WO2017074884A1 - Évaluation de formation - Google Patents

Évaluation de formation Download PDF

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Publication number
WO2017074884A1
WO2017074884A1 PCT/US2016/058560 US2016058560W WO2017074884A1 WO 2017074884 A1 WO2017074884 A1 WO 2017074884A1 US 2016058560 W US2016058560 W US 2016058560W WO 2017074884 A1 WO2017074884 A1 WO 2017074884A1
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WO
WIPO (PCT)
Prior art keywords
data
formation
borehole
inversion
pressure
Prior art date
Application number
PCT/US2016/058560
Other languages
English (en)
Inventor
Richard Birchwood
Prince ABANGWU
Yevgeniy KARPEKIN
Original Assignee
Schlumberger Technology Corporation
Schlumberger Canada Limited
Services Petroliers Schlumberger
Geoquest Systems B.V.
Priority date (The priority date 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 date listed.)
Filing date
Publication date
Application filed by Schlumberger Technology Corporation, Schlumberger Canada Limited, Services Petroliers Schlumberger, Geoquest Systems B.V. filed Critical Schlumberger Technology Corporation
Publication of WO2017074884A1 publication Critical patent/WO2017074884A1/fr

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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
    • E21B47/06—Measuring temperature or pressure
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V11/00—Prospecting or detecting by methods combining techniques covered by two or more of main groups G01V1/00 - G01V9/00
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V3/00—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
    • G01V3/18—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging
    • G01V3/32—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging operating with electron or nuclear magnetic resonance

Definitions

  • Resources may exist in subterranean fields that span large geographic areas.
  • hydrocarbons may exist in a basin that may be a depression in the crust of the Earth, for example, caused by plate tectonic activity and subsidence, in which sediments accumulate (e.g. , to form a sedimentary basin).
  • Hydrocarbon source rock may exist in a basin in combination with appropriate depth and duration of burial such that a so-called "petroleum system" may develop within the basin.
  • Various technologies, techniques, etc. described herein may facilitate assessment of a basin and, for example, development of a basin for production of one or more types of resources.
  • a method includes receiving borehole data for at least two properties associated with a formation; performing an inversion for formation pressure and temperature values based at least in part on at least a portion of the borehole data; and outputting at least a portion of the formation pressure and temperature values.
  • a system includes a processor; memory operatively coupled to the processor; and instructions stored in the memory and executable by the processor to receive borehole data for at least two properties associated with a formation; perform an inversion for formation pressure and temperature values based at least in part on at least a portion of the borehole data; and output at least a portion of the formation pressure and temperature values.
  • At least one computer- readable medium includes processor-executable instructions that instruct a computing device where the instructions include instructions to instruct the computing device to: receive borehole data for at least two properties associated with a formation; perform an inversion for formation pressure and temperature values based at least in part on at least a portion of the borehole data; and output at least a portion of the formation pressure and temperature values.
  • FIG. 1 illustrates examples of equipment in a geologic environment
  • Fig. 2 illustrates examples of equipment and examples of boreholes
  • FIG. 3 illustrates examples of equipment with respect to a geologic environment and an example of a method
  • FIG. 4 illustrates an example of a wireline services system as deployed in a geologic environment
  • Fig. 5 illustrates an example of a scenario as to direct temperature measurements
  • Fig. 6 illustrates an example of a scenario as to direct temperature measurements
  • FIG. 7 illustrates an example of a method and an example of a system
  • Fig. 8 illustrates an example plot associated with an example of a method
  • Fig. 9 illustrates an example plot associated with an example of a method
  • Fig. 10 illustrates an example plot associated with an example of a method
  • Fig. 1 1 illustrates example plots associated with an example of a method
  • Fig. 12 illustrates example components of a system and a networked system.
  • a system may be provided for positioning at least partially in a borehole in a geologic environment.
  • a borehole may be, for example, a lateral borehole (e.g. , non-vertical, horizontal, etc.).
  • a borehole may be a borehole suitable for stimulation of a portion of a geologic environment.
  • stimulation may include one or more of fracturing, chemical treatment, pressure treatment, etc.
  • stimulation may be a stimulation treatment.
  • a system may include components for acquiring data (e.g., signals, etc.) while at least in part disposed in a borehole where at least a portion of that data may be processed to determine, for example, one or more values associated with a formation.
  • data e.g., signals, etc.
  • a region of a formation may be a zone adjacent to a borehole.
  • a method may include estimating pore pressure and/or pore temperature in a region or regions of a formation.
  • Formation pressure may be defined as pressure of fluid(s) within pores of rock. Such pressure may be, for example, hydrostatic pressure as pressure exerted by a static column of water from the formation's depth to sea level. Where relatively impermeable rocks such as shales compacted, pore fluids may be trapped and thereby act to lend support to an overlying rock column, which can lead to anomalously high formation pressures (e.g., overpressures).
  • overpressures anomalously high formation pressures
  • pressure can change as fluids are produced from a reservoir, pressure can be described as being for a specific time.
  • a method can include acquiring temperature data.
  • a temperature log that can be a data record with respect to distance.
  • Such a log may show one or more temperature gradients in a borehole or boreholes.
  • a temperature log can be interpreted for anomalies, or departures, from a reference gradient where the reference gradient might be a geothermal gradient, a log recorded before production started, a log recorded with the well shut-in, etc.
  • an anomaly may be related to entry of fluid(s) into a borehole or fluid(s) exit into a formation.
  • Temperature logs may be used, for example, to help identify a zone or zones producing or taking fluid, to help evaluate a cement or hydraulic fracture treatment, to help locate lost circulation zones and casing leaks, etc.
  • temperature e.g. , heat energy
  • a temperature log can tend to reflect behavior of a well over a longer time period than other measurements.
  • a method can include acquiring temperature data for determining temperature in a formation.
  • Formation temperature can be utilized, for example, to estimate reserves, to evaluate maturity of hydrocarbon reserves, to assess borehole stability, to design well cementing mixtures, etc.
  • formation temperatures can be utilized for
  • water resistivity e.g., to calculate oil saturations from resistivity logs
  • reservoir-fluid formation volume factors e.g., to estimate reserves
  • geothermal gradients e.g., to estimate temperatures of deep zones
  • calibrating petroleum systems models e.g., to calculate generation timing and yields
  • a method can include acquiring pressure data.
  • an analysis of pressure data may aim to uncover pressure changes over time such as those associated with small variations in volume of fluid.
  • a pressure transient analysis may be performed for a well where a limited amount of fluid is allowed to flow from a formation being tested and where pressure at the formation is monitored over time.
  • the well may be closed and the pressure monitored while the fluid within the well equilibrates.
  • such an analysis of pressure changes can provide information such as, for example, information as to the pressure in a formation, the size and shape of a formation, its ability to produce fluid(s), etc.
  • Pore pressure and temperature are formation characteristics that can be used to plan operations and design infrastructure, for example, throughout a life cycle of a project in the oil and gas industry.
  • knowledge of one or both attributes can facilitate safe drilling, design of well completions, evaluation of hydrocarbon maturity, reserves estimation, and field development planning. As explained above, these attributes may be measured directly in boreholes. However such measurements can be, at times, limited in scope or somewhat impractical.
  • a method can include estimating pore pressure and/or pore temperature via indirect measurements. In such an example, measurements may be made using indirect methods which can be faster and can provide better spatial coverage than direct measurements.
  • a method that includes estimating pore pressure and/or pore temperature based on one or more indirect methods may include making one or more theoretical assumptions, which may hold to varying degree based on one or more of a variety of factors.
  • a method can include making at least one direction measurement and making at least one indirect measurement.
  • a method can include selecting a set of indirect methods that can be performed to acquire data to infer formation pressure and/or formation temperature. Such an example may consider that properties of pore fluid(s) depend on pressure and temperature. Therefore, by measuring these properties in a borehole, one or more inversion techniques may be applied to invert for formation pressure and/or formation temperature.
  • Fluid density (e.g., obtained from the hydrogen index);
  • Nuclear magnetic resonance e.g., longitudinal relaxation time, T1 ;
  • Thermal neutron capture cross-section e.g., Sigma, ⁇ .
  • a method can include inverting for formation pressure and temperature based at least in part on information for two properties; noting that more than two properties can be utilized, for example, to reduce uncertainty due to measurement errors, etc.
  • a method can include cross-plotting as an inversion technique that can, for example, help to examine robustness of an inversion to uncertainty in input data.
  • a method can include plotting information (e.g., borehole data that includes two types of borehole data) to a two- dimensional plot where one dimension corresponds to temperature and where another dimension corresponds to pressure.
  • the plot may include orthogonal axes where one axis corresponds to temperature and the other axis corresponds to pressure.
  • a three-dimensional plot may include an axis that corresponds to depth where information (e.g. , borehole data that includes two types of borehole data at various depths) is plotted with respect to temperature and pressure at a plurality of depths.
  • the depths may be vertical depths and/or measured depths. As to measured depths, these may correspond to distance into a borehole from a surface location or another known location. As an example, a measured depth can differ from a vertical depth such as in a deviated borehole.
