Method and System for Treating A Subterranean Formation

Abstract

A method and apparatus to treat a subterranean formation comprising a wellbore including introducing a tool to a wellbore in a region of low permeability or damage, treating the region of low permeability or damage with a fluid, simultaneously measuring a fluid pressure drop and volume of fluid flow in a particular region, and moving the tool to another region. A method and apparatus to treat a subterranean formation comprising a wellbore including introducing to a wellbore a tool in a region of low permeability or damage, treating the region of low permeability or damage with a fluid, introducing a diversion agent, and moving the tool to another region wherein the fluid comprises a tracer.

Description

BACKGROUND

Hydraulic fracturing and/or matrix acidizing oil and gas wells are often used to stimulate production out of more than one layer in the same wellbore. There are many techniques used to insure that the stimulation treatment is isolated from the other layer(s). These techniques have various levels of cost, complexity, reliability, and time consumption. The limited entry technique is less than optimum as it involves placing entry points in the formation without validation of fluid placement efficiency prior to stimulating.

FIGURES

FIG. 1 is a sectional view of a tool in a wellbore.

FIG. 2 is a sectional view of a tool in a wellbore.

FIG. 3 is a plot of pressure as a function of injection rate.

FIG. 4 is a sectional view of a tool in a wellbore.

FIG. 5 is a sectional view of a wellbore.

FIG. 6 is a plot of pressure as a function of injection rate.

FIG. 7 is a sectional view of a tool in a wellbore.

FIG. 8 is a sectional view of a wellbore.

SUMMARY

Embodiments of the invention relate to a method to treat a subterranean formation comprising a wellbore including introducing a tool to a wellbore in a region of low permeability or damage, treating the region of low permeability or damage with a fluid, simultaneously measuring a fluid pressure drop and volume of fluid flow in a particular region, and moving the tool to another region. Embodiments of the invention relate to a method to treat a subterranean formation comprising a wellbore including introducing to a wellbore a tool in a region of low permeability or damage, treating the region of low permeability or damage with a fluid, introducing a diversion agent, and moving the tool to another region wherein the fluid comprises a tracer.

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. The statements made herein merely provide information related to the present disclosure and may not constitute prior art, and may describe some embodiments illustrating the invention.

Embodiments of the invention may make a system where multiple zones can be treated with less wellbore operations, more reliable and predictable, and all along at less cost and time using the limited entry technique. Embodiments of the invention are an improvement on the established process of limited entry zone stimulation and resolve the disadvantages of unpredictability, efficiency, and validation of multiple zones being stimulated. This is a method where each entry point can be tested for fluid acceptance quickly, reliably, and inexpensively.

This is a method to simultaneously stimulate and/or acidize multiple zones or multiple fractures in the same zone. The process involves a zone well that will have each zone or several grouped zones to be treated together so that the treatment is isolated and not going to the previously treated/perforated zones. This gives more control over how each zone will deliver its production.

• • 1. The process will start out as a conventional limited entry design to determine the proper and optimum amount of stimulations per fracture to be created.
  • 2. Then, the initial entry hole or slot will into one zone. Ideally, this will be at in the zone of lowest fracture pressure to be treated. However it is effective in any potential fracture point where it is desirable to restrict the flow. This entry will then be created at some point equal to or less in entrance area than the design for this point. (FIG. 1). Some embodiments may benefit from the use of a tracer during this step.
  • 3. The perforating or jetting device will be left in the hole to continue operations (FIG. 2), while pumping at various rates and pressure is observed and recorded. This will give the entry rates into the fracture verses pressure (FIG. 3) for calibration of the fracture created with real time rates as a function of time. The pressures should be in the operating range of the anticipated treatment for maximum accuracy.
  • 4. Next, the perforating or slotting device is moved to the second fracture point and the process (steps 2- and 3) is repeated. This time the rates are increased to achieve the same pressure range (FIGS. 4, 5, 6). The difference in the rates at same pressures (first rates from second) is the fluid rate going into the second zone. That is, the difference indicates real time fluid behavior. Some embodiments may perform a perforation step, then an injection step. Some additional embodiments may perform an injection step, followed by a perforation step.
  • 5. The process can be repeated in more zones until the maximum allowable rate is achieved for the zones. Some embodiments may benefit from the use of a diverter treatment step.
  • 6. If it is desirable to put a larger portion of the treatment in a zone verses another then with the slotting or perforating device still in the wellbore, add another entry point(s).
  • 7. If it is determined that the limited number of entry points for treatment, would restrict oil or gas production, then with the perforating or slotting device already in the wellbore, add holes.
  • 8. The achieve a lower surface treating pressure the perforating or slotting device maybe removed from the well during the main fracture treatment. Also, FIG. 7 illustrates how the tool may be sized to facilitate fluid flow through the wellbore. FIG. 8 illustrates a clean-up step for some embodiments of the invention.
  • 9. If maximum rate is achieved and there are intervals still needing to be fractured or stimulated, then the conventional diversion or plugging materials, packers, or bridge plugs can be used to isolate these zones.
  • 10. To expedite the process, the steps 2 through 5 can be made without stopping the pumping or fracturing treatment. In this version the initial holes are generated, the allowable treating pressure is met, holes in other (or same zone) are placed while maintaining pressure. The difference is the rate at the new holes. Process is repeated until desired all zones are treating properly or maximum rate is achieved.

