WO2025085338A1 - Procédé de test de puits profond et de détermination de perméabilité dans une direction différente - Google Patents

Procédé de test de puits profond et de détermination de perméabilité dans une direction différente Download PDF

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Publication number
WO2025085338A1
WO2025085338A1 PCT/US2024/051038 US2024051038W WO2025085338A1 WO 2025085338 A1 WO2025085338 A1 WO 2025085338A1 US 2024051038 W US2024051038 W US 2024051038W WO 2025085338 A1 WO2025085338 A1 WO 2025085338A1
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WIPO (PCT)
Prior art keywords
fluid
lateral extension
reservoir
wellbore
marker
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Pending
Application number
PCT/US2024/051038
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English (en)
Inventor
Mohammed Abdullah BATAWEEL
Eyad Ali ALALI
Bander I. QUAIMI
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Saudi Arabian Oil Co
Aramco Services Co
Original Assignee
Saudi Arabian Oil Co
Aramco Services Co
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Application filed by Saudi Arabian Oil Co, Aramco Services Co filed Critical Saudi Arabian Oil Co
Publication of WO2025085338A1 publication Critical patent/WO2025085338A1/fr
Anticipated expiration legal-status Critical
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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
    • 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
    • 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
    • E21B47/111—Locating fluid leaks, intrusions or movements using tracers; using radioactivity using radioactivity
    • 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
    • E21B43/14—Obtaining from a multiple-zone well
    • 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
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • E21B49/008—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells by injection test; by analysing pressure variations in an injection or production test, e.g. for estimating the skin factor
    • 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
    • E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
    • E21B2200/20—Computer models or simulations, e.g. for reservoirs under production, drill bits

Definitions

  • Knowledge of the physical characteristics, such as permeability, may be obtained from core samples and well logging measurements taken from existing wellbores. These physical characteristics may then be interpolated or extrapolated, often guided by deep sensing surface measurements, between existing wellbore locations to form a reservoir model describing the spatial distribution of physical characteristics across the extent of the hydrocarbon reservoir.
  • the present disclosure presents methods and systems for measuring a fluid flow characteristic of a subterranean region of interest.
  • the method includes installing a
  • SUBSTITUTE SHEET (RULE 26) fluid detection sensor in a first lateral extension from a primary wellbore, establishing a fluid conduit from a well-head to a second lateral extension from the primary wellbore, pumping a marker fluid through the fluid conduit from the well-head to the second lateral extension and into the subterranean region of interest.
  • the method further includes detecting, using the fluid detection sensor, the marker fluid in the first lateral extension, wherein the marker fluid in the first lateral extension has flowed from the second lateral extension through the subterranean region of interest and determining the fluid flow characteristic of the subterranean region of interest based, at least in part, on the detected marker fluid.
  • the system includes a primary wellbore extending from a well-head into the subterranean region of interest, a first lateral extension from a primary wellbore, equipped with a fluid detection sensor configured to detect a marker fluid in the first lateral extension, and a second lateral extension from the primary wellbore, fluidically connected to the well-head through a fluid conduit.
  • the system further includes a pump configured to pump a marker fluid through the fluid conduit from the well-head to the second lateral extension and from the second lateral extension through a portion of the subterranean region of interest to the first lateral extension and a computer processor, configured to determine the fluid flow characteristic of the subterranean region of interest based, at least in part, on the detected marker fluid.
  • FIG. 1 depicts a hydrocarbon reservoir in accordance with one or more embodiments.
  • FIG. 2 depicts a flowchart in accordance with one or more embodiments.
  • FIG. 3 depict a drilling system in accordance with one or more embodiments.
  • FIG. 4 depicts cross-sections through rock samples in accordance with one or more embodiments.
  • FIGs. 5A - 5C show lateral extensions in accordance with one or more embodiments.
  • FIG. 6 depicts a system in accordance with one or more embodiments.
  • FIG. 7 depicts a flowchart in accordance with one or more embodiments.
  • FIG. 8 shows a computer system in accordance with one or more embodiments.
  • ordinal numbers e.g., first, second, third, etc.
  • an element i.e., any noun in the application.
  • the use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before,” “after,” “single,” and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements.
  • a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.
  • the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise.
  • reference to a “wellbore” includes reference to one or more of such wellbores.
  • any component described with regard to a figure in various embodiments disclosed herein, may be equivalent to one or more like-named components described with regard to any other figure.
  • descriptions of these components will not be repeated with regard to each figure.
  • each and every embodiment of the components of each figure is incorporated by reference and assumed to be optionally present within every other figure having one or more like-named components.
  • any description of the components of a figure is to be interpreted as an optional embodiment which may be implemented in addition to, in conjunction with, or in place of the embodiments described with regard to a corresponding like-named component in any other figure.
  • FIG. 1 depicts a schematic representation of a subterranean region of interest (100), lying beneath a portion of the surface of the Earth (120).
  • the surface of the Earth (120) may be a land area (as illustrated), or a swamp, lacustrine or marine area, or any combination of these areas.
  • the subterranean region of interest (100) may include one or more hydrocarbon reservoirs, such as a hydrocarbon reservoir (102), lying beneath an overburden (110).
  • overburden refers to the column of rocks lying above the hydrocarbon reservoir (102) that are of lesser interest to those exploring for, or producing, hydrocarbons from the hydrocarbon reservoir (102).
  • the overburden (110) may include a cap rock (112), or seal.
  • the cap rock (112) forms an impermeable layer above the hydrocarbon reservoir (102) through which hydrocarbons cannot flow.