  • Formation pressures can be measured using formation testing tools that can be deployed in boreholes, for example, via wireline or drillpipe. Such tools can be configured to withdraw small amounts of fluid from a formation. Formation pressure can be determined by analyzing pressure in a borehole during postwithdrawal recovery of a tool system (e.g. , pressure build-up phase). Such an approach can take some amount of time, for example, to set the tool against the formation, establish a seal, withdraw fluid, and wait for pressure build-up to occur. At times, seals may fail, for example, where formation is soft or the borehole is rugose. Such measurements can be sparsely distributed and can be restricted to permeable rocks in an effort to minimize waiting time.
  • an indirect technique may provide a more
  • indirect pore pressure estimation can include acquiring one or more of resistivity, drilling mechanics, or acoustic velocity data.
  • a method can include predicting pore pressure from a relation between rock solidity and effective stress.
  • a method can include deducing pore pressure from frequency- dependent velocity or amplitude data generated by active or passive acoustic sources in the bottom-hole assembly of a drillstring.
  • a method can use a combination of acoustic and electromagnetic measurements to determine pore pressure ahead of the bit.
  • a technique can include estimating pore pressure from empirical relations involving formation temperature, which can be relevant when pore pressure is controlled by temperature driven processes.
  • estimation of pore pressure and temperature via joint inversion of suitably sensitive properties can provide alternative means of estimating pressure and temperature.
  • a method can include selecting a set of log-based techniques for inferring pore pressure based on the characteristics of the pore fluid rather than the rock matrix.
  • a method can be a fluid-based method of estimating pore pressure and/or pore temperature.
  • a method can include determining formation temperature along with formation pressure. Such a method can include assuming, as an initial proposition, that temperature is not known; in contrast to an approach aimed at acquiring pore pressure by measuring gas properties that assume that the temperature is known, or that its influence is ignored; or an approach that uses thermal neutron capture cross-section to measure pore pressure in gas bearing sands where, to deduce the pore pressure, temperature is assumed to be known; or an approach that injects gas into the pore space at a first location, to calibrate a logging device used to infer pore pressure at a second location, where no adjustment is made for differences between the temperature of the injected gas and the temperature at the second location.
  • Temperature in a borehole after drilling can be quite different from temperature of an undisturbed formation. Because the thermal diffusivity of rocks tends to be low, the borehole temperature may take weeks, months or even years to attain an acceptable degree of thermal equilibrium with surrounding rock(s). As a consequence, a variety of approximations are used to infer far-field temperatures from short-term transient temperatures in the borehole. For example, consider the Horner plot, which assumes that during drilling, the wellbore can be approximated as a constant heat source, which can lead to inaccuracies.
  • Temperatures in the far- field can be inferred by measuring the temperature of fluid sampled from the formation with a formation testing tool; however, this involves withdrawing enough fluid from the formation to ensure that fluid from the undisturbed zone is being sampled. Such an approach may take a considerable amount of time, which may impact practicality. As an example, relatively reliable results can be obtained using drill-stem tests which involve producing fluid to the surface after the well has been completed; however, such tests tend to be limited to the reservoir and do not provide the same spatial resolution as a logging tool.
  • a method can include simultaneously inverting multiple measurements for temperature and pressure of a fluid in a rock formation.
  • the fluid can be a hydrocarbon fluid or, for example, one or more other types of fluid or fluids.
  • such a method may be applied to a fluid or fluids with log properties that are sensitive to pressure and temperature.
  • Fluid density e.g., p, as may be obtained from the hydrogen index
  • Nuclear magnetic resonance e.g. , longitudinal relaxation time, T1 ;
  • Diffusion coefficient e.g. , D
  • the first property can be deduced from the fluid hydrogen index measured via a neutron density logging tool.
  • the second and third properties can be measured using a nuclear magnetic resonance (NMR) tool.
  • the fourth property can be measured using a reservoir saturation tool (e.g., consider the RSTProTM reservoir saturation tool marketed by Schlumberger Limited, Houston, Texas).
  • inversion for formation pressure and temperature can be performed via a graphical technique, for example, using a cross-plot.
  • inversion can be performed numerically.
  • inversion can be performed graphically and numerically.
  • Fig. 1 shows an example of a geologic environment 120.
  • the geologic environment 120 may be a sedimentary basin that includes layers (e.g. , stratification) that include a reservoir 121 and that may be, for example, intersected by a fault 123 (e.g., or faults).
  • the geologic environment 120 may be outfitted with any of a variety of sensors, detectors, actuators, etc.
  • equipment 122 may include communication circuitry to receive and to transmit information with respect to one or more networks 125.
  • Such information may include information associated with downhole equipment 124, which may be equipment to acquire information, to assist with resource recovery, etc.
  • Other equipment 126 may be located remote from a well site and include sensing, detecting, emitting or other circuitry. Such equipment may include storage and communication circuitry to store and to communicate data, instructions, etc. As an example, one or more pieces of equipment may provide for measurement, collection, communication, storage, analysis, etc. of data (e.g. , for one or more produced resources, etc.). As an example, one or more satellites may be provided for purposes of communications, data acquisition, etc. For example, Fig. 1 shows a satellite in communication with the network 125 that may be configured for communications, noting that the satellite may additionally or alternatively include circuitry for imagery (e.g., spatial, spectral, temporal, radiometric, etc.).
  • imagery e.g., spatial, spectral, temporal, radiometric, etc.
  • Fig. 1 also shows the geologic environment 120 as optionally including equipment 127 and 128 associated with a well that includes a substantially horizontal portion (e.g. , or portions; see, e.g. , the enlarged view of a well with lateral portions) that may intersect with one or more fractures 129 (see, e.g., the enlarged view with fractures that can define a drainage area).
  • a substantially horizontal portion e.g. , or portions; see, e.g. , the enlarged view of a well with lateral portions
  • fractures 129 see, e.g., the enlarged view with fractures that can define a drainage area.
  • a well in a shale formation may include natural fractures, artificial fractures (e.g., hydraulic fractures) or a combination of natural and artificial fractures.
  • a well may be drilled for a reservoir that is laterally extensive. In such an example, lateral variations in properties, stresses, etc.
  • the equipment 127 and/or 128 may include components, a system, systems, etc. for fracturing, seismic sensing, analysis of seismic data, assessment of one or more fractures, injection, production, etc.
  • the equipment 127 and/or 128 may provide for measurement (e.g. , temperature, pressure, etc.), collection, communication, storage, analysis, etc. of data such as, for example, production data (e.g. , for one or more produced resources).
  • one or more satellites may be provided for purposes of communications, data acquisition, etc.
  • Fig. 1 also shows a plot 162 of temperature with respect to depth and time, a plot 164 of heat flow in a particular layer (see dashed lines in the plot 162) with respect to time, a plot 166 of temperature in a particular layer (see dashed and dotted lines in the plot 162) with respect to time and a petroleum systems elements (PSE) chart 168.
  • the information in the plots 162, 164, 166 and 168 can be based on various types of measurements and one or more types of models, for example, one or more models suitable for one or more types of simulations.
  • temporal aspects can include, for example, depositional or formation ages, "critical" moment, and preservation time.
  • a "critical" moment is the time that best depicts the generation-migration-accumulation of hydrocarbons in a petroleum system and preservation time of a petroleum system begins immediately after the generation- migration-accumulation process occurs and may extend to the present day.
  • a PSE chart may be arranged according to an ideal or successful order of events.
  • the source rock could be generated and expel
  • a PSE chart may serve as a basis for risk analysis or be transformed into a risk chart, for example, to better evaluate a play or prospect.
  • frameworks can receive information, analyze information and generate results for a geologic environment and/or one or more related operations.
  • PETRELTM framework Schott al.
  • simulators e.g., simulation frameworks
  • ECLIPSETM reservoir simulator SchottampTM reservoir simulator
  • INTERSECTTM reservoir simulator SchottampTM reservoir simulator
  • VISAGETM geomechanics simulator SchottampTM geomechanics simulator
  • PETROMODTM petroleum systems simulator SchottampTM petroleum systems simulator
  • PIPESI MTM network simulator SchottampTM network simulator
  • the ECLIPSETM simulator includes numerical solvers that may provide simulation results such as, for example, results that may predict dynamic behavior for one or more types of reservoirs.
  • the VISAGETM geomechanics simulator includes finite element numerical solvers that may provide simulation results such as, for example, results as to compaction and subsidence of a geologic environment, well and completion integrity in a geologic environment, cap-rock and fault-seal integrity in a geologic environment, fracture behavior in a geologic environment, thermal recovery in a geologic environment, CO2 disposal, etc.
  • the PETROMODTM simulator includes finite element numerical solvers that may provide simulation results such as, for example, results as to structural evolution, temperature, and pressure history and as to effects of such factors on generation, migration, accumulation, and loss of oil and gas in a petroleum system through geologic time.
  • a simulator can provide properties such as, for example, gas/oil ratios (GOR) and API gravities, which may be analyzed, understood, and predicted as to a geologic environment.
  • GOR gas/oil ratios
  • API gravities which may be analyzed, understood, and predicted as to a geologic environment.
  • the PIPESI MTM simulator includes solvers that may provide simulation results such as, for example, multiphase flow results (e.g., from a reservoir to a wellhead and beyond, etc.), flowline and surface facility performance, etc.