Embodiments of the present invention also allow measurement of a diverter's effectiveness in diverting stimulation and scale treatment fluids from a high permeability layer to a low permeability layer, or from a high pressure zone to a low pressure zone, or from a layer which has a higher fluid mobility to a layer which has a lower fluid mobility. Embodiments of the invention can also be used to evaluate the effectiveness or a diverter to place the injected chemicals more evenly across layers which have different properties and can affect chemical placement. The method allows calculation of volume of fluid injected in the low perm layer vs. the high perm layer, or in the high pressure zone vs. low pressure zone, or in the layer where the fluid has a higher mobility vs. layer where fluid has a lower mobility, and the extent of clean-up, or flow back after the well is put back on production. That is, the different pressure profiles as illustrated by FIGS. 3 and 6 show how more perforations and/or fractures influence the resulting observed pressure and provide a way to estimate flow profile and pressure along the wellbore.

The method allows calculation of volume of fluid injected in the low permeability layer vs. the high permeability layer and the extent of clean-up after the well is put back on production. Consider a stimulation treatment designed for two reservoir zones intersected by a wellbore. Assume that the top zone is a high perm zone (or a low pressure zone, or a zone where fluid mobility is higher) and the bottom zone is a low perm zone (or a high pressure zone, or a zone where fluid mobility is lower). The objective is to measure the volume of stimulation fluid, or scale inhibition fluid that is injected in the both zones (evaluate diverter efficiency) and to determine the effectiveness of clean-up during flow back. Also, this method allows an alternative to the conventional method using distributed temperature sensors (DTS).

To verify the effectiveness of this system (or the limited entry technique), consider a stimulation treatment designed for two reservoir zones intersected by a wellbore. Assume that the top zone is a high perm zone and the bottom zone is a low perm zone. The objective is to measure the volume of stimulation fluid that is injected in the low perm zone (to evaluate diverter efficiency) and to determine the effectiveness of clean-up during flow back. The evaluation as per embodiments of the present invention would comprise of the following steps:

• • 1. Inject stimulation fluid S1 with tracer T1.
  • 2. Inject diverter stage.
  • 3. Inject stimulation fluid S2 with tracer T2.
  • 4. Position downhole sampling device, such as compact production sampler cartridge with multiple sample bottles, between top and the bottom zone.
  • 5. Flow back the well and collect surface samples and downhole samples during flow back and record flow rate during flow back.
  • 6. Analyze composition of the surface and downhole samples.
  • 7. Determine volume of stimulation fluid injected in the lower zone during the first stage (S1 fluid) by analyzing the tracer T1 concentration in the surface sample vs. the downhole sample.
  • 8. Determine volume of stimulation fluid injected during the second stimulation stage (S2 fluid) by analyzing the tracer concentration in the surface sample vs. the downhole sample for Tracer T2.
  • 9. Integrate the flow rates to compute fluid volumes.
  • 10. Compare results from 7 to 9 to determine the effectiveness of diverter stage.
  • 11. Determine the clean-up efficiency of each zone by integrating flow rate of retrieved stimulation fluid from each zone.

