Changes

Other members of the subsurface team will also use the core data. The petrophysicist uses core data to calibrate the measurement of rock properties from wire-line log data. The reservoir engineer obtains data for the various reservoir parameters needed to understand the physics of fluid distribution and flow. Properties such as capillary pressure and relative permeability are measured by special core analysis, and this is referred to by the acronym SCAL. The geologist will frequently get requests from the production engineer to provide core samples for laboratory tests. The aim is to ensure that the various downhole chemical treatments do not react with the rock or the pore fluid to plug up the pore space and impair productivity.

Other members of the subsurface team will also use the core data. The petrophysicist uses core data to calibrate the measurement of rock properties from wire-line log data. The reservoir engineer obtains data for the various reservoir parameters needed to understand the physics of fluid distribution and flow. Properties such as capillary pressure and relative permeability are measured by special core analysis, and this is referred to by the acronym SCAL. The geologist will frequently get requests from the production engineer to provide core samples for laboratory tests. The aim is to ensure that the various downhole chemical treatments do not react with the rock or the pore fluid to plug up the pore space and impair productivity.

{{Fig40

[[File:M91Ch6FG40.JPG|thumb|300px|{{figure number|1}}Museum core on display.]]

The core is slabbed once all the samples have been taken and the measurements are complete. It will be cut into three vertical sections down the length of the core. The middle slab is kept as a reference core for further study by the geologist. It is placed in a wooden frame and set in resin or glued to a firm base. This part of the core will be kept as a museum core (Figure 40). The other two sections of the core, referred to as the half cut, are kept for subsequent sampling.

The core is slabbed once all the samples have been taken and the measurements are complete. It will be cut into three vertical sections down the length of the core. The middle slab is kept as a reference core for further study by the geologist. It is placed in a wooden frame and set in resin or glued to a firm base. This part of the core will be kept as a museum core ([[:file:M91Ch6FG40.JPG|Figure 1]]). The other two sections of the core, referred to as the half cut, are kept for subsequent sampling.

==Coring problems==

==Coring problems==

A core gamma log will also be included in a core analysis report. The gamma-ray response is measured along the length of the core in the laboratory. It is used to match up the core depths to the depths on the wireline gamma-ray log run over the cored interval in the reservoir. These can differ from about half a meter to sometimes more than 6 m (18 ft). This is because over a distance of 2000 or 3000 m (6500 or 10,000 ft) within the borehole, the drill string to which the core barrel is attached will stretch under tension a few meters more or less than the wireline to which the log is attached. Also, incomplete recovery of core, particularly unconsolidated core, can lead to discrepancies in the core log. Comparison of the core gamma with the wireline gamma log allows the core-to-log shift to be determined. This is important for matching features in the core to the equivalent log response.

A core gamma log will also be included in a core analysis report. The gamma-ray response is measured along the length of the core in the laboratory. It is used to match up the core depths to the depths on the wireline gamma-ray log run over the cored interval in the reservoir. These can differ from about half a meter to sometimes more than 6 m (18 ft). This is because over a distance of 2000 or 3000 m (6500 or 10,000 ft) within the borehole, the drill string to which the core barrel is attached will stretch under tension a few meters more or less than the wireline to which the log is attached. Also, incomplete recovery of core, particularly unconsolidated core, can lead to discrepancies in the core log. Comparison of the core gamma with the wireline gamma log allows the core-to-log shift to be determined. This is important for matching features in the core to the equivalent log response.

{{Fig41

[[File:M91Ch6FG41.JPG|thumb|300px|{{figure number|2}}Example of a core photograph. The photograph shows the channel margin facies association from deep-water sediments of the Nelson field, UK North Sea (from Kunka et al., 2003). Reprinted with permission from the Geological Society of London, whose permission is required for additional use.]]

The second report received is the core photography report (Figure 41). This is a set of color photographs of the slabbed core. The geologist can keep this in the office as a substitute for a trip to the core storage location to see the actual rock. If any oil is present in the core, the core will also be photographed under ultraviolet light. Any oil-saturated intervals will show up as fluorescent patches on the photographs.