  • the PIPESIMTM simulator may be integrated, for example, with the AVOCETTM production operations framework (Schlumberger Limited, Houston Texas).
  • AVOCETTM production operations framework Scholberger Limited, Houston Texas
  • a reservoir or reservoirs may be simulated with respect to one or more enhanced recovery techniques (e.g. , consider a thermal process such as SAGD, etc.).
  • information acquired by a tool or tools may be analyzed using a framework such as the TECHLOGTM framework (Schlumberger Limited, Houston, Texas).
  • the PETROMODTM simulation framework may predict if, and how, a reservoir has been charged with hydrocarbons, including, for example, the source and timing of hydrocarbon generation, migration routes, quantities, pore pressure and hydrocarbon type in the subsurface or at surface conditions.
  • workflows may be constructed to provide basin-to-prospect scale exploration solutions. Data exchange between frameworks can facilitate construction of models, analysis of data (e.g.,
  • PETROMODTM framework data analyzed using PETRELTM framework capabilities
  • One or more frameworks can include interfaces for receiving information that can include measurements and/or information based on
  • one or more simulators may generate results that are based at least in part on measurements.
  • a framework and/or a simulator may implement one or more methods for estimation of formation pressure and/or formation temperature using a combination of borehole logs (e.g. ,
  • Geologic formations such as in the geologic environment 120 include rock, which may be characterized by, for example, porosity values and by
  • permeability values may be defined as a percentage of volume occupied by pores, void space, volume within rock that can include fluid, etc. Permeability may be defined as an ability to transmit fluid, measurement of an ability to transmit fluid, etc.
  • rock may include clastic material, carbonate material and/or other type of material.
  • clastic material may be material that includes broken fragments derived from preexisting rocks and transported elsewhere and redeposited before forming another rock. Examples of clastic sedimentary rocks include siliciclastic rocks such as conglomerate, sandstone, siltstone and shale.
  • carbonate material may include calcite (CaCCb), aragonite (CaCCb) and/or dolomite (CaMg(C03)2), which may replace calcite during a process known as dolomitization.
  • CaCCb calcite
  • CaCCb aragonite
  • CaMg(C03)2 dolomite
  • Limestone, dolostone or dolomite, and chalk are some examples of carbonate rocks.
  • carbonate material may be formed through processes of precipitation or the activity of organisms (e.g. , coral, algae, etc.).
  • Carbonates may form in shallow and deep marine settings, evaporitic basins, lakes, windy deserts, etc. Carbonate material deposits may serve as hydrocarbon reservoir rocks, for example, where porosity may have been enhanced through dissolution. Fractures can increase permeability in carbonate material deposits.
  • effective porosity may refer to interconnected pore volume in rock, for example, that may contribute to fluid flow in a formation. As effective porosity aims to exclude isolated pores, effective porosity may be less than total porosity. As an example, a shale formation may have relatively high total porosity yet relatively low permeability due to how shale is structured within the formation.
  • shale may be formed by consolidation of clay- and silt- sized particles into thin, relatively impermeable layers.
  • the layers may be laterally extensive and form caprock.
  • Caprock may be defined as relatively impermeable rock that forms a barrier or seal with respect to reservoir rock such that fluid does not readily migrate beyond the reservoir rock.
  • the permeability of caprock capable of retaining fluids through geologic time may be of the order of about 10 "6 to about 10 "8 D (darcies).
  • shale may refer to one or more types of shales that may be characterized, for example, based on lithology, etc.
  • gas storage and flow may be related to combinations of different geophysical processes.
  • natural gas may be stored as compressed gas in pores and fractures, as adsorbed gas (e.g. , adsorbed onto organic matter), and as soluble gas in solid organic materials.
  • Gas migration and production processes in gas shale sediments can occur, for example, at different physical scales.
  • production in a newly drilled wellbore may be via large pores through a fracture network and then later in time via smaller pores.
  • thermodynamic equilibrium among kerogen, clay and the gas phase in pores can change, for example, where gas begins to desorb from kerogen exposed to a pore network.
  • Sedimentary organic matter tends to have a high sorption capacity for hydrocarbons (e.g. , adsorption and absorption processes). Such capacity may depend on factors such as, for example, organic matter type, thermal maturity (e.g., high maturity may improve retention) and organic matter chemical composition. As an example, a model may characterize a formation such that a higher total organic content corresponds to a higher sorption capacity.
  • hydrocarbons e.g., a hydrocarbon reservoir
  • its hydrocarbon producing potential may depend on various factors such as, for example, thickness and extent, organic content, thermal maturity, depth and pressure, fluid saturations, permeability, etc.
  • a formation that includes gas e.g., a gas reservoir
  • nanodarcy matrix permeability e.g., of the order of 10 "9 D
  • technologies such as stimulation treatment may be applied in an effort to produce gas from the formation, for example, to create new, artificial fractures, to stimulate existing natural fractures (e.g., reactivate calcite-sealed natural fractures), etc. (see, e.g., the one or more fractures 129 in the geologic environment 120 of Fig. 1 ).
  • Material in a geologic environment may vary by, for example, one or more of mineralogical characteristics, formation grain sizes, organic contents, rock fissility, etc. Attention to such factors may aid in designing an appropriate stimulation treatment.
  • an evaluation process may include well construction (e.g., drilling one or more vertical, horizontal or deviated wells), sample analysis (e.g. , for geomechanical and geochemical properties), open-hole logs (e.g., petrophysical log models) and post-fracture evaluation (e.g. , production logs).
  • Effectiveness of a stimulation treatment e.g., treatments, stages of treatments, etc., may determine flow mechanism(s), well performance results, etc.
  • a stimulation treatment may include pumping fluid into a formation via a wellbore at pressure and rate sufficient to cause a fracture to open.
  • a fracture may be vertical and include wings that extend away from the wellbore, for example, in opposing directions according to natural stresses within the formation.
  • proppant e.g., sand, etc.
  • a generated fracture may have a length of about 500 ft (e.g. , about 150 m) extending from a wellbore where proppant maintains a desirable fracture width over about the first 250 ft (e.g. , about 75 m) of the generated fracture.
  • fracturing may be applied over or within a region deemed a "drainage area" (e.g., consider at least one well with at least one artificial fracture), for example, according to a development plan.
  • gas pressure e.g., within the formation's "matrix”
  • matrix e.g., the formation's "matrix”
  • gas pressure in a drainage area tends to decrease (e.g., decreasing the driving force for fluid flow, for example, per Darcy's law, Navier-Stokes equations, etc.).
  • gas production from a drainage area may continue for decades; however, the
  • predictability of decades long production can depend on many factors, some of which may be uncertain (e.g. , unknown, unknowable, estimated with probability bounds, etc.).
  • Fig. 2 shows an example of a wellsite system 200 (e.g. , at a wellsite that may be onshore or offshore).
  • the wellsite system 200 can include a mud tank 201 for holding mud and other material (e.g., where mud can be a drilling fluid), a suction line 203 that serves as an inlet to a mud pump 204 for pumping mud from the mud tank 201 such that mud flows to a vibrating hose 206, a drawworks 207 for winching drill line or drill lines 212, a standpipe 208 that receives mud from the vibrating hose 206, a kelly hose 209 that receives mud from the standpipe 208, a gooseneck or goosenecks 210, a traveling block 21 1 , a crown block 213 for carrying the traveling block 21 1 via the drill line or drill lines 212 (see, e.g., the crown block 173 of Fig.
  • a derrick 214 (see, e.g., the derrick 172 of Fig. 1 ), a kelly 218 or a top drive 240, a kelly drive bushing 219, a rotary table 220, a drill floor 221 , a bell nipple 222, one or more blowout preventors (BOPs) 223, a drillstring 225, a drill bit 226, a casing head 227 and a flow pipe 228 that carries mud and other material to, for example, the mud tank 201 .
  • BOPs blowout preventors
  • embodiments may also use directional drilling.
  • the drillstring 225 is suspended within the borehole 232 and has a drillstring assembly 250 that includes the drill bit 226 at its lower end.
  • the drillstring assembly 250 may be a bottom hole assembly (BHA).
  • the wellsite system 200 can provide for operation of the drillstring 225 and other operations. As shown, the wellsite system 200 includes the platform 21 1 and the derrick 214 positioned over the borehole 232. As mentioned, the wellsite system 200 can include the rotary table 220 where the drillstring 225 pass through an opening in the rotary table 220.
  • the wellsite system 200 can include the kelly 218 and associated components, etc., or a top drive 240 and associated components.
  • the kelly 218 may be a square or hexagonal metal/alloy bar with a hole drilled therein that serves as a mud flow path.
  • the kelly 218 can be used to transmit rotary motion from the rotary table 220 via the kelly drive bushing 219 to the drillstring 225, while allowing the drillstring 225 to be lowered or raised during rotation.
  • the kelly 218 can pass through the kelly drive bushing 219, which can be driven by the rotary table 220.
  • the rotary table 220 can include a master bushing that operatively couples to the kelly drive bushing 219 such that rotation of the rotary table 220 can turn the kelly drive bushing 219 and hence the kelly 218.
