Methods and systems for estimation of formation fluid properties

Abstract

Methods and systems are disclosed herein. A method may include obtaining a well log of a well and obtaining a first fluid sample at a first one of the plurality of depths within the well. The method may include obtaining a second fluid sample at a second one of the plurality of depths within the well. The method may include determining a first fluid property from the first fluid sample and a second fluid property from the second fluid sample. The method may include determining a transform based on the first fluid property, the second fluid property, and the well log data. The method may include applying the transform to the well log data at a third one of the plurality of depths within the well yielding a first predicted fluid property. The method may include determining a subsurface development plan based on the first predicted fluid property.

Description

BACKGROUND

[0001] Production rates of hydrocarbons from reservoir rock are based on the amounts of hydrocarbons generated from source rock and the reservoir characteristics. Production of hydrocarbons is carried out by drilling wells into reservoir rock storing the hydrocarbons. Reservoir rocks at times have poor permeability which may cause difficulties producing hydrocarbons from poor permeability rocks. Development plans are used to map out development projects to produce hydrocarbons from the reservoir.SUMMARY

[0002] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

[0003] In some aspects, the techniques described herein relate to a method for predicting a fluid property. The method may include obtaining, using a logging system, a well log of a well. The well log includes well log data at each of a plurality of depths within the well. The method may include obtaining, using a fluid retrieval system, a first fluid sample at a first one of the plurality of depths within the well. The method may include obtaining, using the fluid retrieval system, a second fluid sample at a second one of the plurality of depths within the well. The method may include determining a first fluid property from the first fluid sample. The method may include determining a second fluid property from the second fluid sample. The method may include determining a transform based on the first fluid property, the second fluid property, and the well log data at both the first one of the plurality of depths and the second one of the plurality of depths. The method may include applying the transform to the well log data at a third one of the plurality of depths within the well yielding a first predicted fluid property. The method may include determining a subsurface development plan based on the first predicted fluid property.

[0004] In some aspects, the techniques described herein relate to a system for estimating a fluid property. The system may include a logging system including a logging tool, a fluid retrieval system, a fluid property analysis system, and a subsurface development planning system. The logging tool is configured to obtain a well log of a well. The well log includes well log data at each of a plurality of depths within the well. The fluid retrieval system is configured to obtain a first fluid sample at a first one of the plurality of depths and a second fluid sample at a second one of the plurality of depths. The fluid property analysis system is configured to determine a first fluid property from the first fluid sample. The fluid property analysis system is configured to determine a second fluid property from the second fluid sample. The fluid property analysis system is configured to determine a transform based on the first fluid property, the second fluid property, and the well log data at both the first one of the plurality of depths and the second one of the plurality of depths. The fluid property analysis system is configured to apply the transform to the well log data at a third one of the plurality of depths within the well yielding a first predicted fluid property. The subsurface development planning system is configured to determine a subsurface development plan based on the first predicted fluid property.

[0005] Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.BRIEF DESCRIPTION OF DRAWINGS

[0006] Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency.

[0007] FIG. 1 depicts a fluid acquisition and analysis system in accordance with one or more embodiments.

[0008] FIG. 2 depicts a fluid acquisition and analysis system in accordance with one or more embodiments.

[0009] FIG. 3 depicts a logging tool in accordance with one or more embodiments.

[0010] FIG. 4 depicts a sonic well log in accordance with one or more embodiments.

[0011] FIG. 5 depicts a transform in accordance with one or more embodiments.

[0012] FIG. 6 depicts a seismic data acquisition system in accordance with one or more embodiments.

[0013] FIG. 7A-7B depicts a fluid properties estimation workflow in accordance with one or more embodiments.

[0014] FIG. 8 depicts a computer system in accordance with one or more embodiments.

[0015] FIG. 9 depicts a hydraulic fracturing system in accordance with one or more embodiments.

[0016] FIG. 10 depicts a fluid properties estimation flowchart in accordance with one or more embodiments.DETAILED DESCRIPTION

[0017] In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

[0018] Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for 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. By way of an example, 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.

[0019] It is to be understood that the singular forms “a,”“an,” and “the” include plural referents unless the context clearly dictates otherwise.

[0020] Terms such as “approximately,”“substantially,” etc., mean that the recited characteristic, parameter, or value need not be achieved exactly, but that deviations or variations, including for example, tolerances, measurement error, measurement accuracy limitations and other factors known to those of skill in the art, may occur in amounts that do not preclude the effect the characteristic was intended to provide.

[0021] It is to be understood that one or more of the steps shown in the flowchart may be omitted, repeated, and / or performed in a different order than the order shown. Accordingly, the scope disclosed herein should not be considered limited to the specific arrangement of steps shown in the flowchart.

[0022] Although multiple dependent claims are not introduced, it would be apparent to one of ordinary skill that the subject matter of the dependent claims of one or more embodiments may be combined with other dependent claims.

[0023] In the following description of FIGS. 1-10, 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. For brevity, descriptions of these components will not be repeated with regard to each figure. Thus, 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. Additionally, in accordance with various embodiments disclosed herein, 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.

[0024] Methods and systems for estimating formation fluid properties are disclosed herein. The method may include obtaining, using a logging system, a well log of a well. The well log may include well log data at each of a plurality of depths within the well. The method includes obtaining, using a fluid retrieval system, fluid samples at multiple depths within the well. The method includes determining one or more fluid properties from the fluid samples. The method includes determining a transform based on the one or more fluid properties and the well log data. The method includes applying the transform to the well log data at another depth within the well yielding a predicted fluid property.

[0025] FIG. 1 shows a system for the estimation of formation fluid properties (hereafter “estimation system” (100)) in accordance with one or more embodiments. The estimation system (100) may include a well (118) and a reservoir (101) having one or more formation fluids (102) (e.g., water, oil, and / or gas). Reservoirs (101), such as the one depicted in FIG. 1, have a source formation (108), a reservoir formation (110), and a cap rock (112). A source formation (108) is a formation rich in organic matter that, over time, is heated sufficiently to form hydrocarbon fluids such as gas and oil. Oil and gas then migrate from the source formation (108) to a more porous and permeable rock called the reservoir formation (110). Due to the inherent nature of these subsurface fluids, gas settles above oil and oil settles above water in the reservoir (101). Therefore, there are various “contacts” within the reservoir (101) that distinguish locations of different subsurface fluids.

[0026] The gas oil contact (“GOC”) (114) is the location or “surface”, in the reservoir (101), above which predominantly gas (e.g., a gas window (106)) occurs and below which predominately oil occurs (e.g., an oil window (104)). The gas that accumulates above the GOC (114) may be called a gas cap or a gas cap reservoir. The oil water contact (“OWC”) (116) is the location or “surface”, in the reservoir (101), above which predominantly oil occurs (e.g., an oil window (104)) and below which predominately water occurs. Wells (118) may be drilled below a surface (122) (e.g., surface of the earth) at a surface location and into a subsurface (132) having a plurality of depths. The subsurface (132) includes the reservoir (101).

[0027] Wells (118) may be drilled into the subsurface (132) at one or more surface locations and along a plurality of depths. In some embodiments, the well (118) may penetrate the reservoir (101) to gather data, produce hydrocarbon fluids, and / or treat the reservoir formation (110). Each well (118) may be an exploration well, a production well, or an injection well. Portions of the well (118) may include vertical and / or deviated well paths that continually deviate from vertical until a borehole is substantially horizontal. Production and injection wells, drilled into similar reservoirs (101), typically target the oil window (104) as the primary hydrocarbon fluid being produced and may inject water to balance reservoir pressure as reservoir pressure declines as oil is produced. Injection wells are wells (118) that may also inject chemicals into the reservoir formation (110) to treat the reservoir formation (110) and help produce oil. The production wells are wells (118) that may produce water and gas as secondary fluids. Wells and reservoirs may be configured in a myriad of ways, therefore the wells (118) and the reservoir (101) illustrated in FIG. 1 are not intended to be limiting with respect to the particular configuration of the wells and formations. Even though FIG. 1 illustrates a separate source formation and a reservoir formation, it is apparent to a person having ordinary skill in the art that the source formation and the reservoir formation may be the same formation such as in “unconventional” reservoirs.

[0028] The estimation system (100) may include a logging system (140) in accordance with one or more embodiments. The logging system (140) includes one or more logging tools configured to obtain a well log (145) of the well (118). In some embodiments, the logging system (140) may include cable systems to maneuver the logging tools and recording systems (e.g., analog and / or digital) to record well log data. The cable systems may include transmission cables to transmit well log data from the logging tools to the logging system (140). The well log data may be utilized to assess properties of the formation fluid (102).

[0029] In some embodiments, the estimation system (100) may include a fluid retrieval system (142). The fluid retrieval system (142) is configured to retrieve one or more fluid samples (147) (e.g., a first fluid sample (148) and / or a second fluid sample (149)) from the various formations (e.g., the source formation (108), the reservoir formation (110), and / or the cap rock (112)) at one or more depths from the surface (122). In some embodiments, the fluid retrieval system (142) may be configured to retrieve the fluid sample (147) at the wellhead (123).

[0030] In some embodiments, the estimation system (100) may include a fluid property analysis system (150). The fluid property analysis system (150) is configured to receive the fluid sample (147). The fluid property analysis system (150) is configured to analyze the fluid sample (147) and to determine fluid property data having one or more fluid properties. The one or more fluid properties may include an American Petroleum Institute (“API”) gravity, a fluid viscosity property, and / or a fluid GOR. For example, the fluid property analysis system (150) may include a hydrometer configured to determine the API gravity. Typical values for hydrocarbons may fall between 10 and 70 degrees. In some embodiments, the fluid property analysis system (150) may include a viscometer configured to determine a fluid viscosity of the fluid sample (147). In some embodiments, the one or more fluid properties may be acquired at the wellhead (123), for example, the fluid property analysis system (150) may include a flowmeter at the wellhead (123) to obtain the fluid GOR.

[0031] In some embodiments, the one or more fluid properties and / or well logs may be used to determine a borehole drilling plan (731 in FIG. 1, also shown in FIGS. 7A-7B). The borehole drilling plan (731) may include production targets within, for example, the reservoir formation (110). Portions of the borehole drilling plan (731) may include vertical and / or deviated well trajectories that continually deviate from vertical until the borchole drilling plan (731) is substantially horizontal. For the context of this disclosure, “vertical” and “horizontal” are in reference to the surface (122) at the surface location of the borehole. Also, terms such as “substantially horizontal” and “substantially vertical” may include portions of the borehole drilling plan (731) and / or the well (118) that may deviate from horizontal and / or vertical in relation to the surface (122) within a geographical region around the well (118).

[0032] FIG. 2 illustrates a well site (200) in accordance with one or more embodiments. Well sites may be configured in a myriad of ways; therefore, the well site (200) is not intended to be limiting with respect to the particular configuration of the drilling equipment, hydraulic fracturing equipment and / or well operations equipment. The well site (200) is depicted as being on land. In other examples, the well site (200) may be offshore, and drilling may be carried out with or without use of a marine riser. The well site (200) may include a drilling system (238), a hydraulic fracturing system (900) as described in relation to FIG. 9, and / or a well operations system. The drilling system (238) may be configured to drill the well (118) having a borehole (204) with a borehole fluid (206) from the surface (122) into the subsurface (132). The well (118) includes a plurality of depths (250) within the well (118) from the surface (122) to the end of the well (118). In some embodiments, the plurality of depths (250) may be a measured depth as described in relation to FIG. 2. The subsurface (132) may include one or more formations (232). Each formation (232) may include layers of rock having primary porosity (e.g., pore space) and / or secondary porosity (e.g., faults and / or dissolution spaces). For the purpose of drilling a new section of borehole (204), a drill string (220) is suspended within the borehole (204). The drill string (220) may include one or more drill pipes connected to form a conduit and a bottom hole assembly (a BHA (228)) disposed at the distal end of the conduit. The BHA (228) may include a drill bit (230) to cut into the subsurface rock. The BHA (228) may include one or more logging tools (240), such as a measurement-while-drilling (MWD) tool or a logging-while-drilling (LWD) tool, as well as other drilling tools that are not specifically shown but would be understood to a person of ordinary skill in the art. In some embodiments, the well site (200) may include the logging system (140) configured to obtain well log data.

[0033] The drill string (220) may be suspended in the borehole (204) by a derrick (e.g., a derrick structure (202)). A crown block (212) may be mounted at the top of the derrick structure (202). A traveling block (214) may hang down from the crown block (212) by means of a cable or drill line (e.g., drill line (208)). One end of the drill line (208) may be connected to a drawworks, which is a reeling device that can be used to adjust the length of the drill line (208) so that the traveling block (214) may move up or down the derrick structure (202). The top drive (218) is coupled to the top of the drill string (220) and is operable to rotate the drill string (220). Alternatively, the drill string (220) may be rotated by means of a rotary table (not shown) on the surface (122). The drill string (220) is used with a BOP (e.g., blowout preventer (236)). The BOP may be used to seal the well (118). Drilling fluid (commonly called mud) (not shown) may be pumped from a mud system (234) into the drill string (220). The mud may flow into the drill string (220) through appropriate flow paths in the top drive (218), or through a rotary swivel if a rotary table is used (not shown). Details of the mud flow path have been omitted for simplicity, but would be readily understood by a person of ordinary skill in the art.

[0034] During a well drilling operation at the well site (200), the drill string (220) is rotated relative to the borchole (204) and weight is applied to the drill bit (230) to enable the drill bit (230) to break rock as the drill string (220) is rotated. In some cases, the drill bit (230) may be rotated independently with a drilling motor (not shown). In other embodiments, the drill bit (230) may be rotated using a combination of a drilling motor (not shown) and the top drive (218) (or a rotary table if used instead of a top drive) to rotate the drill string (220). While cutting rock with the drill bit (230), mud is pumped into the drill string (220). The mud flows down the drill string (220) and exits into the bottom of the borehole (204) through nozzles in the drill bit (230). The mud in the borchole (204) then flows back up to the surface (122) in an annular space between the drill string (220) and the borchole (204) carrying entrained cuttings to the surface (122). The cuttings are removed, and the fluid is returned to the mud system (234) to be recycled and circulated back again into the drill string (220).

[0035] Drilling operations are completed upon the retrieval of the drill string (220), the BHA (228), and the drill bit (230) from the borchole (204). In some embodiments of borchole (204) construction, the production casing operations may commence. Production casing operations includes installing casing in the borehole (204). A casing string (224), which is made up of one or more larger diameter tubulars that have a larger inner diameter than the drill string (220) but a smaller outer diameter than the borehole (204), is lowered into the borchole (204) on the drill string (220). Generally, the casing string (224) is designed to isolate the internal diameter of the borchole (204) from the formation (232). Once the casing string (224) is in position, it is set and cement is pumped down through the internal space of the casing string (224), out of the bottom of the casing shoe (226), and into the annular space between the borehole (204) and the outer diameter of the casing string (224). This secures the casing string (224) in place and creates the desired isolation between the borchole (204) and the formation (232). At this point, drilling of the next section of the borchole (204) or completion and stimulation operations around the borehole (204) may commence such as the stimulation operations described in relation to FIG. 9.

[0036] The estimation system (100) includes one or more fluid property acquisition systems (701) and techniques (e.g., a logging system, a fluid retrieval system, and / or a seismic data acquisition system) are available for determining various reservoir characteristics at one or more locations within the subsurface (132) (e.g., a fourth location (254)). The one or more locations may be within the well (118) or a distance (255) away from the well (118).

[0037] The logging system (140) includes the one or more logging tools (240), such as a sonic logging tool (245) and / or a density logging tool (not shown), for use in generating the well logs (145) of the subsurface (132). The one or more well logs (145) (e.g., a sonic well log and / or a density well log) include well log data. In some embodiments, the well log data may be acquired at each of the plurality of depths (250) within the well. In some embodiments, the well log data may be acquired at the plurality of depths within a depth interval (231). The one or more logging tools (240) may be incorporated into the MWD tool or the LWD tool as described above or may be maneuvered via a wireline using a spooling device configured to adjust the length of wireline. For example, the logging tool (240) may be lowered into the borehole (204) to acquire well log data at the plurality of depths (250) within the well (118) as the tool traverses the depth interval (231) (for example, targeted reservoir section) of the borehole (204). One or more source activation locations (217) (also known as firing / excitation location) are locations at which a logging tool source generates a tool signal as the logging tool is maneuvered either by the drill string (220) or the wireline. The plot of the well log data versus depth may be referred to as a “log” or “well log”. Well logs (145) may provide depth measurements of the well (118) that describe such reservoir characteristics as formation porosity, formation transit time, formation permeability, resistivity, water saturation, and the like. The resulting well log data may be stored as “raw” well logs or processed or both, for example, by the fluid property analysis system (150), to generate corresponding well logs (145) for the well (118). A sonic well log may include, for example, recorded sonic waveforms versus true vertical depth (TVD) across the depth interval (231) or each of the plurality of depths (250) of the borchole (204).

