DESIGN AND FIELD TESTING OF A NEW HIGH-DEFINITION MICRORESISTIVITY IMAGING TOOL...

SPWLA 55th

Annual Logging Symposium, May 18-22, 2014

1

DESIGN AND FIELD TESTING OF A NEW HIGH-DEFINITION

MICRORESISTIVITY IMAGING TOOL ENGINEERED FOR OIL-BASED MUD

Richard Bloemenkamp, Tianhua Zhang, Laetitia Comparon, Robert Laronga, Shiduo Yang, Sihar Marpaung,

Elodie Marquina Guinois, Glenn Valley, Patrick Vessereau, Ehab Shalaby, Bingjian Li, Anish Kumar, Rick Kear,

and Yu Yang, Schlumberger

Copyright 2014, held jointly by the Society of Petrophysicists and Well Log

Analysts (SPWLA) and the submitting authors.

This paper was prepared for presentation at the SPWLA 55th Annual Logging

Symposium held in Abu Dhabi, United Arab Emirates, May 18-22, 2014.

ABSTRACT

While they provide a recognized technical advance for

wells drilled with oil-based mud (OBM), OBM-adapted

microresistivity images of the last 13 years remain far

from the geologic interpretability provided by imagers

that operate in a water-based mud (WBM) environment.

Recently the use of a high-definition WBM imager has

been demonstrated in wells drilled with OBM, but its

application has been principally limited to high-

resistivity formations with excellent hole conditions or

to cases where the drilling fluid has been engineered to

favor acquisition.

To fill this gap, a new wireline microelectrical imager

has been introduced, engineered from the ground up to

acquire high-definition, full-coverage images in any

well drilled with OBM. The all-new physics

architecture includes a strategy to minimize and

eventually eliminate the inevitable contribution of the

nonconductive fluid and to optimize the mode of

operation in accordance with formation parameters.

New tool-specific processing steps complement the

standard borehole image processing workflow to render

highly representative images of the formation.

Examining the measurement response in detail, via both

modeling and real-world examples, demonstrates

several favorable characteristics, for example,

sensitivity to vertical as well as horizontal features,

reduction of shoulder-bed effects, and reduced

sensitivity to desiccation cracks.

The novel mechanical architecture includes a new

sonde design with significant operational advantages. It

conveys a sensor array composed of 192

microelectrodes providing 98% circumferential

coverage in an 8-in. borehole. The individual

microelectrodes are smaller than those of industry-

standard imagers for WBM, each with a surface area of

only 10.8 mm2, which provides excellent spatial

resolution.

From a field test comprising more than 40 operations in

various OBM fluids, high-definition images were

acquired in a variety of environments, from high-

resistivity carbonates to shales and low-resistivity

clastics, demonstrating the robustness and widespread

applicability of the new tool. The examples include

challenging environmental conditions and they explore

the limits of accurate measurement. Comparison with

legacy images demonstrates that the new physics of

measurement coupled with the high-resolution, high-

coverage sensor array has achieved much more than a

microimaging step change. The new images faithfully

reproduce formation geology with photorealistic clarity

and promise to revolutionize the geologic interpretation

of wells drilled with OBM.

HISTORY

The benefits of microresistivity imaging of geologic

formations penetrated by boreholes are well-known,

and a large variety of microresistivity imagers exist

from various suppliers. For wells drilled with WBM

the quality of the images is generally known to be

very good; the images present a “photorealistic”

picture of the formation within the limits of their

0.2-in. spatial resolution. When imaging wells

drilled with oil-based mud (OBM), however, it is

safe to say that the industry has not come close to

the same level of ground truth. Image quality is

often limited, especially in low-resistivity

formations such as those commonly found in

deepwater offshore environments.

To date, the best performing imagers in these

environments produce images with a measurement

aperture of 0.4 in. and a borehole surface coverage

of roughly 64%. In addition, these imagers,

depending on the technology used, may introduce

some artifacts, for example, the appearance of

“shadow” beds as neighbors to beds with high

contrast, or differences in the representation of

geological events depending on the orientation of

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the events with respect to the imaging device.

Certain environmental features such as mud cracks

may be so strongly present in these images that they

hide the geology behind them. One independent

study by Bourke et al. (2010) found that overall,

these images resolve approximately an order of

magnitude fewer sedimentary surfaces than standard

wireline images acquired in the WBM environment.

With the increase of highly deviated and horizontal

wells, pad application, which is key for high-quality

borehole imaging, has become a challenge in

particular if high borehole coverage is desired. We

therefore refrained from improving the existing and

redesigned from zero to address numerous important

concepts. In highly deviated and horizontal wells it

is advantageous if the pad arms are only used to

apply to pad to the borehole and not involved in

centering the tool. This makes it simpler to design a

system where all pads are independently applied to

the borehole wall, which reduces the risk of some

pads not touching.

Additionally it is well-known that one of the prime

challenges of microresistivity imaging lies in the

depth-correction of the images, which is often

needed after the logging and is due to irregular tool

movement downhole. For depth correction to work

optimally it is best if all the pads have the same

vertical offset to the bottom of the tool. A second

best is to have two groups of pads vertically

separated by as short a distance as possible.

TOOL INTRODUCTION

We propose a new OBM-adapted microresistivity

imager based on a new measurement principle that

enables higher resolution, larger borehole coverage,

lower sensitivity to borehole wall imperfections

such as mud cracks, and fewer artifacts such as

artificial side beds and event orientation dependency

compared with previous-generation OBM imager

tools.

The tool mechanics are significantly improved to

allow the ability to log downward, improve pad

application to the formation, and to optimize vertical

offset between the top and bottom pads for good

depth correction of the borehole images (Figure 1).

The electronics of the tool are completely new. For

example, the operating frequencies are higher than

those of any previous imagers and the pad-to-

cartridge communication is fully digital.

The specifications of the tool are listed in Table 1.

Table 1 Specifications of the new high-definition

OBM-adapted microresistivity imager.

Number of azimuthal

pixels

192

Vertical resolution* 0.24 in.

Horizontal resolution* 0.13 in.

Depth of investigation 0.2 in.

Formation resistivity 0.2 to 20,000 Ωm

Azimuthal coverage 98% in 8-in. borehole

Logging speed 3600 ft/h (0.2-in. sampling)

1800 ft/h (0.1-in. sampling)

Borehole size 7.5 to 17 in.

Drilling fluid Nonconductive mud such as

oil-base mud

Temperature 350 degF (175 degC)

Pressure 25,000 psi

Logging direction Log down and log up

* Effective electrode size

TOOL MECHANICS AND ELECTRONICS

The new tool consists of three parts:

1 sonde containing 8 pads

1 power supply cartridge

1 acquisition cartridge with inclinometer

module

Figure 1 shows the tool sonde with an enlarged view

of the top pad section. The eight pads with dual arms

are designed so that the sonde can be used both in

log-up and log-down mode.

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Fig.1 The sonde of the new borehole imager tool

containing 8 pads each supported by two arms.

