Classifications

• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/25—Methods for stimulating production
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/25—Methods for stimulating production
  • E21B43/26—Methods for stimulating production by forming crevices or fractures
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/25—Methods for stimulating production
  • E21B43/26—Methods for stimulating production by forming crevices or fractures
  • E21B43/267—Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B47/00—Survey of boreholes or wells
  • E21B47/10—Locating fluid leaks, intrusions or movements
  • E21B47/11—Locating fluid leaks, intrusions or movements using tracers; using radioactivity

Definitions

• 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.
• Fii *ure 1 is a sectional view of a tool in a wellbore.
• Fii *ure 2 is a sectional view of a tool in a wellbore.
• Fii *ure 3 is a plot of pressure as a function of injection rate
• Fii *ure 4 is a sectional view of a tool in a wellbore.
• Fij *ure 5 is a sectional view of a wellbore.
• Fii *ure 6 is a plot of pressure as a function of injection rate
• Fii *ure 7 is a sectional view of a tool in a wellbore.
• Fii *ure 8 is a sectional view of a wellbore.
• 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.
• composition used/disclosed herein can also comprise some components other than those cited.
• 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.
• 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.
• 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.
• 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.
• 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.
• 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. ( Figure 1). Some embodiments may benefit from the use of a tracer during this step.
• step 4 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 (figures 4, 5, 6).
• the difference in the rates at same pressures 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.
• 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.
• Figure 7 illustrates how the tool may be sized to facilitate fluid flow through the wellbore.
• Figure 8 illustrates a clean-up step for some embodiments of the invention.
• the steps 2 through 5 can be made without stopping the pumping or fracturing treatment.
• 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
• 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 Figures 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.
• 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.
• this method allows an alternative to the conventional method using distributed temperature sensors (DTS).
• DTS distributed temperature sensors
• Position downhole sampling device such as compact production sampler cartridge with multiple sample bottles, between top and the bottom 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.
• the low permeability zones have more dolomite CaMg(C03), while the high permeability zones have more limestone (CaC0 3 ).
• Ca and Mg can serve as tracers and their concentrations in the flow back fluid can be used to determine the diverter efficiency.
• Position downhole sampling device such as compact production sampler cartridge with multiple sample bottles, between top and the bottom zone.
• post stimulation fluid S2 e.g. displacement fluid, post flush fluid, overflush fluid
• Position downhole sampling device such as compact production sampler cartridge with multiple sample bottles, between top and the bottom zone.
• composition of the surface and downhole samples 6) Determine volume of stimulation fluid injected in the both zones during the first stage (SI fluid) by analyzing the tracer Tl concentration in the surface sample vs. the downhole sample.
• pre stimulation fluid SI e.g. reservoir conditioning or pre-conditioning fluid
• Position downhole sampling device such as compact production sampler cartridge with multiple sample bottles, between top and the bottom zone.
• pre stimulation fluid SI e.g. reservoir conditioning or pre-conditioning fluid
• 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 Tl 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 Tl and T2 does not have to be constant.
• the use of step, or a ramp in Tl 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.

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• Geology (AREA)
• Life Sciences & Earth Sciences (AREA)
• Engineering & Computer Science (AREA)
• Mining & Mineral Resources (AREA)
• Physics & Mathematics (AREA)
• Geochemistry & Mineralogy (AREA)
• Fluid Mechanics (AREA)
• General Life Sciences & Earth Sciences (AREA)
• Environmental & Geological Engineering (AREA)
• Geophysics (AREA)
• Sampling And Sample Adjustment (AREA)
• General Preparation And Processing Of Foods (AREA)
• Physical Or Chemical Processes And Apparatus (AREA)
• Processing Of Solid Wastes (AREA)
• Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)
• Analysing Materials By The Use Of Radiation (AREA)
• Measuring Volume Flow (AREA)

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• 2011
  • 2011-05-10 EA EA201291215A patent/EA025825B1/ru not_active IP Right Cessation
  • 2011-05-10 CA CA2799098A patent/CA2799098A1/en not_active Abandoned
  • 2011-05-10 AU AU2011251674A patent/AU2011251674B2/en not_active Ceased
  • 2011-05-10 MX MX2012013138A patent/MX2012013138A/es unknown
  • 2011-05-10 US US13/697,460 patent/US20140166276A1/en not_active Abandoned
  • 2011-05-10 WO PCT/IB2011/052060 patent/WO2011141875A2/en active Application Filing
  • 2011-05-10 EP EP11780291.8A patent/EP2564020A4/en not_active Withdrawn
  • 2011-05-10 CN CN201180034234.2A patent/CN103003520B/zh not_active Expired - Fee Related
• 2016
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