[0038] Multiple types of logging techniques are available for determining various reservoir characteristics at one or more locations within the subsurface (132) (e.g., a fourth location (254)). A particular form of logging may be selected and used based on the logging conditions and the type of desired measurements. For example, sonic logging measures an interval transit time of the formation (232). Thus, sonic logs may measure one or more velocities of sonic compressional and / or shear waves through the formation (232). In so doing, sonic logs may be used alone, or in combination with other logs, to determine both porosity and permeability as well as the types of fluids present in the pore spaces. For determining density, a type of density well log that may be used is called bulk density (“RHOB”) logging. RHOB logging may determine the densities of rocks in the formation (232) by measuring the amount of gamma rays that are scattered back to a gamma ray detector disposed in the density logging tool. The RHOB logging tool source emits gamma rays. The emitted gamma rays interact with the electrons within the formation (232). The interaction of the emitted gamma rays with the electrons of the formation (232) scatters the gamma rays. The amount of scattered gamma rays that reach the detector is related to the formation's electron density, which in turn is related to the formation's bulk density. The bulk density is the average density of rocks of different lithologies (e.g., sand, shale, and / or carbonate lithologies) and formation fluids (102). Shales tend to have a higher bulk density than sandstones, therefore, bulk density well logs may be used to identify sand and shale lithologies.

[0039] To determine travel times in the formation (232), various types of logging techniques may be used. For example, the logging system (140) may measure the speed that acoustic waves travel through rocks in the formation (232). This type of logging may generate compressional and / or shear wave sonic logs, which are also called sonic logs and acoustic logs. In general, sound waves may travel faster through shales than through sandstones because shales generally have greater density than sandstones. Likewise, density logging may also determine density measurements by directly measuring the density of the rocks in the formation (232). In addition, neutron logging may determine porosity measurements by assuming that the reservoir pore spaces within the formation (232) are filled with either water or oil and then measuring the amount of hydrogen atoms (that is, neutrons) in the pores. Furthermore, the logging system (140) may determine geological data for the formation (232) by measuring corresponding well logs (145) for the borehole (204).

[0040] The fluid retrieval system (142) may include a fluid retrieval apparatus (242). The fluid retrieval apparatus (242) may be any fluid retrieval apparatus configured to retrieve the fluid sample (147) from formations (232) (e.g., the source formation (108) and / or the reservoir formation (110)). The fluid sample (147) may be retrieved at one of the plurality of depths (250) (e.g., a first one (251), a second one (252), and / or a third one (253) of the plurality of depths (250)) within the well (118). The fluid retrieval apparatus (242) may also be configured to fluidly couple with the formation (232) so as to isolate any sample of the formation fluid (102) mixing with any extrinsic fluids (e.g., formation fluid from different formations, borehole fluid (206), drilling fluid and / or frac fluid) within the borehole (204). In some embodiments, the fluid retrieval apparatus (242) may be maneuvered via the wireline of the logging system (140). In some embodiments, the fluid retrieval apparatus (242) may be integrated into the BHA (228) and the fluid sample (147) may be retrieved while drilling or when the drilling is briefly paused (e.g., drill pipe connections and / or fluid sampling). It will be apparent to a person of ordinary skill in the art that the location of the samples may be obtained at any depth and the location of the various depths (e.g., the first one (251), the second one (252) and / or the third one (253) of the plurality of depths (250)) are for illustrative purposes and should not be considered limiting as to the scope of the invention.

[0041] While FIG. 1 and FIG. 2 show various configurations of components, other configurations may be used without departing from the scope of the disclosure. For example, various components in FIG. 1 and / or FIG. 2 may be combined to create a single component. As another example, the functionality performed by a single component may be performed by two or more components.

[0042] FIG. 3 shows a sonic logging tool (245) in accordance with one or more embodiments. This sonic logging tool design is one of many possible sonic logging tool designs and is not intended to be limiting on the scope of the invention. The sonic logging tool (245) includes a sonic source (315) and a plurality of sonic receivers (310). The sonic source (315) may be a dipole or a monopole but not limited to this. FIG. 3 shows both types of sonic sources though only one may be activated or disposed within the sonic logging tool on any given logging run. One of the plurality of sonic receivers (310) may be a dipole receiver. The sonic source (315) and the plurality of sonic receivers (310) are operatively disposed in the sonic logging tool (245), which may be a steel pipe. The plurality of sonic receivers (310) may be azimuthally distributed around a tool axis (305) of the sonic logging tool (245) and include one or more principal axes (311). Each of the principal axes may be aligned, for example, with one of the plurality of receivers and its principal recording orientation. In some embodiments, the principal axes (311) may be oriented relative to the tool axis (305) such as perpendicular relative to the tool axis (305). The plurality of sonic receivers (310) detects and record pressure fluctuations of the borehole fluid (206) filling the borchole (204) caused by incident sonic waves. Although eight sonic receivers are shown in FIG. 3, in some embodiments there may be a greater or lesser number of sonic receivers. The sonic logging tool (245) may include an isolation joint (307). The isolation joint (307) is disposed within the sonic logging tool (245) and positioned between the sonic source (315) and the plurality of sonic receivers (310). The isolation joint (307) mitigates noise cross-contamination of the sonic source (315) and the plurality of sonic receivers (310) along the sonic logging tool (245).

[0043] As the one or more logging tools (240) is lowered over the depth interval (231) for a logging run, the sonic source (315) may be activated at the one or more source activation locations (217) emitting a source signal into the borehole (204) and the formation (232) around the sonic source (315). Each sonic receiver (310) measures the source signal as the source signal radiates through the formation (232).

[0044] FIG. 4 illustrates a sonic velocity log (420) in accordance with one or more embodiments. The sonic logging tool (245) measures the sonic slowness of the formation (232), typically in microseconds per foot. The plot of the sonic logging measurements versus depth is the sonic well log (420). The sonic well log data may be processed by the fluid property analysis system (150) and displayed as sonic velocity. The sonic velocity is determined by the reciprocal of the sonic slowness multiplied by a constant to convert units. For example, feet per microseconds is converted to meters per second by multiplying the reciprocal of the sonic slowness by a constant of 304800 to yield the sonic well log in terms of velocity. The X axis (422) represents the sonic well data in terms of velocity. The Y axis (424) represents the sonic source location index. For example, a borehole, as in the borehole (204) in FIG. 2, the source location index may be a measured distance (e.g., “measured depth”) from the surface location along the borehole (204) to the position of the sonic source (315) within the borehole (204) rather than a true vertical depth.

[0045] FIG. 5 shows a transform (510) based on subsurface data (703) including well log data (704) from the well logs (145) and fluid property data (745). The fluid property data (745) includes the one or more fluid properties (e.g., a first fluid property (748) and / or a second fluid property (749)). The first fluid property (748) may be determined from the first fluid sample (148) using the fluid property analysis system (150). The second fluid property (749) may be determined from the second fluid sample (149) using the fluid property analysis system (150). The fluid property analysis system (150) is configured to determine the first fluid property (748) from the first fluid sample (148). The fluid property analysis system (150) is configured to determine the second fluid property (749) from the second fluid sample (149). The first fluid property (748) may be, for example, an API gravity, a fluid viscosity, or a fluid GOR. The second fluid property (749) would be the same type of property as the first fluid property (748). The fluid property analysis system (150) is configured to determine the transform (510) based on the first fluid property (748), the second fluid property (749), and the well log data (704) at both the first one (251) of the plurality of depths (250) and the second one (252) of the plurality of depths (250).

[0046] In some embodiments, the fluid property analysis system (150) may be configured to cross-correlate the first fluid property (748) and the second fluid property (749) with the well log data (704) at both the first one (251) of the plurality of depths (250) and the second one (252) of the plurality of depths (250) yielding a fluid data cross-correlation (515). For example, the first fluid property (748) is a first API gravity determined from the first fluid sample (148) obtained at the first one (251) of the plurality of depths (250). The second fluid property (749) is a second API gravity determined from the second fluid sample (149) obtained at the second one (252) of the plurality of depths (250). The first API gravity and the second API gravity are cross-correlated with the sonic well log data (705) obtained at both the first one (251) of the plurality of depths (250) and the second one (252) of the plurality of depths (250).

[0047] In some embodiments, the fluid property analysis system (150) may be configured to fit a polynomial to the fluid data cross-correlation (515) as shown in FIG. 5. In some embodiments, algorithms may be used such as polynomial regression, least squares, Bayesian methods, and the like.

[0048] In some embodiments, the transform (510) may be a non-linear transform. The non-linear transform may be based on fitting the polynomial to the fluid data cross-correlation (515). The transform (510) may take the form as follows:fp=c*1⁢0t*em*wl(1)where fp is the fluid property data (745), c is a first constant, t is a second constant, m is a third constant, and wl is the well log data (704).In some embodiments, the transform (510) may take the form as follows:fp=c*wl2+t*wl+m,(2)where fp is the fluid property data (745), c is the first constant, t is the second constant, m is the third constant, and wl is the well log data (704). For example, the transform (510) may be determined using the API gravity in units of degrees and the sonic well log data (705) in units of microsecond per foot (micro-s / ft) as shown in FIG. 5. An X-axis (501) represents sonic slowness.

[0051] In some embodiments, the transform (510) may be applied to the well log data (704) at the plurality of depths (250) within the well (118) to yield one or more predicted fluid properties (711) (e.g., a first predicted fluid property (714) and / or a second predicted fluid property (715)). The one or more predicted fluid properties (711) may include, but not limited to, a predicted API gravity, a predicted fluid viscosity, and / or a predicted fluid GOR. For example, the transform (510) may be applied to the well log data (704) at the third one (253) of the plurality of depths (250) within the well (118) yielding the predicted fluid property (711) such as the predicted API gravity. The predicted fluid property (711) will be the same type of fluid property data (745) used to determine the transform (510).

[0052] For example, a development plan may include seven (7) wells as shown in Table 1 below. Each of the seven wells may produce a production fluid with one or more fluid properties (e.g., API, GOR, and / or fluid viscosity (v)) and one or more well log data (e.g., sonic (DTC) and / or density (RHOB)) as shown in Table 1. Each fluid property may be cross-correlated with each well log data recorded at depth of the fluid sample. For example, the transform (510) may be determined using the fluid viscosity (v) in units of centipoise (cP) and the density well log data (RHOB) in units of grams per cubic centimeter (g / cc). The polynomial fit to the fluid viscosity and density data listed in Table 1 take the form in Eq. (1) where the first constant is 3, the second constant is 20, and the third constant is −19.89. The various constants are determined from fitting the polynomial to the fluid data cross-correlation (515) of fluid viscosity and density well log data. For another example, Y-axis (502) represents the API gravity. The transform (510) transforms sonic slowness data to API gravity. The polynomial fit to the fluid viscosity and density data listed in Table 1 take the form in Eq. (2) with the first constant is −0.0728, the second constant is 10.299, and the third constant is −319.31. The X axis (422) represents the sonic well log data (705) in terms of slowness as shown in FIG. 5. The various constants are determined from fitting the polynomial to the fluid data cross-correlation (515) of API gravity and the sonic well log data (705).TABLE 1Table of Fluid PropertiesGOR,WellAPI, degSCF / BBLν, cpDTCRHOBWell-135.56480.78282.042.39Well-239.99320.40779.512.39Well-333.34031.04282.762.37Well-444.859040.07068.962.50Well-542.522490.20074.732.46Well-635.66410.77282.172.40Well-74215270.36177.322.44

[0053] FIG. 6 shows a seismic survey of the subsurface (132) using a seismic data acquisition system (600) configured to obtain seismic data (648) from a geographical region (615) that includes the well (118) and the subsurface (132) having the formation (232). For example, the subsurface (132) contains a gas deposit (620) within the reservoir formation (110) that is being recovered by the wells (118). The gas deposit may be methane, ethane, or another hydrocarbon gas. The seismic data acquisition system (600) uses a seismic source (606) to generate radiated seismic waves (608). The radiated seismic waves (608) may return to the surface (122) as refracted seismic waves (610) or reflected seismic waves (614), where reflected seismic waves (614) occur due to subterranean boundaries (612) between rock within the formation (232). At the surface (122), refracted seismic waves (610) and reflected seismic waves (614) may be detected by seismic receivers (616).

[0054] The refracted seismic waves (610) and reflected seismic waves (614) generated by a single activation of the seismic source (606) is recorded by a seismic receiver (616) as a time-series representing the amplitude of ground-motion at a sequence of discrete times. This time-series may be denoted as a seismic “trace”. A seismic source (606) is positioned at a location denoted (x_s,y_s) where x and y represent orthogonal axes on the surface of the Earth above the subsurface (132). The seismic receivers (616) are positioned at a plurality of seismic receiver locations denoted (x_r,y_r). Thus, the refracted seismic waves (610) and reflected seismic waves (614) generated by a single activation of the seismic source (606) may be represented as five-dimensional seismic data by (x_s,y_s,x_r,y_r,t) where t delimits the time sample at which the amplitude of ground-motion was measured by a seismic receiver (616).

[0055] A subterranean boundary (612) is often called a “horizon” by a person of ordinary skill in the art, particularly when referring to the manifestation of the subterranean boundary (612) in a subsurface image. Use of the term horizon does not imply that the horizon is either flat or planar. Hereinafter, horizon is used to encompass both the subterranean boundary (612) in the subsurface (132) and the manifestation of the subterranean boundary (612) in the subsurface image. Hereinafter, the terms “horizon” and “subterranean boundary” may be used interchangeably.

[0056] FIGS. 7A-7B illustrates a fluid properties estimation workflow (700) in accordance with one or more embodiments. The fluid properties estimation workflow (700) includes steps of acquiring the subsurface data (703) (e.g., the fluid property data (745), the well log data (704), and / or the seismic data (648)), processing the subsurface data (703), forming one or more geologic models, optionally simulating the flow of fluids, including hydrocarbons, though the one or more geological models, drilling, and / or stimulating the reservoir section. Although the steps in the fluid properties estimation workflow (700) are shown in sequential order, it will be apparent to one of ordinary skill in the art that some steps may be conducted in parallel, in a different order than shown, or may be omitted without departing form the scope of the invention.

[0057] In accordance with one or more embodiments, the fluid properties estimation workflow (700) may begin with the use of fluid property acquisition systems (701) including the logging system (140) and the fluid retrieval system (142). The logging system (140) may be used to acquire the well log data (704) including the sonic well log data (705) and / or the density well log data (706), over the plurality of depths (250) within the well (118). Also, the fluid retrieval system (142) may be used to acquire the fluid sample (147) using the fluid retrieval apparatus (242). The fluid property acquisition systems may also include the seismic data acquisition system (600) configured to obtain a seismic data (648) from the geographical region (615) that includes the well (118). The seismic data (648), for example, may be used to characterize the formation (232) around the borehole (204). Other remote sensing data may also be collected at this stage to characterize the subsurface (132). For example, resistivity, transient electromagnetic, and / or gravitation surveys may be collected.

[0058] In some embodiments, the subsurface data (703) includes the well log data (704), the fluid property data (745), the seismic data (648), or a combination thereof. The well log data (704) may include the well logs (145) in an unprocessed “raw” form that may be used to determine the transform (510) with the fluid property data (745). The well log data (704), fluid property data (745), and the seismic data (648) are influenced by formation characteristics of the formation (232).

[0059] In some embodiments, the subsurface data (703) may include a wide variety of noise and distortion which in their unprocessed “raw” form may not provide significant useful information about the subsurface (132). Consequently, in such embodiments the subsurface data (703) may be processed, using a subsurface processing system (650), to remove or attenuate noise and to correctly position the subsurface data (703). For example, processing well logs (145) may include depth matching (i.e., aligning) the distinct logging runs. Depth matching includes aligning portions of the similar types of logs from different logging runs and which overlap in depth so that the logs are corrected for any depth errors between each logging run that may occur. Depth error may include cable stretching, tool sticking, tool slipping, and / or yo-yo effects among other issues that affect depth control of the one or more logging tools (240). Other processing may include de-spiking. De-spiking may include removing any data point that falls outside of a given threshold. The thresholds may be input from a user on a user device. The user device may be connected wirelessly or via cable to a computer system similar or the same as the computer system (800) described in relation to FIG. 8.

[0060] Processing the seismic data (648) includes processes designed to correct for, but not limited to, near-surface effects, depth issues, attenuate noise, compensate for irregularities in an acquisition surface (e.g., surface of the earth or walls of a borehole), calculate a velocity in the case of the sonic well log data (705) and the seismic data (648), calculate one or more subsurface images and attributes (708) to characterize the subsurface (132) and to determine the one or more drilling targets. Each of these processes may be accompanied by one or more quality control processes.

[0061] Processing of the seismic data (648) may be performed by a number of methods known to a person of ordinary skill in the art without departing from the scope of the invention. For example, the seismic data (648) may be time migrated seismic data or depth migrated seismic data. The seismic data (648) may also be further processed to correct for seismic source (606) and seismic receiver (616) location geometry and to attenuate noise while leaving the amplitude of the seismic signal undistorted. The seismic data (648) may be reduced to a two-dimensional (“2D”) or a three-dimensional (“3D”) image that delineates subterranean boundaries (612) as large or bright reflection amplitudes to form the one or more subsurface images and attributes (708).