In particular, when the tool is combined in a tool

string with other tools the down-log capability gives

extra advantages. Traditionally imager tools are

often combined with acoustic tools that have

powered arms to centralize them. These powered

arms may generate friction between the tool string

and the borehole that causes the tool string to move

in a stick-and-slip mode. In addition, various tools

have logging speed restrictions and the stick-and-

slip movement of the tool string becomes worse for

reduced logging speeds.

With the down-log capability the arms of other tools

can be closed during the down-log while the down-

log speed can be optimized for the imager tool. In

several field tests, tool motion was smoother during

the down log than in the up log, resulting in less

stick-and-slip movement on the log. This is visible

through smaller image offsets between neighboring

pads.

The tool has two sets of four pads. The four pads of

each set are at the same depth level while the two

sets of pads are vertically offset by approximately

3.6 ft, which allows for reasonable depth correction

of the borehole images produced by the tool. All

tool arms are fully independent, and the pads are

connected to the arms with swivel joints. The pads

can swivel ±15° around the long axis and can also

change pitch angle because the top and bottom arms

of each pad are independent. This configuration

provides very good pad application to the formation

in wells with arbitrary profiles and deviation.

The tool is approximately centralized by the action

of passive external centralizers. Because all arms are

independent, there is no need to centralize the tool

perfectly. The processing software ensures that the

image data are correctly mapped relative to the

borehole even in an eccentered case. Because the

independently suspended pads do not centralize the

tool, they can be applied to the formation using

spring force only. This reduces the friction of the

pad against the formation and therefore further

reduces the stick-and-slip motion discussed

previously. Bow springs are located behind both the

upper and lower pad arms for equilibrated pad

application.

The tool measures eight radii: four from upper arms

of the top four pads and four from bottom arms of

the bottom four pads. The borehole area is computed

from these eight radii with a proper eccentering

correction. Borehole volume and average hole size

can be computed afterward.

Most of the tool electronics are integrated in a

special-purpose component to accommodate more

sensors, smaller pads, and digital communication

between the pads and the tool cartridge. The latter

brings significant advantages in terms of noise

immunity and reliability through reduction of the

number of electrical connections.

MEASUREMENT PRINCIPLE

Unlike standard water-based mud (WBM) imaging

tools, measurement by the new high-definition

OBM-adapted microresistivity imager is performed

entirely on the tool pad. This pad is equipped with a

row of button electrodes in the center, a guard

electrode surrounding the buttons, and two return

electrodes on either side of the guard.

The button electrodes and the guard electrode are

kept at roughly the same potential and together they

form the injector. The two return electrodes are also

kept at roughly the same potential. A megahertz-

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range voltage is applied between the injector and the

returns.

When placed in front of the formation in a borehole

containing OBM drilling fluid, current will flow

from the injector through the mud into the

formation, back through the mud and to the returns

(Figure 2). Part of the current will flow to the top

return, part of the current to the bottom return. The

reason for having two returns is mainly to have a

symmetric bed response.

Fig.2 Tool pad and current flow. The button and

guard electrodes send current through the mud into

the formation. The current returns to the large return

electrodes on both sides.

The current flowing out of each button is measured

and the complex button impedance Zb is calculated

as

Zb = Vr/Ib, .................................................................. (1)

where Ib is the button current and Vr is the return-

injector voltage. The complex button impedance

contains both the amplitude ratio between the

voltage and the current, and the phase shift between

these two signals.

The button impedance and the current path for each

button naturally lead to a lumped-circuit model of

the measurement consisting of a complex mud

impedance and a complex formation impedance in

series. The mud impedance between the returns and

the formation is small compared with the mud

impedance between the injector and the formation.

In a first-order approximation it can therefore be

neglected.

Legacy borehole imaging tools generally use

operating frequencies in the kilohertz range. For the

new high-definition OBM-adapted microresistivity

imager, higher frequencies are used to ensure lower

mud impedance. OBM is known to behave as a

lossy dielectric while over a large resistivity and

frequency range the formation behaves as a resistor.

Therefore, the impedance of the mud decreases

approximately inversely proportional with the

frequency while the impedance of the formation

remains approximately constant with frequency. The

result is that the sensitivity of the button impedance

to the mud impedance decreases while the

sensitivity to the formation impedance increases.

Unfortunately we cannot increase the frequency

indefinitely, and depending on the formation

resistivity there is a frequency in the megahertz

range for which the permittivity of the formation

starts to become non-negligible. The remaining

effect of the mud impedance is still so high that the

button impedance is very dependent on the thickness

of the mud layer between the button and the

formation. As a result the borehole images of Zb

would show significant standoff and rugosity effects

in low- to medium-resistivity environments.

To correct for the remaining mud impedance

contribution, the phase difference of the mud and

formation impedances is used in what we call Z90

processing. Figure 3 shows the complex impedance

plane with three vectors: the lossy capacitive mud

impedance vector Zm, the resistive formation

impedance vector Zf and the button impedance

vector Zb, which is the sum of the two previous

impedances and which is measured. The goal is to

derive an approximation of the length of the

formation impedance vector from the measured

impedance. The chosen solution is to determine the

phase angle of the mud vector and thereafter to

calculate the distance between the button impedance

and its projection on the line through the mud

vector. This can be written as

Z90 = |Zb| × sin(φb – φm) ≈ |Zf |, ................................. (2)

where Z90 is called the orthogonal impedance and φb

and φm are the phase angles of the button impedance

and the mud impedance, respectively. If the mud

angle is accurate then Z90 is effectively independent

of the mud vector.

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Fig.3 The complex impedance plane. The

measured complex button impedance Zb is the sum

of the mud impedance Zm and the formation

impedance Zf. The vector plots are for a thin mud

layer between the electrodes and the formation

(left) and for a thicker mud layer (right). The Z90

component is an approximate measure of

formation impedance independent of the

magnitude of the mud impedance.

The optimal operating frequency depends on the

resistivity of the formation. By using two

frequencies the most appropriate resistivity range

can be covered. In the resistivity range below

roughly 10 Ωm orthogonal processing is applied to a

measurement at the high frequency: ZT90_F2. In

the range from 10 to 120 Ωm orthogonal processing

is applied to a measurement at the lower frequency:

ZT90_F1. Finally in the range above 120 Ωm an

average mud impedance vector is estimated and

subtracted from the button impedance for the lower

frequency. The result is called the mud-compensated

amplitude: ZTBAMC. The ZT90_F2, ZT90_F1, and

ZTBAMC processing methods also include scaling

by a geometric factor to convert impedance (in Ω) to

impedivity (the inverse of the complex conductivity

in Ωm).

Figure 4 shows the responses of the ZT90_F2,

ZT90_F1, and ZTBAMC processing methods as a

function of formation resistivity. These responses

were obtained with modeling software that generates

full-wave finite-element solutions of Maxwell’s

equations in 3D. The solid curves show the apparent

resistivity for each of the methods for 0.1-in. pad to

formation distance for a known loss tangent of the

borehole fluid with an average relative dielectric

permittivity close to 8 and for an empirically

determined relationship between the formation

conductivity and permittivity.