The tracer concentrations can be measured by monitoring a fluid property related to the concentration, such as, pH, resistivity, density, color etc. The measurements can be made at a single point or at multiple points in the flow path. They can be made in real-time and used in improving the design of the treatment or they can be stored to memory and analyzed later for improving future designs.

The tracer used in monitoring diversion can come from the formation itself. For example, it is possible that in a carbonate reservoir the low permeability zones have more dolomite CaMg(CO₃), while the high permeability zones have more limestone (CaCO₃). In this case the, Ca and Mg can serve as tracers and their concentrations in the flow back fluid can be used to determine the diverter efficiency.

Once the measurement of the tracer concentration is made, the methods of U.S. Pat. No. 7,658,226 which is incorporated by reference herein in its entirety can be used to calculate the diverter efficiency. Additional embodiments may benefit from the alternatives described in U.S. patent application Ser. No. 12/635,002, filed Dec. 10, 2009, entitled, “Method of Determining End Member Concentrations,” and incorporated by reference herein in its entirety. An alternative method for computing diversion efficiency is by simulating the entire process by assuming a certain diverter efficiency and then comparing the calculated concentrations against the measured values and then iteratively adjusting the diverter efficiency until a good match is obtained between the calculated and measured values.

Variation 1

Can combine the above with a PLT positioned above the lower zone.

Variation 2

• • 1) Inject stimulation fluid S1 with tracer T1
  • 2) Inject stimulation fluid mixed with diverted stage S2 with tracer T2
  • 3) Position downhole sampling device, such as compact production sampler cartridge with multiple sample bottles, between top and the bottom zone.
  • 4) Flow back the well and collect surface samples and downhole samples during flow back and record flow rate during flow back.
  • 5) Analyze composition of the surface and downhole samples
  • 6) Determine volume of stimulation fluid injected in the lower zone during the first stage (S1 fluid) by analyzing the tracer T1 concentration in the surface sample vs. the downhole sample.
  • 7) Determine volume of stimulation fluid injected during the second stimulation stage (S2 fluid) by analyzing the tracer concentration in the surface sample vs. the downhole sample for Tracer T2.
  • 8) Integrate the flow rates to compute fluid volumes.
  • 9) Compare results from 6 to 8 to determine the effectiveness of diverter stage.
  • 10) Determine the clean-up efficiency of each zone by integrating flow rate of retrieved stimulation fluid from each zone.

Variation 3

Can combine the above (variation 2) with a PLT positioned above the lower zone.

Variation 4

• • 1) Inject stimulation fluid which has been mixed with diverter chemical S1 with tracer T1
  • 2) Inject post stimulation fluid S2 (e.g. displacement fluid, post flush fluid, overflush fluid) with tracer T2
  • 3) Position downhole sampling device, such as compact production sampler cartridge with multiple sample bottles, between top and the bottom zone.
  • 4) Flow back the well and collect surface samples and downhole samples during flow back and record flow rate during flow back.
  • 5) Analyze composition of the surface and downhole samples
  • 6) Determine volume of stimulation fluid injected in the both zones during the first stage (S1 fluid) by analyzing the tracer T1 concentration in the surface sample vs. the downhole sample.
  • 7) Determine volume of post stimulation fluid injected during the second stage (S2 fluid) by analyzing the tracer concentration in the surface sample vs. the downhole sample for Tracer T2.
  • 8) Integrate the flow rates to compute fluid volumes.
  • 9) Compare results from 6 to 8 to determine the effectiveness of diverter chemicals.
  • 10) Determine the clean-up efficiency of each zone by integrating flow rate of retrieved stimulation fluid from each zone.

Variation 5

Can combine the above (variation 4) with a PLT positioned above the lower zone.

Variation 6

• • 1) Inject pre stimulation fluid S1 (e.g. reservoir conditioning or pre-conditioning fluid) with tracer T1
  • 2) Inject the main stimulation fluid mixed with chemical diverter S2 with tracer T2
  • 3) Position downhole sampling device, such as compact production sampler cartridge with multiple sample bottles, between top and the bottom zone.
  • 4) Flow back the well and collect surface samples and downhole samples during flow back and record flow rate during flow back.
  • 5) Analyze composition of the surface and downhole samples
  • 6) Determine volume of pre stimulation fluid injected in the lower zone during the first stage (S1 fluid) by analyzing the tracer T1 concentration in the surface sample vs. the downhole sample.
  • 7) Determine volume of main stimulation fluid injected during the second injection stage (S2 fluid) by analyzing the tracer concentration in the surface sample vs. the downhole sample for Tracer T2.
  • 8) Integrate the flow rates to compute fluid volumes.
  • 9) Compare results from 6 to 8 to determine the effectiveness of chemical diverter which was mixed with the main treatment fluid.
  • 10) Determine the clean-up efficiency of each zone by integrating flow rate of retrieved stimulation fluid from each zone.