  • the kelly drive bushing 219 can include an inside profile matching an outside profile (e.g., square, hexagonal, etc.) of the kelly 218; however, with slightly larger dimensions so that the kelly 218 can freely move up and down inside the kelly drive bushing 219.
  • the top drive 240 can provide functions performed by a kelly and a rotary table.
  • the top drive 240 can turn the drillstring 225.
  • the top drive 240 can include one or more motors (e.g., electric and/or hydraulic) connected with appropriate gearing to a short section of pipe called a quill, that in turn may be screwed into a saver sub or the drillstring 225 itself.
  • the top drive 240 can be suspended from the traveling block 21 1 , so the rotary mechanism is free to travel up and down the derrick 214.
  • a top drive 240 may allow for drilling to be performed with more joint stands than a kelly/rotary table approach.
  • the mud tank 201 can hold mud, which can be one or more types of drilling fluids.
  • mud can be one or more types of drilling fluids.
  • a wellbore may be drilled to produce fluid, inject fluid or both (e.g., hydrocarbons, minerals, water, etc.).
  • the drillstring 225 (e.g. , including one or more downhole tools) may be composed of a series of pipes threadably connected together to form a long tube with the drill bit 226 at the lower end thereof.
  • the mud may be pumped by the pump 204 from the mud tank 201 (e.g., or other source) via a the lines 206, 208 and 209 to a port of the kelly 218 or, for example, to a port of the top drive 240.
  • the mud can then flow via a passage (e.g., or passages) in the drillstring 225 and out of ports located on the drill bit 226 (see, e.g., a directional arrow).
  • a passage e.g., or passages
  • the mud can then circulate upwardly through an annular region between an outer surface(s) of the drillstring 225 and surrounding wall(s) (e.g., open borehole, casing, etc.), as indicated by directional arrows.
  • the mud lubricates the drill bit 226 and carries heat energy (e.g., frictional or other energy) and formation cuttings to the surface where the mud (e.g. , and cuttings) may be returned to the mud tank 201 , for example, for recirculation (e.g., with processing to remove cuttings, etc.).
  • the mud pumped by the pump 204 into the drillstring 225 may, after exiting the drillstring 225, form a mudcake that lines the wellbore which, among other functions, may reduce friction between the drillstring 225 and surrounding wall(s) (e.g., borehole, casing, etc.). A reduction in friction may facilitate advancing or retracting the drillstring 225.
  • the entire drill string 225 may be pulled from a wellbore and optionally replaced, for example, with a new or sharpened drill bit, a smaller diameter drill string, etc.
  • tripping A trip may be referred to as an upward trip or an outward trip or as a downward trip or an inward trip depending on trip direction.
  • the mud can be pumped by the pump 204 into a passage of the drillstring 225 and, upon filling of the passage, the mud may be used as a transmission medium to transmit energy, for example, energy that may encode information as in mud-pulse telemetry.
  • mud-pulse telemetry equipment may include a downhole device configured to effect changes in pressure in the mud to create an acoustic wave or waves upon which information may modulated.
  • information from downhole equipment e.g. , one or more modules of the drillstring 225
  • telemetry equipment may operate via transmission of energy via the drillstring 225 itself.
  • a signal generator that imparts coded energy signals to the drillstring 225 and repeaters that may receive such energy and repeat it to further transmit the coded energy signals (e.g. , information, etc.).
  • the drillstring 225 may be fitted with telemetry equipment 252 that includes a rotatable drive shaft, a turbine impeller mechanically coupled to the drive shaft such that the mud can cause the turbine impeller to rotate, a modulator rotor mechanically coupled to the drive shaft such that rotation of the turbine impeller causes said modulator rotor to rotate, a modulator stator mounted adjacent to or proximate to the modulator rotor such that rotation of the modulator rotor relative to the modulator stator creates pressure pulses in the mud, and a controllable brake for selectively braking rotation of the modulator rotor to modulate pressure pulses.
  • an alternator may be coupled to the
  • the alternator includes at least one stator winding electrically coupled to a control circuit to selectively short the at least one stator winding to electromagnetically brake the alternator and thereby selectively brake rotation of the modulator rotor to modulate the pressure pulses in the mud.
  • an uphole control and/or data acquisition system 262 may include circuitry to sense pressure pulses generated by telemetry equipment 252 and, for example, communicate sensed pressure pulses or information derived therefrom for process, control, etc.
  • the assembly 250 of the illustrated example includes a logging-while- drilling (LWD) module 254, a measuring-while-drilling (MWD) module 256, an optional module 258, a roto-steerable system and motor 260, and the drill bit 226.
  • LWD logging-while- drilling
  • MWD measuring-while-drilling
  • 258 a roto-steerable system and motor 260
  • the drill bit 226 Such components or modules may be referred to as tools where a drillstring can include a plurality of tools.
  • the LWD module 254 may be housed in a suitable type of drill collar and can contain one or a plurality of selected types of logging tools. It will also be understood that more than one LWD and/or MWD module can be employed, for example, as represented at by the module 256 of the drillstring assembly 250.
  • an LWD module may refer to a module at the position of the LWD module 254, the module 256, etc.
  • An LWD module can include capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment.
  • the LWD module 254 may include a seismic measuring device.
  • the MWD module 256 may be housed in a suitable type of drill collar and can contain one or more devices for measuring characteristics of the drillstring 225 and the drill bit 226.
  • the MWD tool 254 may include equipment for generating electrical power, for example, to power various components of the drillstring 225.
  • the MWD tool 254 may include the telemetry equipment 252, for example, where the turbine impeller can generate power by flow of the mud; it being understood that other power and/or battery systems may be employed for purposes of powering various components.
  • the MWD module 256 may include one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device.
  • Fig. 2 also shows some examples of types of holes that may be drilled. For example, consider a slant hole 272, an S-shaped hole 274, a deep inclined hole 276 and a horizontal hole 278.
  • a drilling operation can include directional drilling where, for example, at least a portion of a well includes a curved axis. For example, consider a radius that defines curvature where an inclination with regard to the vertical may vary until reaching an angle between about 30 degrees and about 60 degrees or, for example, an angle to about 90 degrees or possibly greater than about 90 degrees.
  • a directional well can include several shapes where each of the shapes may aim to meet particular operational demands.
  • a drilling process may be performed on the basis of information as and when it is relayed to a drilling engineer.
  • inclination and/or direction may be modified based on information received during a drilling process.
  • deviation of a borehole may be accomplished in part by use of a downhole motor and/or a turbine.
  • a motor for example, a drillstring can include a positive displacement motor (PDM).
  • PDM positive displacement motor
  • a system may be a steerable system and include equipment to perform a method such as geosteering.
  • a steerable system can include a PDM or a turbine on a lower part of a drillstring which, just above a drill bit, a bent sub can be mounted.
  • MWD equipment that provides real time or near real time data of interest (e.g., inclination, direction, pressure, temperature, real weight on the drill bit, torque stress, etc.) and/or LWD equipment may be installed.
  • LWD equipment can make it possible to send to the surface various types of data of interest, including for example, geological data (e.g. , gamma ray log, resistivity, density and sonic logs, etc.).
  • the coupling of sensors providing information on the course of a well trajectory, in real time or near real time, with, for example, one or more logs characterizing the formations from a geological viewpoint, can allow for implementing a geosteering method.
  • Such a method can include navigating a subsurface environment, for example, to follow a desired route to reach a desired target or targets.
  • a real time or near real time method can include inverting borehole data for pressure and temperature to characterize a formation.
  • temperature ranges may be rendered to a display (e.g., as numeric values, as a plot, etc.).
  • formation pressure and/or formation temperatures may be utilized in making one or more decisions as to development of a reservoir.
  • a drillstring can include an azimuthal density neutron (ADN) tool for measuring density and porosity; a MWD tool for measuring inclination, azimuth and shocks; a compensated dual resistivity (CDR) tool for measuring resistivity and gamma ray related phenomena; one or more variable gauge stabilizers; one or more bend joints; and a geosteering tool, which may include a motor and optionally equipment for measuring and/or responding to one or more of inclination, resistivity and gamma ray related phenomena.
  • ADN azimuthal density neutron
  • MWD for measuring inclination, azimuth and shocks
  • CDR compensated dual resistivity
  • geosteering can include intentional directional control of a wellbore based on results of downhole geological logging measurements in a manner that aims to keep a directional wellbore within a desired region, zone (e.g. , a pay zone), etc.
  • geosteering may include directing a wellbore to keep the wellbore in a particular section of a reservoir, for example, to minimize gas and/or water breakthrough and, for example, to maximize economic production from a well that includes the wellbore.
  • the wellsite system 200 can include one or more sensors 264 that are operatively coupled to the control and/or data acquisition system 262.
  • a sensor or sensors may be at surface locations.
  • a sensor or sensors may be at downhole locations.
  • a sensor or sensors may be at one or more remote locations that are not within a distance of the order of about one hundred meters from the wellsite system 200.
  • a sensor or sensor may be at an offset wellsite where the wellsite system 200 and the offset wellsite are in a common field (e.g., oil and/or gas field).
  • one or more of the sensors 264 can be provided for tracking pipe, tracking movement of at least a portion of a drillstring, etc.