In reality, the standoff, borehole fluid, and relation

between formation permittivity and conductivity

vary. In addition, it is inevitable to have some

uncertainty in the measurement. The influence of

these variations and uncertainties has been estimated

and propagated to the three apparent resistivities.

This allowed us to determine approximate upper and

lower bounds for the apparent resistivity. It is

illustrative to see how each processing method has a

region where the upper and lower bounds are close,

indicating a measurement that is robust against the

given uncertainties. As we move away from these

sweet spots the methods become more sensitive to

the various uncertainties until a point where the

methods become unusable or even show reversed

polarity or “rollover,” as with the ZT90_F2 and

ZT90_F1 methods.

As long as the correct resistivity ranges for each

method are respected, we obtain a robust apparent

resistivity that is monotonic for the full range from

0.2 to 20,000 Ωm. Initially, we apply all three

modes of processing over the entire acquired

interval. Then, based on the data at the two

frequencies, a “blending logic” determines the

approximate resistivity of the formation at each

point and selects among the three modes to produce

a single, continuous blended image from each pad

spanning the full resistivity range. This technique,

which we refer to as “composite processing,” is

computationally efficient. Composite processing is

normally conducted on a commercial Windows-

based wellbore interpretation platform, but a more

limited version is available within the acquisition

platform, which can even be applied in real time

when a first “quicklook” image is required.

Above approximately 500 Ωm the apparent

resistivity tapers off due to the dielectric effect of the

formation. This can be corrected by again using an

approximate formula for the relationship between

formation conductivity and permittivity. To date we

have not considered this correction as valuable. For

example, it has no influence on statically and

dynamically normalized resistivity images. Strictly

speaking, the processing methods are closer to

apparent impedivity.

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TOOL RESPONSE MODELING

Figure 5 shows a 3D modeled pad of the new

imager injecting megahertz-frequency current from

the electrode in the middle into a 1-Ωm

homogeneous formation. The current splits and

returns to the return electrodes at the top and bottom

of the pad.

Layer response. Most of the value of borehole

images is in the correct geometrical representation

of borehole features such as layers, laminations,

texture, and other events. The response to various

layers has been modeled and Figure 6 shows a small

number of response curves in the common

resistivity range from 1 to 10 Ωm. The curves show

that the measurement behaves well for both

positively and negatively contrasting layers, for

weakly and strongly contrasting layers, and for thick

and thin layers. In particular no significant side

lobes or horns are present, as have been observed

with other OBM-adapted imagers.

Fig.5 An impression of the 3D modeling geometry

and electromagnetic field distribution. Cones

indicate the direction of the current.

Fig.4 The relationship between the computed resistivity and the true resistivity for three different

processing methods (solid) and estimated uncertainty curves for the three methods (dotted and dashed).

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Fig.6 Layer response curves. On the left: 1-Ωm background, 10-Ωm layers (dashed), and 3-Ωm layers

(solid). On the right: 10-Ωm background, 3-Ωm layers (solid), and 1-Ωm layers (dashed). The 5-in.

layers are in blue and 0.5-in. layers in black.

Fig.7 Response to gradually thinning 1-Ωm layers in a 10-Ωm background. From left to right: dark gray

layers have widths of 0.1, 0.2, 0.4, and 0.8 in. The spacing between two layers (white) is equal to the

thickness of the layer on the left.

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The thin-layer response shows less contrast than the

thick layer. Enhancement filters can boost the

contrast of thin layers. For example, a high-spatial-

frequency booster could correct this effect. We have

not chosen to do this at this stage because of the risk

of introducing artifacts. We believe that dynamic

normalization of the generated borehole image is

usually sufficient to bring out lower-contrasting thin

layers, with the normalization length as a well-

understood parameter for the interpreter.

Resolution. One of the key features of the new

OBM-adapted imager is its high resolution leading

to very clear and natural texture representation. To

investigate the resolution aspect of the new imager

in more detail, its response to a sequence of layers

with diminishing thickness was modeled in Figure 7.

The resulting curves are the responses for three

different standoffs of 1, 2, and 5 mm that show that

subsequent layers are distinguishable down to very

thin layers and layer separation but that the contrast

gradually decreases. This decrease is desirable

because it avoids aliasing when layers become too

thin with respect to the sensor size or sampling.

Layers of 0.2-in. thickness with 0.2-in. separation

are clearly distinguishable as long as the standoff is

small enough and the contrast of the layers and

measurement precision are sufficient. The response

curve for 2 mm standoff shows only minor

degradation of the response contrast with respect to

the 1 mm standoff response.

The response curve for the large standoff of 5 mm

shows that in this resistivity range the measurement

can still clearly distinguish very thin layers. In

reality, the presence of noise may lead to reaching

the detection limit before reaching the resolution

limit for this case.

Depth of investigation. Two investigation methods

are provided for users to understand the response

penetration depth into the formation.

The first method is to examine the current

distribution in a homogeneous formation. Figure 8

shows the current distribution in front of the middle

injection electrode at different formation resistivities

and different frequencies.

The radial distance where the current drops to 1/e

(36.8%) of its initial value in the formation can be

identified as the radial penetration length. This

indicates up to which radial distance the majority of

the current (63.2%) penetrates. The values are

summarized in Table 2.

Fig.8 Current distribution in a homogeneous

formation for various resistivities.

Table 2 Radial distance of the pad current coverage.

Frequency and Formation

Resistivity (Ωm)

63.2% of Distance (in.)

HF 1 0.24

LF 1 0.25

HF 10 0.24

LF 10 0.24

HF 100 0.26

LF 100 0.24

HF = high frequency; LF = low frequency

The second method to examine the radial response

is by modeling the “electrical penetration length,”

which describes the radial depth into the formation

at which a dipping bed boundary is detected.

Characterization of the electrical penetration length

is critical for borehole imaging tools because it has

an important influence on dip computations. Three

configurations of dipping beds are simulated. The

position when the new OBM-adapted imager pad is

right in front of the dipping bed boundary (z = 0) is

shown in the Figure 9.

3.5 4 4.5 5 5.5 6 6.5 710

-8

10-6

10-4

10-2

100

Radial Position [inch]

No

rmal

ized

Cu

rren

t

HF 1 m

HF 10 m

HF 100 m

LF 1 m

LF 10 m

LF 100 m

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Fig.9 Imager pad in front of a dipping bed boundary. The dip angles are 26.6°, 45.0°, and 63.4°.

Three resistivity contrasts are simulated as R1/R2 =

2/1, 5/1, and 10/1. Figure 10 shows the simulated

resistivity for the new OBM-adapted imager pad for

the 26.6° dipping bed case with three resistivity

contrasts.

The electrical penetration length (EPL) is an average

measure of how deep into the formation the pad is

measuring. For a dipping interface it can be chosen

as the penetration distance where the pad is

“equally” influenced by the resistivities above and

below the interface. The EPL is thus determined

from the modeled dip angle and vertical position

where the imager pad reads the resistivity equal to

the square root of (R1 × R2).

This radial distance is summarized for three dipping

beds and three resistivity contrasts in each dip case

in Figure 11. The EPL is taken as 0.2-in. based on

the statistics.