  • Below the hydrocarbon reservoir (102) lie further rock layers, sometimes called an “underburden” (114) or “basement”.
  • the underburden (114) may contain the source rock from which the hydrocarbon has been produced from biological material under the combined effect of heat and pressure over geological time periods.
  • a subterranean region of interest (100) may contain two or more hydrocarbon reservoirs disposed at different depths.
  • a shallow hydrocarbon reservoir may form part of the overburden (110) for a deeper hydrocarbon reservoir.
  • the hydrocarbon reservoir (102) may itself be subdivided into different layers or “legs”.
  • the shallowest layer within the hydrocarbon reservoir (102) may predominantly contain gas with the pores of the rock and be referred to as the “gas leg” (104).
  • the gas leg (104) may lie an “oil leg” (106) where the pores are predominantly filled with oil.
  • the lowest level form a “water leg” (108) where the pores are predominantly filled with water or brine.
  • This ordering with a gas leg (104) lying above an oil leg (106), lying in turn above a water leg (108), is controlled by the relative buoyancy of gas, oil and water and the gradual flow or movement of the three fluids through the pores of the rock over geological time.
  • all three layers may be present in some hydrocarbon reservoirs, other may contain only two, for example oil and water.
  • Producing hydrocarbon from a hydrocarbon reservoir may require the drilling of a wellbore using a drilling system (118).
  • the wellbore may be drilled directly from the surface of the Earth (120) to the hydrocarbon reservoir (102).
  • Such a wellbore, drilled from the surface to the reservoir may be called a “primary wellbore” (116).
  • the wellbore may be drilled from a primary wellbore.
  • Such a wellbore may be termed a “lateral extension” (122) or simply lateral, or a sidetrack.
  • the lateral extension (122) may be initiated from the primary wellbore (116) hundreds or thousands of meters (thousands of feet) below the surface of the Earth (120). More than one lateral extension, such as lateral extension (122), may originate from the same primary wellbore (116).
  • a reservoir modeling system such as reservoir modeling system (204) shown in FIG. 2, may be used.
  • a reservoir modeling system (204) may include one or more computer systems with appropriate software configured to receive reservoir data (202) and generate at least one reservoir model (206).
  • Reservoir data may further be combined to determine rock formation characteristics, such as permeability, porosity and elastic moduli, by the reservoir modeling system.
  • the reservoir modeling system may further interpolate and/or extrapolate the measured sensor values, and the determined rock formation characteristics into the space between the wellbores, to produce a digital representation of the subterranean region of interest including the hydrocarbon reservoir.
  • a digital representation may be termed a reservoir model (206).
  • the reservoir model (206) may include values of rock formation and pore fluid characteristics on a three-dimensional (3D) Cartesian or irregular grid spanning the subterranean region of interest.
  • the reservoir model may be the input to a reservoir simulator (208).
  • a reservoir simulator comprises functionality for simulating the flow of fluids, including hydrocarbon fluids such as oil and gas, through a hydrocarbon reservoir composed of porous, permeable reservoir rocks in response to natural and anthropogenic pressure gradients.
  • a reservoir simulator (208) may solve a set of mathematical governing equations that represent the physical laws that govern fluid flow in porous, permeable media. For example, the flow of a single-phase slightly compressible oil with a constant viscosity and compressibility the equations capture Darcy’s law, the continuity condition and the equation of state and may be written as: where p represents fluid in the reservoir, x is a vector representing spatial position and t represents time, (p, p, c t , and k represent the physical and petrophysical properties of porosity, fluid viscosity, total combined rock and fluid compressibility, and permeability, respectively. V 2 represents the spatial Laplacian operator.
  • the reservoir simulator (208) may be used to predict one or more fluid flow and production scenario (210).
  • the reservoir simulator (208) may be used to predict the changes in fluid flow, including fluid flow into well penetrating the reservoir, as a result of fluid injection and/or extraction of time.
  • the reservoir simulator may be used to predict changes in hydrocarbon production rate that would result from the injection of water into the reservoir from wells around the hydrocarbon reservoir’s periphery.
  • the reservoir simulator (208) may be used to predict the hydrocarbon production rate that would result from proposed new wellbores.
  • Fluid flow and production scenarios (210) may be used to form or update a reservoir production plan (212).
  • the reservoir production plan may specify where and in what order to drill wellbores to penetrate the hydrocarbon and which wellbore may be used to inject fluids, such as water, rather than to produce hydrocarbons.
  • the reservoir production plan (212) may specify which planned wellbores are to be primary wellbores, such as primary wellbore (116) and which planned wellbore are to be lateral extensions, such as lateral extension (122).
  • the reservoir production plan (212) may specify wellbore completions.
  • the reservoir production plan may specify the location and parameters of another form of lateral extension that wellbores may undergo, namely hydraulic fracturing.
  • hydraulic fracturing the fluid pressure inside a wellbore may be increase by injecting fluid from the surface until the rock formation surrounding the wellbore cracks or fractures creatin a subterranean fissure emanating from the wellbore lateral to the axis of the wellbore.
  • proppant often a fine sand may be pumped from the surface of the Earth into the hydraulic fracture.
  • proppant props the hydraulic fracture at least partially open when the fluid pressure is reduced thus creating a hydraulic pathway from the wellbore into the body of the hydrocarbon reservoir.
  • Drilling systems (214) may be used to drill further wellbores, both primary wellbores (116) and lateral extensions (122) guided by the reservoir production plan (212). Further the wellbores (116, 122) drilled by the drilling system (214) may be used to collect additional reservoir data (202).