Variation 7

Can combine the above (variation 4) with a PLT positioned above the lower zone.

Variation 8

Can combine steps 1 to 2 in Variations 2, 4 and 6 above with the following:

• • 3. Flow back the well and collect surface samples during flow back and record flow rate during flow back.
  • 4. Analyze composition of the surface samples
  • 5. Determine volume of stimulation fluid injected in the lower zone during the first stage (S1 fluid) by analyzing the tracer T1 concentration in the surface sample
  • 6. Determine volume of post stimulation fluid injected during the second stage (S2 fluid) by analyzing the tracer concentration in the surface sample for Tracer T2.
  • 7. Integrate the flow rates to compute fluid volumes.
  • 8. Compare results from 5 to 7 to determine the effectiveness of diverter chemicals.
  • 9. Determine the clean-up efficiency of each zone by integrating flow rate of retrieved stimulation fluid from each zone.

Variation 9

• • 1) Inject pre stimulation fluid S1 (e.g. reservoir conditioning or pre-conditioning fluid) with tracer T1
  • 2) Inject the main stimulation fluid mixed with chemical diverter S2 with tracer T2
  • 3) Inject post stimulation fluid S3 (e.g. reservoir conditioning or pre-conditioning fluid) with tracer T3
  • 4) Position downhole sampling device, such as compact production sampler cartridge with multiple sample bottles, between top and the bottom zone.
  • 5) Flow back the well and collect surface samples and downhole samples during flow back and record flow rate during flow back.
  • 6) Analyze composition of the surface and downhole samples
  • 7) Determine volume of pre stimulation fluid injected in the lower zone during the first stage (S1 fluid) by analyzing the tracer T1 concentration in the surface sample vs. the downhole sample.
  • 8) Determine volume of main stimulation fluid injected during the second injection stage (S2 fluid) by analyzing the tracer concentration in the surface sample vs. the downhole sample for Tracer T2.
  • 9) Determine volume of post stimulation fluid injected during the third injection stage (S3 fluid) by analyzing the tracer concentration in the surface sample vs. the downhole sample for Tracer T3.
  • 10) Integrate the flow rates to compute fluid volumes.
  • 11) Compare results from 7 to 10 to determine the effectiveness of chemical diverter which was mixed with the main treatment fluid.
  • 12) Determine the clean-up efficiency of each zone by integrating flow rate of retrieved stimulation fluid from each zone.

Variation 10

Can combine steps 1 to 3 in Variation 9 above with the following:

• • 4. Flow back the well and collect surface samples during flow back and record flow rate during flow back.
  • 5. Analyze composition of the surface samples
  • 6. Determine volume of pre stimulation fluid injected in the lower zone during the first stage (S1 fluid) by analyzing the tracer T1 concentration in the surface sample vs. the downhole sample.
  • 7. Determine volume of main stimulation fluid injected during the second injection stage (S2 fluid) by analyzing the tracer concentration in the surface sample vs. the downhole sample for Tracer T2.
  • 8. Determine volume of post stimulation fluid injected during the third injection stage (S3 fluid) by analyzing the tracer concentration in the surface sample vs. the downhole sample for Tracer T3.
  • 9. Integrate the flow rates to compute fluid volumes.
  • 10. Compare results from 6 to 9 to determine the effectiveness of diverter chemicals.
  • 11. Determine the clean-up efficiency of each zone by integrating flow rate of retrieved stimulation fluid from each zone.

Variation 11

Can combine the above (Variation 9 and variation 10) with a PLT positioned above the lower zone.

Variation 12

Can combine all the above, with chemical return profile analyses usually sampled at topside to evaluate diverter efficiency and treatment efficiency.