Fig.10 Modeled resistivity response of pad in front of a 26.6° dipping bed boundary, with R1/R2 = 2/1,

5/1, and 10/1 contrasts.

-10 -8 -6 -4 -2 0 2 4 6 8 100

1

2

3

Ap

p.

Res

. [

m]

Hole Diameter 8.5 inch

-10 -8 -6 -4 -2 0 2 4 6 8 100

2

4

6

Ap

p.

Res

. [

m]

-10 -8 -6 -4 -2 0 2 4 6 8 100

5

10

Pad position [inch]

Ap

p.

Res

. [

m]

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Fig.11 Computed electrical penetration lengths for

three dip angles and three different contrasts.

CASE STUDY 1: UNCONVENTIONAL

SHALE RESERVOIR IN THE UNITED

STATES

An operator in the US drilled a well for the

evaluation of an unconventional (shale) reservoir.

There were three main objectives for running the

new high-definition OBM-adapted microelectrical

imager in this well: natural fracture identification,

accurate geologic and depth context of sidewall

cores, and mapping the sedimentology and

stratigraphy of formations above and below the

target shales. In the past, it was a challenge to

achieve these objectives in wells drilled with OBM

due to the technical limitations of legacy OBM-

adapted imagers as previously mentioned.

Fig.12 A 1/50-scale example of subvertical natural fractures imaged by the new high-definition OBM-adapted

microresistivity imager in Shale B. From left to right: track 1: depth scale in ft with bit size and gamma ray (GR)

curve; track 2: dynamic high- definition images with sinusoids of fracture traces picked; track 3: tadpole plot

showing dip azimuth and strike for individual resistive fractures identified on images and a stereonet summary of

strike for all fractures within the presented interval; and track 4: clean (uninterpreted) dynamic high-definition

images.

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Natural fracture characterization. Identification

and characterization of natural fractures provides

critical information for the evaluation and

development of many unconventional shale

reservoirs. Fractures can provide potential

enhanced reservoir permeability if open, and they

influence hydraulic fracture propagation in terms

of initiation, orientation, and overall fracturing

network complexity during the stimulation process

even if closed, because closed fractures still

represent planes of weakness in the reservoir. In

the past there were two challenges for the

identification of natural fractures in this shale

formation when drilled with OBM. First, imaging

and correlating the fracture traces around the

borehole was not always an easy task due to the

existing limitations of image resolution and

circumferential coverage. Second, the incidence of

fractures in a vertical pilot hole can be low

because natural fractures in the studied shale are

typically vertical or subvertical in dip. With legacy

imagers this presents an additional challenge due

to the previously mentioned reduced sensitivity to

wellbore-parallel features.

In the studied well drilled with an 8.5-in bit, high-

resolution resistivity images were successfully

acquired with excellent data quality and 93%

effective circumferential coverage. There are two

shale units, nominally referred to as Shale A, the

targeted reservoir, and Shale B, which overlies it.

Natural fractures are well observed within Shale B

Fig. 13 A 1/10-scale example of small natural fractures imaged by the new high-definition OBM-adapted

microresistivity imager in the studied Shale A. A sidewall core hole is also visible at xx98.5. From left to right: track

1: depth scale in ft with GR curve; track 2: dynamic high-definition images with sinusoids of fracture traces picked;

track 3: tadpole plot showing dip azimuth and strike for individual resistive fractures identified on images and a

stereonet summary of strike for fractures within the targeted shale; and track 4: static high-definition images.

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with accurate dip and strike interpreted. Figure 12

shows an example of natural fractures clearly

imaged on the high-resolution resistivity images.

Unfortunately only limited fractures were

encountered in Shale A due to the generally low

chance of intersecting high-angle fractures in the

pilot well.

Fracture analysis in Shale B shows that they are all

vertical or subvertical, striking dominantly ENE–

WSW (average strike at 75°–255°). It is expected

that the fracture system in both shales would be

similar in orientation, as both units experienced

similar tectonic history although fracture intensity

may vary either vertically or in lateral space

between the two shales. Therefore, the dominant

fracture set in Shale A can most likely be expected

to have ENE-WSW strike and subvertical dip.

Fortunately, there are a few small-scale or non-

wellbore-crossing fractures observed in Shale A to

validate this prediction. Figure 13 shows two small

fractures seen on the images that confirm the high

dip angle and the strike of 70°–80° or ENE–WSW.

From the new OBM-adapted images, the operator

gained confidence that the ENE–WSW subvertical

fracture set is likely an important fracture set in

Shale A as well.

It is worth noting that the fractures are present in

the image primarily as resistive features relative to

the matrix, as expected for the OBM environment.

Of course, from the resistivity response alone, it is

not possible to determine if fractures are open or

closed. An advanced study by Chen et al. (2014)

on the images from this well suggests that they

may be at least partially open at the wellbore.

Determining sidewall core position and context.

Another important objective was to determine the

precise context from which sidewall cores had

been taken on a previous descent. Figure 14 shows

two short intervals where sidewall cores were

taken with the exact core plug position indicated

by small round holes left after core plugs were

removed at depths of xx22.5 ft and xx34 ft.

Although coreholes are typically assumed to be

filled with resistive mud, they may sometimes

appear as conductive features due to the “rollover”

effect of the Z90 processing described above. This

can occur because the coreholes are a relatively

small feature having an extreme contrast against

the lower background resistivity. The composite

processing in this case has selected the mode that

is most “in tune” with the formation resistivity.

Reservoir properties can be highly variable within

a vertical sequence in a shale. Knowing the exact

sidewall core location provides aid in

understanding how representative each sample is

of bulk reservoir properties. In addition, the

identification of facies or rock types interpreted

based on the new high-definition OBM-adapted

microresistivity images can help to facilitate a

petrophysical rock-typing workflow in

combination with laboratory measurements on

multiple cores taken throughout the studied

section.

Fig. 14 A 1/10-scale example of sidewall core positions

imaged by the new high-definition OBM-adapted

microresistivity imager. From left to right: track 1:

depth scale in ft with GR curve; track 2: static high-

resolution images with sidewall core position indicated;

track 3: blank tadpole plot; and track 4: dynamic high-

resolution images.

Sedimentological and stratigraphic details. As a

secondary objective for the studied well, the new

high-definition OBM-adapted microresistivity

images were acquired in fluvial-dominated sand

deposits above the targeted shales for purposes of

gathering stratigraphic information. Figure 15

shows an example of cross-bedded sands with

sedimentary structures and textural details clearly

imaged on the high-resolution image log. Three

sets of cross-beds observed in this example most

likely represent channel lateral acretions

succeeded by two sets of traction deposits on the

channel bottom. Their dip azimuth provides

important paleocurrent data when corrected for

structural dip.

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A summary azimuth plot is present for each cross-

bed set in the third track in Figure 15. Strike of the

lateral accretion set indicates the channel axis as

W20S, whereas dip of the two upper cross-bed sets

indicates dominantly westerly current direction.