  • FIG. 3 depicts a drilling system (214), in accordance with one or more embodiments.
  • a wellbore (302) following a wellbore trajectory (304) may be drilled by a drill bit (306) attached by a drillstring (308) to a drill rig (310) located on the surface of the Earth (120).
  • the drill rig (310) may include framework, such as a derrick (312) to hold drilling machinery.
  • a top drive (314) sits at the top of the derrick (312) and provides clockwise torque via the drive shaft (316) to the drillstring (308) in order to drill the wellbore (302).
  • the drillstring (308) may comprise a plurality of sections of drillpipe attached at the uphole end to the drive shaft (316) and downhole to a bottomhole assembly (“BHA”) (318).
  • the BHA may be composed of a plurality of sections of heavier drillpipe and one or more measurement-while-drilling (“MWD”) tools configured to measure drilling parameters, such as torque, weight-on-bit, drilling direction, temperature, etc., and one or more logging-while-drilling (“LWD”) tools configured to measure parameters of the rock surrounding the wellbore (302), such as electrical resistivity, density, sonic propagation velocities, gamma-ray emission, etc.
  • MWD measurement-while-drilling
  • LWD logging-while-drilling
  • the wellbore (302) may traverse a plurality of overburden (110) layers and one or more cap-rock (112) layers to a hydrocarbon reservoir (102) within the subterranean region of interest (100), and specifically to a drilling target (324) within the hydrocarbon reservoir (102).
  • the wellbore trajectory (304) may be a curved or a straight trajectory. All or part of the wellbore trajectory (304) may be vertical, and some portions of the wellbore trajectory (304) may be deviated or be horizontal.
  • One or more portions of the wellbore (302) may be cased with casing (326) in accordance with the wellbore plan.
  • the hoisting system To start drilling, or “spudding in” the well, the hoisting system lowers the drillstring (308) suspended from the derrick (312) towards the planned surface location of the wellbore.
  • An engine such as a diesel engine, may be used to supply power to the top drive (314) to rotate the drillstring (308).
  • the weight of the drillstring (308) combined with the rotational motion enables the drill bit (306) to bore the wellbore.
  • the near-surface is typically made up of loose or soft sediment or rock, so large diameter casing (326), e.g., “base pipe” or “conductor casing,” is often put in place while drilling to stabilize and isolate the wellbore.
  • base pipe e.g., “base pipe” or “conductor casing”
  • the wellhead At the top of the base pipe is the wellhead, which serves to provide pressure control through a series of spools, valves, or adapters.
  • water or drill fluid may be used to force the base pipe into place using a pumping system until the wellhead is situated just above the surface of the Earth (120).
  • Drilling may continue without any casing (326) once deeper, or more compact rock is reached.
  • a drilling mud system (328) may pump drilling mud from a mud tank on the surface of the Earth (120) through the drill pipe. Drilling mud serves various purposes, including pressure equalization, removal of rock cuttings, and drill bit cooling and lubrication.
  • drilling may be paused and the drillstring (308) withdrawn from the wellbore.
  • Sections of casing (326) may be connected and inserted and cemented into the wellbore.
  • Casing string may be cemented in place by pumping cement and mud, separated by a “cementing plug,” from the surface of the Earth (120) through the drill pipe.
  • the cementing plug and drilling mud force the cement through the drill pipe and into the annular space between the casing and the wellbore wall.
  • drilling may recommence.
  • the drilling process is often performed in several stages. Therefore, the drilling and casing cycle may be repeated more than once, depending on the depth of the wellbore and the pressure on the wellbore walls from surrounding rock.
  • BOP blowout preventer
  • a drilling system (214) may be disposed at and communicate with other systems in the well environment.
  • the drilling system (214) may control at least a portion of a drilling operation by providing controls to various components of the drilling operation.
  • the system may receive data from one or more sensors arranged to measure controllable parameters of the drilling operation.
  • sensors may be arranged to measure weight-on-bit, drill rotational speed (RPM), flow rate of the mud pumps (GPM), and rate of penetration of the drilling operation (ROP).
  • RPM drill rotational speed
  • GPS flow rate of the mud pumps
  • ROP rate of penetration of the drilling operation
  • Each sensor may be positioned or configured to measure a desired physical stimulus. Drilling may be considered complete when a drilling target (324) is reached, or the presence of hydrocarbons is established.
  • the drilling target (324) may be a portion of the hydrocarbon reservoir (102) that the reservoir model (206) predicts to be a region of high porosity and high permeability, since regions such as these may both contain significant amounts of hydrocarbons and allow them to flow with relative ease from the rock formation to the wellbore.
  • FIG. 4 depicts cross-sections through rocks with high and low porosity and high and low permeability.
  • Cross-section (402) depicts a rock with low porosity and low permeability. The rock is composed almost entirely of grains (406) with almost no void spaces, i.e., pores (408) between them. Further, cross-section (402) exhibits few pathways between the pores (408) to allow the fluid to flow from one pore to another under a pressure gradient.
  • cross-section (402) depicts a rock sample with both low permeability and low porosity.
  • cross-section (410) depicts a rock sample with high porosity but low permeability.
  • the pores (408) between the grains (406) contributes a much larger fraction of the volume of rock sample depicted in cross-section (410) than of rock sample depicted in cross-section (402), and hence has a higher porosity, these pores (408) are not well connected by pathways through which pore fluid may flow.
  • cross-section (410) depicts a rock sample with low permeability.
  • Cross-section (420) depicts a rock sample with low porosity, i.e., a small fraction of the volume of the rock sample is composed of pores, it does exhibit continuous pathways between the pores, such as pathway (422) indicated by the dashed line, through which fluid may flow.
