DAS enables simultaneous multiwell VSP

Understanding the geological features in which hydrocarbons are trapped is crucial for oil and gas production. Seismic surveys allow geoscientists to map subsurface geological features and define the distribution of different types of rocks as well as the fluids they contain. Repeated surface seismic surveys are widely used to monitor producing oil and gas fields.

FIGURE 1. A sketch of the experiment shows the mutual position of the well tracks for wells A, B, and C used in this trial. Only the sections of the wells containing fiber are shown. The dashed lines indicate planned sail lines of the shooting vessel. Near the platform the actual sail lines had to deviate from the sketched lines to avoid the safety zone around the platform.

Although time-lapse borehole seismic data can add to improved understanding of the reservoir, vertical seismic profiling (VSP) data in producing wells are rarely acquired. This is mostly due to the costly rig time and the technical difficulty in deploying the seismic array through a pressurized wellhead.

Silixa’s intelligent distributed acoustic sensing technology offers a cost-effective method for VSP acquisition in producing wells without disturbing the regular operations. The intelligent acoustic sensor (iDAS) measures the full acoustic field, capturing the full amplitude and phase of the incident wave up to frequencies of several kilohertz (kHz) with a wide dynamic range. The sensor can be retrofitted to existing standard telecom optic fiber and can be used as a massive acoustic sensor array.

Fiber-optic technology

When a pulse of light is launched into an optical fiber, a small amount of the light is naturally scattered and returns to the sensor unit. By analyzing these reflections and measuring the time between the laser pulse being launched and the signal being received, the iDAS can measure the seismic signal at all points along the fiber, which can be tens of kilometers long. Typically the spatial resolution obtained with such a distributed fiber sensor is about 1 m (3 ft).

The principle of distributed sensing is well known from the distributed temperature sensor, which uses the interaction of the source light with thermal vibrations (Raman scattering) to determine the temperature at all points along the fiber. Because the returning light level is very weak, this measurement typically requires a few minutes averaging to get a reasonable signal-to-noise ratio. With the new system, measurements can be made at a rate of up to 100 kHz, opening up possibilities for seismic measurements.

FIGURE 2. Shot gathers from the same seismic shot were recorded by fibers in two different wells. Each plot contains about 2,000 traces. The shot was fired vertically above Well A on the sketch shown in Figure 1. Data recorded in Well A are displayed to the left. The plot to the right shows data from the same shot recorded in Well C. A bandpass filter has been applied to the data before display.

North Sea case study

A simultaneous multiwell iDAS acquisition has recently been carried out in the North Sea using optical fibers installed in three wells drilled from the same platform. Figure 1 shows the layout of the trial, with the three wells labeled A, B, and C. Wells B and C had redundant fiber-optic cables, and simultaneous measurements were made on cables in all three wells and also on two cables in the same well. Four iDAS units were measuring simultaneously during the seismic acquisition.

The units were retrofitted to the top side of the fibers to record the seismic signals in the wells while the seismic vessel was shooting in the area around the platform. A trigger transmitted by very high frequency from the seismic source vessel to the platform-based synchronized units was used to initiate each sequential shot acquisition. The experiment used a towed source, and lines were shot over each of the three well tracks as shown in Figure 1. In addition, a few other lines were shot, including one line dividing the angle between wells B and C and some repeat lines. The operation of the wells was completely unaffected by the data acquisition. All three wells were producing during the trial, allowing the possibility for iDAS-based flow measurements to be carried out alongside the seismic survey. After completion of the trial, the fibers were put back into normal operation.

The multiwell acquisition was carried out successfully, with all four units recording data for the entire seismic survey. The loss in the optical path for each of the fibers chosen for the trial was similar, and good data quality was obtained. Figure 2 displays two shot gathers obtained from the same seismic shot as recorded by fibers in two different wells.

The shot in Figure 2 was fired vertically above Well A and recorded simultaneously in Well A and Well C. The recording of this shot in Well A corresponds to conventional vertical incidence or walkaway geometry. The geometry of the recording of the same shot in Well C is more unusual. In this case the shot is fired from a position laterally displaced from the well track of the well in which it is recorded. Figure 3 shows a qualitative comparison of data recorded simultaneously by fibers in two different cables installed in the same well.

FIGURE 3. Shot gathers are shown for the same seismic shot recorded by fibers in two different cables, both installed in Well C. The shot for which the displayed data were recorded was fired vertically above Well C. The same bandpass filter has been applied to each shot gather.

The distributed acoustic fiber-optic technology has considerable benefits. It offers a cost-effective method for real-time permanent reservoir monitoring, improving the overall recovery from the well. The iDAS measures the first break along the entire well with one single shot and allows subsidence monitoring as well as reservoir imaging using advanced VSP processing. The primary value to operators, however, is that while acquiring good-quality seismic data, production remains undisturbed.

References available.