The characterization of paleocurrent and

depositional environment based on detailed

sedimentary structural and textural information

from the image offers important information for

understanding the evolution of depositional

systems within the basin.

Fig. 15 A 1/10-scale example of cross-bedded fluvial sands imaged by the new high-definition OBM-adapted

microresistivity imager. From left to right: track 1: depth scale in ft with bit size and GR curve; track 2: static

images with markup; track 3: tadpole plot showing structurally corrected dip and azimuth of each individual cross-

bed as well as set boundaries identified on images with a stereonet summary of dip azimuth for each cross-bed set

within the presented interval (strike in the case of the lower set, which represents lateral accretions); track 4: clean

dynamic images.

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CASE STUDY 2: DEEPWATER GULF OF

MEXICO

Deepwater depositional systems in the Gulf of

Mexico are universally drilled with OBM and

represent the most challenging environment in the

world for the acquisition of high-quality borehole

images. While deep wells (often below 30,000 ft)

and high pressure (often approaching 30,000 psi)

present obvious operational challenges, it is the

measurement challenges that are most daunting.

Low formation resistivity, commonly 1 Ωm in

shales and as low as 0.2 Ωm in water-bearing

sandstones, implies that we are trying to measure a

very small signal. There is little tolerance for

measurement error or noise; imaging tools designed

for this environment must have the highest-precision

electronics and signal processing to be capable of

faithfully capturing subtle variations in the

formation resistivity.

An industry-standard OBM-adapted imager

introduced in 2001 (Cheung et al.) has been

frequently run in this environment during the last

decade. For certain applications it has enjoyed

reasonable success despite its limitations; it has been

especially successful in structural analysis of

tectonically disturbed sections and in differentiation

of sand and shale, particularly in thin-bedded

depositional environments. Sedimentological facies

classification is sometimes performed when the data

is of top quality, preferably with some conventional

core to provide a control on the interpretation.

At this point, the interpretability of the legacy OBM-

adapted images reaches a limit. These

interpretations remain speculative in nature and

the number of facies that can be differentiated are

limited. Thick sandstone units often appear to be

“massive” or “blocky” because few internal

structures can be observed other than what appear to

be rip-up clasts. Orientable features indicative of

paleoslope or paleocurrent direction are rarely

observed in the legacy OBM-adapted images. Even

simple applications such as structural dip

determination in shales are sometimes challenging

in cases where dehydration cracking dominates the

images.

Fig. 16 A typical sequence of sediments resulting from

the migration of a levied submarine channel and its

associated deposits. From left: track one: gamma ray;

track two: enhanced static image of the new OBM-

adapted imager; track three: tadpole plot showing true

(structurally uncorrected) dips; track four: detail of

enhanced dynamic image on a zoomed 1/10 scale with

dip interpretation; track five: zoomed tadpole plot.

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Fig. 17 Detailed 1/10 scale example of a typical high-resolution net sand count analysis performed with the new

high-definition OBM-adapted images. From left: track one: array induction resistivity vs. impedivity of the center

button of pad one; track two: dynamic OBM-adapted image; track three: static OBM-adapted image; track four:

shale-silt-sand classification; track five: cumulative thickness of sand and silt; track six: bed thickness.

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Data acquisition and processing. We present an

example of the new high-definition OBM-adapted

images recently acquired in the deepwater Gulf of

Mexico. The studied wellbore targeted elements of

a deepwater slope system. The borehole was

drilled with a common high-performance

synthetic-base mud using a 9-7/8 in bit. The new

imager was run in combination with an advanced

sonic tool. Images were acquired during both

down and up passes, with the clear result that the

downlog images were of better quality due to

fewer and lesser stick-and-slip events.

Following acquisition, data were loaded on a

commercial wellbore interpretation software

platform for processing and interpretation. After

composite processing was performed, an improved

version of the method of Zhang et al. (2006) was

run to fill the gaps between the pads. In this hole

size, real circumferential coverage is

approximately 80%, and the algorithm does a

generally outstanding job. The resulting images

are both more aesthetically pleasing to view and

cognitively much easier to interpret, because the

geologist’s brain does not have to work so hard on

the first prerequisite step to interpretation:

envisioning what features may lie in the gaps.

When interpreting deepwater clastics, we follow

the assumption described by Hansen et al. (2000)

that the average grain size varies directly with the

apparent resistivity of the static image. For the

new high-definition OBM-adapted imager, this

methodology is even more relevant for two

reasons. First, we consider that in the OBM

environment, invasion likely displaces free water

with OBM filtrate. Formation conductivity

therefore relates primarily to clay and/or bound

water volume. Secondly, since the new imager has

a very shallow depth-of-investigation (an order of

magnitude shallower than legacy OBM-adapted

imagers) it is a much safer assumption that the

zone of measurement has been completely flushed

by filtrate.

As the data were acquired shortly before the

present manuscript deadline, a full interpretation is

still in process, and any results below are

preliminary. Nonetheless many interesting aspects

of the geology can be described with high

confidence based on a “quick” interpretation.

Net-to-gross analysis. A common application of

borehole images in deepwater wells is to perform

analysis of net sand thickness at a resolution that is

far superior to standard logs, based on simple

resistivity cutoffs. We include in figure 17 a

demonstration of this workflow performed on the

impedivity measured by one button, noting that the

cutoffs are nominally chosen and have not been

determined methodically for this example, which

constitutes only proof of principle. Hansen et al.

(2000), Cheung et al. (2001) and others discuss

criteria for sensible and robust cutoff selection, most

notably the availability of core in at least one well.

Compared to the legacy OBM-adapted imager, we

anticipate many advantages as well as a slight

complication for this application. The

complication is that the result of the composite

processing scheme is, strictly speaking, an image

of impedivity rather than resistivity. We simplify

and assume that at relatively low formation

resistivity we may choose to ignore the dielectric

effect and treat this curve as resistivity. This point

will be addressed in short time by the introduction

of an advanced inversion-based workflow as

detailed by Chen et al. (2014). The obvious

advantage compared to legacy technology is the

increased spatial resolution, but an even greater

advantage arises from the lack of significant

shoulder bed effects on the new measurement.

Structural interpretation. Initial structural

interpretation of the images from the new high-

definition OBM-adapted microresistivity imager

revealed that the area is in a field with very high

stresses and is structurally complex with

unconformities and faults. The high resolution and

superior definition of the images allows the clear

visualization of these features. Even in clay-rich

intervals, there is no problem to visualize bed

boundaries, as any imprint of mud cracks on the

image is minor. The faulting caused wide-ranging

changes to structural dips both in terms of

magnitude and azimuth. The imprint of the

stresses on the local geology continues to date.

Also observed in the images were abundant natural

and drilling-induced fractures. With legacy

images, it was often difficult to visualize fractures

at all. The visualization of drilling-induced

fractures, occurring on the NNE and SSW sides of

the wellbore as frequent en-echelon subvertical

features (see figures 18 and 19) enables

determination of the current maximum horizontal

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Fig. 18 Detail of the background sedimentation and distal levee deposits from the lower part of the sequence in

figure 16. From left: track one: gamma ray; track two: enhanced static image of the new OBM-adapted imager; track

three: tadpole plot showing true (structurally uncorrected) dips; track four: detail of enhanced dynamic image on a

zoomed 1/10 scale with dip interpretation; track five: zoomed tadpole plot.