  • the system 200 can include one or more sensors 266 that can sense and/or transmit signals to a fluid conduit such as a drilling fluid conduit (e.g. , a drilling mud conduit).
  • a fluid conduit such as a drilling fluid conduit (e.g. , a drilling mud conduit).
  • the one or more sensors 266 can be operatively coupled to portions of the standpipe 208 through which mud flows.
  • a downhole tool can generate pulses that can travel through the mud and be sensed by one or more of the one or more sensors 266.
  • the downhole tool can include associated circuitry such as, for example, encoding circuitry that can encode signals, for example, to reduce demands as to transmission.
  • circuitry at the surface may include decoding circuitry to decode encoded information transmitted at least in part via mud-pulse telemetry.
  • circuitry at the surface may include encoder circuitry and/or decoder circuitry and circuitry downhole may include encoder circuitry and/or decoder circuitry.
  • the system 200 can include a transmitter that can generate signals that can be transmitted downhole via mud (e.g., drilling fluid) as a transmission medium.
  • mud e.g., drilling fluid
  • stuck can refer to one or more of varying degrees of inability to move or remove a drillstring from a borehole.
  • a stuck condition it might be possible to rotate pipe or lower it back into a borehole or, for example, in a stuck condition, there may be an inability to move the drillstring axially in the borehole, though some amount of rotation may be possible.
  • a stuck condition there may be an inability to move at least a portion of the drillstring axially and rotationally.
  • stuck pipe this can refer to a portion of a drillstring that cannot be rotated or moved axially.
  • a condition referred to as “differential sticking” can be a condition whereby the drillstring cannot be moved (e.g., rotated or reciprocated) along the axis of the borehole. Differential sticking may occur when high-contact forces caused by low reservoir pressures, high wellbore pressures, or both, are exerted over a sufficiently large area of the drillstring. Differential sticking can have time and financial cost.
  • a sticking force can be a product of the differential pressure between the wellbore and the reservoir and the area that the differential pressure is acting upon. This means that a relatively low differential pressure (delta p) applied over a large working area can be just as effective in sticking pipe as can a high differential pressure applied over a small area.
  • a condition referred to as "mechanical sticking” can be a condition where limiting or prevention of motion of the drillstring by a mechanism other than differential pressure sticking occurs.
  • Mechanical sticking can be caused, for example, by one or more of junk in the hole, wellbore geometry anomalies, cement, keyseats or a buildup of cuttings in the annulus.
  • Fig. 3 illustrates an example of a system 310 that includes a drill string 312 with a tool (or module) 320 and telemetry equipment 340 (e.g. , which may be part of the tool 320 or another tool) and an example of a method 360 that may be implemented using the system 310.
  • the system 310 is illustrated with respect to a wellbore 302 (e.g., a borehole) in a portion of a subterranean formation 301 (e.g. , a sedimentary basin).
  • the wellbore 302 may be defined in part by an angle ( ⁇ ); noting that while the wellbore 302 is shown as being deviated, it may be vertical (e.g. , or include one or more vertical sections along with one or more deviated sections, which may be, for example, lateral, horizontal, etc.).
  • a portion of the wellbore 302 includes casings 304-1 and 304-2 having casing shoes 306-1 and 306-2.
  • cement annuli As shown in an enlarged view with respect to an r, z coordinate system (e.g., a cylindrical coordinate system), a portion of the wellbore 302 includes casings 304-1 and 304-2 having casing shoes 306-1 and 306-2.
  • cement annuli As shown, cement annuli
  • 303- 1 and 303-2 are disposed between the wellbore 302 and the casings 304-1 and
  • cement such as the cement annuli 303-1 and 303-2 can support and protect casings such as the casings 304-1 and 304-2 and when cement is disposed throughout various portions of a wellbore such as the wellbore 302, cement can help achieve zonal isolation.
  • a large diameter section may be a surface casing section, which may be three or more feet in diameter and extend down several hundred feet to several thousand feet.
  • a surface casing section may aim to prevent washout of loose unconsolidated formations.
  • an intermediate casing section it may aim to isolate and protect high pressure zones, guard against lost circulation zones, etc.
  • intermediate casing may be set at about X thousand feet and extend lower with one or more intermediate casing portions of decreasing diameter (e.g., in a range from about thirteen to about five inches in diameter).
  • a so-called production casing section may extend below an intermediate casing section and, upon completion, be the longest running section within a wellbore (e.g., a production casing section may be thousands of feet in length).
  • production casing may be located in a target zone where the casing is perforated for flow of fluid into a lumen of the casing.
  • the tool 320 of Fig. 3 may carry one or more transmitters 322 and one or more receivers 324.
  • the tool 320 includes circuitry 326 and a memory device 328 with memory for storage of data (e.g., information), for example, signals sensed by one or more receivers 324 and processed by the circuitry 326 of the tool 320.
  • the tool 320 may buffer data to the memory device 328.
  • data buffered in the memory device 328 may be read from the memory device 328 and transmitted to a remote device using a telemetry technique (e.g. , wired, wireless, etc.).
  • FIG. 4 shows an example of an environment 401 that includes a subterranean portion 403 where a rig 410 is positioned at a surface location above a bore 420.
  • various wirelines services equipment can be operated to perform one or more wirelines services including, for example, acquisition of data from one or more positions within the bore 420.
  • the bore 420 includes drillpipe 422, a casing shoe, a cable side entry sub (CSES) 423, a wet-connector adaptor 426 and an openhole section 428.
  • the bore 420 can be a vertical bore or a deviated bore where one or more portions of the bore may be vertical and one or more portions of the bore may be deviated, including substantially horizontal.
  • the CSES 423 includes a cable clamp 425, a packoff seal assembly 427 and a check valve 429. These components can provide for insertion of a logging cable 430 that includes a portion 432 that runs outside the drillpipe 422 to be inserted into the drillpipe 422 such that at least a portion 434 of the logging cable runs inside the drillpipe 422.
  • the logging cable 430 runs past the wet-connect adaptor 426 and into the openhole section 428 to a logging string 440.
  • a logging truck 450 (e.g., a wireline services vehicle) can deploy the wireline 430 under control of a system 460.
  • the system 460 can include one or more processors 462, memory 464 operatively coupled to at least one of the one or more processors 462, instructions 466 that can be, for example, stored in the memory 464, and one or more interfaces 468.
  • the system 460 can include one or more processor-readable media that include processor-executable instructions executable by at least one of the one or more processors 462 to cause the system 460 to control one or more aspects of equipment of the logging string 440 and/or the logging truck 450.
  • the memory 464 can be or include the one or more processor-readable media where the processor-executable instructions can be or include instructions.
  • a processor-readable medium can be a computer-readable storage medium that is not a signal and that is not a carrier wave.
  • the system 460 can be operatively coupled to a client layer 480.
  • the client layer 480 can include features that allow for access and interactions via one or more private networks 482, one or more mobile platforms and/or mobile networks 484 and via the "cloud" 486, which may be considered to include distributed equipment that forms a network such as a network of networks.
  • the system 460 can include circuitry to establish a plurality of connections (e.g., sessions).
  • connections may be via one or more types of networks.
  • connections may be client-server types of connections where the system 460 operates as a server in a client-server architecture. For example, clients may log-in to the system 460 where multiple clients may be handled, optionally simultaneously.
  • Fig. 4 also shows an example of a toolstring 490 that can include various assemblies.
  • the toolstring 490 can include a hostile- environment natural gamma ray sonde (HNGS) assembly 492, an accelerator porosity sonde (APS) assembly 494, an integrated porosity lithology (IPL) cartridge assembly 496 and a litho-density sonde (LDS) assembly 498.
  • HNGS hostile- environment natural gamma ray sonde
  • APS accelerator porosity sonde
  • IPL integrated porosity lithology
  • LDS litho-density sonde
  • the toolstring 490 may be an integrated porosity lithology (IPL) system such as, for example, the IPL system marketed by Schlumberger Limited, Houston, Texas.
  • IPL integrated porosity lithology
  • a toolstring may include one or more other types of tools and may be suitable for deployment and use with one or more wireline services systems.
  • a toolstring can include circuitry, which may include one or more controllers, memory, etc.
  • a controller may be a microcontroller (e.g., an ARM chip, etc.), a processor, an ASIC, etc.
  • a controller may operate via instructions stored in memory (e.g. , firmware
  • circuitry may be included in a cartridge.
  • one or more assemblies may include interfaces, for example, for communication of information.
  • one or more assemblies may include memory, for example, as a storage device that may store one or more of data and instructions.
  • a method may be implemented in part via instructions that may be executable by circuitry (e.g. , a controller, microcontroller, processor, etc.).
  • wireline services can include deployment of one or more tools in a bore in a geologic environment, for example, as drilled via a rig.
  • Wireline services can include acquiring petrophysical measurements that can, for example, help to determine petrophysical properties of a reservoir, its fluid contents, etc.
  • Some examples of wireline services tools include a lithology scanner spectrometer (e.g., to measure elements and quantitatively determine total organic carbon (TOC) in a wide variety of formations), a dielectric scanner (e.g., to measure water volume and rock textural information to determine hydrocarbon volume, whether in carbonates, shaly or laminated sands, or heavy oil reservoirs), a magnetic
  • an Rt scanner e.g., to acquire resistivity measurements germane to formation dip, anisotropy, beds, etc.