The second report received is the core photography report ([[:file:M91Ch6FG41.JPG|Figure 2]]). This is a set of color photographs of the slabbed core. The geologist can keep this in the office as a substitute for a trip to the core storage location to see the actual rock. If any oil is present in the core, the core will also be photographed under ultraviolet light. Any oil-saturated intervals will show up as fluorescent patches on the photographs.

{{Fig42

[[File:M91Ch6FG42.JPG|thumb|300px|{{figure number|3}}Example of a sedimentological core log, Well d-2-C/94a-16, Peejay field, Canada (after Caplan and Moslow, 1999).]]

==The sedimentology report==

==The sedimentology report==

It is good practice to call in an expert sedimentologist to look at the core and to provide a detailed sedimentological report. The report will include a sedimentological log with a detailed description of all the sedimentological features seen in the core (Figure 42). Various details will be noted (Blackbourn, 1990).

It is good practice to call in an expert sedimentologist to look at the core and to provide a detailed sedimentological report. The report will include a sedimentological log with a detailed description of all the sedimentological features seen in the core ([[:file:M91Ch6FG42.JPG|Figure 3]]). Various details will be noted (Blackbourn, 1990).

These include:

These include:

{{Table 9

{{Table 9

{{Fig 43

[[File:M91Ch6FG43.JPG|thumb|300px|{{figure number|4}}Gamma-ray, density, neutron, and sonic log response of a sandstone and shale sequence. This example is from well 16/29a-9 in the Fleming field, UK North Sea (from Stuart, 2002). Reprinted with permission from the Geological Society, whose permission is required for further use.]]

==Gamma-ray logs==

==Gamma-ray logs==

A gamma-ray log measures the natural radiation in the rocks, much of which is emitted by the elements potassium, uranium, and thorium (Figure 43). The geologist typically uses the log to differentiate between sandstone and shale for correlation purposes. Sandstones normally show a lower gamma-ray response than shales. The gamma ray is an excellent tool for this, providing it is used in conjunction with other logs to confirm the lithology response. Care should be taken with the interpretation of the gamma-ray log in some sandstones. Sandstones rich in potassium-rich minerals such as potassium feldspar, muscovite mica, illite, or glauconite can give a high gamma response that is easily mistaken for a shale. A gamma spike at the base of a sand-prone upper shoreface profile can be the result of concentrations of heavy, radioactive accessory minerals by wave winnowing.

A gamma-ray log measures the natural radiation in the rocks, much of which is emitted by the elements potassium, uranium, and thorium ([[:file:M91Ch6FG43.JPG|Figure 4]]). The geologist typically uses the log to differentiate between sandstone and shale for correlation purposes. Sandstones normally show a lower gamma-ray response than shales. The gamma ray is an excellent tool for this, providing it is used in conjunction with other logs to confirm the lithology response. Care should be taken with the interpretation of the gamma-ray log in some sandstones. Sandstones rich in potassium-rich minerals such as potassium feldspar, muscovite mica, illite, or glauconite can give a high gamma response that is easily mistaken for a shale. A gamma spike at the base of a sand-prone upper shoreface profile can be the result of concentrations of heavy, radioactive accessory minerals by wave winnowing.

==Spectral gamma-ray logs==

==Spectral gamma-ray logs==

Wireline pressure test data in infill wells can provide valuable information on the reservoir performance. The formation tester log contains a probe, which is pushed horizontally against the formation to take a measurement of the reservoir pressure. A small fluid sample can also be taken if required. The pressure measurements are repeated at various depths throughout the reservoir, enabling a pressure-depth plot to be made.

Wireline pressure test data in infill wells can provide valuable information on the reservoir performance. The formation tester log contains a probe, which is pushed horizontally against the formation to take a measurement of the reservoir pressure. A small fluid sample can also be taken if required. The pressure measurements are repeated at various depths throughout the reservoir, enabling a pressure-depth plot to be made.

{{Fig 44

[[File:M91Ch06FG44.JPG|thumb|300px|{{figure number|5}}Formation pressure measurements are repeated at various depths throughout the reservoir to make a pressure-depth profile. Tests conducted in a virgin reservoir preproduction can allow the free-water level to be defined. Postproduction, formation tester data can give information on where the reservoir may be separating into zones of different pressures as a result of depletion.]]

