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==Production well-test data and interference and pulse tests==
==Production well-test data and interference and pulse tests==
Production well tests are an important for reservoir management because they provide information on flow rates, reservoir architecture, rock properties, and reservoir pressures. A production well test is performed by inducing pressure variations in a well over time. An example of this is where a production well is shut in to conduct a pressure buildup test. Fluid will then move into the pressure sink caused by the production, and the pressure will gradually increase in the well. The pressure data are used to assess the properties of the reservoir and the reservoir fluid around the wellbore by a technique known as pressure transient analysis (Lee, 1992). For instance, the higher the permeability, the more rapidly the fluid moves in and the quicker the pressure builds up.
Production well tests are an important for reservoir management because they provide information on flow rates, reservoir architecture, rock properties, and reservoir pressures. A production well test is performed by inducing pressure variations in a well over time. An example of this is where a production well is shut in to conduct a pressure buildup test. Fluid will then move into the pressure sink caused by the production, and the pressure will gradually increase in the well. The pressure data are used to assess the properties of the reservoir and the reservoir fluid around the wellbore by a technique known as pressure transient analysis (Lee, 1992). For instance, the higher the permeability, the more rapidly the fluid moves in and the quicker the pressure builds up.
Two types of tests can be run to give an idea of interwell communication. Interference tests are set up by assigning one of the wells in a specific sector of the reservoir as an observation well. Then one or a number of wells is produced from or injected into and the pressure response is measured in the monitor well. Pulse tests are a variation on the theme of interference tests. The difference is that the active well is shut in, returned to production, shut in, and so on, in a series of pulses. These tests are especially useful in assessing the communication between injection and production wells (Kamal, 1983).
Two types of tests can be run to give an idea of interwell communication. Interference tests are set up by assigning one of the wells in a specific sector of the reservoir as an observation well. Then one or a number of wells is produced from or injected into and the pressure response is measured in the monitor well. Pulse tests are a variation on the theme of interference tests. The difference is that the active well is shut in, returned to production, shut in, and so on, in a series of pulses. These tests are especially useful in assessing the communication between injection and production wells (Kamal, 1983).
Radioactive or chemical tracers can be put into an injection well and nearby production wells will be monitored to see when and where the tracers are back produced (Bjornstad et al., 1990). For example, radioactive tracers have been used in the Endicott field in Alaska to identify communication pathways between injection and production wells. The data were used to assess the validity of the geological correlation for the reservoir (Shaw et al., 1996).
Radioactive or chemical tracers can be put into an injection well and nearby production wells will be monitored to see when and where the tracers are back produced (Bjornstad et al., 1990). For example, radioactive tracers have been used in the Endicott field in Alaska to identify communication pathways between injection and production wells. The data were used to assess the validity of the geological correlation for the reservoir (Shaw et al., 1996).
==Fluid samples==
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
==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.
{{Fig 47
==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.
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 are acquired in the broadest sense by sending sound waves into the subsurface and then detecting the echo. Most of the energy will be transmitted deeper into the subsurface, but part of the energy will be reflected at interfaces of different densities and velocities within the rock layers. The reflected energy returns to the surface where it is recorded by geophones, electronic receivers that convert ground motion into electronic signals. The offshore equivalent of a geophone is a hydrophone, which records the pressure pulses returning through the sea. The strength of the reflected seismic energy depends on the acoustic impedance (AI) contrast at the boundary between two layers of rock. The AI is the product of the rock density and the transmission velocity. The higher the AI contrast, the greater the strength of the reflected signal.
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
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).
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 seismic data are interpreted with the principal objective of mapping out the structure of the reservoir. If the top of the reservoir gives a usable seismic reflection, a seismic time surface is mapped out. The map will be contoured in two-way time. It can be depth converted using velocity information to create a depth map in meters or feet.
==3-D seismic surveys==
The most common method of acquiring seismic data involves shooting a 3-D survey. This is where a dense coverage of seismic data has been collected over an area with the objective of determining spatial relations in three dimensions. The data are collected such that it can be processed to get as close to the correct spatial representation of the subsurface as can be practically achieved. This involves migrating the seismic data to correct for oblique reflections from dipping surfaces and faults. After processing, a 3-D data set will consist of a dense box-shaped grid of seismic data covering the field area. The grid comprises a series of inlines and crossline traces at regular intervals, every 12.5 m (41 ft) for instance.
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.