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stress orientation as such.

Sedimentological interpretation. Thick sands in

channel fill deposits are commonly the most

sought-after targets in deepwater exploration. The

sands encountered in this well can be well-

interpreted with the abundant detail now visible in

the borehole images. A typical example illustrated

by Figure 17 is a sand sequence that starts with a

low-energy influx of sediment. There were several

small pulses of sand deposition that created thin

beds. Subsequently, there was an increase in

energy and thicker sands were rapidly deposited,

culminating in deposition of the massive sand

from xx73-77 ft. The analysis allows interpretation

that the sequence consists of a channel and

associated deposits, with deposition migrating

from off-axis to a more axial position up-section.

This is evident from the disturbed nature of these

sands affiliated with fluid escape from rapidly

deposited sediment. Clasts are also present

indicating the high level of energy in the system.

The rapid deposition of the sands has applied

weight on the still soft lower layers in the unit

causing their deformation. Angular channel scours

such as the one at xx77 ft are a common feature in

this environment that can be used to orient the

channel axis, in this case approximately S10E.

Hansen et al. (2000) described the presentation of

deepwater depositional facies in microresistivity images

acquired in WBM during the 1990’s, before the rise of

OBM-drilling. In the next paragraphs we examine in

detail many of the same features using the new high-

definition OBM-adapted images.

Background sedimentation and distal levee. Figure 18

shows a detailed 1/10 scale view of the interval near the

bottom of the sequence in figure 17. We usually think

of shales, as seen in the interval below xx12 ft, as

low-energy deposition. Observations in shales in

this well showed high energy mixed within an

otherwise quiet environment of deposition. Slumps

are observed and so are rapid changes in dip—

mostly abrupt changes related to syndepositional

slips. Based on these observations, the shale might

be interpreted as having been deposited in a slope

setting.

Above xx12 ft, cm-scale laminations of silt or fine

sand dominate the image texture. Some

laminations appear to be rippled or starved. The

most likely depositional environment is a distal

levee, or overbank. A careful determination of

structural dip, and subsequent structural correction

of the lamination dips in this interval might give a

useful indication of the direction to the associated

channel, which will be found up-dip.

Channel axis. Figure 19 presents a 1/100 scale

overview of another channel story set intersected

by the well, with a zoomed view of the base of one

of these channel stories at 1/10 scale. This section

can be interpreted as lying close to the channel

axis, due to medium to thick massive and/or

conglomeritic beds and relatively flat attitude.

Disturbed nature of many beds can be observed

and is likely due to water escape. Orienting the

channel when the well intersects close to the axis

is usually not easy as most of the scours are close

to flat, and would be all but impossible to

recognize with legacy OBM-adapted images. A

dipping portion of a basal scour is interpreted at

xx31.3 ft, suggesting that the axis of deposition is

N20E – S20W. The scour is filled by a 1 ft thick

lower-energy deposit. Thanks to the resolution

and clarity of the new images, we succeed at

recognizing several other scours above this one,

suggesting that paleotransport shifted to a NW-SE

axis up-section.

Slump. A key challenge in the deepwater slope

exploration setting is to differentiate in-situ

deposition by turbidity currents from mass

transport deposits of various types. Slumping of

sediments in this environment is known to occur

over a broad range of scales, from centimeters to

kilometers. In the studied well, we were able to

recognize slumps on the scale of centimeters to

tens of meters.

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Fig. 19 Another channel story set featuring coarser grained sediment deposited close to the channel axis. From left:

track one: gamma ray; track two: enhanced static image of the new OBM-adapted imager; track three: tadpole plot

showing true (structurally uncorrected) dips; track four: detail of enhanced dynamic image on a zoomed 1/10 scale

with dip interpretation; track five: zoomed tadpole plot.

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Fig. 20 1/10 scale detail of a spectacularly slumped sand with an interpreted 3D view of the wellbore. From left:

track one: gamma ray; track two: static image of the new OBM-adapted imager with dip interpretation; track three:

tadpole plot showing true (structurally uncorrected) dips; track four: enhanced dynamic image; track five: array

induction; far right: 3D view.

Figure 20 presents a sandy section of approximately 15

ft showing rapid change in dip. The legacy OBM-

adapted images would have missed most of the internal

features of this sand, especially from xx91 - xx96 ft

where the bedding is subvertical. The sand might have

been assumed to be part of the net pay column.

The new-generation high-definition OBM-adapted

images reveal the truth. The massive deformation

within these sands is clearly visualized and reveals the

interval as a series of slump folds. The changes in dip

are easily tracked and can be analyzed in a stereonet to

precisely determine the fold axes, of which there are

four in this case, striking dominantly NW-SE. For those

not versed in the interpretation of borehole images, this

is best visualized in the accompanying 3D view.

The implications of this interpretation are threefold.

First, the slump axes approximate the strike of the

paleoslope and give context to the overall direction of

the system. Second, the petrophysicist should beware

that the true stratigraphic thickness of these sands is

much less than half of the apparent thickness. Third,

and most importantly, one may wish to reconsider

whether such sands should be considered as net pay at

all, since connectivity to the original sand body is

uncertain. In this situation a wireline formation tester

might shed light on the problem.

Sheet sands. Coarse, highly parallel beds with

numerous flat scours seen in figure 20 most likely

represent lobe or “sheet sand” deposits. High net-to-

gross, presence of cohesive debris flows (xx65.5 – xx67

ft and xx58.5 – 59.5 ft), Bouma Ta as well as Tb- Te

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Fig. 21 An example of sheet sands imaged by the new high-definition OBM-adapted imager with incredible

photorealistic detail. Preferred imbrication (white) of shale clasts near xx66.5 ft defines the paleotransport direction

as approximately S35E while current ripples in a 3-in-thick sand bed at xx61.5 (red) confirm the system orientation.

From left: track 1: calipers one through four; track 2: static OBM-adapted image with markup; track 3: classified dip

tadpoles, no structural correction; track 4: enhanced dynamic composite image; track 5: array induction.

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members, and occasional angular scours (not shown)

suggest the wellbore is close to the proximal end of the

lobe. Sheet sands may be difficult to orient from dip

alone, especially if deposited flat on the basin floor. In

this case, interpreting the new high-definition OBM-

adapted images, we observe that preferred imbrication

(white) of shale clasts near xx66.5 ft suggests the

paleotransport direction was approximately S35E.

Current ripples clearly observable in a 3-in-thick sand

bed at xx61.5 (red) corroborate this interpretation of the

depositional orientation of the system.

All these observations allow better understanding

of the high energy in this location, both in

geologic time and at present. In this and six other

field tests in the Gulf of Mexico, it has been

demonstrated that the new high-definition OBM-

adapted imager overcomes the challenges of the

previous generation, enabling operators to

photographically observe and describe the geology

of deepwater reservoirs as never before.