  • cross-section (420) depicts a rock sample with higher permeability than either cross-section (402) or cross-section (410) but a lower permeability than cross-section (410).
  • cross-section (430) depicts a rock sample with both high porosity and high permeability. That is, cross-section (430) both has a high volume fraction of pore space and flow pathways through which pore fluid may flow when subjected to a pressure gradient.
  • Predicting characteristics of the hydrocarbon reservoir (102) surrounding a primary wellbore (116) from reservoir data recorded along said primary wellbore (116) presents several difficulties. In particular, predicting permeability of the reservoir (102) is challenging.
  • a hydrocarbon reservoir may exhibit significant spatial heterogeneity in its characteristics both vertically and laterally. This makes simple interpolation inaccurate. Such heterogeneity may include discontinuous changes, due to the presence of a fault intersecting the reservoir, as well as gradual continuous changes.
  • a hydrocarbon reservoir (102) penetrated by numerous primary wellbores (116) only a fraction of the volume of the hydrocarbon reservoir (102) may be sampled. This is particularly apparent when it is understood that reservoir data collected from each primary wellbore (116) has a depth of investigation into the rock formation of only one or two wellbore diameters at most, i.e., 0.3 to 0.6 meters (a foot or two feet). In contrast, neighboring primary wellbores (116) may be separated by several tens, if not, hundreds or thousands of meters.
  • the process of drilling a primary wellbore (116) may damage the rock adjacent to the primary wellbore (116).
  • the surrounding rock may suffer micro-cracking and changes in the stress field as a result of the creating of the wellbore.
  • the rock adjacent to the primary wellbore (116) may experience infiltration of the drilling mud used to lubricate the drill bit and flush rock fragments.
  • the drilling mud may replace the pore fluids originally saturating the rock, and the grains of the rock may undergo chemical changes, e.g., swelling, as a result of exposure to the drilling mud. Furthermore, the rock may undergo thermal changes, such as heating or cooling, during the drilling of the primary wellbore (116). Each of these changes, and others not listed, may change the physical characteristics of the rock formation adjacent to the primary wellbore (H6).
  • sensors deployed in the primary wellbore (116) may not measure physical characteristics representative of the hydrocarbon reservoir (102) as a whole.
  • the unrepresentative physical characteristics may be erroneously interpolated or extrapolated using the reservoir modeling system. Inaccurate determination of physical characteristics is damaging to the drilling and completion of the hydrocarbon reservoir (102).
  • embodiments disclosed herein outline systems and methods that can be used to accurately determine the physical characteristics of the hydrocarbon reservoir (102) by mimicking multi-well testing using a single primary wellbore (116).
  • the embodiments disclosed herein create lateral extensions, and/or hydraulic fractures, from a primary wellbore (116).
  • the lateral extensions may be created using any means in the art, such as drilling a sidetracked wellbore, using tunneling equipment to create tunnels, etc.
  • the lateral extensions, and/or hydraulic fractures are used to measure the formation properties of the reservoir (102) located between neighboring lateral extensions, and/or hydraulic fractures.
  • the lateral extensions/hydraulic fractures work together, or work with the primary wellbore (116), to create an injection/production system. At least one of the lateral extensions/hydraulic fractures or primary wellbore (116) is formed as an “injection side” and at least one of the lateral extensions/hydraulic fractures or primary wellbore (116) is formed as an “observation side”.
  • the observation side is equipped with measurement tools to help determine the formation properties in-situ between the injection side and the observation side. Such measurements will give a better understanding of the reservoir (102) permeability at different orientations. Any combination of number and orientation of lateral extensions may be used without departing from the scope of the disclosure herein.
  • FIGs. 5A - 5C show example orientations of lateral extensions in accordance with one or more embodiments.
  • FIGs 5A - 5C show a small sample of potential lateral extension orientations and combinations. Any number and orientation of lateral extensions may be used without departing from the scope of the disclosure herein.
  • FIGs. 5A - 5C share several like-numbered elements in common and to prevent repetition those common elements may be discussed in connection with only one of the figures. It will be understood that the essential characteristics of the like-numbered elements are unchanged with FIGs. 5A - 5C.
  • FIG. 5A a primary wellbore (116) is shown drilled by a drilling system (214) from the surface of the Earth (120) through a hydrocarbon reservoir (102).
  • a plurality of lateral extensions (510a - 51 Of) are shown created from one or more subterranean locations along the primary wellbore (116).
  • a single lateral extension may be formed, while in other embodiments a plurality of lateral extensions may be formed.
  • the lateral extensions (510a - 51 Of) may be considered, or termed, tunnels or miniature wellbores without departing from the scope of the disclosure herein.
  • the lateral extensions (510a - 51 Of) may deviate several meters to several hundred meters (several feet to several hundred feet) or more from the primary wellbore (116). In some embodiments, the lateral extensions (510a - 51 Of) may themselves have a length of a few meters to a few hundred meters (a few feet to a few hundred feet), and a diameter of a few centimeters to a few tens of centimeters (an inch to several inches). However, the example length range and diameter range of the lateral extensions should not be regarded as limiting to the claimed invention.
  • the lateral extensions (510a - 51 Of) shown in FIG. 5 A may be miniature wellbores or tunnels formed from the primary wellbore (116).
  • the lateral extensions (510a - 5 lOf) are drilled as sidetracked wells using a drilling rig or coiled tubing.
  • Methods for constructing sidetracked wells are well known in the art. For example, directional equipment or whipstocks may be used to drill each lateral extension (510a - 51 Of) from the primary wellbore (116).
