Borehole Imaging (Borehole Imaging Methods)

Borehole Imaging Methods

Borehole Imaging Methods

Image Processing

Enhanced downhole signal processing and data compression techniques have lead to a substantial increase in the amount of data transmitted uphole. These improvements, in turn, have created a need to increase processing capability. In recent years, developments in log data processing include:

faster processing rates,

more information made available from log measurements, and

more effective integration of data from multiple sources (such as drilling, mud logging, core analysis, geology, testing and production).

Borehole imaging data are processed to filter noise and apply resistivity or amplitude and travel time corrections. The images are then oriented using inclinometry and accelerometer data before being displayed for interpretation.

Typical processing features applied during the post-acquisition phase include:

interactive dip picking with several categorization levels,

image enhancement techniques,

borehole cross-sections generated from caliper data, and

speed correction algorithms.

 

Oriented Images

Acoustic and resistivity tools use a flat sheet of logging paper to present measurements taken within a cylindrical borehole. They present the image as either a flat plot of the "unrolled" cylinder, or as a 3D depiction of the cylinder. Figure 1 (FMI presentation showing sand-shale sequence and "bull's-eye" structure; courtesy of Schlumberger Oilfield Services) shows a flat plot. Figure 2 (FMI presentation of sand-shale sequence in 3D; courtesy of Schlumberger Oilfield Services) shows the same image presented as a "rolled-up" cylinder.

 

Borehole Imaging Methods

Dip Analysis from Acoustic and Resistivity Tools

The very tools that are able to distinguish such features as bed boundaries, laminations, and fractures are also capable of producing high-quality dipmeter logs (Serra, 1989).

Tool design features that provide a high degree of borehole coverage and high vertical resolution enable borehole imaging technology to be used to create dipmeters. Electrical imaging tools take advantage of electrode overlap and extensive pad coverage to produce very detailed dipmeter measurements ( Figure 1 – Dipmeter presentation of EMI tool in a laminated sand/shale sequence; courtesy of Halliburton Energy Services).

The electrical imaging tools also have smaller electrodes than conventional dipmeters, for enhanced lateral resolution (Antoine and Delhomme, 1993). Acoustic imaging tools use the high sample rate of the rotating transducer to obtain their dipmeter measurements. An acoustic tool was used to acquire the dipmeter data shown in Figure 2 (CBIL log with dipmeter presentation; courtesy of Baker Atlas).

 

 

The high density of measurements provided by each type of tool improves the accuracy of the dipmeter, and imaging technology helps to ensure that local heterogeneities are not misinterpreted as layer boundaries ( Figure 3 - Dipmeter presentation with fault plane detected by STAR Imager; courtesy of Baker Atlas).

 

Dipmeters produced by imaging tools can distinguish:

features that are not perfectly continuous or are interrupted by other features, such as fractures crossing bed boundaries or laminations;

small apparent angle between the plane and the borehole axis; and

highly deviated boreholes.

 

According to Serra (1989), any plane not perpendicular to the borehole axis intersects the cylindrical borehole surface along an ellipse. When cut and unrolled onto a flat log presentation, the ellipse is represented by a sine wave ( Figure 4 - Ellipse intersecting a cylinder, after Serra, 1989).

The azimuth taken at the lowest point of the sine wave indicates the apparent azimuth of the dipping plane. Its apparent dip angle is the maximum dip read at the inflection point. Its tangent is equal to the difference between the bottom and the top of the sine wave divided by the borehole diameter. The apparent strike of the plane is given by the azimuth at the bottom of the sine wave, plus or minus 90 degrees.

The user can choose to compute dips interactively on a workstation or compute dips automatically using a program that correlates inflection points and determines dip planes.

 
Borehole Imaging Methods

Image Analysis and Interpretation

The improved resolution and increased coverage of borehole imagers are used to:

· Describe structures and features such as faults and fractures,

· Define and characterize sedimentary bodies and environments,

· Determine sedimentary dip direction,

· Recognize and evaluate thin beds and internal bed characteristics, and

· Complement core data.

Here, we will describe some of the features commonly seen by borehole imagers.

Structural Analysis

Acoustic and resistivity borehole imagers provide a high degree of borehole coverage and high data density. These features provide benefits such as:

Detection and definition of faults or fractures,

Discrimination of sedimentary dips, and

Visualization of complex structures: folds, unconformities, reefs and salt domes.