[0062] In another step in processing the seismic data (648), a velocity model (707) may be determined representing the speed at which sonic waves propagate at various points within the subsurface (132). In some cases, the velocity model (707) may be calibrated using the sonic velocity log (420) based on velocity data obtained from the sonic well log data (705) (e.g., seismic well ties). The seismic data (648) and the velocity model (707) may be combined using a process called “migration” to form the subsurface image and attributes (708). Migrating seismic data (648) may take a substantial amount of computational time and memory relative to other processing steps. Typically, the subsurface image displays points of high and low reflection amplitude on a color scale or grayscale on a dense 2D or 3D grid of points representing the subsurface (132) around the geographical region (615) of the seismic survey area. Such an image may then be interpreted, together with other information, to determine geological structures surrounding the borehole (204) based on the subsurface image that may influence fluid flow within the subsurface (132).

[0063] Another result of processing the subsurface data (703) with the subsurface processing system (650) may be the one or more subsurface images and attributes (708) using subsurface imaging tools such as optical imaging tools, electrical imaging tools, acoustic imaging tools, or in combinations thereof. The subsurface processing system (650) may be configured to determine the subsurface image and attributes (708) of the subsurface (132) based on the seismic data (648) and the well log data (704). The subsurface image and attributes (708) may be a 2D or 3D image of the points within the subsurface (132) that generates a distinctive subsurface response. For example, the subsurface image may display the points at which acoustic energy is reflected, or scattered, within the subsurface (132) such as with the seismic data (648). Other characteristics or “attributes” of the subsurface (132) may be displayed as the subsurface image and attributes (708). For example, the strength of conversion of energy from one type of source wave to another as in acoustic imaging of the subsurface (132), or the strength of absorption of source energy, or the velocity of source propagation may be displayed as a function of subsurface position in the subsurface image and attributes (708). The examples of attributes given above are purely illustrative, and a person having ordinary skill in the art will appreciate that anyone of dozens of other attributes may be displayed as the subsurface image and the examples described should not be interpreted as limiting the scope of the invention in any way.

[0064] The subsurface processing system (650) may include a computer system, such as the computer system (800) shown in FIG. 8. The subsurface processing system (650) will typically be configured with appropriate subsurface data processing and analysis software and augmented with a number of purpose specific elements, such as high-capacity tape drives or hard drives connected through high-speed buses to computer processing units (“CPUs”). Further the CPUs of the subsurface processing system (650) will typically be connected to a plurality of graphical processing units (“GPUs”) that perform many of the computationally intensive operations on the subsurface data (703), banks of high-speed tape, or hard-drive, readers to read the data from storage, high-speed tape or hard-drive writers to output final or intermediate results, and high-speed communication buses to connect these elements.

[0065] It will be appreciated by a person having ordinary skill in the art that subsurface data (703) are extremely large, typically occupying hundreds of Gigabytes to Terabytes of data samples and cannot be manipulated or “processed” without the assistance of the subsurface processing system (650) purposely configured to handle the subsurface data (703). Based upon the disclosure provided herein, one of ordinary skill in the art will appreciate that the gathering of the data involves specialized tools to obtain the vast quantities of gathered data, and high-speed processing capability capable of performing at least one thousand calculations per second. Indeed, in some embodiments, processors capable of millions, billions, or even more calculations per second are used.

[0066] The subsurface images and attributes (708) may be an image, typically composed of pixels of varying intensity, and is not itself a model of the geological structure of the subsurface (132) to which it pertains. To determine the geological structure corresponding to, or that produced, the subsurface image is typically “interpreted” using the fluid property analysis system (150).

[0067] The fluid property analysis system (150) may include a subsurface interpretation workstation. The subsurface interpretation workstation is primarily used by subsurface interpreters (e.g., geoscientists and petrophysicists) and development teams in the oil and gas industry for analyzing the subsurface data (703) to understand geological structures and characteristics of the subsurface (132). Subsurface interpreters use the subsurface interpretation workstation to visualize the subsurface data (703), including, but not limited to, the well log data (704), the seismic data (648) such as 2D or 3D seismic volumes, seismic cross-sections, seismic attribute maps, and seismic attribute plots. These visualizations provide insights into subsurface structures, faults, and potential hydrocarbon reservoir formations and hydrocarbon source formations. Additional data may be used within the subsurface interpretation workstation to facilitate the interpretation of the subsurface data (703). Such data may also include other remote sensing data such as seismic, resistivity, transient electromagnetic, and / or gravitational surveys.

[0068] Subsurface interpreters may pick and interpret key geologic horizons within the seismic data (648) to identify stratigraphic layers, boundaries, and structural features. Horizon interpretation tools and workflows allow for the accurate extraction of geological information from seismic volumes. For example, the fluid property analysis system (150) enables interpreters to identify and interpret the one or more anomalies (e.g., horizons (612) and / or subsurface faults) that may impact the formation (232). Subsurface interpretation tools and visualization techniques help in understanding geometry, connectivity, and spatial relationships of the formation (232). Subsurface attributes, such as amplitude, frequency, and gradient, provide additional information about subsurface properties and can be analyzed using various algorithms and statistical methods. Attribute analysis tools in the workstation aid in defining reservoir characteristics, identifying anomalies, and highlighting potential hydrocarbon traps. Maps of the formation (232) may be used to determine the spatial extent of the formation fluid (102) including the oil window (104) and / or gas window (106).

[0069] The fluid property analysis system (150) may be used to determine the assessment of reservoir production potential, where subsurface interpreters may identify and assess areas with hydrocarbon exploration and production potential. The subsurface interpreters may perform detailed geological, petrophysical, and geophysical analysis, identify drilling targets, and quantify the risk and uncertainty associated with potential prospects.

[0070] In some embodiments, the one or more fluid properties may be determined by applying the transform (510) to the velocity model (707) yielding the one or more predicted fluid properties (711) at the one or more location within the subsurface (132) (e.g., the fourth location (254)). The fluid property analysis system (150) may be configured to apply the transform (510) to the velocity model (707) yielding the one or more predicted fluid properties (711) (e.g., the second predicted fluid property (715)) at the one or more locations within the subsurface (132) (e.g., the fourth location (254)). The one or more locations (e.g., the fourth location (254)) may be located the distance (255) away from the well (118) within the formation (232).

[0071] The fluid property analysis system (150) includes essential tools for subsurface interpreters involved in exploration and production activities, helping them make informed decisions about drilling locations, optimize production strategies, and understand complex subsurface geologic structures. The fluid property analysis system (150) may be a specialized computer system used by geoscientists and subsurface interpreters for analyzing and interpreting the subsurface data (703).

[0072] Subsurface interpretation involves data intensive tasks like data visualization, horizon picking, attribute analysis, and 3D modeling. For example, data visualization may include rendering 10s of gigabytes of data within several seconds in accordance with one or more embodiments. A high-performance subsurface interpretation workstation with a powerful processor, ample memory, and a high-resolution display is essential to handle these computationally demanding tasks efficiently. Dedicated GPUs may be utilized for rendering of the seismic data (648) to enable smooth and interactive visualization. GPUs with high memory and parallel processing capabilities accelerate tasks like volume rendering and horizon visualization.

[0073] In some embodiments, the subsurface interpretation workstation may automatically process the seismic volume to identify portions of the seismic data (648) that may include hydrocarbon reservoir potential and render the seismic data (648). In some embodiments, the subsurface interpretation workstation may interpret the data automatically and identify potential digital source rock formations that may be planned for hydrocarbon appraisal and production.

[0074] Subsurface interpretation involves working with large and complex data sets. Multiple high-resolution monitors allow interpreters to view the subsurface data (703), cross-sections, attribute maps and plots, and other visualizations simultaneously, enhancing productivity and analysis accuracy. The subsurface interpretation workstation may be equipped with industry-standard software applications tailored for subsurface interpretation, such as petrophysical, seismic and / or VSP data processing and visualization tools, well logs and petrophysics interpretation systems, attribute analysis software, and 3D modeling software.

[0075] Subsurface processing and interpretation projects generate substantial amounts of data, including petrophysical interpretations of the well logs (145), seismic volumes, processed data such as the one or more subsurface images and attributes (708) formed from the seismic data (648), the velocity models (707), the sonic well log data (705), and interpretation results such as subsurface interpretations and geological and reservoir models. A high-capacity and fast storage system, such as solid-state drives (SSDs) or RAID arrays, is necessary to store and access this data efficiently. The subsurface processing system (650) and the fluid property analysis system (150) often require network connectivity to access centralized data repositories, collaborate with colleagues, and share interpretation results. A robust network infrastructure with fast Ethernet or fiber connections ensures smooth data transfer and collaboration capabilities. The fluid property analysis system (150) may be configured to identify drilling targets based, at least in part, on the subsurface image and attributes (708).

[0076] Essential peripherals like keyboards, mice, and graphics tablets enable efficient interaction with data and software interfaces. The fluid property analysis system (150) may be augmented with purpose specific peripherals such as high capability display devices that may include immersive or virtual reality devices, such as virtual-reality headsets or immersive “caves”. Additionally, color-calibrated, and high-accuracy input devices enhance the precision of interpretation tasks like picking horizons representing stratigraphy or drawing geological features. The fluid property analysis system (150) should have backup solutions in place to protect valuable data from loss or damage. Automated backup systems, external storage devices, or network-attached storage (NAS) can be utilized to ensure data safety. In some cases, subsurface interpreters may need remote access to the fluid property analysis system (150) or collaborate with colleagues remotely. Setting up remote access capabilities, such as Virtual Private Networks (VPNs) or remote desktop solutions, allows interpreters to work from different locations and share their work effectively. The fluid property analysis system (150) may be customized to meet the needs of interpreters and the specific requirements of projects. The hardware specifications may vary based on factors like the complexity of interpretations, the size of data sets, and the software tools utilized.

[0077] The result of interpreting the well logs (145), the fluid property data (745), and the subsurface image and attributes (708) may be one or more geological and reservoir models (712) of the subsurface (132). The geological and reservoir models (712) may include utilizing an analysis of the subsurface interpretation to identify structural traps, seals, source formation generation and migration, and reservoir formation presence and quality. The geological and reservoir models (712) may include the locations of horizons, such as the boundary between formations (232) (e.g., the reservoir formation (110) and the source formation (108)) containing different rock types (“facies”), and faults and fractures. The geological and reservoir models (712) may also include descriptions of the characteristics of the different facies including characteristics such as porosity and permeability, and the relative amounts of different fluids, such as hydrocarbons, and brine, within the pores in each facies. The porosity and permeability may be used to define the reservoir formation quality for example. These characteristics may be included in the rock properties models. The fluid property analysis system (150) may include system software tools configured to populate geological, rock properties models, and fluid properties models such as using variograms and other statistical tools.

[0078] In some embodiments, the geological model and reservoir models (712) may include the one or more predicted fluid properties (711) based on applying the transform (510) to the fluid property data (745) and the well log data (704). The one or more predicted fluid properties (711) may include the predicted API gravity, the predicted fluid viscosity, and / or the predicted fluid GOR. In some embodiments, the fluid property analysis system (150) may output one or more predicted fluid properties (711), using the transform (510), that is defined over the formations (232) (e.g., the reservoir formation (110) and / or the source formation (108)) based on the well log data (704), the fluid property data (745), and the one or more seismic images and attributes (708).

[0079] In some embodiments, the geological model and reservoir models (712) may be input to a reservoir simulator (716). A reservoir simulator (716) comprises functionality for simulating the flow of fluids, including the formation fluid (102), through the reservoir (101) composed of porous, permeable reservoir formation (110) in response to natural and anthropogenic pressure gradients. The reservoir simulator (716) may be used to predict changes in fluid flow, including fluid flow into a well penetrating the reservoir (101) as a result of planned well drilling, fluid injection and extraction, and stimulation of the reservoir (101). For example, the reservoir simulator (716) may be used to predict fluid flow and production scenarios (717) including changes in hydrocarbon production rate that would result from the injection of water into the reservoir (101) from wells around the reservoirs periphery.

[0080] In some embodiments, the geological and reservoir models (712) include the predicted fluid properties (711), geological, and petrophysical properties that contains a digital description of the physical properties of the rocks (e.g., porosity, density, permeability, facies, lithologies, and the like). The reservoir simulator (716) may use the geological models and reservoir models (712) as a function of position within the reservoir (101) and the formation fluid (102) within the pores of the porous, permeable reservoir rocks at a given time. In some embodiments, the digital description may be in the form of a dense 3D model grid with the physical properties of the rocks and fluids defined at each node. In some embodiments, the 3D model grid may be a cartesian grid, while in other embodiments the model grid may be an irregular grid.

[0081] Reservoir simulators (716) 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 fluid with a constant viscosity and compressibility the equations capture Darcy's law, the continuity condition, and the equation of state.

[0082] Additional, and more complicated equations are required when more than one fluid, or more than one phase, e.g., liquid and gas, are present in the reservoir (101). Further, when the physical and petrophysical properties of the rocks and fluids vary as a function of position the governing equations may not be solved analytically and must instead be discretized into a grid of cells or blocks. The governing equations must then be solved by one of a variety of numerical methods, such as, without limitation, explicit or implicit finite-difference methods, explicit or implicit finite element methods, or discrete Galerkin methods.

[0083] The geological models may be based on the subsurface data (703) and may include identifying the reservoir formation (110), the source formation (108), the cap rock (112), seal, trap among other features (e.g., fluid properties, reservoir formation properties, and source formation properties). For example, data sets from acquiring remote sensing geophysical surveys, such as seismic surveys, gravity surveys, and active and passive source resistivity surveys, may be employed. In addition, data collected from the well logs (145) acquired in the well (118) penetrating the reservoir (101) may be used to determine physical and petrophysical properties along the segment of the well trajectory traversing the reservoir formation (110) and / or the source formation (108). For example, porosity, permeability, density, sonic velocity, and resistivity may be measured along these segments of the borehole (204). In accordance with some embodiments, remote sensing geophysical surveys and physical and petrophysical properties determined from the well logs (145) may be combined to estimate physical and petrophysical properties for the entire geological and reservoir simulation model grid.

[0084] In some embodiments, the fluid property analysis system (150) may be used to determine a reservoir fluid window (719) based on the predicted fluid properties (711) (e.g., the first predicted fluid property (714) and / or the second predicted fluid property (715)). The reservoir fluid window (719) may include one or more fluid windows such as the gas window (106) and / or the oil window (104). The oil window (104) may include a black oil window, a light oil window, a condensate window or combination thereof. The reservoir fluid window (719) identifies the potential fluid to be encountered by the borehole (204) and or induced fractures from borchole stimulation.

[0085] In some embodiments, the geological and reservoir models (712) may be used to create a subsurface development plan (721) using a subsurface development planning system (720) configured to determine the subsurface development plan (721) based on the one or more predicted fluid properties (711). The subsurface development plan (721) may include potential hydrocarbon production rates based on a number of production and injection wells, the placement of the production and injection wells in relation to the reservoir formation (110) (e.g., the drilling targets) and the geological and reservoir models characterization of the subsurface (132). The subsurface development plan (721) may include the borehole drilling plan (731) and a stimulation plan (751) for the well (118). The subsurface planning system may include a well planning system (730) configured to design the borehole drilling plan (731) based on the one or more predicted fluid properties (711) (e.g., the second predicted fluid property (715) at the fourth location (254). In some embodiments, the subsurface development planning system (720) may include a stimulation planning system (750) configured to design a stimulation plan (751) based on the one or more predicted fluid properties (711) (e.g., the first predicted fluid property (714) at the third one (253) of the plurality of depths (250)) to stimulate the reservoir formation (110) in order to potentially increase hydrocarbon production rates (e.g., production rates at the third one (253) of the plurality of depths (250).

[0086] In some embodiments, the borehole drilling plan (731) may be used for drilling a borehole (204) using the drilling system (238). The borehole drilling plan (731) may be based on the one or more predicted fluid properties (711) and / or the reservoir fluid window (719) as well as the geological and reservoir models (712). The well planning system (730) is configured to design the borehole drilling plan (731) to penetrate any drilling targets while simultaneously avoiding drilling hazard, such as preexisting boreholes, shallow gas pockets, and fault zones, and not exceeding the constraints, such as torque, drag and borehole curvature, of the drilling system (238) as described in relation to FIG. 2 and accompanying description. The drilling system (238) is configured to drill the borehole (204) based on the borehole drilling plan (731). Similarly, the borehole drilling plan (731) may include a determination of borehole caliper, and casing points.

[0087] The well planning system (730) may include a computer system that is the same or similar to the computer system (800) as described in relation to FIG. 8. The well planning system (730) may include dedicated well planning software stored on a memory of the computer system (800). The borehole drilling plan (731) may be informed by the best available information at the time of planning. This may include geohazard models encapsulating subterranean stress conditions, pore pressure models, the trajectory of any existing boreholes (which may be desirable to avoid), and the existence of other drilling hazards, such as shallow gas pockets, over-pressure zones, and active fault planes.