When these tests are conducted in a virgin reservoir preproduction, it may be possible to define the depth of the free-water level. This will correspond to the intersection of the water and oil (gas) gradients. Postproduction, formation tester data can give information on where the reservoir is separating into zones of different pressures as a result of depletion (Figure 44).

When these tests are conducted in a virgin reservoir preproduction, it may be possible to define the depth of the free-water level. This will correspond to the intersection of the water and oil (gas) gradients. Postproduction, formation tester data can give information on where the reservoir is separating into zones of different pressures as a result of depletion ([[:file:M91Ch06FG44.JPG|Figure 5]]).

The raw log data will show the rate at which the pressure built up for each test, and a crude assessment of the formation permeability can be made from this (Smolen, 1992a).

The raw log data will show the rate at which the pressure built up for each test, and a crude assessment of the formation permeability can be made from this (Smolen, 1992a).

* They are used for steering horizontal wells (see [[Well types]]).

* They are used for steering horizontal wells (see [[Well types]]).

{{Fig 45

[[File:M91Ch6FG45.JPG|thumb|300px|{{figure number|6}}Production logs are run in a producing well to determine downhole flow rates and to evaluate reservoir sweep.]]

==Production logs==

==Production logs==

Production logs are run in a producing well to determine downhole flow rates and to evaluate reservoir sweep (Figure 45; Table 10). They give the subsurface team an understanding of how the reservoir is behaving under production. For example, if a well is producing water, the logs can then be analyzed to determine which perforated intervals are sourcing the water. The perforations can then be isolated to restore the well to dry oil production (Smolen, 1992b).

Production logs are run in a producing well to determine downhole flow rates and to evaluate reservoir sweep ([[:file:M91Ch6FG45.JPG|Figure 6]]; Table 10). They give the subsurface team an understanding of how the reservoir is behaving under production. For example, if a well is producing water, the logs can then be analyzed to determine which perforated intervals are sourcing the water. The perforations can then be isolated to restore the well to dry oil production (Smolen, 1992b).

{{Table 10

{{Table 10

The taking of oil and formation water fluid samples at the appraisal stage of field development can provide valuable data later on in field life. For instance, variation in oil and water geochemistry data can be used to define reservoir compartments within a field (see [[Areal compartment]]s).

The taking of oil and formation water fluid samples at the appraisal stage of field development can provide valuable data later on in field life. For instance, variation in oil and water geochemistry data can be used to define reservoir compartments within a field (see [[Areal compartment]]s).

{{Fig 46

[[File:M91Ch6FG46.JPG|thumb|300px|{{figure number|7}}Production data for an individual oil producer. The well has a variable history of water production. Water shut-offs in 2000 and 2004 were partially successful in reducing the water cut. ]]

==Production data==

==Production data==

Production data can be used to make inferences about reservoir continuity and connectivity. The geologist should have direct access to the well-by-well production profiles (Figure 46). These show the rate of production against time for each well including the total fluid flow rate, hydrocarbon flow rate, water flow rate, and the water cut (percentage of water flowing relative to total flow). The idea is to look out for any unexplained changes in production or unexpected anomalies. Sometimes this happens for mechanical reasons, but, typically the anomaly may give an insight into the fluid pathways within the reservoir. For instance, a new injection well may be brought on stream, and this will cause the flow rates to increase in nearby producers. This demonstrates reservoir connectivity between the injector and the producers.

Production data can be used to make inferences about reservoir continuity and connectivity. The geologist should have direct access to the well-by-well production profiles ([[:file:M91Ch6FG46.JPG|Figure 7]]). These show the rate of production against time for each well including the total fluid flow rate, hydrocarbon flow rate, water flow rate, and the water cut (percentage of water flowing relative to total flow). The idea is to look out for any unexplained changes in production or unexpected anomalies. Sometimes this happens for mechanical reasons, but, typically the anomaly may give an insight into the fluid pathways within the reservoir. For instance, a new injection well may be brought on stream, and this will cause the flow rates to increase in nearby producers. This demonstrates reservoir connectivity between the injector and the producers.

{{Fig 47

[[File:M91Ch6FG47.JPG|thumb|300px|{{figure number|8}}Seismic line and equivalent interpretation through the Penguin C South field, UK North Sea (from Dominguez, 2007). Reprinted with permission from the Geological Society of London, whose permission is required for further use.]]

