling agents (fluids) to artificially reduce the permeability of the targeted zone and thus divert the flow of stimulation fluids. In one method, formation treatment fluid (FTF) plus fiber is used to selectively plug an area of the formation.

The chemistry of some compositions used in embodiments are developed/designed in such a way that artificial chemical block can withstand the very high temperature of steam injection processes (i.e. temperatures as high as 300° C.) in a timely fashion. The diverting agent or bridging material can be of a non-fibrous or fibrous material (in the following paragraphs the terms “fiber”, “bridging agent”, and “diverting agent” may all refer to the same material). The chemistry of the composition, and the physical structure of the fiber, can be modified in such a way that the plug integrity can be maintained over a certain period of time (up to few weeks or few months) under steam injection conditions. This can be controlled by selecting the appropriate fibrous or particulate material for the task. If a plug is to last a very long time, then a hydrolytically stable fiber such as KYNOL (Novoloid Resin) can be used. If the plug is to last a short time, then glass fibers of different grades can be used. In general glass fibers with alkali resistant (commonly referred to as AR glass) compositions have longer lifetimes at higher temperatures than the more common E-glass. If the plug is to last a very short time then high temperature polyesters or other condensation polymers can be used. The invention also includes aspects of making the diverting agents with physical properties that facilitate transport at the low velocities of steam injection. The particulate could contain glass bubbles to reduce the density. They could also have high surface areas to facilitate entrainment in the steam.

The physical structure of the fiber, particularly its diameter and its surface to volume ratio may have an impact on the dissolution and degradation of the material. Fibers that have a high surface area to volume ratio may tend to degrade faster. Degradation can also be modified by physical and chemical methods that modify the diffusion rate of water molecules in the material. For example polymers can be electron-beam crosslinked to increase their melting temperatures and decrease their permeability.

In some embodiments, the term “fibers” may refer to any particulate material with an aspect ratio. Therefore the fiber could be a ribbon, strip or plate.

In one embodiment, the composition and method may be used to plaster or coat a portion of the wellbore. This method may utilize an adhesive binder. In such case, placement and performance of the fibers and the performance of the resultant fiber plugs can be assisted by the use of permanent or temporary adhesive materials. These materials can be heat and or hydrolytically activated. One method would be to use fibers where the adhesive is an integral component of the material. Adhesive placement could be useful for creating “spray-on” active barrier plugs.

To achieve some embodiments of the invention, placement method can be considered. The composition may be placed by either active or passive placement methods. In active placement method, method and composition will be preferentially placed by using a coiled tubing arrangement. This approach provides the mean to intervene during the ongoing production, in an effort to correct or improve the liquids and steam flow.

In passive placement approach, the fiber containing fluid could be co-injected with the steam, thereby not requiring a significant intervention at the wellhead. In such a case, the composition will be carried with the carrier fluid and most likely will end up in high permeability areas where majority of flow to the subterranean formation occurs. Passive placement could be achieved by any suitable method. As one example, if the steam flux is high enough it could be achieved by metering in fibers at a very low concentration. The fibers would accumulate at the regions where the most steam is being injected. Alternatively the fibers could be mixed into a high temperature emulsion or fluid and bullheaded into the well. Alternatively various methods of viscosifying the steam, such as the use of foaming agents could be used.

A potential concern for passive placement of the fibers is the settlement of the fibers from the carrier fluid during transportation to the placement location. As such, the type of carrier fluid and the flow regime in the wellbore tubing may help achieve fiber placement in the well. A turbulent all-steam stream may be used to carry the fibers directly to the placement position carrying the fibers similar to aerosol. Potentially an all-liquid stream possibly even in a laminar flow regime may also be able to carry the fibers to the placement location. Depending on the nature of fibers, a compatible aqueous or non-aqueous liquid may be used. It is expected that a laminar two phase (gas-liquid) will be least efficient flow regime for fiber transportation as most likely they will settle particularly under laminar flow regime. However, a two-phase slugging flow may be effective at placing particulate material as a plug.

Another aspect is the active design and selection process so that the bridging material, and the particular port or screen used in the liner of the injection well work together in concert to achieve the desired effect. We have a composition, method and process to:

• 1) To selectively plug or block a high permeability zone during steam injection for the purpose of heavy oil production i.e. either during start up or production phase, in order to evenly distribute the flow of steam to the formation.
• 2) As a method to plug naturally occurring or steam induced fractures in the formation; fibers are may be effective for such.
• 3) As a plastering agent to cover the surface of a high permeability region of the wellbore.
• 4) As a plug, plaster, film or fabric forming particulate agent that selectively plugs screens, slotted liners or ports on the liner in the steam injection wellbore. The ports and particulate agent can be co-designed to work together similar to a lock and key. That is, some particles can block off some ports but not others.
• 5) As a temporary plug in the wellbore (i.e. form a temporary bridge plug).
• 6) As a high temperature diverting agent for stimulation, workovers and interventions into both the injector and production well.
• 7) As a diverting agent to allow the removal of scale from the production tubulars.