[0088] In some embodiments, the stimulation plan (751) may be used for stimulating a well as described in relation to FIG. 9. The stimulation plan (751) may be based on the one or more predicted fluid properties (711) and / or the reservoir fluid window (719) as well as the geological and reservoir models (712). The stimulation planning system is configured to design the stimulation plan (751) to stimulate the reservoir formation (110) to potentially induce fractures to increase permeability and hydrocarbon flow to the borehole (204). The stimulation plan (751) may include a stimulating section defined along the depth interval (231) of the borehole (204) expected to contain hydrocarbons.

[0089] The stimulation planning system (750) may include a computer system that is the same or similar to the computer system (800) as described in relation to FIG. 8. The stimulation planning system (750) may include dedicated stimulation planning software stored on a memory of the computer system (800). The stimulation plan (751) may be informed by the best subsurface data such as the geological and reservoir models (712) at the time of planning. This may include subterranean stress models used to predict potential fracture orientations and induced permeability. This also may include proppant requirements for propping the induced fractures open for needed production time frames.

[0090] The fluid flow and production scenarios (717) produced by the reservoir simulator (716) may be used by the well planning system (730) to determine the borehole drilling plan (731) and / or the stimulation plan (751). The borehole drilling plan (731) may target optimal drilling targets within the reservoir formation (110) for high fluid flow production rates. The stimulation plan (751) may be designed to obtain optimal fluid flow from the reservoir formation (110).

[0091] While the borehole drilling plan (731) and the stimulation plan (751) is formed using the best available information at the time at which it is formed, additional information may become available when drilling the borehole (204) specified by the borehole drilling plan (731). For example, the well logs (145) may provide new information about the reservoir structure and characteristic which may be acquired while drilling such as the LWD well logs or during drilling pauses in, or at the completion of drilling of, the borehole (204) specified by the borehole drilling plan (731). The well logs (145) acquired during pauses or at the cessation of drilling may be acquired using wireline or coiled tubing conveyed well logging tools. However, acquired, these new wells may be used to update the predicted fluids properties and the geological and reservoir models (712) with the aid of the fluid property analysis system (150).

[0092] FIG. 8 depicts a block diagram of a computer system (800) having a computer (802) used to provide computational functionalities associated with described algorithms, methods, functions, processes, flows, and procedures as described in this disclosure, according to one or more embodiments. 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. Additionally, 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 GUI.

[0093] 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). In some implementations, one or more components of the computer (802) may be configured to operate within environments, including cloud-computing-based, local, global, or other environment (or a combination of environments).

[0094] At a high level, the computer (802) is an electronic computing device operable to receive, transmit, process, store, or manage data and information associated with the described subject matter. According to some implementations, 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).

[0095] 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. 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.

[0096] Each of the components of the computer (802) can communicate using a system bus (803). In some implementations, 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 (812) or a service layer (813) (or a combination of the application programming interface (812) and service layer (813). The application programming interface (812) may include specifications for routines, data structures, and object classes. The application programming interface (812) may be either computer-language independent or dependent and refer to a complete interface, a single function, or even a set of application programming interfaces. The service layer (813) provides software services to the computer (802) or other components (whether or not illustrated) 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. For example, 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. While illustrated as an integrated component of the computer (802), alternative implementations may illustrate the application programming interface (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). Moreover, any or all parts of the application programming interface (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.

[0097] 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). Generally, 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).

[0098] The computer (802) 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 machine learning networks, algorithms, methods, functions, processes, flows, and procedures as described in the instant disclosure.

[0099] The computer (802) also 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). For example, 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).

[0100] 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. For example, application (807) can serve as one or more components, modules, applications, etc. Further, although illustrated as a single application (807), the application (807) may be implemented as multiple applications (807) on the computer (802). In addition, although illustrated as integral to the computer (802), in alternative implementations, the application (807) can be external to the computer (802).

[0101] There may be any number of computers (802) associated with, or external to, a computer system containing a computer (802), wherein cach computer (802) communicates over network (830). Further, the term “client,”“user,” and other appropriate terminology may be used interchangeably as appropriate without departing from the scope of this disclosure. Moreover, this disclosure contemplates that many users may use one computer (802), or that one user may use multiple computers (802).

[0102] FIG. 9 shows the hydraulic fracturing system (900) undergoing a stimulation operation according to the stimulation plan (751) design by the stimulation planning system (750) in accordance with one or more embodiments. The particular stimulation operation and hydraulic fracturing system (900) shown is for illustration purposes only. The scope of this disclosure is intended to encompass any type of hydraulic fracturing system (900) and stimulation operation. In general, a stimulation operation includes two separate operations: a perforation operation and a pumping operation. As such, FIG. 9 shows a stimulation operation occurring on a first well (902) and a second well (904). The first well (902) is undergoing the perforation operation and the second well (904) is undergoing the pumping operation.

[0103] The first well (902) and the second well (904) are horizontal wells meaning that each well includes a vertical section and a lateral section. The lateral section is a section of the well that is drilled at least eighty degrees from vertical. The first well (902) is capped by a first frac tree (906) and the second well (904) is capped by a second frac tree (908). A frac trec (906, 908) is similar to a Christmas / production tree but is specifically installed for the stimulation operation. Frac trees (906, 908) tend to have larger bores and higher-pressure ratings than a Christmas / production tree would have. Further, stimulation operations require abrasive materials being pumped into the well at high pressures, so the frac tree (906, 908) is designed to handle a higher rate of erosion.

[0104] In accordance with one or more embodiments, the perforating operation includes installing a wireline blow out preventor (BOP) (910) onto the first frac tree (906). A wireline BOP (910) is similar to a drilling BOP; however, a wireline BOP (910) has seals designed to close around (or shear) wireline (912) rather than drill pipe. The wireline (912) is maneuvered by a wireline truck (922) and a wireline spool (920). A lubricator (914) is connected to the opposite end of the wireline BOP (910). A lubricator (914) is a long, high-pressure pipe used to equalize downhole pressure and atmosphere pressure in order to run downhole tools, such as a perforating gun (916), into the well.

[0105] When the perforating gun (916) reaches a predetermined depth, a message is sent along the wireline (912) to set the frac plug (918). After the frac plug (918) is set, another message is sent through the wireline (912) to detonate the explosives, as shown in FIG. 9. The explosives create perforations in casing (926) and in the surrounding formation. There may be more than one set of explosives on a singular perforating gun (916), cach detonated by a distinct message. Multiple sets of explosives are used to perforate different depths along the casing (926) for a singular stage. Further, the frac plug (918) may be set separately from the perforation operation without departing from the scope of the disclosure herein.

[0106] As explained above, FIG. 9 shows the second well (904) undergoing the pumping operation after the fourth stage perforating operation has already been performed and perforations are left behind in the casing (926) and the surrounding formation. A pumping operation includes pumping a frac fluid (928) into the perforations in order to propagate the perforations and create fractures (942) in the surrounding formation. The frac fluid (928) often comprises a certain percentage of water, proppant, and chemicals.

[0107] FIG. 9 also shows chemical storage containers (930), water storage containers (932), and proppant storage containers (934) located on the hydraulic fracturing system (900). Frac lines (936) and transport belts (not pictured) transport the chemicals, proppant, and water from the storage containers (930, 932, 934) into a frac blender (938). The frac blender (938) blends the water, chemicals, and proppant to become the frac fluid (928). The frac fluid (928) is transported to one or more frac pumps, often pump trucks (940), to be pumped through the second frac tree (908) into the second well (904). The frac fluid (928) is transported from the pump truck (940) to the second frac tree (908) using a plurality of frac lines (936). The fluid pressure propagates and creates the fractures (942) while the proppant props open the fractures (942) once the pressure is released.

[0108] FIG. 10 depicts a fluid properties estimation flowchart in accordance with one or more embodiments describing a method for estimation of formation fluid properties (hereafter “estimation method” (1000)). In accordance with one or more embodiments, the estimation method may use the estimation system (100). Although the steps in the flowchart using the estimation method are shown in sequential order, it will be apparent to one of ordinary skill in the art that some steps may be conducted in parallel, in a different order than shown, or may be omitted without departing form the scope of the invention.

[0109] In Block (1001), the estimation method (1000) includes obtaining, using the logging system (140), the well log (145) of the well (118) in accordance with one or more embodiments. The well log (145) comprises well log data (704) at each of the plurality of depths (250) within the well (118). In some embodiments, obtaining the well log (145) may include obtaining the sonic well log, and / or the density well log. The well log data (704) includes, but is not limited to, sonic well log data (705), and / or density well log data (706).

[0110] In Block (1002), the estimation method (1000) includes obtaining, using the fluid retrieval system (142), the first fluid sample (148) at the first one (251) of the plurality of depths (250) within the well (118) in accordance with one or more embodiments. In box (1003), the estimation method (1000) includes obtaining, using the fluid retrieval system (142), the second fluid sample (149) at the second one (252) of the plurality of depths (250) within the well in accordance with one or more embodiments.

[0111] In Block (1004), the first fluid property (748) is determined from the first fluid sample (148) in accordance with one or more embodiments. The fluid property analysis system (150) is configured to determine the first fluid property (748) from the first fluid sample (148). The first fluid sample (148) may include a first API gravity, a first fluid viscosity, or a first fluid GOR at the first one (251) of the plurality of depths (250).

[0112] In Block (1005), the estimation method (1000) includes determining the second fluid property (749) from the second fluid sample (149) in accordance with one or more embodiments. The fluid property analysis system (150) is configured to determine the second fluid property (749) from the second fluid sample (149). The second fluid sample (149) may include a second API gravity, a second fluid viscosity, or a second fluid GOR at the second one (252) one of the plurality of depths (250).

[0113] In Block (1006), the estimation method (1000) includes determining the transform (510) based on the first fluid property (748), the second fluid property (749), and the well log data (704) at both the first one (251) of the plurality of depths (250) and the second one (252) of the plurality of depths (250) in accordance with one or more embodiments. In some embodiments, determining the transform (510) comprises cross-correlating the first fluid property (748) and the second fluid property (749) with the well log data (704) at both the first one (251) of the plurality of depths (250) and the second one (252) of the plurality of depths (250) yielding the fluid data cross-correlation (515).

[0114] In Block (1007), the transform (510) is applied to the well log data (704) at the third one (253) of the plurality of depths (250) within the well (118) yielding the first predicted fluid property (714) in accordance with one or more embodiments. The first predicted fluid property (714) may include a first predicted API gravity, a first predicted fluid viscosity, and a first predicted fluid GOR at the third one (253) of the plurality of depths (250) within the well (118). Applying the transform (510) may include inputting the well log data (704) into the transform (510) and outputting the predicted fluid properties (711) using the fluid property analysis system (150).

[0115] In Block (1008), the estimation method (1000) includes determining, using the subsurface development planning system (720), the subsurface development plan (721) based on the first predicted fluid property (714) in accordance with one or more embodiments. Determining the subsurface development plan (721) may include planning well locations for wells to be drilled to penetrate the reservoir formation (110) and / or the source formation (108). Determining the subsurface development plan (721) may include planning well sections for stimulation to potentially enhance hydrocarbon recovery.

[0116] In Block (1009), determining the subsurface development plan (721) may include designing, using the stimulation planning system (750), the stimulation plan (751) based on the first predicted fluid property (714) in accordance with one or more embodiments. Designing the stimulation plan (751) may include planning a perforation operation and a pumping operation.

[0117] In Block (1010), determining the subsurface development plan (721) may include stimulating, using the hydraulic fracturing system (900), the formation (232) around the well (118) based on the stimulation plan (751) in accordance with one or more embodiments. Stimulating the formation (232) may include perforating the casing (926) and pumping frac fluid (928) and proppant into the formation (232).

[0118] In some embodiments, the estimation method (1000) may include fitting a polynomial to the fluid data cross-correlation (515). Fitting the polynomial may include using polynomial interpolation, polynomial regression optimized with a least-squares method, and the like. In some embodiments, applying the transform (510) may include applying a non-linear transform based on fitting the polynomial.

[0119] In some embodiments, the estimation method (1000) may include obtaining, using the seismic data acquisition system (600), seismic data (648) from the geographical region (615) that includes the well (118). In some embodiments, the estimation method (1000) may include determining, using the subsurface processing system (650), the velocity model (707) based on the seismic data (648) at a fourth location (254), wherein the fourth location (254) is the distance (255) from the well (118) within the formation (232).

[0120] In some embodiments, the estimation method (1000) may include applying the transform (510) to the velocity model (707) yielding the one or more predicted fluid properties (711) (e.g., the second predicted fluid property (715)). The fluid property analysis system (150) may be configured to apply the transform (510) to the velocity model (707) yielding the one or more predicted fluid properties (711) at the one or more location within the subsurface (132) (e.g., the fourth location (254)). The one or more locations (e.g., the fourth location (254)) may be located the distance (255) away from the well (118) within the formation (232).

[0121] In some embodiments, the estimation method (1000) may include determining, using the fluid property analysis system (150), the reservoir fluid window (719) based on the one or more predicted fluid properties (711). The reservoir fluid window (719) may include the oil window (104) and the gas window (106).

[0122] In some embodiments, the estimation method (1000) may include designing, using the well planning system (730), the borehole drilling plan (731) based on the second predicted fluid property (715). In some embodiments, the borehole drilling plan (731) may be based on the reservoir fluid window (719). In some embodiments, the estimation method (1000) may include drilling, using the drilling system (238), the borehole (204) based on the borehole drilling plan (731).

[0123] Embodiments of the present disclosure may provide at least one of the following advantages. The present disclosure provides methods and systems for improving estimation of fluid properties with minimal sampling or lab testing of formations (232) at the distance (255) from the well (118). The estimation method (1000) predicts expected well behavior and formation fluid properties using raw well log data (704). The estimation method (1000) improves the ability to predict formation fluid properties in new exploration areas using the well logs (145) without the need for drilling and production prior to planning the borehole drilling plan (731) and / or stimulation plan (751). The decrease in lab testing and improved planning thereby provides potential improvement in recovery of hydrocarbons with reduction in costs, emissions, and waste.

[0124] Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.

Examples

Embodiment Construction

[0017]In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

[0018]Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for 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. By way of an example, a first element is distinct from...

BACKGROUND

[0001] Production rates of hydrocarbons from reservoir rock are based on the amounts of hydrocarbons generated from source rock and the reservoir characteristics. Production of hydrocarbons is carried out by drilling wells into reservoir rock storing the hydrocarbons. Reservoir rocks at times have poor permeability which may cause difficulties producing hydrocarbons from poor permeability rocks. Development plans are used to map out development projects to produce hydrocarbons from the reservoir.SUMMARY

[0002] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

[0003] In some aspects, the techniques described herein relate to a method for predicting a fluid property. The method may include obtaining, using a logging system, a well log of a well. The well log includes well log data at each of a plurality of depths within the well. The method may include obtaining, using a fluid retrieval system, a first fluid sample at a first one of the plurality of depths within the well. The method may include obtaining, using the fluid retrieval system, a second fluid sample at a second one of the plurality of depths within the well. The method may include determining a first fluid property from the first fluid sample. The method may include determining a second fluid property from the second fluid sample. The method may include determining a transform based on the first fluid property, the second fluid property, and the well log data at both the first one of the plurality of depths and the second one of the plurality of depths. The method may include applying the transform to the well log data at a third one of the plurality of depths within the well yielding a first predicted fluid property. The method may include determining a subsurface development plan based on the first predicted fluid property.

[0004] In some aspects, the techniques described herein relate to a system for estimating a fluid property. The system may include a logging system including a logging tool, a fluid retrieval system, a fluid property analysis system, and a subsurface development planning system. The logging tool is configured to obtain a well log of a well. The well log includes well log data at each of a plurality of depths within the well. The fluid retrieval system is configured to obtain a first fluid sample at a first one of the plurality of depths and a second fluid sample at a second one of the plurality of depths. The fluid property analysis system is configured to determine a first fluid property from the first fluid sample. The fluid property analysis system is configured to determine a second fluid property from the second fluid sample. The fluid property analysis system is configured to determine a transform based on the first fluid property, the second fluid property, and the well log data at both the first one of the plurality of depths and the second one of the plurality of depths. The fluid property analysis system is configured to apply the transform to the well log data at a third one of the plurality of depths within the well yielding a first predicted fluid property. The subsurface development planning system is configured to determine a subsurface development plan based on the first predicted fluid property.

[0005] Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.BRIEF DESCRIPTION OF DRAWINGS

[0006] Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency.

[0007] FIG. 1 depicts a fluid acquisition and analysis system in accordance with one or more embodiments.

[0008] FIG. 2 depicts a fluid acquisition and analysis system in accordance with one or more embodiments.

[0009] FIG. 3 depicts a logging tool in accordance with one or more embodiments.

[0010] FIG. 4 depicts a sonic well log in accordance with one or more embodiments.