==Seismic data==

==Seismic data==

Seismic data allow subsurface structures to be identified and mapped. It provides structural information for determining suitable places to drill in an oil field. Seismic data will also help to determine the nature of the reservoir between wells, albeit at a relatively low resolution both spatially and vertically (Figure 47). Horizontally, a data point is typically acquired every 12.5 m (41 ft) with modern seismic acquisition methods offshore. Vertical resolution will mostly depend on the depth of the reservoir and to some extent on the seismic acquisition and processing parameters. The resolution decreases with increasing depth with the higher frequency component of the signal progressively getting filtered out as the sound wave passes through the subsurface. The shape of the seismic pulse will also change as a function of depth, further distorting the signal. At typical Jurassic reservoir depths in the North Sea for instance, the frequency content of the signal corresponds to a vertical resolution of about 20–40 m (66–132 ft). Features smaller than this will not be seen on seismic sections at these depths. This resolution is sufficient to make an interpretation of the reservoir structure and the position of the larger faults. The geologist will use the seismic interpretation as the basis for the structural framework in their geological scheme. An analysis of seismic data can also occasionally give an indication of the nature of reservoir porosity, fluid type, and an outline of sediment bodies.

Seismic data allow subsurface structures to be identified and mapped. It provides structural information for determining suitable places to drill in an oil field. Seismic data will also help to determine the nature of the reservoir between wells, albeit at a relatively low resolution both spatially and vertically ([[:file:M91Ch6FG47.JPG|Figure 8]]). Horizontally, a data point is typically acquired every 12.5 m (41 ft) with modern seismic acquisition methods offshore. Vertical resolution will mostly depend on the depth of the reservoir and to some extent on the seismic acquisition and processing parameters. The resolution decreases with increasing depth with the higher frequency component of the signal progressively getting filtered out as the sound wave passes through the subsurface. The shape of the seismic pulse will also change as a function of depth, further distorting the signal. At typical Jurassic reservoir depths in the North Sea for instance, the frequency content of the signal corresponds to a vertical resolution of about 20–40 m (66–132 ft). Features smaller than this will not be seen on seismic sections at these depths. This resolution is sufficient to make an interpretation of the reservoir structure and the position of the larger faults. The geologist will use the seismic interpretation as the basis for the structural framework in their geological scheme. An analysis of seismic data can also occasionally give an indication of the nature of reservoir porosity, fluid type, and an outline of sediment bodies.

In most companies, geophysicists are responsible for interpreting and analyzing seismic data. However, it is becoming more common for geologists in oil companies to make some of the seismic interpretation.

In most companies, geophysicists are responsible for interpreting and analyzing seismic data. However, it is becoming more common for geologists in oil companies to make some of the seismic interpretation.

Seismic data can be acquired both on land and at sea. On land, a variety of sound sources have been used, including dynamite, a heavy weight repeatedly dropped on the ground, or a vibrating steel plate on the ground surface. Airguns are typically used in the marine environment.

Seismic data can be acquired both on land and at sea. On land, a variety of sound sources have been used, including dynamite, a heavy weight repeatedly dropped on the ground, or a vibrating steel plate on the ground surface. Airguns are typically used in the marine environment.

{{Fig 48

[[File:M91Ch6FG48.JPG|thumb|300px|{{figure number|9}}Seismic boat and streamers (courtesy of Woodside Petroleum, Web site: www.woodside.com.au, whose permission is required for further use).]]

Recording devices on land consist of arrays of connected geophones laid out in long lines. At sea, hydrophones are strung together within a long plastic sheath known as a streamer. The streamer can be several kilometers long. At the end of the 20th century, a streamer was typically 3500–4000 m (11,500–13,000 ft) long. The trend today is for increasingly longer cables to allow a greater distance between the source and the furthest hydrophone on the streamer (known as the far offset, the distance between the source and the nearest hydrophone being known as the near offset). This greater distance allows for better discrimination of the variation in the recorded amplitudes for a given reflector with increasing offset, a technique known as amplitude versus offset or AVO. This can be helpful in determining whether hydrocarbons are present at a given location (Russell, 2002). Several sources and several streamers can be towed behind the seismic boat at one time (Figure 48).