  • Tunneling technology typically requires less surface equipment than the equipment required to fully sidetrack a well. Tunneling technology may use lasers, high pressured water, acid, miniature drill bits, etc., to form the tunnels. Tunneling technology may also use coiled tubing or wireline to deploy the downhole tunneling tools.
  • FIG. 5 A shows the lateral extensions (510a - 51 Of) each having a reception portion (512) disposed within the hydrocarbon reservoir (102).
  • the reception portions (512) may be instrumented with sensors designed to detect a characteristic of a marker fluid or an injection fluid.
  • the sensors may include pressure sensors, flow rate sensors, and/or temperature sensors.
  • FIG. 5 A shows the primary wellbore (116) equipped with an injection zone (514) disposed in the hydrocarbon reservoir (102).
  • a marker fluid may be pumped into the primary wellbore (116), through the injection zone (514), and into the portion of the hydrocarbon reservoir (102) surrounding the injection zone (514).
  • the marker fluid may flow, under an imposed pressure gradient, through the hydrocarbon reservoir (102) to one or more of the reception portions (512) of the lateral extensions (510a - 51 Of).
  • the imposed pressure gradient may be produced by elevating the pressure in the injection zone (514).
  • the pressure gradient may be produced by lowering the pressure in the reception portions (512).
  • a pressure gradient may be produced by raising the pressure in the injection zone (514) while simultaneously lowering the pressure in the reception portions (512).
  • the injection zone (514) lies in the primary wellbore (116) and the reception portions (512) lie in the lateral extensions (510a - 51 Of).
  • the injection zone (514) may lie in one or more of the lateral extensions (510a - 5 lOf) and the reception portions (512) may lie in the primary wellbore (116).
  • the injection zone (514) may be called the active side and the reception portions (512) may be called the receiving or observation sides.
  • the reception portions (512) may be completed to allow the marker fluid to enter the reception portion (512) from the surrounding reservoir (102). Once the marker fluid has entered the reception portion (512), the marker fluid may flow out of the reception portion (512) to one or more sensors disposed further within the lateral extension (510a - 51 Of .
  • the completion may include a casing disposed within each reception portion (512). The casing may be perforated to allow the marker fluid to enter the reception portions (512).
  • the reception portion (512) of the lateral extensions (510a - 51 Of) may remain uncompleted and coiled tubing, or temporary tubing, may be connected to or deployed within the reception portion (512).
  • the marker fluid may be injected into the reservoir (102) using at least one of the injection zones (514).
  • the marker fluid may travel through the reservoir (102) to be received by the coiled tubing, or temporary tubing, in the reception portion (512).
  • the coiled tubing or temporary tubing may be equipped with the sensors and may detect arrival time and other fluid properties of the marker fluid. This data may be used to determine the permeability of the reservoir (102) between the injection zone (514) and the reception portion (512).
  • the coiled tubing or the temporary tubing may be used as a conduit for the marker fluid to travel to the surface of the Earth (120).
  • the marker fluid may be measured or detected using sensors or the human eye.
  • coiled tubing or temporary tubing may be connected to or deployed within the injection zone (514).
  • the marker fluid can be injected in the annulus between the coiled tubing, or temporary tubing, and the reservoir (102).
  • the marker fluid then flows through the reservoir (102) to be received or detected at the reception portion (512).
  • the reception portion (512) may include sensors to indicate reception of the marker fluid and/or measure fluid properties of the marker fluid.
  • the reception portion (512) may be equipped with casing that acts as a conduit for the marker fluid to travel to the surface of the Earth (120).
  • the marker fluid may be measured or detected using sensors or the human eye.
  • the marker fluid may include any fluid that is injected into the reservoir (102) from the injection zone (514).
  • the marker fluid possess at least one measurable characteristic that differ from the fluids already present in the hydrocarbon reservoir.
  • the marker fluid may be gas.
  • the marker fluid may be water.
  • the marker fluid may be a fluorescent fluid, while in other embodiments the marker fluid may be a radioactive fluid.
  • the marker fluid may possess a specific chemical structure, such as a polymer.
  • Several different characteristics of the marker fluid may be measured at lateral extensions (510a - 5 lOf). For example, in some embodiments the arrival time of the marker fluid at the reception portions (512) and/or the lateral extensions (510a - 51 Of) may be recorded. Alternatively, the transit time between the beginning of injection at the injection zone (514) to the detection of the marker fluid at the lateral extensions (510a - 51 Of) may be recorded. In other embodiments, the flow rate, or concentration of the marker fluid once a steady state has been reached, may be recorded.
  • FIG. 5B shows an alternative geometry of lateral extensions (510g, 51 Oh) running at an orientation that is highly deviated from the vertical or horizontal from the primary wellbore (116).
  • lateral extension (510g) may be disposed wholly or approximately parallel to, and above, lateral extension (51 Oh).
  • the lateral extensions (510g) and (51 Oh) may be disposed approximately parallel to one another and at the same depth.
  • One of the horizontal lateral extensions may contain an injection zone (514) and the other a reception portion (512).
  • lateral extension (510g) has an injection zone (514) and lateral extension (5 lOh) has a reception portion (512).
  • lateral extension (510g) may have a reception portion (512) and lateral extension (5 lOh) may have an injection zone (514).
  • the injection of the marker fluid, the reception of marker fluid, and the determination of physical characteristics of the reservoir (102) may be similar to that explained above with respect to FIG. 5 A.
  • FIG. 5C depicts another geometry, in accordance with one or more embodiments.