[0011] FIG. 5 depicts a transform in accordance with one or more embodiments.

[0012] FIG. 6 depicts a seismic data acquisition system in accordance with one or more embodiments.

[0013] FIG. 7A-7B depicts a fluid properties estimation workflow in accordance with one or more embodiments.

[0014] FIG. 8 depicts a computer system in accordance with one or more embodiments.

[0015] FIG. 9 depicts a hydraulic fracturing system in accordance with one or more embodiments.

[0016] FIG. 10 depicts a fluid properties estimation flowchart in accordance with one or more embodiments.DETAILED DESCRIPTION

[0017] In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

[0018] Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for 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. By way of an example, 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.

[0019] It is to be understood that the singular forms “a,”“an,” and “the” include plural referents unless the context clearly dictates otherwise.

[0020] Terms such as “approximately,”“substantially,” etc., mean that the recited characteristic, parameter, or value need not be achieved exactly, but that deviations or variations, including for example, tolerances, measurement error, measurement accuracy limitations and other factors known to those of skill in the art, may occur in amounts that do not preclude the effect the characteristic was intended to provide.

[0021] It is to be understood that one or more of the steps shown in the flowchart may be omitted, repeated, and / or performed in a different order than the order shown. Accordingly, the scope disclosed herein should not be considered limited to the specific arrangement of steps shown in the flowchart.

[0022] Although multiple dependent claims are not introduced, it would be apparent to one of ordinary skill that the subject matter of the dependent claims of one or more embodiments may be combined with other dependent claims.

[0023] In the following description of FIGS. 1-10, 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. For brevity, descriptions of these components will not be repeated with regard to each figure. Thus, 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. Additionally, in accordance with various embodiments disclosed herein, 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.

[0024] Methods and systems for estimating formation fluid properties are disclosed herein. The method may include obtaining, using a logging system, a well log of a well. The well log may include well log data at each of a plurality of depths within the well. The method includes obtaining, using a fluid retrieval system, fluid samples at multiple depths within the well. The method includes determining one or more fluid properties from the fluid samples. The method includes determining a transform based on the one or more fluid properties and the well log data. The method includes applying the transform to the well log data at another depth within the well yielding a predicted fluid property.

[0025] FIG. 1 shows a system for the estimation of formation fluid properties (hereafter “estimation system” (100)) in accordance with one or more embodiments. The estimation system (100) may include a well (118) and a reservoir (101) having one or more formation fluids (102) (e.g., water, oil, and / or gas). Reservoirs (101), such as the one depicted in FIG. 1, have a source formation (108), a reservoir formation (110), and a cap rock (112). A source formation (108) is a formation rich in organic matter that, over time, is heated sufficiently to form hydrocarbon fluids such as gas and oil. Oil and gas then migrate from the source formation (108) to a more porous and permeable rock called the reservoir formation (110). Due to the inherent nature of these subsurface fluids, gas settles above oil and oil settles above water in the reservoir (101). Therefore, there are various “contacts” within the reservoir (101) that distinguish locations of different subsurface fluids.

[0026] The gas oil contact (“GOC”) (114) is the location or “surface”, in the reservoir (101), above which predominantly gas (e.g., a gas window (106)) occurs and below which predominately oil occurs (e.g., an oil window (104)). The gas that accumulates above the GOC (114) may be called a gas cap or a gas cap reservoir. The oil water contact (“OWC”) (116) is the location or “surface”, in the reservoir (101), above which predominantly oil occurs (e.g., an oil window (104)) and below which predominately water occurs. Wells (118) may be drilled below a surface (122) (e.g., surface of the earth) at a surface location and into a subsurface (132) having a plurality of depths. The subsurface (132) includes the reservoir (101).

[0027] Wells (118) may be drilled into the subsurface (132) at one or more surface locations and along a plurality of depths. In some embodiments, the well (118) may penetrate the reservoir (101) to gather data, produce hydrocarbon fluids, and / or treat the reservoir formation (110). Each well (118) may be an exploration well, a production well, or an injection well. Portions of the well (118) may include vertical and / or deviated well paths that continually deviate from vertical until a borehole is substantially horizontal. Production and injection wells, drilled into similar reservoirs (101), typically target the oil window (104) as the primary hydrocarbon fluid being produced and may inject water to balance reservoir pressure as reservoir pressure declines as oil is produced. Injection wells are wells (118) that may also inject chemicals into the reservoir formation (110) to treat the reservoir formation (110) and help produce oil. The production wells are wells (118) that may produce water and gas as secondary fluids. Wells and reservoirs may be configured in a myriad of ways, therefore the wells (118) and the reservoir (101) illustrated in FIG. 1 are not intended to be limiting with respect to the particular configuration of the wells and formations. Even though FIG. 1 illustrates a separate source formation and a reservoir formation, it is apparent to a person having ordinary skill in the art that the source formation and the reservoir formation may be the same formation such as in “unconventional” reservoirs.

[0028] The estimation system (100) may include a logging system (140) in accordance with one or more embodiments. The logging system (140) includes one or more logging tools configured to obtain a well log (145) of the well (118). In some embodiments, the logging system (140) may include cable systems to maneuver the logging tools and recording systems (e.g., analog and / or digital) to record well log data. The cable systems may include transmission cables to transmit well log data from the logging tools to the logging system (140). The well log data may be utilized to assess properties of the formation fluid (102).

[0029] In some embodiments, the estimation system (100) may include a fluid retrieval system (142). The fluid retrieval system (142) is configured to retrieve one or more fluid samples (147) (e.g., a first fluid sample (148) and / or a second fluid sample (149)) from the various formations (e.g., the source formation (108), the reservoir formation (110), and / or the cap rock (112)) at one or more depths from the surface (122). In some embodiments, the fluid retrieval system (142) may be configured to retrieve the fluid sample (147) at the wellhead (123).

[0030] In some embodiments, the estimation system (100) may include a fluid property analysis system (150). The fluid property analysis system (150) is configured to receive the fluid sample (147). The fluid property analysis system (150) is configured to analyze the fluid sample (147) and to determine fluid property data having one or more fluid properties. The one or more fluid properties may include an American Petroleum Institute (“API”) gravity, a fluid viscosity property, and / or a fluid GOR. For example, the fluid property analysis system (150) may include a hydrometer configured to determine the API gravity. Typical values for hydrocarbons may fall between 10 and 70 degrees. In some embodiments, the fluid property analysis system (150) may include a viscometer configured to determine a fluid viscosity of the fluid sample (147). In some embodiments, the one or more fluid properties may be acquired at the wellhead (123), for example, the fluid property analysis system (150) may include a flowmeter at the wellhead (123) to obtain the fluid GOR.

[0031] In some embodiments, the one or more fluid properties and / or well logs may be used to determine a borehole drilling plan (731 in FIG. 1, also shown in FIGS. 7A-7B). The borehole drilling plan (731) may include production targets within, for example, the reservoir formation (110). Portions of the borehole drilling plan (731) may include vertical and / or deviated well trajectories that continually deviate from vertical until the borchole drilling plan (731) is substantially horizontal. For the context of this disclosure, “vertical” and “horizontal” are in reference to the surface (122) at the surface location of the borehole. Also, terms such as “substantially horizontal” and “substantially vertical” may include portions of the borehole drilling plan (731) and / or the well (118) that may deviate from horizontal and / or vertical in relation to the surface (122) within a geographical region around the well (118).

[0032] FIG. 2 illustrates a well site (200) in accordance with one or more embodiments. Well sites may be configured in a myriad of ways; therefore, the well site (200) is not intended to be limiting with respect to the particular configuration of the drilling equipment, hydraulic fracturing equipment and / or well operations equipment. The well site (200) is depicted as being on land. In other examples, the well site (200) may be offshore, and drilling may be carried out with or without use of a marine riser. The well site (200) may include a drilling system (238), a hydraulic fracturing system (900) as described in relation to FIG. 9, and / or a well operations system. The drilling system (238) may be configured to drill the well (118) having a borehole (204) with a borehole fluid (206) from the surface (122) into the subsurface (132). The well (118) includes a plurality of depths (250) within the well (118) from the surface (122) to the end of the well (118). In some embodiments, the plurality of depths (250) may be a measured depth as described in relation to FIG. 2. The subsurface (132) may include one or more formations (232). Each formation (232) may include layers of rock having primary porosity (e.g., pore space) and / or secondary porosity (e.g., faults and / or dissolution spaces). For the purpose of drilling a new section of borehole (204), a drill string (220) is suspended within the borehole (204). The drill string (220) may include one or more drill pipes connected to form a conduit and a bottom hole assembly (a BHA (228)) disposed at the distal end of the conduit. The BHA (228) may include a drill bit (230) to cut into the subsurface rock. The BHA (228) may include one or more logging tools (240), such as a measurement-while-drilling (MWD) tool or a logging-while-drilling (LWD) tool, as well as other drilling tools that are not specifically shown but would be understood to a person of ordinary skill in the art. In some embodiments, the well site (200) may include the logging system (140) configured to obtain well log data.

[0033] The drill string (220) may be suspended in the borehole (204) by a derrick (e.g., a derrick structure (202)). A crown block (212) may be mounted at the top of the derrick structure (202). A traveling block (214) may hang down from the crown block (212) by means of a cable or drill line (e.g., drill line (208)). One end of the drill line (208) may be connected to a drawworks, which is a reeling device that can be used to adjust the length of the drill line (208) so that the traveling block (214) may move up or down the derrick structure (202). The top drive (218) is coupled to the top of the drill string (220) and is operable to rotate the drill string (220). Alternatively, the drill string (220) may be rotated by means of a rotary table (not shown) on the surface (122). The drill string (220) is used with a BOP (e.g., blowout preventer (236)). The BOP may be used to seal the well (118). Drilling fluid (commonly called mud) (not shown) may be pumped from a mud system (234) into the drill string (220). The mud may flow into the drill string (220) through appropriate flow paths in the top drive (218), or through a rotary swivel if a rotary table is used (not shown). Details of the mud flow path have been omitted for simplicity, but would be readily understood by a person of ordinary skill in the art.

[0034] During a well drilling operation at the well site (200), the drill string (220) is rotated relative to the borchole (204) and weight is applied to the drill bit (230) to enable the drill bit (230) to break rock as the drill string (220) is rotated. In some cases, the drill bit (230) may be rotated independently with a drilling motor (not shown). In other embodiments, the drill bit (230) may be rotated using a combination of a drilling motor (not shown) and the top drive (218) (or a rotary table if used instead of a top drive) to rotate the drill string (220). While cutting rock with the drill bit (230), mud is pumped into the drill string (220). The mud flows down the drill string (220) and exits into the bottom of the borehole (204) through nozzles in the drill bit (230). The mud in the borchole (204) then flows back up to the surface (122) in an annular space between the drill string (220) and the borchole (204) carrying entrained cuttings to the surface (122). The cuttings are removed, and the fluid is returned to the mud system (234) to be recycled and circulated back again into the drill string (220).

[0035] Drilling operations are completed upon the retrieval of the drill string (220), the BHA (228), and the drill bit (230) from the borchole (204). In some embodiments of borchole (204) construction, the production casing operations may commence. Production casing operations includes installing casing in the borehole (204). A casing string (224), which is made up of one or more larger diameter tubulars that have a larger inner diameter than the drill string (220) but a smaller outer diameter than the borehole (204), is lowered into the borchole (204) on the drill string (220). Generally, the casing string (224) is designed to isolate the internal diameter of the borchole (204) from the formation (232). Once the casing string (224) is in position, it is set and cement is pumped down through the internal space of the casing string (224), out of the bottom of the casing shoe (226), and into the annular space between the borehole (204) and the outer diameter of the casing string (224). This secures the casing string (224) in place and creates the desired isolation between the borchole (204) and the formation (232). At this point, drilling of the next section of the borchole (204) or completion and stimulation operations around the borehole (204) may commence such as the stimulation operations described in relation to FIG. 9.

[0036] The estimation system (100) includes one or more fluid property acquisition systems (701) and techniques (e.g., a logging system, a fluid retrieval system, and / or a seismic data acquisition system) are available for determining various reservoir characteristics at one or more locations within the subsurface (132) (e.g., a fourth location (254)). The one or more locations may be within the well (118) or a distance (255) away from the well (118).

[0037] The logging system (140) includes the one or more logging tools (240), such as a sonic logging tool (245) and / or a density logging tool (not shown), for use in generating the well logs (145) of the subsurface (132). The one or more well logs (145) (e.g., a sonic well log and / or a density well log) include well log data. In some embodiments, the well log data may be acquired at each of the plurality of depths (250) within the well. In some embodiments, the well log data may be acquired at the plurality of depths within a depth interval (231). The one or more logging tools (240) may be incorporated into the MWD tool or the LWD tool as described above or may be maneuvered via a wireline using a spooling device configured to adjust the length of wireline. For example, the logging tool (240) may be lowered into the borehole (204) to acquire well log data at the plurality of depths (250) within the well (118) as the tool traverses the depth interval (231) (for example, targeted reservoir section) of the borehole (204). One or more source activation locations (217) (also known as firing / excitation location) are locations at which a logging tool source generates a tool signal as the logging tool is maneuvered either by the drill string (220) or the wireline. The plot of the well log data versus depth may be referred to as a “log” or “well log”. Well logs (145) may provide depth measurements of the well (118) that describe such reservoir characteristics as formation porosity, formation transit time, formation permeability, resistivity, water saturation, and the like. The resulting well log data may be stored as “raw” well logs or processed or both, for example, by the fluid property analysis system (150), to generate corresponding well logs (145) for the well (118). A sonic well log may include, for example, recorded sonic waveforms versus true vertical depth (TVD) across the depth interval (231) or each of the plurality of depths (250) of the borchole (204).

[0038] Multiple types of logging techniques are available for determining various reservoir characteristics at one or more locations within the subsurface (132) (e.g., a fourth location (254)). A particular form of logging may be selected and used based on the logging conditions and the type of desired measurements. For example, sonic logging measures an interval transit time of the formation (232). Thus, sonic logs may measure one or more velocities of sonic compressional and / or shear waves through the formation (232). In so doing, sonic logs may be used alone, or in combination with other logs, to determine both porosity and permeability as well as the types of fluids present in the pore spaces. For determining density, a type of density well log that may be used is called bulk density (“RHOB”) logging. RHOB logging may determine the densities of rocks in the formation (232) by measuring the amount of gamma rays that are scattered back to a gamma ray detector disposed in the density logging tool. The RHOB logging tool source emits gamma rays. The emitted gamma rays interact with the electrons within the formation (232). The interaction of the emitted gamma rays with the electrons of the formation (232) scatters the gamma rays. The amount of scattered gamma rays that reach the detector is related to the formation's electron density, which in turn is related to the formation's bulk density. The bulk density is the average density of rocks of different lithologies (e.g., sand, shale, and / or carbonate lithologies) and formation fluids (102). Shales tend to have a higher bulk density than sandstones, therefore, bulk density well logs may be used to identify sand and shale lithologies.

[0039] To determine travel times in the formation (232), various types of logging techniques may be used. For example, the logging system (140) may measure the speed that acoustic waves travel through rocks in the formation (232). This type of logging may generate compressional and / or shear wave sonic logs, which are also called sonic logs and acoustic logs. In general, sound waves may travel faster through shales than through sandstones because shales generally have greater density than sandstones. Likewise, density logging may also determine density measurements by directly measuring the density of the rocks in the formation (232). In addition, neutron logging may determine porosity measurements by assuming that the reservoir pore spaces within the formation (232) are filled with either water or oil and then measuring the amount of hydrogen atoms (that is, neutrons) in the pores. Furthermore, the logging system (140) may determine geological data for the formation (232) by measuring corresponding well logs (145) for the borehole (204).

[0040] The fluid retrieval system (142) may include a fluid retrieval apparatus (242). The fluid retrieval apparatus (242) may be any fluid retrieval apparatus configured to retrieve the fluid sample (147) from formations (232) (e.g., the source formation (108) and / or the reservoir formation (110)). The fluid sample (147) may be retrieved at one of the plurality of depths (250) (e.g., a first one (251), a second one (252), and / or a third one (253) of the plurality of depths (250)) within the well (118). The fluid retrieval apparatus (242) may also be configured to fluidly couple with the formation (232) so as to isolate any sample of the formation fluid (102) mixing with any extrinsic fluids (e.g., formation fluid from different formations, borehole fluid (206), drilling fluid and / or frac fluid) within the borehole (204). In some embodiments, the fluid retrieval apparatus (242) may be maneuvered via the wireline of the logging system (140). In some embodiments, the fluid retrieval apparatus (242) may be integrated into the BHA (228) and the fluid sample (147) may be retrieved while drilling or when the drilling is briefly paused (e.g., drill pipe connections and / or fluid sampling). It will be apparent to a person of ordinary skill in the art that the location of the samples may be obtained at any depth and the location of the various depths (e.g., the first one (251), the second one (252) and / or the third one (253) of the plurality of depths (250)) are for illustrative purposes and should not be considered limiting as to the scope of the invention.