DISCUSSION

Nonconductive mud properties. In the

nonconductive OBM environment, the combination

of high-resistivity muds along with very low

formation resistivity tends to be the most

challenging combination for achieving a valid

microelectrical measurement. Because the new

high-definition OBM-adapted microresistivity

imager employs a high-frequency current, the mud

insulation effect is greatly decreased. According to

more than 40 field test jobs to date, no limitation on

mud type is observed. There are good images

obtained in OBM formulations having an oil/water

ratio as low as 60/40 and as high as 90/10. It should

be noted, however, that the physics predict and the

field test results bear out that a lower oil/water ratio

is more forgiving in cases of borehole rugosity.

Electrical stability or “ES” is a common measure of

drilling fluid emulsion stability at surface that may

or may not be truly representative of emulsion

stability downhole. Poor emulsion stability

downhole has sometimes been suspected of causing

poor images acquired by legacy OBM-adapted

imagers, but in fact the cause is poorly understood.

One very plausible theory suggests that the voltage

(up to 340 V) applied by the legacy OBM-adapted

imager can in certain situations cause the emulsion

to break down locally in front of the sensor array.

The new high-definition OBM-adapted imager

applies only very low voltages (less than 2V) in the

borehole so that it will certainly not affect mud

stability. Based on the field tests results to date, no

degradation of images has been observed that can be

attributed to emulsion stability.

Thick filter cake may form an additional layer

between the measurement electrode and the

formation and may have electrical properties that are

slightly or significantly different from those of the

bulk fluid. The latter case is not contemplated by our

processing model, which assumes a single mud

vector but in most cases is capable to reasonably

approximate the impedivity of the mud plus mud

cake as a single vector, provided that conditions do

not vary abruptly with depth. Processing strategies

for complex environmental conditions are an area of

future development.

Rugosity and wash out. The new OBM-adapted

measurements do not require direct contact of the

pad with the formation, which makes the

measurement less sensitive to the borehole surface

condition. However, the sensitivity of the signal to

the formation is not infinite, especially in low

formation resistivity, where the formation

impedivity vector is very small, while standoff

rapidly increases the magnitude of the mud

impedivity vector. In this extreme case, the

processing becomes very sensitive to small errors in

the mud angle. Formation texture may be masked

and drilling-induced features such as surface

scratches or threading patterns may show up in the

processed image.

Flushed zone resistivity. Because the established

depth of investigation of the new high-definition

OBM-adapted microresistivity imager is shallow, at

approximately 0.2 in., the resistivity derived through

processing most likely indicates the flushed zone,

unless there is no invasion.

Due to the usage of high-frequency current, a

dielectric effect exists in the measurement and

processing. The proposed composite processing is

not intended to correct the dielectric effect to derive

a quantitative flushed zone resistivity. The main

target of the composite processing is to generate an

electrical image that reflects the formation resistivity

contrast. For quantified resistivity, an advanced

inversion processing mode will be needed.

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Chen et al. (2014) present an advanced inversion-

based workflow as an alternative for processing the

new high-definition OBM-adapted images to fully

separate button standoff, button resistivity, and

button dielectric permittivity at each depth level for

each button. Among other benefits, the technique

produces a quantitative formation resistivity image

corrected for the dielectric effect.

Fractures. The new high-definition OBM-adapted

microresistivity imager pad sends current

perpendicular to the borehole wall, which makes the

new OBM-adapted measurement is equally sensitive

to both horizontal and vertical features. Thus the

new imager can measure fractures at any dip angle.

An inherent and well-known ambiguity of imaging

fractures in OBM is that both open fractures filled

with OBM and fractures that are cemented with

resistive minerals such as calcite or quartz are by

nature resistive features. To add to this, such

resistive fractures present a challenge for the

proposed processing scheme in that they are very

small features compared with the background.

The alternative inversion-based workflow of Chen et

al. (2014) is beneficial to fracture interpretation in

that it both correctly represents the conductive or

resistive nature of the fracture and provides

additional indicators that can help to discriminate

whether a resistive or conductive fracture is in fact

open or closed.

CONCLUSIONS

A new high-definition microresistivity imager tool

for oil-based mud has been designed and tested with

very good results.

The highly-improved borehole image quality has

become possible thanks to a fully-new physical,

mechanical and electrical architecture. A new high

frequency, current injection measurement combined

with advanced processing lead to a higher resolution

and fewer artifacts. Special purpose electrical

components inside the pads open the way for dense

integration, needed for high resolution and coverage,

as well as digital communication between the pads

and cartridge, which reduces interference and

reliability issues. Eight fully-articulated and

independently opening pads allow for a very good

pad application in all hole deviations. The dual-arm

pad suspension adds the possibility to log the tool on

the way down which can reduce stick-and-slip

motion, increases flexibility and data-security and

reduces logging time.

Case studies demonstrate the applicability of the tool

in very different and challenging settings with robust

and useful results. What stands out immediately is

the photorealistic brilliance of the images that can be

achieved with the new tool. The modeling and field

test results show that the new tool brings water-

based mud imaging quality—or better—to oil-based

mud environments. Borehole coverage and

resolution have been greatly improved compared to

previous generation tools, while various artifacts

such as mud-crack sensitivity and side lobe effects

have been reduced or eliminated.

A large number of well-established borehole

imaging applications developed for high-definition

water-base images are available today on

commercial software platforms and can be readily

applied to the new high-definition OBM-adapted

imager, ranging from improved structural

interpretation and sand count to full-blown

sedimentology studies that in the past could only

have been performed with conventional core.

Operators drilling in challenging environments such

as unconventional or deepwater will finally be able

to see their reservoirs.

ACKNOWLEDGMENTS

The authors acknowledge Schlumberger for

technical and financial support for the new OBM-

adapted imager project. In particular we wish to

thank Andrew Hayman, Philip Cheung, Pierre-

Marie Petit, and Gregoire Jacob for their decisive

technical contributions in important stages of this

project. We also note that the success of the

project would not have been possible without the

excellent team of engineers and technicians, who

spent long hours designing, assembling and testing

the new imager.

REFERENCES

Bourke, L.T., and Prosser, D.J., 2010, “An independent

comparison of borehole imaging tools and their

geological interpretability,” paper GGG presented at the

SPWLA 51st Annual Logging Symposium, Perth,

Australia.

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Chen, Y., Omeragic, D., Habashy, T., Bloemenkamp,

R., Zhang, T., Cheung, P., and Laronga, R., 2014,

Inversion-based workflow for quantitative

interpretation of the new-generation oil-based mud

resistivity imager: Transactions of the 55th SPWLA

Annual Logging Symposium, Abu Dhabi, UAE, May

18–22.

Cheung, P., Pittman, D., Hayman, A., Laronga, R.,

Vessereau, P., Ounadjela, A., Desport, O., Hansen,

S., Kear, R., Lamb, M., Borbas, T., and Wendt, B.,

2001, Field test results of a new oil base mud

formation imager tool: Transactions of the 42nd

SPWLA Annual Logging Symposium, June 17–20,

paper XX.

