Software and Information Technology - The Three Components of Well Placement

1.5 The Three Components of Well Placement

1.5.2 Software and Information Technology

1.5.2.1 Real-time data transmission

1.5.2.1.1 Real-time transmission from downhole to the surface system

Data acquired by the downhole LWD tools is compressed, encoded and transmitted to surface, most commonly through a mud-pulse telemetry system. Due to the limited bandwidth of the current mud-pulse systems (typically 0.5 to 12 bits per second) the amount of data that can be transmitted to surface in real-time is limited. Improvements continue to be made in telemetry rate (the number of bits that can be transmitted per second) and data compression (the amount of data transmitted per bit). Selection of what data is to be sent is still required as bandwidth capable of transmitting all the data all the time, as is the case with wireline tools, is unlikely to be widely available in the near future.

Real-time data is grouped into data points (d-points) each of which represents a particular measurement (e.g. formation bulk density) or part of a larger collection of data such as part of an image which is spread across several d-points.

These d-points are grouped into frames which define the data to be transmitted when the BHA is in a particular mode of operation. For example, a frame designed for use when the BHA is sliding in a deviated well would contain the gravity tool face (GTF) and non-azimuthal formation measurements, as there is no point wasting bandwidth sending azimuthal data which cannot be acquired when the BHA is not rotating. A frame designed for use when the BHA is rotating would, in contrast, likely contain d-points for azimuthal and perhaps image data, but would not contain a tool face d-point as the tool face is not of interest when the BHA is rotating.

Generally real-time data is transmitted in 4 designated frames:

• Magnetic tool face (MTF) frame – used in near vertical wells when sliding.

• Gravity tool face (GTF) frame – used in deviated and horizontal wells when sliding.

• Rotary frame – used when the BHA is rotating.

• Utility frame – used to transmit data acquired while the mud pumps were off and hence the mud-pulse telemetry was not operational. This frame will generally contain the static surveys (acquired when the BHA is quiet) and hydrostatic mud pressure. It is increasingly used for applications such as acoustic (sonic and seismic) transit times and waveforms as well as formation pressure data acquired with the pumps turned off to minimize measurement interference.

Frame

Synchronization word and Frame Identifier

d-points

Figure 1-55: d-points containing the measurement data are grouped into frames.

The selection of which frame to transmit is made by the downhole tool based on the well inclination (MTF or GTF frame), whether the tool is rotating (rotary frame) and whether the mud flow has just started again after a period of no-flow (utility frame). After a few training bits to allow the surface system to synchronize, the frame identifier is sent. As both the surface and downhole systems have been programmed with the same frames, the subsequent stream of bits will be divided into the corresponding d-points and decoded by the surface system.

d-points Figure 1-56: The bit stream encoded in the mud-pulse pressure wave is divided back into the d-points by the surface system, which has been programmed with the same frame information as the downhole tool.

Decoding involves the conversion of the binary bit stream to decimal followed by application of the reverse transform that was applied to the data downhole. For example a downhole density measurement of RHOB = 2.4 g/cc may have 0.9 g/cc subtracted and the remainder divided by 0.01 giving a decimal number of 150. The eight-bit binary equivalent, 10010110, is transmitted via the mud-pulse system so the binary number 10010110, is now available at surface where it is converted back to the decimal number 150 and the reverse transform, RHOB_RT = 0.01*X + 0.9 g/cc is applied. The time RHOB_RT = 2.4 g/cc measurement (the _RT designating it as real-time data so that it can be distinguished from the recorded mode RHOB) is then available for visualization and interpretation.

1.5.2.1.2 Real-time transmission from the surface system to the decision-maker If the real-time data user and decision-maker are on the wellsite then further transmission of the data from the acquisition system may not be necessary. However, with increasing use of remote operations support, it is likely that the data will need to be securely distributed to approved users.

Data encryption and satellite transmission enable the data to be securely transferred from any rig to a satellite receiving station from which it can be distributed over the Internet while still encrypted. Dedicated user accounts with password protection ensure that the data is only available to approved users.

In a few seconds, data acquired under the extreme conditions of temperature, pressure and shock while drilling can be made available to approved users anywhere in the world for subsequent interpretation and decision-making.

1.5.2.2 Real-time information extraction

Having transmitted the data from the downhole tools to surface and from the surface acquisition computer to the decision maker, the data must then be presented in a manner that helps the decision maker extract the relevant information encoded in the data stream.

In the case of image data this is generally best achieved by 2-D and 3-D visualization of the data, color coded to represent the formation parameter being measured. The addition of interactivity and dip-picking to the visualization environment allows the decision-maker to extract quantitative information about the formation dip from the data stream. This facilitates well placement using the real-time dip determination technique.

The model-compare-update well placement method requires more sophisticated software support as the incoming real-time data must be displayed in comparison to modeled tool responses. The software must be able to create and modify a formation structural model populated with multiple formation properties, and a planned well trajectory. In addition, the software must be able to simulate (forward model) the response of the LWD tools and stream in the real-time trajectory and logging data so that they can be compared to the simulated log response. As discussed in section 1.4.1, discrepancies between the simulated and real data are an indication that the formation model does not accurately represent the subsurface formation and hence the model needs to be updated so that the simulated and actual data match. Once they match the position of the wellbore in the formation can be assessed and appropriate well placement decisions taken and communicated to the directional driller.

Presentation of this data is generally of the form shown in Figure 1-57. A curtain section of the formation along the planned well trajectory, color coded to show one of the formation properties of interested is plotted in the lower panel with true vertical depth as the vertical axis and true horizontal length as the horizontal axis. Formation structural information is captured in the scaled geometry of the curtain section layers and faults. The formation model can be color-coded for any of the formation properties entered during the pre-drilling model construction.

Both the planned and real-time well trajectories are generally displayed so that any departure of the actual well from the planned well trajectory can be identified. Note that the curtain section is constructed during the pre-drilling preparation phase when only the planned well is available.

Hence the curtain section is generally a 2-D vertical slice through a 3-D formation model along the planned well trajectory. If the actual well trajectory departs significantly from the azimuth of the planned well trajectory the curtain section may need to be reconstructed along the new well trajectory. More recent software allows log forward modeling and comparison in a 3-D environment, thereby removing this 2-D constraint.

Horizontal log tracks in the upper panel display both the real-time data and forward modeled log responses so that any discrepancies between them can be identified. Image data may also be displayed in the horizontal log tracks. If a discrepancy between the forward modeled and real-time logs is identified then interactive adjustments are made to the formation model. The simulated log responses are then recomputed for the edited formation model and compared again to the real-time data. This model-compare-update cycle is repeated until a match is achieved.

Phase Resistivity (ohm-m)GR (GAPI)Phase Resistivity (ohm-m)GR (GAPI) 0.2 200 100

True Vertical Depth, TVD (ft)

True Horizontal Length, THL (ft)

Real-time GR data (green) Forward modeled GR data (red)

Real-time well trajectory

2.7

1.7

RHOB (g/cc)

Curtain section showing the formation structural model color coded with a selected property value.