Variation 13

Can combine all the above with flowback properties (rates and concentration) and flow profile of tagged chemicals that may be present in the pre, main and/or post treatment fluid to evaluate diverter efficiency and treatment efficiency over the long term.

Also, when the composition of the downhole fluid sample and the surface fluid sample is analyzed one should analyze the full composition. For example, in addition to looking for T1 and T2, one should look for Ca, Mg ions as well as any component from the diverter stage. Most likely the low perm formation will be different in composition (may contain more dolomite) then analysis of Ca/Mg concentration would allow one to calculate the flow rate from the low perm zone without the need for a PLT. The analysis for the components of the diverter may also lead to a similar result. The concentration of T1 and T2 does not have to be constant. The use of step, or a ramp in T1 and T2 concentration is also possible. The use of mass balance tracer T3 can also be used to confirm the amount of stimulation fluid produced back.

The preceding description has been presented with reference to some illustrative embodiments of the Inventors' concept. Persons skilled in the art and technology to which this invention pertains will appreciate that alterations and changes in the described structures and methods of operation can be practiced without meaningfully departing from the principle, and scope of this invention. Accordingly, the foregoing description should not be read as pertaining only to the precise structures described and shown in the accompanying drawings, but rather should be read as consistent with and as support for the following claims, which are to have their fullest and fairest scope.

Furthermore, none of the description in the present application should be read as implying that any particular element, step, or function is an essential element which must be included in the claim scope: the scope of patented subject matter is defined only by the allowed claims. Moreover, none of these claims are intended to invoke paragraph six of 35 USC §112 unless the exact words “means for” are followed by a participle. The claims as filed are intended to be as comprehensive as possible, and no subject matter is intentionally relinquished, dedicated, or abandoned.

Claims

1. A method to treat a subterranean formation comprising a wellbore, comprising:

introducing a tool to a wellbore in a region of low permeability or damage;

treating the region of low permeability or damage with a fluid;

simultaneously measuring a fluid pressure drop and volume of fluid flow in a particular region;

and moving the tool to another region.

2. The method of claim 1, further comprising calculating properties of the region of low permeability or damage using the fluid pressure drop and volume of fluid flow.

3. The method of claim 1, wherein the treating the region of low permeability or damage comprises a matrix acid treatment, a hydraulic fracturing treatment, introducing proppant, stimulating the region, or a combination thereof.

4. The method of claim 1, further comprising introducing a tracer with the fluid.

5. The method of claim 5, further comprising repeating the treating and moving the tool steps.

6. The method of claim 1, wherein the tool has dimensions to allow fluid flow through the wellbore.

7. A method to treat a subterranean formation comprising a wellbore, comprising:

introducing to a wellbore a tool in a region of low permeability or damage;

treating the region of low permeability or damage with a fluid;

introducing a diversion agent;

and moving the tool to another region

wherein the fluid comprises a tracer.

8. The method of claim 7, wherein the diversion agent comprises a tracer.

9. The method of claim 7, further comprising simultaneously measuring a fluid pressure drop and volume of fluid flow.

10. The method of claim 9, further comprising calculating properties of the region of low permeability or damage using the fluid pressure drop and volume of fluid flow.

11. The method of claim 7, wherein the treating the region of low permeability or damage comprises a matrix acid treatment, a hydraulic fracturing treatment, introducing proppant, stimulating the region, or a combination thereof.

12. A method to treat a subterranean formation comprising a wellbore, comprising:

introducing to a wellbore a tool in a region of low permeability or damage;

treating the region of low permeability or damage with a fluid;

introducing a diversion agent;

monitoring the fluid, wherein the fluid comprises a tracer; and

moving the tool to an additional region.

13. The method of claim 12, further comprising evaluating the fluid.

14. The method of claim 13, wherein evaluating the fluid comprises estimating the permeability of the region of low permeability or damage.

15. The method of claim 12, wherein the monitoring comprises measuring the concentration of tracer.

16. The method of claim 15, further comprising calculating properties of the region of low permeability or damage using the fluid pressure drop and volume of fluid flow.

17. The method of claim 12, wherein the monitoring the fluid comprises measuring parameters to estimate diversion agent properties.

18. The method of claim 17, wherein the diversion agent properties include effectiveness of the diversion agent.