  • FIG. 5C shows a primary wellbore (116) that has undergone hydraulic fracturing.
  • the primary wellbore (116) has at least two hydraulic fractures.
  • the primary wellbore (116) has hydraulic fracture (520a) and hydraulic fracture (520b).
  • lateral extensions such as lateral extensions (510a - 5 lOh)
  • hydraulic fractures such as hydraulic fractures (520a, 520b).
  • a hydraulic fracture may be used for injection of the marker fluid and a lateral extension may be used for the deployment of sensors to form a reception portion, or vice versa.
  • one or more lateral extensions may be drilled and a hydraulic fracture may be initiated in the lateral extension.
  • the lateral extensions can be positioned in different numbers and orientations to enhance the permeability measurements in the X, Y, and Z axis.
  • the flow pattern may be varied from radial to linear by creating parallel fractures.
  • one or more physical characteristic of the rock formation of the hydrocarbon reservoir may be determined from the characteristics of the marker fluid.
  • the permeability of the portion of the hydrocarbon reservoir lying between the injection zone and the reception portion of the lateral extensions may be determined.
  • permeability of the reservoir (102) between the injection zone (514) and the reception portion (512) can be calculated by the injection pressure, injection rate, measured flow rate, and pressure from the reception portion (512).
  • these portions of the hydrocarbon reservoir (102) may be several, tens or hundreds of meters (tens or hundreds of feet) in spatial extent, i.e., much larger volumes than that sensed by sensors located in the primary wellbore (116). Furthermore, the portion of the hydrocarbon reservoir (102) lying between the injection zone (514) and the reception portion (512) of the lateral extensions (510a - 51 Oh) may be much less subject to alteration or damage than the rocks immediately surrounding the primary wellbore (116).
  • numerical simulation may be required to determine the physical characteristics of the hydrocarbon reservoir (102) from the measured or observed characteristic of the marker fluid.
  • a plurality of fluid flows may be simulated by a reservoir simulator, one for each of a range of physical characteristic values, such as permeability values.
  • the simulations may be performed using manual estimates of the permeability value, or randomly selected permeability values or within a formal inversion procedure, without departing from the scope of the invention.
  • the value of permeability that produces a simulation that best fits the observed or measured characteristics of the marker fluid may be taken as a reliable estimate of the true permeability value of the hydrocarbon reservoir (102) between the locations of the injection zone (514) and reception portions (512) of the lateral extensions (510a - 51 Of).
  • permeabilities may be measured in different orientations. For example, a north-south permeability and an east-west permeability may be measured within the reservoir. This may allow measurement of two or more components of the permeability tensor to be measured. In some instances, permeabilities may vary with orientation of measurement, an example of a phenomenon called “anisotropy” due, for example, to the presence of aligned natural fractures in the hydrocarbon reservoir.
  • FIG 6 depicts a primary wellbore (116) and two lateral extensions (610a, 610b), in accordance with one or more embodiments.
  • the primary wellbore (116) may include casing (606), typically composed of annular metallic pipes, that may be bonded to the wellbore wall with cement (608) filling the annulus between the casing (606) and the rock formation of the hydrocarbon reservoir (102).
  • the primary wellbore (116) is shown as a vertical wellbore with the two lateral extensions (610a, 610b) extending at an angle away from the primary wellbore (116).
  • Lateral extension (610b) is shown acting as an injection zone (514) and lateral extension (610a) is show acting as a reception portion (512).
  • the two lateral extensions (610a, 610b) may extend at any angle away from the primary wellbore (116). Furthermore, the two lateral extensions (610a, 610b) need not extend at the same angle. For example, lateral extension (610a) may extend at a 45 degree angle from the primary wellbore (116) while lateral extension (610b) may extend at a 90 degree angle from the primary wellbore, or vice versa. In other embodiments, the lateral extensions (610a, 610b) shown in FIG. 6 may be replaced with hydraulic fractures.
  • the primary wellbore (116) may be a horizontal wellbore without departing from the scope of the disclosure herein.
  • the portion of the hydrocarbon reservoir (102) immediately adjacent to the wellbore (116) may be a damaged or altered zone (604) where the rock has been damaged or altered by the process of drilling and completing the wellbore (116).
  • the lateral extension (610a, 610b) are left un-cased (“barefoot”).
  • the lateral extensions (610a, 610b) may be cased and cemented.
  • the lateral extensions (610a, 610b) may be cased with no cement.
  • coiled tubing, or temporary tubing may be disposed in the lateral extensions (610a, 610b) to act as a conduit.
  • a packer (612) may be disposed within the primary wellbore (116) between the intersection of the first lateral extension (610a) with the primary wellbore (116) and the intersection of the second lateral extension (610b) with the primary wellbore (116).
  • the packer (612) may form a hydraulic seal, isolating the portions of the wellbore (116) lying on either side.
  • the packer (612) may be deployed on, and penetrated by, a tubing (614) that may form a fluid conduit (616) from the surface to the second lateral extension (610b) through which marker fluid may be pumped.
  • At least one sensor such as sensors (618a-e) may be disposed in the first lateral extension (610a). In other embodiments, at least one sensor, may be positioned in the primary wellbore (116) close to the intersection between the primary wellbore (116) and the first lateral extension (610a), not shown.
  • the sensors may be connected to the wellhead through a physical communications channel (620), such as a wireline or an optical fiber.
  • the sensors may have wireless communication with the wellhead.
  • the sensors may store data autonomously to be retrieved later by a data retrieval tool (not shown) or by recovering the sensors themselves to the surface.