  • a sonic scanner acoustic scanning platform e.g., to understand a reservoir stress regime and anisotropy through 3D acoustic measurements made axially, azimuthally, and/or radially
  • an analysis behind casing tool e.g., well log data— including the collection of fluid samples— in cased holes to find bypassed pay, etc.
  • wireline services can include conveying equipment in a bore of a geologic environment. Conveyance can be performed by a crew in a hands-on manner to account for bore characteristics, particularly bore geometries.
  • a tool may be configured to acquire electrical borehole images.
  • the fullbore Formation Microlmager (FMI) tool FMI
  • a data acquisition sequence for such a tool can include running the tool into a borehole with acquisition pads closed, opening and pressing the pads against a wall of the borehole, delivering electrical current into the material defining the borehole while translating the tool in the borehole, and sensing current remotely, which is altered by interactions with the material.
  • Analysis of information may reveal features such as, for example, vugs, dissolution planes (e.g. , dissolution along bedding planes), stress-related features, dip events, etc.
  • a tool may acquire information that may help to characterize a reservoir, optionally a fractured reservoir where fractures may be natural and/or artificial (e.g. , hydraulic fractures).
  • a method may be performed in real time or near real time where a tool or toolstring is moved in a borehole.
  • borehole data from one or more tools or toolstrings may be inverted in real time or near real time for formation pressure and formation temperature.
  • formation pressure and/or formation temperature may be rendered to a display for the boreholes, for example, with locations in a formation (e.g. , as to depth, which may be measured depth).
  • formation pressures and/or formation temperatures may be linked to generate a line or a surface in a formation, which may, for example, be associated with a layer, which may be laterally extensive and span a range of depths.
  • Fig. 5 shows an example of a scenario 500 that is illustrated via a graphic of a borehole within a formation 510 and a plot 520 of temperature data versus a spatial dimension (e.g. depth).
  • fluid is injected into the borehole of the formation for a period of time, which may be, for example, of the order of days.
  • the temperature of the borehole e.g. , and sensor(s)
  • the temperature of the borehole e.g. , and sensor(s)
  • the temperature of the borehole e.g. , and sensor(s)
  • the fluid may be expected to be approximately that of the fluid being injected (e.g. , as provided at the surface).
  • the temperature may rise within a period of time of the order of hours (see, e.g., the 24 hour temperature profile); however, where larger amounts of injection fluid enter the formation (see, e.g., depths of about 4500 ft (about 1370 m) to about 5000 ft (about 1525 m)), temperature may rise more slowly, in a more extended period of time back toward the geothermal gradient (e.g., formation temperature profile).
  • the graphic 410 shows a 100 mD layer and surrounding formation at 10 mD.
  • the higher permeability 100 mD layer may take up an amount of injection fluid such that a temperature increase may occur more slowly compared to the surrounding formation at 10 mD, for example, even at 30 days, the temperature at the 100 mD layer remains close to that of the injection fluid.
  • Fig. 6 shows an example of a scenario 600 that is illustrated via a graphic of a borehole within a formation 610 and a plot 620 of temperature data versus a spatial dimension (e.g. , depth).
  • a distributed temperature survey may be acquired for at least a portion of the borehole, which, as shown in the plot 620, may span over a thousand feet (e.g. , over approximately 300 meters).
  • a baseline temperature profile characterizes the geothermal effect of the formation while additional temperature profiles 632, 634 and 636 provide information as to injection and warm-back.
  • the temperature profiles 632, 634 and 636 include deviations 642, 644 and 646 toward lower temperatures that correspond to regions of the formation that have taken up more injection fluid. Such regions may be of particular interest and help to characterize one or more zones in the formation (e.g. , high intake zones, low intake zones, etc.).
  • Fig. 7 shows an example of a method 710 and an example of a system 770.
  • the method 710 includes an acquisition block 715 for acquiring borehole data; a reception block 720 for receiving at least a portion of the acquired borehole data for at least two properties associated with a formation; a performance block 730 for performing an inversion for formation pressure and temperature values based at least in part on the received borehole data; and an output block 740 for outputting at least a portion of the formation pressure values and/or the formation temperature values.
  • the system 770 includes one or more information storage devices 772, one or more computers 774, one or more networks 780 and instructions 790.
  • each computer may include one or more processors (e.g., or processing cores) 776 and memory 778 for storing the instructions 790, for example, executable by at least one of the one or more processors.
  • a computer may include one or more network interfaces (e.g. , wired or wireless), one or more graphics cards, a display interface (e.g., wired or wireless), etc.
  • a method may be implemented in part using computer- readable media (CRM), for example, as a module, a block, etc. that includes information such as instructions suitable for execution by one or more processors (or processor cores) to instruct a computing device or system to perform one or more actions.
  • CRM computer-readable media
  • a single medium may be configured with instructions to allow for, at least in part, performance of various actions of a method.
  • a computer-readable medium may be a computer-readable storage medium (e.g., a non-transitory medium that is not a carrier wave).
  • a toolstring may implement one or more methods, which may include processing data from one or more tools of a toolstring.
  • a toolstring can include one or more processors that can receive measurements (e.g., measurement data) from one or more tools and generate information such as pressure and temperature values (e.g., via inversion of measurement data).
  • a toolstring may implement at least in part a portion of a method such as the method 710 of Fig. 7.
  • various blocks 716, 721 , 731 and 741 are illustrated as optionally being part of the system 770.
  • such blocks may be modules of the one or more modules 790 and, for example, include information such as instructions suitable for execution by one or more of the one or more processors 776.
  • such blocks may optionally be stored in the one or more information storage devices 772, in the memory 778, etc.
  • such blocks may be in the form of computer-readable media, that are non-transitory and not carrier waves.
  • Fluid density e.g., p, as may be obtained from the hydrogen index
  • Nuclear magnetic resonance e.g. , longitudinal relaxation time, T1 ;
  • Diffusion coefficient e.g. , D
  • the first property can be deduced from the fluid hydrogen index measured via a neutron density logging tool.
  • the second and third properties can be measured using a nuclear magnetic resonance (NMR) tool.
  • the fourth property can be measured using a reservoir saturation tool.
  • inversion for pressure and temperature can be performed via a graphical technique, for example, using a cross-plot.
  • inversion can be performed numerically.
  • inversion can be performed graphically and numerically.
  • a computer can include a processor and/or a graphics processor that can be implemented to perform an inversion, which may be rendered to a display as a graphic, for example, as a plot.
  • the plot can include an axis for temperature and an axis for pressure.
  • a region of the plot e.g., as indicated by properties based on borehole tool data
  • such a region can include bounds such as a temperature bound and a pressure bound.
  • a centroid may be indicated for a region, which may represent a most likely temperature and pressure.
  • GUI graphical user interface
  • a computer e.g., a computing device
  • the GUI may allow for progression from one type of plot to another type of plot where temperature and pressure can be determined via property inversion.
  • checkboxes may be rendered with available properties that can be utilized to perform an inversion or inversions to generate formation pressure and/or formation temperature.
  • a reservoir saturation tool can include a pulsed neutron generator and a dual-detector spectrometry system that measures elemental concentrations, including carbon and oxygen, and the formation neutron-capture cross section (Sigma, ⁇ ).
  • a hydrogen index can be defined as a number of hydrogen atoms per unit volume divided by a number of hydrogen atoms per unit volume of pure water at surface conditions.
  • Hydrogen index can be a factor in the response of a neutron porosity log.
  • a neutron porosity log may be acquired by a tool that acquires data as to neutrons emitted by a source. Hydrogen can slow down and capture neutrons. As hydrogen tends to exist mainly in pore fluids, a neutron porosity log can respond to porosity; noting that matrix and the type of fluid can also have an effect.
  • neutron capture can occur as a neutron interaction in which the neutron is absorbed by a target nucleus, producing an isotope in an excited state.
  • the activated isotope can de-excite through emission of characteristic gamma rays.
  • Neutron capture also called thermal capture, can occur at low thermal energies at which the neutrons have about the same energy as the surrounding matter, for example, below about 0.4 eV (e.g., about 0.025 eV at room temperature). Some elements are better thermal absorbers than others.
  • Neutron capture principles can provide for generation of one or more types of logs such as, for example, a pulsed neutron capture log, an elemental capture spectroscopy log, a pulsed neutron spectroscopy log or a thermal neutron porosity measurement.
  • a method can include acquiring borehole NMR data for T1 (longitudinal relaxation or spin-lattice relaxation) and/or T2 (transverse relaxation or spin-spin relaxation).
  • T1 longitudinal relaxation or spin-lattice relaxation
  • T2 transverse relaxation or spin-spin relaxation
  • deterioration of an NMR signal can be analyzed in terms of separate processes where each process can include its own time constant.
  • one process, associated with T1 can be responsible for loss of signal intensity while another process, associated with T2, can be responsible for broadening of a signal.
  • T1 can be the time constant for the physical processes responsible for the relaxation of the components of the nuclear spin magnetization vector M parallel to the external magnetic field
  • BO and T2 relaxation can affect the components of M perpendicular to BO. Relaxation can depend on temperature and, for example, there can also be a pressure dependence as to relaxation, for example, in relationship to an environment (e.g., a pore space, etc.).