[0041] While FIG. 1 and FIG. 2 show various configurations of components, other configurations may be used without departing from the scope of the disclosure. For example, various components in FIG. 1 and / or FIG. 2 may be combined to create a single component. As another example, the functionality performed by a single component may be performed by two or more components.

[0042] FIG. 3 shows a sonic logging tool (245) in accordance with one or more embodiments. This sonic logging tool design is one of many possible sonic logging tool designs and is not intended to be limiting on the scope of the invention. The sonic logging tool (245) includes a sonic source (315) and a plurality of sonic receivers (310). The sonic source (315) may be a dipole or a monopole but not limited to this. FIG. 3 shows both types of sonic sources though only one may be activated or disposed within the sonic logging tool on any given logging run. One of the plurality of sonic receivers (310) may be a dipole receiver. The sonic source (315) and the plurality of sonic receivers (310) are operatively disposed in the sonic logging tool (245), which may be a steel pipe. The plurality of sonic receivers (310) may be azimuthally distributed around a tool axis (305) of the sonic logging tool (245) and include one or more principal axes (311). Each of the principal axes may be aligned, for example, with one of the plurality of receivers and its principal recording orientation. In some embodiments, the principal axes (311) may be oriented relative to the tool axis (305) such as perpendicular relative to the tool axis (305). The plurality of sonic receivers (310) detects and record pressure fluctuations of the borehole fluid (206) filling the borchole (204) caused by incident sonic waves. Although eight sonic receivers are shown in FIG. 3, in some embodiments there may be a greater or lesser number of sonic receivers. The sonic logging tool (245) may include an isolation joint (307). The isolation joint (307) is disposed within the sonic logging tool (245) and positioned between the sonic source (315) and the plurality of sonic receivers (310). The isolation joint (307) mitigates noise cross-contamination of the sonic source (315) and the plurality of sonic receivers (310) along the sonic logging tool (245).

[0043] As the one or more logging tools (240) is lowered over the depth interval (231) for a logging run, the sonic source (315) may be activated at the one or more source activation locations (217) emitting a source signal into the borehole (204) and the formation (232) around the sonic source (315). Each sonic receiver (310) measures the source signal as the source signal radiates through the formation (232).

[0044] FIG. 4 illustrates a sonic velocity log (420) in accordance with one or more embodiments. The sonic logging tool (245) measures the sonic slowness of the formation (232), typically in microseconds per foot. The plot of the sonic logging measurements versus depth is the sonic well log (420). The sonic well log data may be processed by the fluid property analysis system (150) and displayed as sonic velocity. The sonic velocity is determined by the reciprocal of the sonic slowness multiplied by a constant to convert units. For example, feet per microseconds is converted to meters per second by multiplying the reciprocal of the sonic slowness by a constant of 304800 to yield the sonic well log in terms of velocity. The X axis (422) represents the sonic well data in terms of velocity. The Y axis (424) represents the sonic source location index. For example, a borehole, as in the borehole (204) in FIG. 2, the source location index may be a measured distance (e.g., “measured depth”) from the surface location along the borehole (204) to the position of the sonic source (315) within the borehole (204) rather than a true vertical depth.

[0045] FIG. 5 shows a transform (510) based on subsurface data (703) including well log data (704) from the well logs (145) and fluid property data (745). The fluid property data (745) includes the one or more fluid properties (e.g., a first fluid property (748) and / or a second fluid property (749)). The first fluid property (748) may be determined from the first fluid sample (148) using the fluid property analysis system (150). The second fluid property (749) may be determined from the second fluid sample (149) using the fluid property analysis system (150). The fluid property analysis system (150) is configured to determine the first fluid property (748) from the first fluid sample (148). The fluid property analysis system (150) is configured to determine the second fluid property (749) from the second fluid sample (149). The first fluid property (748) may be, for example, an API gravity, a fluid viscosity, or a fluid GOR. The second fluid property (749) would be the same type of property as the first fluid property (748). The fluid property analysis system (150) is configured to determine the transform (510) based on the first fluid property (748), the second fluid property (749), and the well log data (704) at both the first one (251) of the plurality of depths (250) and the second one (252) of the plurality of depths (250).

[0046] In some embodiments, the fluid property analysis system (150) may be configured to cross-correlate the first fluid property (748) and the second fluid property (749) with the well log data (704) at both the first one (251) of the plurality of depths (250) and the second one (252) of the plurality of depths (250) yielding a fluid data cross-correlation (515). For example, the first fluid property (748) is a first API gravity determined from the first fluid sample (148) obtained at the first one (251) of the plurality of depths (250). The second fluid property (749) is a second API gravity determined from the second fluid sample (149) obtained at the second one (252) of the plurality of depths (250). The first API gravity and the second API gravity are cross-correlated with the sonic well log data (705) obtained at both the first one (251) of the plurality of depths (250) and the second one (252) of the plurality of depths (250).

[0047] In some embodiments, the fluid property analysis system (150) may be configured to fit a polynomial to the fluid data cross-correlation (515) as shown in FIG. 5. In some embodiments, algorithms may be used such as polynomial regression, least squares, Bayesian methods, and the like.

[0048] In some embodiments, the transform (510) may be a non-linear transform. The non-linear transform may be based on fitting the polynomial to the fluid data cross-correlation (515). The transform (510) may take the form as follows:fp=c*1⁢0t*em*wl(1)where fp is the fluid property data (745), c is a first constant, t is a second constant, m is a third constant, and wl is the well log data (704).In some embodiments, the transform (510) may take the form as follows:fp=c*wl2+t*wl+m,(2)where fp is the fluid property data (745), c is the first constant, t is the second constant, m is the third constant, and wl is the well log data (704). For example, the transform (510) may be determined using the API gravity in units of degrees and the sonic well log data (705) in units of microsecond per foot (micro-s / ft) as shown in FIG. 5. An X-axis (501) represents sonic slowness.

[0051] In some embodiments, the transform (510) may be applied to the well log data (704) at the plurality of depths (250) within the well (118) to yield one or more predicted fluid properties (711) (e.g., a first predicted fluid property (714) and / or a second predicted fluid property (715)). The one or more predicted fluid properties (711) may include, but not limited to, a predicted API gravity, a predicted fluid viscosity, and / or a predicted fluid GOR. For example, the transform (510) may be applied to the well log data (704) at the third one (253) of the plurality of depths (250) within the well (118) yielding the predicted fluid property (711) such as the predicted API gravity. The predicted fluid property (711) will be the same type of fluid property data (745) used to determine the transform (510).

[0052] For example, a development plan may include seven (7) wells as shown in Table 1 below. Each of the seven wells may produce a production fluid with one or more fluid properties (e.g., API, GOR, and / or fluid viscosity (v)) and one or more well log data (e.g., sonic (DTC) and / or density (RHOB)) as shown in Table 1. Each fluid property may be cross-correlated with each well log data recorded at depth of the fluid sample. For example, the transform (510) may be determined using the fluid viscosity (v) in units of centipoise (cP) and the density well log data (RHOB) in units of grams per cubic centimeter (g / cc). The polynomial fit to the fluid viscosity and density data listed in Table 1 take the form in Eq. (1) where the first constant is 3, the second constant is 20, and the third constant is −19.89. The various constants are determined from fitting the polynomial to the fluid data cross-correlation (515) of fluid viscosity and density well log data. For another example, Y-axis (502) represents the API gravity. The transform (510) transforms sonic slowness data to API gravity. The polynomial fit to the fluid viscosity and density data listed in Table 1 take the form in Eq. (2) with the first constant is −0.0728, the second constant is 10.299, and the third constant is −319.31. The X axis (422) represents the sonic well log data (705) in terms of slowness as shown in FIG. 5. The various constants are determined from fitting the polynomial to the fluid data cross-correlation (515) of API gravity and the sonic well log data (705).TABLE 1Table of Fluid PropertiesGOR,WellAPI, degSCF / BBLν, cpDTCRHOBWell-135.56480.78282.042.39Well-239.99320.40779.512.39Well-333.34031.04282.762.37Well-444.859040.07068.962.50Well-542.522490.20074.732.46Well-635.66410.77282.172.40Well-74215270.36177.322.44

[0053] FIG. 6 shows a seismic survey of the subsurface (132) using a seismic data acquisition system (600) configured to obtain seismic data (648) from a geographical region (615) that includes the well (118) and the subsurface (132) having the formation (232). For example, the subsurface (132) contains a gas deposit (620) within the reservoir formation (110) that is being recovered by the wells (118). The gas deposit may be methane, ethane, or another hydrocarbon gas. The seismic data acquisition system (600) uses a seismic source (606) to generate radiated seismic waves (608). The radiated seismic waves (608) may return to the surface (122) as refracted seismic waves (610) or reflected seismic waves (614), where reflected seismic waves (614) occur due to subterranean boundaries (612) between rock within the formation (232). At the surface (122), refracted seismic waves (610) and reflected seismic waves (614) may be detected by seismic receivers (616).

[0054] The refracted seismic waves (610) and reflected seismic waves (614) generated by a single activation of the seismic source (606) is recorded by a seismic receiver (616) as a time-series representing the amplitude of ground-motion at a sequence of discrete times. This time-series may be denoted as a seismic “trace”. A seismic source (606) is positioned at a location denoted (x_s,y_s) where x and y represent orthogonal axes on the surface of the Earth above the subsurface (132). The seismic receivers (616) are positioned at a plurality of seismic receiver locations denoted (x_r,y_r). Thus, the refracted seismic waves (610) and reflected seismic waves (614) generated by a single activation of the seismic source (606) may be represented as five-dimensional seismic data by (x_s,y_s,x_r,y_r,t) where t delimits the time sample at which the amplitude of ground-motion was measured by a seismic receiver (616).

[0055] A subterranean boundary (612) is often called a “horizon” by a person of ordinary skill in the art, particularly when referring to the manifestation of the subterranean boundary (612) in a subsurface image. Use of the term horizon does not imply that the horizon is either flat or planar. Hereinafter, horizon is used to encompass both the subterranean boundary (612) in the subsurface (132) and the manifestation of the subterranean boundary (612) in the subsurface image. Hereinafter, the terms “horizon” and “subterranean boundary” may be used interchangeably.

[0056] FIGS. 7A-7B illustrates a fluid properties estimation workflow (700) in accordance with one or more embodiments. The fluid properties estimation workflow (700) includes steps of acquiring the subsurface data (703) (e.g., the fluid property data (745), the well log data (704), and / or the seismic data (648)), processing the subsurface data (703), forming one or more geologic models, optionally simulating the flow of fluids, including hydrocarbons, though the one or more geological models, drilling, and / or stimulating the reservoir section. Although the steps in the fluid properties estimation workflow (700) are shown in sequential order, it will be apparent to one of ordinary skill in the art that some steps may be conducted in parallel, in a different order than shown, or may be omitted without departing form the scope of the invention.

[0057] In accordance with one or more embodiments, the fluid properties estimation workflow (700) may begin with the use of fluid property acquisition systems (701) including the logging system (140) and the fluid retrieval system (142). The logging system (140) may be used to acquire the well log data (704) including the sonic well log data (705) and / or the density well log data (706), over the plurality of depths (250) within the well (118). Also, the fluid retrieval system (142) may be used to acquire the fluid sample (147) using the fluid retrieval apparatus (242). The fluid property acquisition systems may also include the seismic data acquisition system (600) configured to obtain a seismic data (648) from the geographical region (615) that includes the well (118). The seismic data (648), for example, may be used to characterize the formation (232) around the borehole (204). Other remote sensing data may also be collected at this stage to characterize the subsurface (132). For example, resistivity, transient electromagnetic, and / or gravitation surveys may be collected.

[0058] In some embodiments, the subsurface data (703) includes the well log data (704), the fluid property data (745), the seismic data (648), or a combination thereof. The well log data (704) may include the well logs (145) in an unprocessed “raw” form that may be used to determine the transform (510) with the fluid property data (745). The well log data (704), fluid property data (745), and the seismic data (648) are influenced by formation characteristics of the formation (232).

[0059] In some embodiments, the subsurface data (703) may include a wide variety of noise and distortion which in their unprocessed “raw” form may not provide significant useful information about the subsurface (132). Consequently, in such embodiments the subsurface data (703) may be processed, using a subsurface processing system (650), to remove or attenuate noise and to correctly position the subsurface data (703). For example, processing well logs (145) may include depth matching (i.e., aligning) the distinct logging runs. Depth matching includes aligning portions of the similar types of logs from different logging runs and which overlap in depth so that the logs are corrected for any depth errors between each logging run that may occur. Depth error may include cable stretching, tool sticking, tool slipping, and / or yo-yo effects among other issues that affect depth control of the one or more logging tools (240). Other processing may include de-spiking. De-spiking may include removing any data point that falls outside of a given threshold. The thresholds may be input from a user on a user device. The user device may be connected wirelessly or via cable to a computer system similar or the same as the computer system (800) described in relation to FIG. 8.

[0060] Processing the seismic data (648) includes processes designed to correct for, but not limited to, near-surface effects, depth issues, attenuate noise, compensate for irregularities in an acquisition surface (e.g., surface of the earth or walls of a borehole), calculate a velocity in the case of the sonic well log data (705) and the seismic data (648), calculate one or more subsurface images and attributes (708) to characterize the subsurface (132) and to determine the one or more drilling targets. Each of these processes may be accompanied by one or more quality control processes.

[0061] Processing of the seismic data (648) may be performed by a number of methods known to a person of ordinary skill in the art without departing from the scope of the invention. For example, the seismic data (648) may be time migrated seismic data or depth migrated seismic data. The seismic data (648) may also be further processed to correct for seismic source (606) and seismic receiver (616) location geometry and to attenuate noise while leaving the amplitude of the seismic signal undistorted. The seismic data (648) may be reduced to a two-dimensional (“2D”) or a three-dimensional (“3D”) image that delineates subterranean boundaries (612) as large or bright reflection amplitudes to form the one or more subsurface images and attributes (708).

[0062] In another step in processing the seismic data (648), a velocity model (707) may be determined representing the speed at which sonic waves propagate at various points within the subsurface (132). In some cases, the velocity model (707) may be calibrated using the sonic velocity log (420) based on velocity data obtained from the sonic well log data (705) (e.g., seismic well ties). The seismic data (648) and the velocity model (707) may be combined using a process called “migration” to form the subsurface image and attributes (708). Migrating seismic data (648) may take a substantial amount of computational time and memory relative to other processing steps. Typically, the subsurface image displays points of high and low reflection amplitude on a color scale or grayscale on a dense 2D or 3D grid of points representing the subsurface (132) around the geographical region (615) of the seismic survey area. Such an image may then be interpreted, together with other information, to determine geological structures surrounding the borehole (204) based on the subsurface image that may influence fluid flow within the subsurface (132).

[0063] Another result of processing the subsurface data (703) with the subsurface processing system (650) may be the one or more subsurface images and attributes (708) using subsurface imaging tools such as optical imaging tools, electrical imaging tools, acoustic imaging tools, or in combinations thereof. The subsurface processing system (650) may be configured to determine the subsurface image and attributes (708) of the subsurface (132) based on the seismic data (648) and the well log data (704). The subsurface image and attributes (708) may be a 2D or 3D image of the points within the subsurface (132) that generates a distinctive subsurface response. For example, the subsurface image may display the points at which acoustic energy is reflected, or scattered, within the subsurface (132) such as with the seismic data (648). Other characteristics or “attributes” of the subsurface (132) may be displayed as the subsurface image and attributes (708). For example, the strength of conversion of energy from one type of source wave to another as in acoustic imaging of the subsurface (132), or the strength of absorption of source energy, or the velocity of source propagation may be displayed as a function of subsurface position in the subsurface image and attributes (708). The examples of attributes given above are purely illustrative, and a person having ordinary skill in the art will appreciate that anyone of dozens of other attributes may be displayed as the subsurface image and the examples described should not be interpreted as limiting the scope of the invention in any way.

[0064] The subsurface processing system (650) may include a computer system, such as the computer system (800) shown in FIG. 8. The subsurface processing system (650) will typically be configured with appropriate subsurface data processing and analysis software and augmented with a number of purpose specific elements, such as high-capacity tape drives or hard drives connected through high-speed buses to computer processing units (“CPUs”). Further the CPUs of the subsurface processing system (650) will typically be connected to a plurality of graphical processing units (“GPUs”) that perform many of the computationally intensive operations on the subsurface data (703), banks of high-speed tape, or hard-drive, readers to read the data from storage, high-speed tape or hard-drive writers to output final or intermediate results, and high-speed communication buses to connect these elements.

[0065] It will be appreciated by a person having ordinary skill in the art that subsurface data (703) are extremely large, typically occupying hundreds of Gigabytes to Terabytes of data samples and cannot be manipulated or “processed” without the assistance of the subsurface processing system (650) purposely configured to handle the subsurface data (703). Based upon the disclosure provided herein, one of ordinary skill in the art will appreciate that the gathering of the data involves specialized tools to obtain the vast quantities of gathered data, and high-speed processing capability capable of performing at least one thousand calculations per second. Indeed, in some embodiments, processors capable of millions, billions, or even more calculations per second are used.