  • the sensors (618a-e) may be configured to detect the presence and/or characteristics of the marker fluid that may percolate through the hydrocarbon reservoir (102) from the second lateral extension (610b) to the first lateral extension (610a), as indicated by the arrows (618), substantially avoiding the damaged or altered zone (604).
  • FIG. 7 shows a flowchart (700) in accordance with one or more embodiments.
  • a fluid detection sensor (618a) may be installed in a first lateral extension (610a) from a primary wellbore (116).
  • the first lateral extension (610a) may be a sidetracked wellbore, a tunnel, or a hydraulic fracture (520a, 520b).
  • a fluid conduit (616) from a wellhead to a second lateral extension (610b) from the primary wellbore (116) may be established.
  • the second lateral extension (610b) may be a sidetracked wellbore, a tunnel, or a hydraulic fracture (520a, 520b).
  • the first lateral extension (610a) and the second lateral extension (610b) are hydraulically isolated within the primary wellbore (116) with an impermeable packer (612) disposed between the lateral extensions (610a, 610b).
  • the fluid conduit (161) may be established by inserting a coiled tubing from the wellhead through the packer (612).
  • a marker fluid may be pumped through the fluid conduit (616) from the wellhead to the second lateral extension (610b) and into the subterranean region of interest.
  • the marker fluid may be a radioactive tracer, while in other embodiments the marker fluid may be a fluorescent fluid, or a polymer. In other embodiments the marker fluid may be any fluid with characteristics distinct from the hydrocarbon reservoir pore fluid.
  • the marker fluid in the first lateral extension (610a) may be detected using at least one fluid detection sensor (618a - e).
  • the detected marker fluid may have flowed to the first lateral extension (610a) from the second lateral extension (610b) through the subterranean region of interest.
  • the fluid detection sensor (618a - e) may detect characteristics of the marker fluid.
  • the marker fluid characteristic may be a steady-state flow rate, or a detection time of the marker fluid after the initiation of injection.
  • the fluid flow characteristic of the subterranean region of interest may be determined based, at least in part, on the detected marker fluid.
  • the fluid flow characteristic may be a permeability or one or more components of a permeability tensor.
  • determining the fluid flow characteristic may include performing fluid flow modelling for a relative geometry of the first lateral extension and the second lateral extension. Such a fluid flow modeling may be performed using a reservoir simulator.
  • a reservoir model may be determined or updated using a reservoir modeling system, based, at least in part, on the fluid flow characteristic.
  • a reservoir production plan describing planned wellbore drilling and completion operations, and surface production facility construction may be revising based, at least in part, on the updated reservoir model.
  • the reservoir production plan may include the drilling, using a drilling system, of new wellbore, including extended-reach and sidetrack wellbores based, at least in part, on the revised reservoir production plan.
  • FIG. 8 shows a computer system in accordance with one or more embodiments.
  • the computer system is used to provide computational functionalities associated with described algorithms, methods, functions, processes, flows, and procedures as described in the present disclosure, according to one or more embodiments.
  • a computer system such as the computer system shown in FIG. 8 may form part of both a reservoir modeling system and a reservoir simulator.
  • the illustrated computer (802) is intended to encompass any computing device such as a server, desktop computer, laptop/notebook computer, wireless data port, smart phone, personal data assistant (PDA), tablet computing device, one or more processors within these devices, or any other suitable processing device, including both physical or virtual instances (or both) of the computing device.
  • the computer (802) may include a computer that includes an input device, such as a keypad, keyboard, touch screen, or other device that can accept user information, and an output device that conveys information associated with the operation of the computer (802), including digital data, visual, or audio information (or a combination of information), or a graphical user interface (GUI).
  • GUI graphical user interface
  • the computer (802) can serve in a role as a client, network component, a server, a database or other persistency, or any other component (or a combination of roles) of a computer system for performing the subject matter described in the instant disclosure.
  • the illustrated computer (802) is communicably coupled with a network (830).
  • a generic computer (802), reservoir modeling system (204), and reservoir simulator (208) may be communicably coupled using a network (830).
  • one or more components of the computer (802) may be configured to 1 operate within environments, including cloud-computing-based, local, global, or other environment (or a combination of environments).
  • the computer (802) is an electronic computing device operable to receive, transmit, process, store, or manage data and information associated with the described subj ect matter.
  • the computer (802) may also include or be communicably coupled with an application server, e-mail server, web server, caching server, streaming data server, business intelligence (BI) server, or other server (or a combination of servers).
  • an application server e-mail server, web server, caching server, streaming data server, business intelligence (BI) server, or other server (or a combination of servers).
  • BI business intelligence
  • the computer (802) can receive requests over network (830) from a client application, for example, executing on another computer (802) and responding to the received requests by processing the said requests in an appropriate software application. For example, since seismic processing and seismic interpretation may not be sequential, each computer (802) system may receive requests over a network (830) from any other computer (802) and respond to the received requests appropriately. In addition, requests may also be sent to the computer (802) from internal users (for example, from a command console or by other appropriate access method), external or third-parties, other automated applications, as well as any other appropriate entities, individuals, systems, or computers.
  • the computer (802) includes an interface (804). Although illustrated as a single interface (804) in FIG. 8, two or more interfaces (804) may be used according to particular needs, desires, or particular implementations of the computer (802).
  • the interface (804) is used by the computer (802) for communicating with other systems in a distributed environment that are connected to the network (830).
  • the interface (804) includes logic encoded in software or hardware (or a combination of software and hardware) and operable to communicate with the network (830). More specifically, the interface (804) may include software supporting one or more communication protocols associated with communications such that the network (830) or interface's hardware is operable to communicate physical signals within and outside of the illustrated computer (802).