  • NMR data may be or include hydrogen NMR data as may be associated with one or more constituents that include hydrogen.
  • NMR data that can be analyzed as to different populations of protons. For example, consider hydroxyls from clay (e.g. , T2 ⁇ -0.1 ms, -10 ⁇ T1/T2 ⁇ -100), water (T1/T2 - 2), and in certain situations organic matter (10 ⁇ T1/T2 ⁇ -100). As an example, methane may be distinguished with a particular T1/T2 ratio.
  • NMR data may be analyzed according to a model such as, for example, a pore model that can include a bulk volume with a volume fraction fb and a surface layer with a volume fraction f s where, for example, fb + fs - 1 .
  • a model such as, for example, a pore model that can include a bulk volume with a volume fraction fb and a surface layer with a volume fraction f s where, for example, fb + fs - 1 .
  • a model such as, for example, a pore model that can include a bulk volume with a volume fraction fb and a surface layer with a volume fraction f s where, for example, fb + fs - 1 .
  • an exchange can exist between the surface and bulk volumes, which may be characterized by an exchange time.
  • NMR data may provide information for one or more fluid properties.
  • T1 and T2 can increase with pressure and decrease with temperature, and, for example, be in a range of about 3000 ms to about 7000 ms at a methane pressure of about 6000 psi (e.g. , about 41 MPa) and a temperature of between about 25 degrees C and about 175 degrees C.
  • methane pressure about 6000 psi (e.g. , about 41 MPa)
  • temperature of between about 25 degrees C and about 175 degrees C.
  • relaxation of methane still occurs, although weaker despite water wetting the surface.
  • a NMR tool can provide for acquiring data as to nuclear magnetic properties of one or more constituents in a formation. Such an approach may utilize one or more Larmor frequencies as may be determined in part via one or more gyromagnetic ratios (e.g., H-1 of 42.58, P-31 of 17.24, etc.).
  • an NMR log can include T1 and/or T2 data at various depths.
  • information germane to hydrocarbon typing, diffusion, etc. may be acquired.
  • the diffusion coefficient of a pore fluid may be acquired by processing the spin echo sequences from two logging passes acquired with different echo spacings.
  • a property can be Sigma, which can be defined as a macroscopic cross section for the absorption of thermal neutrons, or capture cross section, of a volume of matter, measured in capture units (c.u.). Sigma may also be used as an adjective to refer to a log of this quantity. Sigma can be an output of a pulsed neutron capture log, which can be used to determine water saturation. As an example, a log may be acquired for a portion of a borehole that is cased and/or for a portion of a borehole that is uncased.
  • formation sigma and the inelastic C/O ratio can be two measurements that may be available and optionally used in reservoir evaluation and saturation monitoring, for example, optionally through casing.
  • formation water salinity may be sufficiently greater than oil salinity and relatively known such that a method can include computing saturation from Sigma.
  • saturation may be derived from a salinity-independent C/O ratio measurement.
  • Sigma may be utilized as it may be measured at faster logging speeds.
  • the method 710 of Fig. 7 may be applied to estimate pressure and temperature in a virgin formation (e.g., undisturbed by a drilling process).
  • the estimates can be for a region or zone near a borehole.
  • a region or zone may be a region or zone that is a radial distance from a borehole, a region or zone that is a distance from a wall of a borehole, a region or zone that spans an arc distance about a longitudinal axis of a borehole (e.g. , up to 360 degrees), etc.
  • the method 710 may be performed using an
  • a method can include measuring one or more undisturbed properties via processing tool signals, for example, at multiple depths of investigation.
  • formation disturbance may be minimized using one or more logging while drilling (LWD) tools.
  • LWD logging while drilling
  • a tool or tools can measure one or more formation properties, for example, within a short period of time after an interval of a borehole has been drilled to minimize effects of disturbances to formation properties that may be caused by drilling.
  • the method 710 of Fig. 7 can include making an assumption that the pressure and temperature dependence of the relevant fluid property has been characterized.
  • Such an approach can be applied, for example, to a fluid or various fluid systems.
  • a fluid of interest is substantially pure such as, for example, substantially pure methane gas (e.g., greater than about 90 percent methane).
  • a method can include laboratory characterization as to the composition. For example, consider a composition that includes methane and another constituent. In such an example, laboratory characterizations may be performed using a range that may approximate an expected compositional range of the fluids in a region or zone of a formation proximate to a borehole.
  • Figs. 8 and 9 show examples of contour plots 810, 820, 910 and 920 associated with methane gas, as an example of a fluid that can be in a formation (e.g., in pores of rock, etc.).
  • the example plots 810, 820, 910 and 920 correspond to a plurality of properties, specifically, a selected set of four properties that can be inverted for the pressure and temperature of the gas.
  • the resolution of the contours represents the degree of accuracy of a particular measurement. For example, it is assumed that the NMR T1 relaxation time is measured to within a range of about 50 ms (e.g., error of about ⁇ 25 ms).
  • the example contour plots of properties of methane gas that are functions of pressure and temperature include, the plot 810, nuclear magnetic resonance longitudinal relaxation time (T1 ), in the plot 820 thermal neutron capture cross-section (e.g., Sigma, ⁇ ), in the plot 910, density (p), and in the plot 920, diffusion coefficient (D).
  • T1 nuclear magnetic resonance longitudinal relaxation time
  • p density
  • D diffusion coefficient
  • Figs. 8 and 9 can be measured using various logging tools. The ranges of these measured properties are shown in Table 1 , below:
  • Table 1 Measured values of properties of methane gas. T1 (ms) Sigma (c.u.) Density (kg/m 3 ) Diffusion Coefficient (10-3 ⁇ 4m 2 /s)
  • a method can include performing an inversion, for example, by superimposing areas between corresponding contour lines in the example plots of Figs. 8 and 9 where the plots include a temperature dimension (e.g., a temperature axis) and a pressure dimension (e.g., a pressure axis).
  • a temperature dimension e.g., a temperature axis
  • a pressure dimension e.g., a pressure axis
  • Figs. 10 and 1 1 show example plots 1010, 1020, 1 1 10 and 1 120 that illustrate an example of a graphical superposition technique. Specifically, Figs. 10 and 1 1 shows various actions involved in an example simultaneous inversion of T1 , Sigma ( ⁇ ), density (p) and the diffusion coefficient (D) of the example fluid (methane gas) for pressure and temperature using superposition of contour lines.
  • the example plot 1010 shows inversion of T1 alone; the example plot 1020 shows joint inversion of T1 and Sigma ( ⁇ ); the example plot 1 1 10 shows joint inversion of T1 , Sigma and density; and the example plot 1 120 shows joint inversion of T1 , Sigma ( ⁇ ), density (p), and diffusion coefficient (D).
  • the plot 1010 shows ranges of pressure and temperature corresponding to the measured T1 to be unbounded. However both pressure and temperature can be bounded by jointly inverting T1 and Sigma, as shown in the plot 1020 of Fig. 10. This results in an estimated pressure of about 1905 ( ⁇ 45) psi and a corresponding temperature of about 57.8 ( ⁇ 3.8) degrees C. As the additional properties of the density and the diffusion coefficient are incorporated in the inversion, the ranges of pressure and temperature are further reduced (see, e.g. , the plots 1 1 10 and 1 120 of Fig. 1 1 ). The results for each successive property of the inversion are shown in Table 2, below. In such an example, with each successive advance, the inverted parameters are altered and the uncertainty ranges are reduced (e.g., an area becomes smaller where the area is defined by a range of temperatures and a range of pressures).
  • Table 2 Pressure and temperature inferred at each of the four inversion actions illustrated in Figs. 10 and 1 1 .
  • Action 1 Action 2
  • Action 3 Action 4
  • Figs. 10 and 1 1 illustrate a number of features.
  • the size of the uncertainty region can be controlled by distances between successive contours of the same property and by angles between intersecting contours of different properties.
  • joint inversion of T1 and Sigma results in the smallest uncertainty region of pairs of property combinations because successive contours of T1 have the smallest distance between them and the angle between the contour lines of T1 and Sigma is larger than that of any other pair of properties. Therefore such a contour plot can be used to design
  • the foregoing example illustrates how the method 710 of Fig. 7 may be implemented.
  • a set of properties may be selected and inverted.
  • results of the inversion can provide estimates of pressure and temperature.
  • an inversion technique can be graphical, numerical, etc.
  • a method can include receiving borehole data for at least two properties associated with a formation; performing an inversion for formation pressure and temperature values based at least in part on at least a portion of the borehole data; and outputting at least a portion of the formation pressure and temperature values.
  • borehole data can include one or more of, for example, NMR data, neutron data (e.g., emissions data), hydrogen index data, or other type of borehole data (e.g. , as may be acquired via a borehole tool that can be disposed in a bore in a formation).
  • NMR data nuclear magnetic resonance data
  • neutron data e.g., emissions data
  • hydrogen index data e.g., hydrogen index data
  • other type of borehole data e.g. , as may be acquired via a borehole tool that can be disposed in a bore in a formation.
  • At least two properties can include one or more of, for example, fluid density, a relaxation time (or relaxation times), a diffusion coefficient, a thermal neutron capture cross-section, or other type of property.