Situations 1-3 may have the particulate material pass through the hardware and liner of the injector well into the formation. When this is the desired effect, such as the case of geological situations where thermal fracturing of the formation is likely, then the artisan may choose a liner/bridging material combination where the bridging material is forced into the formation. The geometry of the screen or slot could be designed to facilitate this process, and the bridging material can be designed to penetrate this aperture.

Another consideration regarding the application of fibers is their aspect ratio with respect to slot sizes in the slotted liner of the well completion. In some cases, the smallest recommended slot width is about 150 microns. Additionally, the slot design is an important factor affecting anti-plugging characteristics of the slots. The other factor that may also affect the flow of fibers is that the slot design (configuration) may be different for the injection and production wells.

Situations 4 and 5 require the particulate material to bridge out in the injector wellbore or on the ports, screens or slots that provide access to the well bore. In such situations, the artisan may want to size the bridging material so that it would collect on the screen or port.

Another aspect in some embodiments is the method of feeding the bridging material into the injection well.

• 1. Slug: This could be a method of placing a diverting agent that is of a permanent nature. Also if plugging a thermal fracture from a producer well side is desired, then the placement of this plug may be via a slug approach.
• 2. Continuous: This could be an option for uniform placement of steam if a light-weight degradable fiber is used at low concentrations. Since the fiber is entrained in the steam, the greatest amount of fiber will follow the steam into high conductivity channels—eventually plugging them and diverting the steam to other locations along. If the fiber is chosen to degrade slowly, then these plugs will not be permanent. Therefore, over time the steam will be diverted back and forth through the formation such as a river passing through a delta. The instantaneous effect would not be one of uniform passage of steam through the formation, but the time averaged effect would be.
• 3. Semi-continuous: A combination of the above two approaches. This may be the best for degradable materials that have a relatively long lifetime, but are not permanent.

Another aspect of is an integrated junk basket, chamber, compartment, or mechanism to collect waste bridging material that may not be completely placed where intended, and to facilitate its degradation or periodic removal. For example, an extended compartment could be placed at the end of the injector well (i.e. an intentionally designed rat hole). Alternatively, a tubing could be placed in the Steam Injector line so that compressed gas, foam, or another fluid could be blown backwards to clear out the debris. Alternatively a capillary line could be placed to spot reactive material (such as an acid) on waste bridging material debris to enhance degradation.

While the invention has been shown in only some of its forms, it should be apparent to those skilled in the art that it is not so limited, but is susceptible to various changes and modifications without departing from the scope of the invention. Accordingly, it is appropriate that the appended claims be construed broadly and in a manner consistent with the scope of the invention.

Claims

1. A method of treating a subterranean formation as a portion of steam-assisted gravity drainage operation, the method comprising:

a. providing a fluid comprising a diverting agent;

b. injecting the fluid into a first wellbore;

c. allowing the diverting agent to divert fluid placement;

d. performing steam-assisted gravity drainage; and,

e. producing formation fluids from a second wellbore.

2. The method of claim 1 wherein the diverting agent is functional at high temperature.

3. The method of claim 1 wherein the fluid further comprises a particulate.

4. The method of claim 3 wherein the particulate further comprises glass bubbles to reduce the density.

5. The method of claim 3 wherein the particulate has a high surface areas to facilitate entrainment in steam.

6. The method of claim 1 wherein the diverting agent is a fibrous material.

7. The method of claim 1 wherein the diverting agent is a nonfibrous material.

8. The method of claim 1 wherein the diverting agent is a fibrous bridging agent.

9. The method of claim 1 wherein the diverting agent is a nonfibrous bridging agent.

10. The method of claim 1 further comprising utilization of an adhesive binder.

11. The method of claim 10 wherein the adhesive binder is a permanent adhesive.

12. The method of claim 10 wherein the adhesive binder is a temporary adhesive.

13. The method of claim 1 wherein the diverting agent is placed by an active placement method.

14. The method of claim 1 wherein the diverting agent is placed by a passive placement method.

15. A method of treating a subterranean formation as a portion of steam-assisted operation, the method comprising:

a. providing a fluid comprising a diverting agent;

b. injecting the fluid into a first wellbore;

c. allowing the diverting agent to divert fluid placement; and,

d. performing steam-assisted production of formation fluids from a second wellbore.

16. The method of claim 15 wherein the diverting agent is functional at high temperature.

17. The method of claim 15 wherein the fluid further comprises a particulate.

18. The method of claim 17 wherein the particulate further comprises glass bubbles to reduce the density.

19. The method of claim 17 wherein the particulate has a high surface areas to facilitate entrainment in steam.

20. The method of claim 15 wherein the diverting agent is a fibrous material or nonfibrous material.

21. The method of claim 15 further comprising utilization of an adhesive binder, wherein the adhesive binder is either a permanent adhesive or temporary adhesive.

22. The method of claim 15 wherein the diverting agent is placed by an active placement method or a passive placement method.

23. A method of treating a subterranean formation comprising:

a. providing a fluid comprising a diverting agent and adhesive;

b. injecting the fluid into a first wellbore;

c. allowing the diverting agent to divert fluid placement; and,

d. performing steam-assisted production of formation fluids from a second wellbore.