Faults will show as features that are similar to fractures, but with more displacement from one side to the other. This displacement may produce depth shifts between the two sides of the event, often with different textures or a loss of continuity between the two sides, and often accompanied by abrupt changes in dip Serra (1989). The displacement and textural shift caused by faulting
is illustrated in Figure 1
(Fault, with no associated drag; courtesy of Schlumberger Oilfield Services)

Open fractures that are filled with mud, shale, or pyrite are more conductive than the surrounding formation. They will appear as slightly irregular, dark features that may not be seen by each pad. Since fractures are not perfectly planar surfaces, they will appear as vertical or inclined features that are seldom straight, and are often seen over a relatively long interval Serra (1989).

 

Fractures that are healed by cementation from formation fluids rich in salts produce images that are characterized by fine, vertical or oblique features. These fractures are resistive, and will therefor be lighter in color than the surrounding medium. The minimum detected fracture width is controlled by the width of the electrode, which is on the order of a few millimeters Serra (1989). An illustration of open and closed fractures is shown in Figure 2 (STAR Imager data used to distinguish open fractures [on the left] from closed fractures [on the right]; courtesy of Baker Atlas). Pattern recognition techniques may be used to find and measure fractures, and detect vugs, and nodules.

 

Textural Analysis

Reservoir porosity and permeability are influenced by textural features such as stylolites, vugs, burrows, and concretions. These fine features may be seen by imaging tools, and the accuracy of their definition is based on the resolution of the sensor. Sands, composed primarily of quartz grains, are highly resistive, and are seen as light-colored resistivity images. On the other hand, conductive shale fragments appear dark in resistivity images. Any textural differences between the two can be recognized by a change in overall resistivity due to a change in grain size.

 

Stylolites are commonly found in compact, cemented carbonates. They are seen as conductive, often undulating lines with abrupt and erratic short vertical displacements. They are accompanied by conductive tension gashes that are perpendicular to the stylolite (Serra, 1989).

Various rock textures are shown in the following examples:

( Figure 3 : CBIL image showing vugular porosity and stylolites; courtesy of Baker Atlas)

( Figure 4 : Burrows and root traces in a mudstone sequence; courtesy of Schlumberger Oilfield Services)

( Figure 5 :Solution breccia and unconformity in a sandy dolostone; courtesy of Schlumberger Oilfield Services).

 

 

Analysis of Bedding Features

Thinly laminated sand-shale sequences are often important producers of hydrocarbons. Conventional resistivity tools frequently do not have the resolution to detect thin laminations within a reservoir. However, borehole imagers are capable of detecting beds that are only a fraction of an inch thick. This capability allows easy identification of sand/shale facies within the formation for precise sand thickness counts.

Bedding features such as foreset beds produced by sand dunes, longshore bars, and point bars are easily recognized by their alternating laminae of coarse and fine-grained sediments. They show as features that are parallel, planar, or oblique to bedding boundaries, often with abrupt contacts at the base. These features are typically seen over a thick interval, and may sometimes be interrupted by other parallel features that dip in different directions. They often exhibit high resistivity contrasts caused by changes in grain size or porosity (Serra, 1989). An example of borehole imaging of bedding features is shown in Figure 6 (Cross-bedding shown on STAR Imager; courtesy of Baker Atlas).

 

Graded bedding shows a progressive change in grain size, which is reflected by a gradual change in color intensity on the image. The fining-upward sequence common to fluvial deposits, transgressive sands, and turbidite deposits is characterized by a change from light colors at the bottom of the sequence, to darker shades at the top. Coarsening- upward sequences are found in deltaic deposits, regressive barrier bars, and upper fan turbidite deposits; they are characterized by a change from dark to lighter shades (Serra, 1989).

Net Pay Determination

Resistivity imagers use microconductivity curves to help identify laminated intervals and bed boundaries or evaluate shale content within sands. Image analysis techniques are then used to assess formation properties. The borehole imager resistivity curve can be integrated with conventional resistivity and porosity logs to enhance hydrocarbon saturation computations and evaluate the quality and producibility of the reservoir.

 

 

Complement or Substitute for Core Data

Rock properties are too diverse to be adequately described by acoustic and resistivity measurements alone, so cores and core photos are often used to aid the interpretation of borehole images. Some operators run imaging tools through cored intervals to 'calibrate' the tools. Once tool resolution is deemed sufficient to discern thin pays, or distinguish between open and closed fractures within the reservoir, the operator may then elect to run the imaging tool in uncored wells within the reservoir. This saves the operator the cost of rig-time for coring, as well as the cost of core analysis.

Figure 7 (Comparison of EMI image and fullbore core, showing abrupt fault with no associated drag; courtesy of Halliburton Energy Services) shows a core photo on the far left side, and an EMI log with borehole image, diplog, and core simulation. The discontinuity in the core had erroneously been interpreted as an accidental break, while the log actually proved that a fault was present.