  • a property can be a fluid property or a property of fluids (e.g., a mixture of different fluids).
  • a method can include performing one or more of, for example, a graphical inversion technique, a Bayesian inversion technique, a least squares inversion technique, a computer-implemented inversion technique or one or more other types of inversion techniques.
  • a method can include determining an unobserved variable or variables using one or more techniques of inferential statistics. For example, consider a method that includes using Bayesian probability.
  • a method can include outputting at least one of pressure and/or temperature values to a display.
  • an inversion may be performed for data associated with a region of a formation, which may be, for example, a region proximate to a borehole and along a length of a borehole.
  • the inversion can provide pressure and temperature values that may be plotted with respect to a dimension or dimensions of the borehole and/or the formation. For example, consider the scenarios of Figs. 5 and 6 given for temperature as directly measured.
  • a method can include outputting estimated values and/or information based at least in part on estimated values.
  • a method can include plotting directly measured values and estimated values.
  • the estimated values may be at a larger depth of investigation than the directly measured values for a portion of a borehole.
  • a NMR tool may acquire data at a larger depth of investigation than a DTS tool (e.g., or a pressure measurement tool).
  • a method can include performing at least one field operation on a formation based at least in part on at least one of one or more estimated pressure and/or temperature values (e.g., as estimated via an inversion).
  • a system can include a processor; memory operatively coupled to the processor; and instructions stored in the memory and executable by the processor to receive borehole data for at least two properties associated with a formation; perform an inversion for formation pressure and temperature values based at least in part on at least a portion of the borehole data; and output at least a portion of the formation pressure and temperature values.
  • the borehole data can include at least one log that includes data that corresponds to a length of a borehole in the formation.
  • one or more computer-readable storage media can include processor-executable instructions that instruct a computing device where the instructions include instructions to instruct the computing device to: receive borehole data for at least two properties associated with a formation; perform an inversion for formation pressure and temperature values based at least in part on at least a portion of the borehole data; and output at least a portion of the formation pressure and temperature values.
  • formation temperature can be utilized, for example, to estimate reserves, to evaluate maturity of hydrocarbon reserves, to assess borehole stability, to design of well cementing mixtures, etc.
  • a workflow can include utilizing formation temperature for one or more of determining water resistivity (e.g. , to calculate oil saturations from resistivity logs), determining reservoir-fluid formation volume factors (e.g. , to estimate reserves), determining geothermal gradients (e.g., to estimate temperatures of deep zones), calibrating petroleum systems models (e.g. , to calculate generation timing and yields) and/or one or more other purposes.
  • a method can include receiving borehole data for at least two properties associated with a formation; performing an inversion for formation pressure and temperature values based at least in part on at least a portion of the borehole data; and performing one or more simulations based at least in part on a portion of the formation pressure and/or the formation temperature values.
  • Such a method can include implementing one or more of a reservoir simulator, a geomechanics simulator, a petroleum systems simulator, and a surface network simulator.
  • data acquired via a tool or tools may be analyzed locally and/or remotely.
  • a framework such as the TECHLOGTM framework may be implemented to analyze data.
  • a module e.g., instructions
  • a plugin operative with a framework.
  • one or more methods described herein may include associated computer-readable storage media (CRM) blocks.
  • CRM computer-readable storage media
  • Such blocks can include instructions suitable for execution by one or more processors (or cores) to instruct a computing device or system to perform one or more actions.
  • one or more computer-readable media may include computer-executable instructions to instruct a computing system to output information for controlling a process.
  • such instructions may provide for output to sensing process, an injection process, drilling process, an extraction process, an extrusion process, a pumping process, a heating process, etc.
  • Fig. 12 shows components of a computing system 1200 and a networked system 1210.
  • the system 1200 includes one or more processors 1202, memory and/or storage components 1204, one or more input and/or output devices 1206 and a bus 1208.
  • instructions may be stored in one or more computer-readable media (e.g., memory/storage components 1204). Such instructions may be read by one or more processors (e.g., the processor(s) 1202) via a communication bus (e.g., the bus 1208), which may be wired or wireless.
  • the one or more processors may execute such instructions to implement (wholly or in part) one or more attributes (e.g. , as part of a method).
  • a user may view output from and interact with a process via an I/O device (e.g., the device 1206).
  • a computer-readable medium may be a storage component such as a physical memory storage device, for example, a chip, a chip on a package, a memory card, etc.
  • components may be distributed, such as in the network system 1210.
  • the network system 1210 includes components 1222- 1 , 1222-2, 1222-3, . . . 1222-N.
  • the components 1222-1 may include the processor(s) 1202 while the component(s) 1222-3 may include memory accessible by the processor(s) 1202.
  • the component(s) 1202-2 may include an I/O device for display and optionally interaction with a method.
  • the network may be or include the Internet, an intranet, a cellular network, a satellite network, etc.
  • a device may be a mobile device that includes one or more network interfaces for communication of information.
  • a mobile device may include a wireless network interface (e.g. , operable via IEEE 802.1 1 , ETSI GSM, BLUETOOTH®, satellite, etc.).
  • a mobile device may include components such as a main processor, memory, a display, display graphics circuitry (e.g. , optionally including touch and gesture circuitry), a SIM slot,
  • a mobile device may be configured as a cell phone, a tablet, etc.
  • a method may be implemented (e.g. , wholly or in part) using a mobile device.
  • a system may include one or more mobile devices.
  • a system may be a distributed environment, for example, a so-called “cloud" environment where various devices, components, etc. interact for purposes of data storage, communications, computing, etc.
  • a device or a system may include one or more components for
  • a communication occurs via one or more Internet protocols), a cellular network, a satellite network, etc.
  • a method may be implemented in a distributed environment (e.g., wholly or in part as a cloud-based service).
  • information may be input from a display (e.g. , consider a touchscreen), output to a display or both.
  • information may be output to a projector, a laser device, a printer, etc. such that the information may be viewed.
  • information may be output stereographically or
  • a printer may include one or more substances that can be output to construct a 3D object.
  • data may be provided to a 3D printer to construct a 3D representation of a subterranean formation.
  • layers may be constructed in 3D (e.g. , horizons, etc.), geobodies constructed in 3D, etc.
  • holes, fractures, etc. may be constructed in 3D (e.g. , as positive structures, as negative structures, etc.).

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Abstract

L'invention concerne un procédé pouvant comprendre la réception de données de trou de forage pour au moins deux propriétés associées à une formation; la mise en oeuvre d'une inversion des valeurs de température et de pression de la formation sur la base au moins en partie d'au moins une partie des données de trou de forage; et la sortie d'au moins une partie des valeurs de température et de pression de la formation.
PCT/US2016/058560 2015-10-28 2016-10-25 Évaluation de formation WO2017074884A1 (fr)

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RU2796803C1 (ru) * 2022-12-02 2023-05-30 Общество С Ограниченной Ответственностью "Газпром Добыча Надым" Способ контроля положения газоводяного контакта

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WO2018222054A1 (fr) 2017-06-01 2018-12-06 Equinor Energy As Procédé de calcul de température et de porosité de structure géologique
JP7277385B2 (ja) 2017-06-01 2023-05-18 エクイノール・エナジー・アーエス 地質構造の温度及び間隙率の計算方法
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GB2563048A (en) * 2017-06-01 2018-12-05 Equinor Energy As Method of calculating temperature and porosity of geological structure
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JP2020522689A (ja) * 2017-06-01 2020-07-30 エクイノール・エナジー・アーエスＥｑｕｉｎｏｒ Ｅｎｅｒｇｙ Ａｓ 地質構造の温度及び間隙率の計算方法
CN109425904A (zh) * 2017-08-30 2019-03-05 中国石油化工股份有限公司 一种碳酸盐岩地层孔隙压力获取方法
CN109425904B (zh) * 2017-08-30 2020-07-31 中国石油化工股份有限公司 一种碳酸盐岩地层孔隙压力获取方法
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CN109505590A (zh) * 2017-09-13 2019-03-22 中国石油化工股份有限公司 页岩气储层压力的确定方法及计算机可读存储介质
US11346833B2 (en) 2018-01-17 2022-05-31 Schlumberger Technology Corporation Reservoir fluid characterization system
CN109577969A (zh) * 2018-12-07 2019-04-05 中国地质大学（武汉） 一种基于岩石压缩系数计算碳酸盐岩地层孔隙压力的方法
CN114117590A (zh) * 2021-11-11 2022-03-01 山东大学 基于随钻测试与地化特征分析的隧道围岩分级系统及方法
CN114117590B (zh) * 2021-11-11 2024-02-20 山东大学 基于随钻测试与地化特征分析的隧道围岩分级系统及方法
CN114961716B (zh) * 2022-08-02 2023-01-10 中国矿业大学(北京) 岩体性质与劣化特征随钻评价方法
CN114961716A (zh) * 2022-08-02 2022-08-30 中国矿业大学(北京) 岩体性质与劣化特征随钻评价方法
RU2796803C1 (ru) * 2022-12-02 2023-05-30 Общество С Ограниченной Ответственностью "Газпром Добыча Надым" Способ контроля положения газоводяного контакта

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