Recording devices on land consist of arrays of connected geophones laid out in long lines. At sea, hydrophones are strung together within a long plastic sheath known as a streamer. The streamer can be several kilometers long. At the end of the 20th century, a streamer was typically 3500–4000 m (11,500–13,000 ft) long. The trend today is for increasingly longer cables to allow a greater distance between the source and the furthest hydrophone on the streamer (known as the far offset, the distance between the source and the nearest hydrophone being known as the near offset). This greater distance allows for better discrimination of the variation in the recorded amplitudes for a given reflector with increasing offset, a technique known as amplitude versus offset or AVO. This can be helpful in determining whether hydrocarbons are present at a given location (Russell, 2002). Several sources and several streamers can be towed behind the seismic boat at one time ([[:file:M91Ch6FG48.JPG|Figure 9]]).

Land and marine acquisition techniques differ slightly but in principle are mostly the same. The following describes the marine case. A seismic boat acquires data by sailing as carefully as it can along a predetermined line over the area of interest. When it reaches the end of this line, it turns around and acquires data along a parallel line in the opposite direction. The boat will steam back and forth line after line acquiring the seismic survey for up to months at a time depending on how large an area is to be acquired and on the weather conditions. The boat travels slowly along the predetermined line, and periodically (every 12.5 m [41 ft] or perhaps every 25 m [82 ft]) discharges the airgun. The point on the line where this occurs is known as a shotpoint. The hydrophones then record the reflection echoes from the subsurface. Simultaneously, compressors will recharge the airgun ready for the next discharge, and the process repeats over and over again. The result is a record of a large number of shot and receiver pairs for each reflection point in the subsurface. The data are recorded digitally and will include the time it takes for the seismic pulse to return to the surface, the waveform of the seismic signal, and the sound and source location. The time that the seismic energy takes to travel from the source to the reflection and back to the surface again is called the two-way traveltime (TWT). This can take 2–3 s or more. Because of the rapid velocity of seismic waves through the subsurface, seismic intervals are measured in milliseconds; 1000 ms equals 1 s.

Land and marine acquisition techniques differ slightly but in principle are mostly the same. The following describes the marine case. A seismic boat acquires data by sailing as carefully as it can along a predetermined line over the area of interest. When it reaches the end of this line, it turns around and acquires data along a parallel line in the opposite direction. The boat will steam back and forth line after line acquiring the seismic survey for up to months at a time depending on how large an area is to be acquired and on the weather conditions. The boat travels slowly along the predetermined line, and periodically (every 12.5 m [41 ft] or perhaps every 25 m [82 ft]) discharges the airgun. The point on the line where this occurs is known as a shotpoint. The hydrophones then record the reflection echoes from the subsurface. Simultaneously, compressors will recharge the airgun ready for the next discharge, and the process repeats over and over again. The result is a record of a large number of shot and receiver pairs for each reflection point in the subsurface. The data are recorded digitally and will include the time it takes for the seismic pulse to return to the surface, the waveform of the seismic signal, and the sound and source location. The time that the seismic energy takes to travel from the source to the reflection and back to the surface again is called the two-way traveltime (TWT). This can take 2–3 s or more. Because of the rapid velocity of seismic waves through the subsurface, seismic intervals are measured in milliseconds; 1000 ms equals 1 s.

The data are stored on a computer. The interpreter can call up the data set on the screen. It is possible to display any vertical or horizontal slice through the data as required. Vertical slices are typically used for picking horizons and faults. Two types of horizontal slices can be derived from a 3-D seismic data set. A time slice is a horizontal slice through a volume of 3-D data, which can show areal amplitude variation. Under favorable conditions, this can reveal geometrical patterns related to the depositional environment. A horizon slice is a reflection that has been flattened and then redisplayed as a time slice. It shows areal amplitude variation along the reflection.

The data are stored on a computer. The interpreter can call up the data set on the screen. It is possible to display any vertical or horizontal slice through the data as required. Vertical slices are typically used for picking horizons and faults. Two types of horizontal slices can be derived from a 3-D seismic data set. A time slice is a horizontal slice through a volume of 3-D data, which can show areal amplitude variation. Under favorable conditions, this can reveal geometrical patterns related to the depositional environment. A horizon slice is a reflection that has been flattened and then redisplayed as a time slice. It shows areal amplitude variation along the reflection.

==See also==

==See also==