Hansen, S.M., and Fett, T., 2000, “Identification

and Evaluation of Turbidite and Other Deep Water

Sands Using Open Hole Logs and Borehole

Images,” in AAPG Memoir 72 / SEPM Special

Publication No. 68: Fine-Grained Turbidite

Systems by Bouma, A.H. and Stone, C.G., eds.

Zhang T, Switzer P, Journel AG (2006) Filter-

based classification of training image patterns for

spatial simulation. Mathematical Geology 38: 63–

80

ABOUT THE AUTHORS

Richard Bloemenkamp is a physicist at Schlumberger-

Riboud Product Centre (SRPC), Clamart, France. He is

the physics and interpretation team leader of the new

OBM-adapted microresistivity imager project. He

joined Schlumberger in 2003 and has worked on

experimental physics, electromagnetic modeling, and

interpretation products for borehole imaging. He

received an MSc in electrical engineering in 1998 and a

PhD in electromagnetic inverse scattering in 2002, both

from Delft University of Technology in the

Netherlands.

Tianhua Zhang is an interpretation/development

engineer at SRPC, where she is currently engaged in

the image processing and answer product software

development for the new OBM-adapted

microresistivity imager. Since joining Schlumberger

in 2001, she has worked in Beijing on interpretation

software development and in Saudi Arabia on

carbonate lithology and multifrequency dielectric

laboratory measurement projects. She has a PhD in

space physics from Peking University in China.

Laetitia Comparon is an interpretation/development

engineer at SRPC. Prior to joining the new OBM-

adapted microresistivity imager team, she has worked

on cased-hole electromagnetic tools and an open-hole

dielectric tool. She has an MSc in Geophysics from the

Earth Science Institute of Strasbourg (IPGS/EOST),

and a PhD in experimental rock physics from the Earth

Science Institute of Paris (IPGP) in France.

Robert Laronga is the headquarters geologist for

Schlumberger Wireline based in Clamart, France. In

this position he advises Schlumberger engineering

teams on the development of new borehole imaging

and coring technology and related interpretation

software and he provides support to Schlumberger

geologists and customers in the field with

introduction of these technologies. Robert has held

several positions during his 20-year career with

Schlumberger, starting as a wireline field engineer

in the Permian basin. His work with borehole

images began in 1999 as the field test engineer for

the first prototype OBM-adapted imaging tool.

Robert received BA degrees in archaeology and

geology from Cornell University, in Ithaca, New

York, USA.

Shiduo Yang is a senior geologist at SRPC. He has

worked in reservoir characterization with borehole

images in complex volcanic, tight carbonates, and

lacustrine clastics. He graduated with BA in geology

and BA in computer science from Petroleum

University and completed a PhD in geology from

China University of Geoscience.

Sihar Marpaung is currently mechanical team

leader for the new OBM-adapted microresistivity

imager. He joined Schlumberger in Japan in 2006

and has been working mainly on development of a

downhole fluid analysis project. He transferred to

France in 2010. He received his BSc and MSc in

mechanical engineering from Tokyo Institute of

Technology, Japan, in 2004 and 2006,

respectively.

Elodie Marquina Guinois is an electrical team

leader for the new OBM-adapted microresistivity

imager. Since joining Schlumberger in 2007, she

has worked on both logging-while-drilling and

wireline tools. She has a BSc from Supelec,

France, and an MSc in electronics from the

University Rennes I in France.

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Glenn Valley is an embedded software specialist at

SRPC. During the last 10 years, he participated in

the development of openhole imagers and now

brings his experience to logging-while-drilling tools.

Glenn holds a BSc in electronics and an MSc in

embedded software from the University of

Montpellier in France.

Patrick Vessereau is the project manager of the new

OBM-adapted microresistivity imager project. He

joined Schlumberger in 1990 and has been involved

in testing, production logging, and evaluation

services tool designs. Patrick received a DEA at the

Institute of Fundamental Electronics of the

University of Orsay (Paris XI) in 1990.

Ehab Shalaby is the wireline product champion for

geology imaging and dielectric measurement

technologies, based in Clamart, France. He is

responsible for new product development and leads

the field introduction and deployment of the new

technologies. He joined Schlumberger in 1998 as a

wireline field engineer. During his career he held a

variety of positions in the Middle East, Europe, and

Asia. Ehab earned his BSc degree in electrical

engineering from the University of Ain Shams,

Egypt.

Bingjian Li is currently a principal geologist and

geology domain champion for Schlumberger US

Land based in Houston. Since he joined

Schlumberger in 1998, he has been working in

Canada, Vietnam/Thailand, and Kuwait. Prior to

Schlumberger, he was employed by the R&D Center

at PetroChina for 8 years as a geologist based in

Beijing. Bingjian has been working extensively in

borehole image interpretation as well as new tool

evaluation in both water- and oil-based muds. Also,

he gained considerable experience in many types of

fractured reservoirs including clastics, carbonate,

and basement and now is heavily involved in

unconventional US shales and tight carbonates.

Bingjian has a BS in petroleum geology from the

North East Petroleum University (China) and a PhD

in reservoir geology from the University of

Aberdeen (UK). Bingjian has authored and

coauthored more than 20 papers.

Anish Kumar received his Masters degree in

Geology from University of Roorkee, in India. He

earned his Ph.D. in Geology at Texas Tech

University. In 1997, Anish got a job with Special

Core Analysis Labs, Inc., Midland, Texas, as a

Geologist and Lab Manager. He started his career

with Schlumberger in July 2001 in New Orleans as

an Interpretation Development Geologist with a

focus on Borehole Geology and deepwater deposits.

He later moved to Houston continuing in the same

role, and supporting geological interpretation for

Schlumberger all over North America. Anish is

currently a Geology Domain Champion for

Schlumberger’s North America Offshore Wireline

operations.

Rick Kear is the Schlumberger Wireline Geology

Domain Champion for North-America Land and is

an Advisor of Geology and Petrophysics based in

Conway, Arkansas, USA. His specific area of

responsibility is the eastern half of the USA from

Colorado eastward. In the past he has worked as

field engineer, district manager, sales manager,

interpretation development engineer. He has

authored and co-authored a multitude of papers on

geology and petrophysics and has taught a large

number of geology courses and lead numerous field

trips. He has received a university degree from the

University of Florida. His professional activities

include NOGS – Past President, NOGS Memorial

Foundation – Past Chairman & current board

member, SPWLA, (Past New Orleans Chapter

President), SPE – Central Arkansas Study Group –

current chairman, interests petrophysics, geological

and imaging interpretation, especially in resistive

fluids, depositional environment determination, field

studies and leading field trips and workshops.

Yu Yang is a geologist for Schlumberger US Land

in the Pittsburgh office. He has been mainly

involved with unconventional reservoirs since 2012.

He has also conducted multiple-well geological

modeling and near-well structural modeling for

special local practices. He has a master’s degree in

geology from China University of Geosciences

Beijing (CUGB). He has been with Schlumberger

since 2008.

DESIGN AND FIELD TESTING OF A NEW HIGH-DEFINITION MICRORESISTIVITY IMAGING TOOL...

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