[0066] The subsurface images and attributes (708) may be an image, typically composed of pixels of varying intensity, and is not itself a model of the geological structure of the subsurface (132) to which it pertains. To determine the geological structure corresponding to, or that produced, the subsurface image is typically “interpreted” using the fluid property analysis system (150).

[0067] The fluid property analysis system (150) may include a subsurface interpretation workstation. The subsurface interpretation workstation is primarily used by subsurface interpreters (e.g., geoscientists and petrophysicists) and development teams in the oil and gas industry for analyzing the subsurface data (703) to understand geological structures and characteristics of the subsurface (132). Subsurface interpreters use the subsurface interpretation workstation to visualize the subsurface data (703), including, but not limited to, the well log data (704), the seismic data (648) such as 2D or 3D seismic volumes, seismic cross-sections, seismic attribute maps, and seismic attribute plots. These visualizations provide insights into subsurface structures, faults, and potential hydrocarbon reservoir formations and hydrocarbon source formations. Additional data may be used within the subsurface interpretation workstation to facilitate the interpretation of the subsurface data (703). Such data may also include other remote sensing data such as seismic, resistivity, transient electromagnetic, and / or gravitational surveys.

[0068] Subsurface interpreters may pick and interpret key geologic horizons within the seismic data (648) to identify stratigraphic layers, boundaries, and structural features. Horizon interpretation tools and workflows allow for the accurate extraction of geological information from seismic volumes. For example, the fluid property analysis system (150) enables interpreters to identify and interpret the one or more anomalies (e.g., horizons (612) and / or subsurface faults) that may impact the formation (232). Subsurface interpretation tools and visualization techniques help in understanding geometry, connectivity, and spatial relationships of the formation (232). Subsurface attributes, such as amplitude, frequency, and gradient, provide additional information about subsurface properties and can be analyzed using various algorithms and statistical methods. Attribute analysis tools in the workstation aid in defining reservoir characteristics, identifying anomalies, and highlighting potential hydrocarbon traps. Maps of the formation (232) may be used to determine the spatial extent of the formation fluid (102) including the oil window (104) and / or gas window (106).

[0069] The fluid property analysis system (150) may be used to determine the assessment of reservoir production potential, where subsurface interpreters may identify and assess areas with hydrocarbon exploration and production potential. The subsurface interpreters may perform detailed geological, petrophysical, and geophysical analysis, identify drilling targets, and quantify the risk and uncertainty associated with potential prospects.

[0070] In some embodiments, the one or more fluid properties may be determined by applying the transform (510) to the velocity model (707) yielding the one or more predicted fluid properties (711) at the one or more location within the subsurface (132) (e.g., the fourth location (254)). The fluid property analysis system (150) may be configured to apply the transform (510) to the velocity model (707) yielding the one or more predicted fluid properties (711) (e.g., the second predicted fluid property (715)) at the one or more locations within the subsurface (132) (e.g., the fourth location (254)). The one or more locations (e.g., the fourth location (254)) may be located the distance (255) away from the well (118) within the formation (232).

[0071] The fluid property analysis system (150) includes essential tools for subsurface interpreters involved in exploration and production activities, helping them make informed decisions about drilling locations, optimize production strategies, and understand complex subsurface geologic structures. The fluid property analysis system (150) may be a specialized computer system used by geoscientists and subsurface interpreters for analyzing and interpreting the subsurface data (703).

[0072] Subsurface interpretation involves data intensive tasks like data visualization, horizon picking, attribute analysis, and 3D modeling. For example, data visualization may include rendering 10s of gigabytes of data within several seconds in accordance with one or more embodiments. A high-performance subsurface interpretation workstation with a powerful processor, ample memory, and a high-resolution display is essential to handle these computationally demanding tasks efficiently. Dedicated GPUs may be utilized for rendering of the seismic data (648) to enable smooth and interactive visualization. GPUs with high memory and parallel processing capabilities accelerate tasks like volume rendering and horizon visualization.

[0073] In some embodiments, the subsurface interpretation workstation may automatically process the seismic volume to identify portions of the seismic data (648) that may include hydrocarbon reservoir potential and render the seismic data (648). In some embodiments, the subsurface interpretation workstation may interpret the data automatically and identify potential digital source rock formations that may be planned for hydrocarbon appraisal and production.

[0074] Subsurface interpretation involves working with large and complex data sets. Multiple high-resolution monitors allow interpreters to view the subsurface data (703), cross-sections, attribute maps and plots, and other visualizations simultaneously, enhancing productivity and analysis accuracy. The subsurface interpretation workstation may be equipped with industry-standard software applications tailored for subsurface interpretation, such as petrophysical, seismic and / or VSP data processing and visualization tools, well logs and petrophysics interpretation systems, attribute analysis software, and 3D modeling software.

[0075] Subsurface processing and interpretation projects generate substantial amounts of data, including petrophysical interpretations of the well logs (145), seismic volumes, processed data such as the one or more subsurface images and attributes (708) formed from the seismic data (648), the velocity models (707), the sonic well log data (705), and interpretation results such as subsurface interpretations and geological and reservoir models. A high-capacity and fast storage system, such as solid-state drives (SSDs) or RAID arrays, is necessary to store and access this data efficiently. The subsurface processing system (650) and the fluid property analysis system (150) often require network connectivity to access centralized data repositories, collaborate with colleagues, and share interpretation results. A robust network infrastructure with fast Ethernet or fiber connections ensures smooth data transfer and collaboration capabilities. The fluid property analysis system (150) may be configured to identify drilling targets based, at least in part, on the subsurface image and attributes (708).

[0076] Essential peripherals like keyboards, mice, and graphics tablets enable efficient interaction with data and software interfaces. The fluid property analysis system (150) may be augmented with purpose specific peripherals such as high capability display devices that may include immersive or virtual reality devices, such as virtual-reality headsets or immersive “caves”. Additionally, color-calibrated, and high-accuracy input devices enhance the precision of interpretation tasks like picking horizons representing stratigraphy or drawing geological features. The fluid property analysis system (150) should have backup solutions in place to protect valuable data from loss or damage. Automated backup systems, external storage devices, or network-attached storage (NAS) can be utilized to ensure data safety. In some cases, subsurface interpreters may need remote access to the fluid property analysis system (150) or collaborate with colleagues remotely. Setting up remote access capabilities, such as Virtual Private Networks (VPNs) or remote desktop solutions, allows interpreters to work from different locations and share their work effectively. The fluid property analysis system (150) may be customized to meet the needs of interpreters and the specific requirements of projects. The hardware specifications may vary based on factors like the complexity of interpretations, the size of data sets, and the software tools utilized.

[0077] The result of interpreting the well logs (145), the fluid property data (745), and the subsurface image and attributes (708) may be one or more geological and reservoir models (712) of the subsurface (132). The geological and reservoir models (712) may include utilizing an analysis of the subsurface interpretation to identify structural traps, seals, source formation generation and migration, and reservoir formation presence and quality. The geological and reservoir models (712) may include the locations of horizons, such as the boundary between formations (232) (e.g., the reservoir formation (110) and the source formation (108)) containing different rock types (“facies”), and faults and fractures. The geological and reservoir models (712) may also include descriptions of the characteristics of the different facies including characteristics such as porosity and permeability, and the relative amounts of different fluids, such as hydrocarbons, and brine, within the pores in each facies. The porosity and permeability may be used to define the reservoir formation quality for example. These characteristics may be included in the rock properties models. The fluid property analysis system (150) may include system software tools configured to populate geological, rock properties models, and fluid properties models such as using variograms and other statistical tools.

[0078] In some embodiments, the geological model and reservoir models (712) may include the one or more predicted fluid properties (711) based on applying the transform (510) to the fluid property data (745) and the well log data (704). The one or more predicted fluid properties (711) may include the predicted API gravity, the predicted fluid viscosity, and / or the predicted fluid GOR. In some embodiments, the fluid property analysis system (150) may output one or more predicted fluid properties (711), using the transform (510), that is defined over the formations (232) (e.g., the reservoir formation (110) and / or the source formation (108)) based on the well log data (704), the fluid property data (745), and the one or more seismic images and attributes (708).

[0079] In some embodiments, the geological model and reservoir models (712) may be input to a reservoir simulator (716). A reservoir simulator (716) comprises functionality for simulating the flow of fluids, including the formation fluid (102), through the reservoir (101) composed of porous, permeable reservoir formation (110) in response to natural and anthropogenic pressure gradients. The reservoir simulator (716) may be used to predict changes in fluid flow, including fluid flow into a well penetrating the reservoir (101) as a result of planned well drilling, fluid injection and extraction, and stimulation of the reservoir (101). For example, the reservoir simulator (716) may be used to predict fluid flow and production scenarios (717) including changes in hydrocarbon production rate that would result from the injection of water into the reservoir (101) from wells around the reservoirs periphery.

[0080] In some embodiments, the geological and reservoir models (712) include the predicted fluid properties (711), geological, and petrophysical properties that contains a digital description of the physical properties of the rocks (e.g., porosity, density, permeability, facies, lithologies, and the like). The reservoir simulator (716) may use the geological models and reservoir models (712) as a function of position within the reservoir (101) and the formation fluid (102) within the pores of the porous, permeable reservoir rocks at a given time. In some embodiments, the digital description may be in the form of a dense 3D model grid with the physical properties of the rocks and fluids defined at each node. In some embodiments, the 3D model grid may be a cartesian grid, while in other embodiments the model grid may be an irregular grid.

[0081] Reservoir simulators (716) 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 fluid with a constant viscosity and compressibility the equations capture Darcy's law, the continuity condition, and the equation of state.

[0082] Additional, and more complicated equations are required when more than one fluid, or more than one phase, e.g., liquid and gas, are present in the reservoir (101). Further, when the physical and petrophysical properties of the rocks and fluids vary as a function of position the governing equations may not be solved analytically and must instead be discretized into a grid of cells or blocks. The governing equations must then be solved by one of a variety of numerical methods, such as, without limitation, explicit or implicit finite-difference methods, explicit or implicit finite element methods, or discrete Galerkin methods.

[0083] The geological models may be based on the subsurface data (703) and may include identifying the reservoir formation (110), the source formation (108), the cap rock (112), seal, trap among other features (e.g., fluid properties, reservoir formation properties, and source formation properties). For example, data sets from acquiring remote sensing geophysical surveys, such as seismic surveys, gravity surveys, and active and passive source resistivity surveys, may be employed. In addition, data collected from the well logs (145) acquired in the well (118) penetrating the reservoir (101) may be used to determine physical and petrophysical properties along the segment of the well trajectory traversing the reservoir formation (110) and / or the source formation (108). For example, porosity, permeability, density, sonic velocity, and resistivity may be measured along these segments of the borehole (204). In accordance with some embodiments, remote sensing geophysical surveys and physical and petrophysical properties determined from the well logs (145) may be combined to estimate physical and petrophysical properties for the entire geological and reservoir simulation model grid.

[0084] In some embodiments, the fluid property analysis system (150) may be used to determine a reservoir fluid window (719) based on the predicted fluid properties (711) (e.g., the first predicted fluid property (714) and / or the second predicted fluid property (715)). The reservoir fluid window (719) may include one or more fluid windows such as the gas window (106) and / or the oil window (104). The oil window (104) may include a black oil window, a light oil window, a condensate window or combination thereof. The reservoir fluid window (719) identifies the potential fluid to be encountered by the borehole (204) and or induced fractures from borchole stimulation.

[0085] In some embodiments, the geological and reservoir models (712) may be used to create a subsurface development plan (721) using a subsurface development planning system (720) configured to determine the subsurface development plan (721) based on the one or more predicted fluid properties (711). The subsurface development plan (721) may include potential hydrocarbon production rates based on a number of production and injection wells, the placement of the production and injection wells in relation to the reservoir formation (110) (e.g., the drilling targets) and the geological and reservoir models characterization of the subsurface (132). The subsurface development plan (721) may include the borehole drilling plan (731) and a stimulation plan (751) for the well (118). The subsurface planning system may include a well planning system (730) configured to design the borehole drilling plan (731) based on the one or more predicted fluid properties (711) (e.g., the second predicted fluid property (715) at the fourth location (254). In some embodiments, the subsurface development planning system (720) may include a stimulation planning system (750) configured to design a stimulation plan (751) based on the one or more predicted fluid properties (711) (e.g., the first predicted fluid property (714) at the third one (253) of the plurality of depths (250)) to stimulate the reservoir formation (110) in order to potentially increase hydrocarbon production rates (e.g., production rates at the third one (253) of the plurality of depths (250).

[0086] In some embodiments, the borehole drilling plan (731) may be used for drilling a borehole (204) using the drilling system (238). The borehole drilling plan (731) may be based on the one or more predicted fluid properties (711) and / or the reservoir fluid window (719) as well as the geological and reservoir models (712). The well planning system (730) is configured to design the borehole drilling plan (731) to penetrate any drilling targets while simultaneously avoiding drilling hazard, such as preexisting boreholes, shallow gas pockets, and fault zones, and not exceeding the constraints, such as torque, drag and borehole curvature, of the drilling system (238) as described in relation to FIG. 2 and accompanying description. The drilling system (238) is configured to drill the borehole (204) based on the borehole drilling plan (731). Similarly, the borehole drilling plan (731) may include a determination of borehole caliper, and casing points.

[0087] The well planning system (730) may include a computer system that is the same or similar to the computer system (800) as described in relation to FIG. 8. The well planning system (730) may include dedicated well planning software stored on a memory of the computer system (800). The borehole drilling plan (731) may be informed by the best available information at the time of planning. This may include geohazard models encapsulating subterranean stress conditions, pore pressure models, the trajectory of any existing boreholes (which may be desirable to avoid), and the existence of other drilling hazards, such as shallow gas pockets, over-pressure zones, and active fault planes.

[0088] In some embodiments, the stimulation plan (751) may be used for stimulating a well as described in relation to FIG. 9. The stimulation plan (751) may be based on the one or more predicted fluid properties (711) and / or the reservoir fluid window (719) as well as the geological and reservoir models (712). The stimulation planning system is configured to design the stimulation plan (751) to stimulate the reservoir formation (110) to potentially induce fractures to increase permeability and hydrocarbon flow to the borehole (204). The stimulation plan (751) may include a stimulating section defined along the depth interval (231) of the borehole (204) expected to contain hydrocarbons.

[0089] The stimulation planning system (750) may include a computer system that is the same or similar to the computer system (800) as described in relation to FIG. 8. The stimulation planning system (750) may include dedicated stimulation planning software stored on a memory of the computer system (800). The stimulation plan (751) may be informed by the best subsurface data such as the geological and reservoir models (712) at the time of planning. This may include subterranean stress models used to predict potential fracture orientations and induced permeability. This also may include proppant requirements for propping the induced fractures open for needed production time frames.

[0090] The fluid flow and production scenarios (717) produced by the reservoir simulator (716) may be used by the well planning system (730) to determine the borehole drilling plan (731) and / or the stimulation plan (751). The borehole drilling plan (731) may target optimal drilling targets within the reservoir formation (110) for high fluid flow production rates. The stimulation plan (751) may be designed to obtain optimal fluid flow from the reservoir formation (110).

[0091] While the borehole drilling plan (731) and the stimulation plan (751) is formed using the best available information at the time at which it is formed, additional information may become available when drilling the borehole (204) specified by the borehole drilling plan (731). For example, the well logs (145) may provide new information about the reservoir structure and characteristic which may be acquired while drilling such as the LWD well logs or during drilling pauses in, or at the completion of drilling of, the borehole (204) specified by the borehole drilling plan (731). The well logs (145) acquired during pauses or at the cessation of drilling may be acquired using wireline or coiled tubing conveyed well logging tools. However, acquired, these new wells may be used to update the predicted fluids properties and the geological and reservoir models (712) with the aid of the fluid property analysis system (150).

[0092] FIG. 8 depicts a block diagram of a computer system (800) having a computer (802) used to provide computational functionalities associated with described algorithms, methods, functions, processes, flows, and procedures as described in this disclosure, according to one or more embodiments. 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. Additionally, 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 GUI.

[0093] 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). In some implementations, one or more components of the computer (802) may be configured to operate within environments, including cloud-computing-based, local, global, or other environment (or a combination of environments).

[0094] At a high level, the computer (802) is an electronic computing device operable to receive, transmit, process, store, or manage data and information associated with the described subject matter. According to some implementations, 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).

[0095] 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. 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.

[0096] Each of the components of the computer (802) can communicate using a system bus (803). In some implementations, 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 (812) or a service layer (813) (or a combination of the application programming interface (812) and service layer (813). The application programming interface (812) may include specifications for routines, data structures, and object classes. The application programming interface (812) may be either computer-language independent or dependent and refer to a complete interface, a single function, or even a set of application programming interfaces. The service layer (813) provides software services to the computer (802) or other components (whether or not illustrated) 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. For example, 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. While illustrated as an integrated component of the computer (802), alternative implementations may illustrate the application programming interface (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). Moreover, any or all parts of the application programming interface (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.