  • the computer (802) also includes at least one computer processor (805). Although illustrated as a single computer processor (805) in FIG. 8, two or more processors may be used according to particular needs, desires, or particular implementations of the computer (802). Generally, the computer processor (805) executes instructions and manipulates data to perform the operations of the computer (802) and any algorithms, methods, functions, processes, flows, and procedures as described in the instant disclosure.
  • the computer (802) further includes a memory (806) that holds data for the computer (802) or other components (or a combination of both) that can be connected to the network (830).
  • memory (806) can be a database storing data consistent with this disclosure. Although illustrated as a single memory (806) in FIG. 8, two or more memories may be used according to particular needs, desires, or particular implementations of the computer (802) and the described functionality. While memory (806) is illustrated as an integral component of the computer (802), in alternative implementations, memory (806) can be external to the computer (802).
  • the application (807) is an algorithmic software engine providing functionality according to particular needs, desires, or particular implementations of the computer (802), particularly with respect to functionality described in this disclosure.
  • application (807) can serve as one or more components, modules, applications, etc.
  • the application (807) may be implemented as multiple applications (807) on the computer (802).
  • the application (807) can be external to the computer (802).
  • Each of the components of the computer (802) can communicate using a system bus (803).
  • any or all of the components of the computer (802), both hardware or software (or a combination of hardware and software) may interface with each other or the interface (804) (or a combination of both) over the system bus (803) using an application programming interface (API) (812) or a service layer (813) or a combination of the API (812) and service layer (813).
  • the API (812) may include specifications for routines, data structures, and object classes.
  • the API (812) may be either computer-language independent or dependent and refer to a complete interface, a single function, or even a set of APIs.
  • the service layer (813) provides software services to the computer (802) or other components (whether illustrated or not) that are communicably coupled to the computer (802).
  • the functionality of the computer (802) may be accessible for all service consumers using this service layer.
  • Software services, such as those provided by the service layer (813) provide reusable, defined business functionalities through a defined interface.
  • the interface may be software written in JAVA, C++, or other suitable language providing data in extensible markup language (XML) format or another suitable format.
  • API (812) or the service layer (813) may illustrate the API (812) or the service layer (813) as stand-alone components in relation to other components of the computer (802) or other components (whether or not illustrated) that are communicably coupled to the computer (802).
  • any or all parts of the API (812) or the service layer (813) may be implemented as child or sub-modules of another software module, enterprise application, or hardware module without departing from the scope of this disclosure.
  • computers (802) associated with, or external to, a computer system containing computer (802), wherein each computer (802) communicates over network (830).
  • one computer system may be specifically configured for reservoir simulation and denoted the reservoir simulator (208).
  • Another computer system may be specifically configured for reservoir modeling and denoted the reservoir modeling (204).
  • seismic processing such as steps 502-522 of FIG. 5, may be conducted using a first computer (802) configured as a seismic processor with one or more seismic processing applications (807).
  • client may use one computer (802), or that one user may use multiple computers (802).

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  • Fluid Mechanics (AREA)
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  • General Life Sciences & Earth Sciences (AREA)
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Abstract

Sont divulgués des procédés et des systèmes. Le procédé peut consister à installer un capteur de détection de fluide (618a-e) dans une première extension latérale (610a) à partir d'un puits de forage primaire (116), à établir un conduit de fluide (616) d'une tête de puits à une seconde extension latérale (610b) à partir du puits de forage primaire (116), à pomper un fluide marqueur à travers le conduit de fluide (616) de la tête de puits à la seconde extension latérale (610b) et dans la région d'intérêt souterraine. Le procédé consiste en outre à détecter, à l'aide du capteur de détection de fluide (618a-e), le fluide marqueur dans la première extension latérale (610a), le fluide marqueur dans la première extension latérale (610a) s'étant écoulé de la seconde extension latérale (610b) à travers la région d'intérêt souterraine, et à déterminer la caractéristique d'écoulement de fluide de la région d'intérêt souterraine sur la base, au moins en partie, du fluide marqueur détecté.
PCT/US2024/051038 2023-10-16 2024-10-11 Procédé de test de puits profond et de détermination de perméabilité dans une direction différente Pending WO2025085338A1 (fr)

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Citations (4)

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CA2870609A1 (fr) * 2012-04-16 2013-10-24 Weatherford/Lamb, Inc. Procede et appareil de surveillance d'outil de fond de trou
WO2015058110A2 (fr) * 2013-10-17 2015-04-23 Weatherford/Lamb, Inc. Appareil et procédé de surveillance d'un fluide
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WO2023118580A1 (fr) * 2021-12-23 2023-06-29 Testall As Système intelligent d'essais de puits

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US9249559B2 (en) * 2011-10-04 2016-02-02 Schlumberger Technology Corporation Providing equipment in lateral branches of a well

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CA2870609A1 (fr) * 2012-04-16 2013-10-24 Weatherford/Lamb, Inc. Procede et appareil de surveillance d'outil de fond de trou
WO2015058110A2 (fr) * 2013-10-17 2015-04-23 Weatherford/Lamb, Inc. Appareil et procédé de surveillance d'un fluide
WO2022115407A1 (fr) * 2020-11-24 2022-06-02 Saudi Arabian Oil Company Accessibilité latérale avancée, surveillance segmentée et commande de puits multiples latéraux
WO2023118580A1 (fr) * 2021-12-23 2023-06-29 Testall As Système intelligent d'essais de puits

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