[0097] 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). Generally, 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).

[0098] The computer (802) 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 machine learning networks, algorithms, methods, functions, processes, flows, and procedures as described in the instant disclosure.

[0099] The computer (802) also 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). For example, 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).

[0100] 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. For example, application (807) can serve as one or more components, modules, applications, etc. Further, although illustrated as a single application (807), the application (807) may be implemented as multiple applications (807) on the computer (802). In addition, although illustrated as integral to the computer (802), in alternative implementations, the application (807) can be external to the computer (802).

[0101] There may be any number of computers (802) associated with, or external to, a computer system containing a computer (802), wherein cach computer (802) communicates over network (830). Further, the term “client,”“user,” and other appropriate terminology may be used interchangeably as appropriate without departing from the scope of this disclosure. Moreover, this disclosure contemplates that many users may use one computer (802), or that one user may use multiple computers (802).

[0102] FIG. 9 shows the hydraulic fracturing system (900) undergoing a stimulation operation according to the stimulation plan (751) design by the stimulation planning system (750) in accordance with one or more embodiments. The particular stimulation operation and hydraulic fracturing system (900) shown is for illustration purposes only. The scope of this disclosure is intended to encompass any type of hydraulic fracturing system (900) and stimulation operation. In general, a stimulation operation includes two separate operations: a perforation operation and a pumping operation. As such, FIG. 9 shows a stimulation operation occurring on a first well (902) and a second well (904). The first well (902) is undergoing the perforation operation and the second well (904) is undergoing the pumping operation.

[0103] The first well (902) and the second well (904) are horizontal wells meaning that each well includes a vertical section and a lateral section. The lateral section is a section of the well that is drilled at least eighty degrees from vertical. The first well (902) is capped by a first frac tree (906) and the second well (904) is capped by a second frac tree (908). A frac trec (906, 908) is similar to a Christmas / production tree but is specifically installed for the stimulation operation. Frac trees (906, 908) tend to have larger bores and higher-pressure ratings than a Christmas / production tree would have. Further, stimulation operations require abrasive materials being pumped into the well at high pressures, so the frac tree (906, 908) is designed to handle a higher rate of erosion.

[0104] In accordance with one or more embodiments, the perforating operation includes installing a wireline blow out preventor (BOP) (910) onto the first frac tree (906). A wireline BOP (910) is similar to a drilling BOP; however, a wireline BOP (910) has seals designed to close around (or shear) wireline (912) rather than drill pipe. The wireline (912) is maneuvered by a wireline truck (922) and a wireline spool (920). A lubricator (914) is connected to the opposite end of the wireline BOP (910). A lubricator (914) is a long, high-pressure pipe used to equalize downhole pressure and atmosphere pressure in order to run downhole tools, such as a perforating gun (916), into the well.

[0105] When the perforating gun (916) reaches a predetermined depth, a message is sent along the wireline (912) to set the frac plug (918). After the frac plug (918) is set, another message is sent through the wireline (912) to detonate the explosives, as shown in FIG. 9. The explosives create perforations in casing (926) and in the surrounding formation. There may be more than one set of explosives on a singular perforating gun (916), cach detonated by a distinct message. Multiple sets of explosives are used to perforate different depths along the casing (926) for a singular stage. Further, the frac plug (918) may be set separately from the perforation operation without departing from the scope of the disclosure herein.

[0106] As explained above, FIG. 9 shows the second well (904) undergoing the pumping operation after the fourth stage perforating operation has already been performed and perforations are left behind in the casing (926) and the surrounding formation. A pumping operation includes pumping a frac fluid (928) into the perforations in order to propagate the perforations and create fractures (942) in the surrounding formation. The frac fluid (928) often comprises a certain percentage of water, proppant, and chemicals.

[0107] FIG. 9 also shows chemical storage containers (930), water storage containers (932), and proppant storage containers (934) located on the hydraulic fracturing system (900). Frac lines (936) and transport belts (not pictured) transport the chemicals, proppant, and water from the storage containers (930, 932, 934) into a frac blender (938). The frac blender (938) blends the water, chemicals, and proppant to become the frac fluid (928). The frac fluid (928) is transported to one or more frac pumps, often pump trucks (940), to be pumped through the second frac tree (908) into the second well (904). The frac fluid (928) is transported from the pump truck (940) to the second frac tree (908) using a plurality of frac lines (936). The fluid pressure propagates and creates the fractures (942) while the proppant props open the fractures (942) once the pressure is released.

[0108] FIG. 10 depicts a fluid properties estimation flowchart in accordance with one or more embodiments describing a method for estimation of formation fluid properties (hereafter “estimation method” (1000)). In accordance with one or more embodiments, the estimation method may use the estimation system (100). Although the steps in the flowchart using the estimation method are shown in sequential order, it will be apparent to one of ordinary skill in the art that some steps may be conducted in parallel, in a different order than shown, or may be omitted without departing form the scope of the invention.

[0109] In Block (1001), the estimation method (1000) includes obtaining, using the logging system (140), the well log (145) of the well (118) in accordance with one or more embodiments. The well log (145) comprises well log data (704) at each of the plurality of depths (250) within the well (118). In some embodiments, obtaining the well log (145) may include obtaining the sonic well log, and / or the density well log. The well log data (704) includes, but is not limited to, sonic well log data (705), and / or density well log data (706).

[0110] In Block (1002), the estimation method (1000) includes obtaining, using the fluid retrieval system (142), the first fluid sample (148) at the first one (251) of the plurality of depths (250) within the well (118) in accordance with one or more embodiments. In box (1003), the estimation method (1000) includes obtaining, using the fluid retrieval system (142), the second fluid sample (149) at the second one (252) of the plurality of depths (250) within the well in accordance with one or more embodiments.

[0111] In Block (1004), the first fluid property (748) is determined from the first fluid sample (148) in accordance with one or more embodiments. The fluid property analysis system (150) is configured to determine the first fluid property (748) from the first fluid sample (148). The first fluid sample (148) may include a first API gravity, a first fluid viscosity, or a first fluid GOR at the first one (251) of the plurality of depths (250).

[0112] In Block (1005), the estimation method (1000) includes determining the second fluid property (749) from the second fluid sample (149) in accordance with one or more embodiments. The fluid property analysis system (150) is configured to determine the second fluid property (749) from the second fluid sample (149). The second fluid sample (149) may include a second API gravity, a second fluid viscosity, or a second fluid GOR at the second one (252) one of the plurality of depths (250).

[0113] In Block (1006), the estimation method (1000) includes determining the transform (510) based on the first fluid property (748), the second fluid property (749), and the well log data (704) at both the first one (251) of the plurality of depths (250) and the second one (252) of the plurality of depths (250) in accordance with one or more embodiments. In some embodiments, determining the transform (510) comprises cross-correlating the first fluid property (748) and the second fluid property (749) with the well log data (704) at both the first one (251) of the plurality of depths (250) and the second one (252) of the plurality of depths (250) yielding the fluid data cross-correlation (515).

[0114] In Block (1007), the transform (510) is applied to the well log data (704) at the third one (253) of the plurality of depths (250) within the well (118) yielding the first predicted fluid property (714) in accordance with one or more embodiments. The first predicted fluid property (714) may include a first predicted API gravity, a first predicted fluid viscosity, and a first predicted fluid GOR at the third one (253) of the plurality of depths (250) within the well (118). Applying the transform (510) may include inputting the well log data (704) into the transform (510) and outputting the predicted fluid properties (711) using the fluid property analysis system (150).

[0115] In Block (1008), the estimation method (1000) includes determining, using the subsurface development planning system (720), the subsurface development plan (721) based on the first predicted fluid property (714) in accordance with one or more embodiments. Determining the subsurface development plan (721) may include planning well locations for wells to be drilled to penetrate the reservoir formation (110) and / or the source formation (108). Determining the subsurface development plan (721) may include planning well sections for stimulation to potentially enhance hydrocarbon recovery.

[0116] In Block (1009), determining the subsurface development plan (721) may include designing, using the stimulation planning system (750), the stimulation plan (751) based on the first predicted fluid property (714) in accordance with one or more embodiments. Designing the stimulation plan (751) may include planning a perforation operation and a pumping operation.

[0117] In Block (1010), determining the subsurface development plan (721) may include stimulating, using the hydraulic fracturing system (900), the formation (232) around the well (118) based on the stimulation plan (751) in accordance with one or more embodiments. Stimulating the formation (232) may include perforating the casing (926) and pumping frac fluid (928) and proppant into the formation (232).

[0118] In some embodiments, the estimation method (1000) may include fitting a polynomial to the fluid data cross-correlation (515). Fitting the polynomial may include using polynomial interpolation, polynomial regression optimized with a least-squares method, and the like. In some embodiments, applying the transform (510) may include applying a non-linear transform based on fitting the polynomial.

[0119] In some embodiments, the estimation method (1000) may include obtaining, using the seismic data acquisition system (600), seismic data (648) from the geographical region (615) that includes the well (118). In some embodiments, the estimation method (1000) may include determining, using the subsurface processing system (650), the velocity model (707) based on the seismic data (648) at a fourth location (254), wherein the fourth location (254) is the distance (255) from the well (118) within the formation (232).

[0120] In some embodiments, the estimation method (1000) may include applying the transform (510) to the velocity model (707) yielding the one or more predicted fluid properties (711) (e.g., the second predicted fluid property (715)). The fluid property analysis system (150) may be configured to apply the transform (510) to the velocity model (707) yielding the one or more predicted fluid properties (711) at the one or more location within the subsurface (132) (e.g., the fourth location (254)). The one or more locations (e.g., the fourth location (254)) may be located the distance (255) away from the well (118) within the formation (232).

[0121] In some embodiments, the estimation method (1000) may include determining, using the fluid property analysis system (150), the reservoir fluid window (719) based on the one or more predicted fluid properties (711). The reservoir fluid window (719) may include the oil window (104) and the gas window (106).

[0122] In some embodiments, the estimation method (1000) may include designing, using the well planning system (730), the borehole drilling plan (731) based on the second predicted fluid property (715). In some embodiments, the borehole drilling plan (731) may be based on the reservoir fluid window (719). In some embodiments, the estimation method (1000) may include drilling, using the drilling system (238), the borehole (204) based on the borehole drilling plan (731).

[0123] Embodiments of the present disclosure may provide at least one of the following advantages. The present disclosure provides methods and systems for improving estimation of fluid properties with minimal sampling or lab testing of formations (232) at the distance (255) from the well (118). The estimation method (1000) predicts expected well behavior and formation fluid properties using raw well log data (704). The estimation method (1000) improves the ability to predict formation fluid properties in new exploration areas using the well logs (145) without the need for drilling and production prior to planning the borehole drilling plan (731) and / or stimulation plan (751). The decrease in lab testing and improved planning thereby provides potential improvement in recovery of hydrocarbons with reduction in costs, emissions, and waste.

[0124] Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.

Examples

Embodiment Construction

[0017]In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

[0018]Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for 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. By way of an example, a first element is distinct from...

Claims

1. A method for predicting a fluid property, the method comprising:obtaining, using a logging system, a well log of a well,wherein the well log comprises well log data at each of a plurality of depths within the well;obtaining, using a fluid retrieval system, a first fluid sample at a first one of the plurality of depths within the well;obtaining, using the fluid retrieval system, a second fluid sample at a second one of the plurality of depths within the well;determining a first fluid property from the first fluid sample;determining a second fluid property from the second fluid sample;determining a transform based on the first fluid property, the second fluid property, and the well log data at both the first one of the plurality of depths and the second one of the plurality of depths;applying the transform to the well log data at a third one of the plurality of depths within the well yielding a first predicted fluid property; anddetermining a subsurface development plan based on the first predicted fluid property.

2. The method of claim 1, wherein obtaining the well log comprises obtaining a sonic well log, and wherein the well log data comprises sonic well log data.

3. The method of claim 1, wherein the first fluid property comprises a first American Petroleum Institute (API) gravity, and wherein the second fluid property comprises a second API gravity.

4. The method of claim 1, wherein determining the transform comprises cross-correlating the first fluid property and the second fluid property with the well log data at both the first one of the plurality of depths and the second one of the plurality of depths yielding a fluid data cross-correlation.

5. The method of claim 4, further comprises fitting a polynomial to the fluid data cross-correlation.

6. The method of claim 5, wherein applying the transform comprises applying a non-linear transform based on fitting the polynomial.

7. The method of claim 1, wherein determining the subsurface development plan comprises:designing, using a stimulation planning system, a stimulation plan based on the first predicted fluid property; andstimulating, using a hydraulic fracturing system, a formation around the well based on the stimulation plan.

8. The method of claim 1, further comprising:determining, using a fluid property analysis system, a reservoir fluid window based on the first predicted fluid property, wherein the reservoir fluid window comprises an oil window and a gas window.

9. The method of claim 1, further comprising:obtaining, using a seismic data acquisition system, seismic data from a geographical region that includes the well;determining, using a subsurface processing system, a velocity model based on the seismic data at a fourth location, wherein the fourth location is a distance from the well within a formation; andapplying the transform to the velocity model yielding a second predicted fluid property at the fourth location.

10. The method of claim 9, further comprising:designing, using a well planning system, a borehole drilling plan based on the second predicted fluid property; anddrilling, using a drilling system, a borehole based on the borehole drilling plan.

11. A method for predicting a fluid property, the method comprising:obtaining, using a logging system, a well log of a well, wherein the well log comprises well log data at each of a plurality of depths within the well;obtaining, using a fluid retrieval system, a first fluid sample at a first one of the plurality of depths within the well;obtaining, using the fluid retrieval system, a second fluid sample at a second one of the plurality of depths within the well;determining a first fluid property from the first fluid sample;determining a second fluid property from the second fluid sample;determining a transform based on the first fluid property, the second fluid property, and the well log data at both the first one of the plurality of depths and the second one of the plurality of depths;applying the transform to the well log data at a third location yielding a first predicted fluid property,wherein the third location comprises a third one of the plurality of depths within the well;determining a subsurface development plan based on the first predicted fluid property;obtaining, using a seismic data acquisition system, seismic data from a geographical region that includes the well;determining, using a subsurface processing system, a velocity model based on the seismic data at a fourth location, wherein the fourth location is a distance from the well within a formation;applying the transform to the velocity model yielding a second predicted fluid property at the fourth location;determining, using a fluid property analysis system, a reservoir fluid window based on the first predicted fluid property and the second predicted fluid property,wherein the reservoir fluid window comprises an oil window and a gas window;designing, using a well planning system, a borehole drilling plan based on the reservoir fluid window; anddrilling, using a drilling system, a borehole based on the borehole drilling plan.

12. A system for estimating a fluid property, the system comprising:a logging system comprising a logging tool configured to obtain a well log of a well,wherein the well log comprises well log data at each of a plurality of depths within the well;a fluid retrieval system configured to obtain a first fluid sample at a first one of the plurality of depths and a second fluid sample at a second one of the plurality of depths;a fluid property analysis system configured to:determine a first fluid property from the first fluid sample,determine a second fluid property from the second fluid sample,determine a transform based on the first fluid property, the second fluid property, and the well log data at both the first one of the plurality of depths and the second one of the plurality of depths, andapply the transform to the well log data at a third one of the plurality of depths within the well yielding a first predicted fluid property; anda subsurface development planning system configured to determine a subsurface development plan based on the first predicted fluid property.

13. The system of claim 12, wherein the well log comprises a sonic well log and wherein the well log data comprises sonic well log data.

14. The system of claim 12, wherein the fluid property analysis system is further configured to cross-correlate the first fluid property and the second fluid property with the well log data at both the first one of the plurality of depths and the second one of the plurality of depths yielding a fluid data cross-correlation.

15. The system of claim 14, wherein the fluid property analysis system is further configured to fit a polynomial to the fluid data cross-correlation.

16. The system of claim 15, wherein applying the transform comprises applying a non-linear transform based on fitting the polynomial.

17. The system of claim 12, further comprising:a stimulation planning system configured to design a stimulation plan based on the first predicted fluid property; anda hydraulic fracturing system configured to stimulate a formation around the well based on the stimulation plan.

18. The system of claim 12, wherein the fluid property analysis system is further configured to determine a reservoir fluid window based on the first predicted fluid property, wherein the reservoir fluid window comprises an oil window and a gas window.

19. The system of claim 12, further comprising:a seismic data acquisition system configured to obtain seismic data from a geographical region that includes the well;a subsurface processing system configured to determine a velocity model based on the seismic data at a fourth location, wherein the fourth location is a distance from the well within a formation; andthe fluid property analysis system is configured to apply the transform to the velocity model yielding a second predicted fluid property at the fourth location.

20. The system of claim 19, further comprising:a well planning system configured to design a borehole drilling plan based on the second predicted fluid property; anda drilling system configured to drill a borehole based on the borehole drilling plan.

Images