This document provides an overview and table of contents for a book about petroleum formation evaluation. The foreword introduces topics that will be covered, including formation evaluation procedures, drilling data, well logging, log interpretation, integration with seismic data, well deviation and steering, and production testing. Suggestions are welcomed for improving the next edition which will provide further overview of the petroleum industry. The book aims to describe the measurement, sampling, testing and analysis methods used to characterize rock and fluid properties during the various stages of drilling, logging and production testing a well.

2. i
FOREWORD
This book, with named PETROLEUM FORMATION EVALUATION
OVERVIEW is an overview of petroleum Formation Evaluation, with content
Formation Evaluation procedure such; Measure, Sample, and Test, MWD
(measuring while drilling) & LWD (logging while drilling), determine rocks and
fluid properties. And formation drilling data such The Drilling Rate, Bottoms Up
Circulation, Oil and Gas Shows, The Cuttings, Core Sampling (Coring), and SWC
(side wall coring) in common.
This book also describe generally about Well Logging comprises well logging
tools, Well logging operations, well log types, well logging methods, log
interpretation such Quick-look methods, Quantitative interpretation, water and
hydrocarbon saturation, pressure or sampling. In addition describe integration
with seismic, Well deviation, Surveying, and Geosteering. Finally production tests
types of production tests, DST (drill stem tests), WFT (wareline formation tests),
IP (initial potential) test.
Suggestions and constructive criticism is expected in the preparation of the next
book about Overview petroleum industry.
August, 2018
A. ANRIANSYAH

3. ii
TABLE OF CONTENTS
FOREWORD................................................................................................................................ ¡
TABLE OF CONTENTS.............................................................................................................. ¡¡
1. INTRODUCTION..................................................................................................................... .1
2. FORMATION EVALUATION PROCEDURE............................................................................1
2.1 Measure, Sample, and Test..............................................................................................1
2.2 Determine Rocks and Fluid Properties..............................................................................1
2.3 MWD (Measuring While Drilling) & LWD (Logging While Drilling).................................... 4
2.4 DST (Drills Stem Test) & WFT (Wireline Formation Tests).............................................. 5
2.5 IP (Initial Potential) Test................................................................................................... 7
2.6 Petroleum Wells............................................................................................................... 7
2.7 Wild Cat Wells.................................................................................................................. 8
2.8 Development Wells........................................................................................................... 9
3. FORMATION DRILLING DATA............................................................................................. 10
3.1 The Drilling Rate............................................................................................................. 11
3.2 Bottoms Up Circulation....................................................................................................12
3.3 Oil And Gas Shows..........................................................................................................13
3.4 The Cuttings..... ..............................................................................................................15
3.5 Three Major Considerations........................................................................................... 17
3.6 The Main Task Drilling Department................................................................................ 21
3.7 Core Sampling (Coring).................................................................................................. 23
3.8 Core Analysis.................................................................................................................. 25
3.9 SWC (Side Wall Coring)................................................................................................. 26
4. WELL LOGGING .................................................................................................................29
4.1 Well Logging Tools......................................................................................................... 32
4.2 Well Logging Operations................................................................................................ 33
4.3 Well Log Types............................................................................................................... 35
4.4 Well Logging Methods.................................................................................................... 38
4.5 Lithology Logs.................................................................................................................39
4.5.1 SP (Spontaneous Potential) Log............................................................................40
4.5.2 GR (Gamma Ray) Log ...........................................................................................41
4.6 Porosity Logs...................................................................................................................42
4.6.1 Density Log.............................................................................................................43
4.6.2 Neutron Log............................................................................................................44
4.6.3 Gas Zone................................................................................................................45
4.6.4 Sonic Log............................................................................................................... 46
4.7 Resistivity Log................................................................................................................. 47
4.7.1 Fluid Saturation (Archie Formula).......................................................................... 50
4.8 Caliper Log..................................................................................................................... 52
4.9 Others Well Logs.............................................................................................................53
5. LOG INTERPRETATION....................................................................................................... 57
5.1 Quick-Look Methods....................................................................................................... 57
5.2 Quantitative Interpretation.............................................................................................. 59
5.3 Porosity and Mineral Composition ................................................................................. 59
5.4 Water and Hydrocarbon Saturation................................................................................ 61
5.5 Pressure or Sampling..................................................................................................... 62
5.6 Permeability.................................................................................................................... 64

4. iii
5.7 Core capillary Pressure Analysis ................................................................................... 65
6. INTEGRATION WITH SEISMIC............................................................................................. 68
6.1 Synthetic Seismograms.................................................................................................. 68
6.2 Fluid Replacement Modelling......................................................................................... 70
6.3 Acoustic/Elastic Impedance Modelling........................................................................... 70
7. WELL DEVIATION, SURVEYING, AND GEOSTEERING.................................................... 71
7.1 Well Deviation................................................................................................................. 71
7.2 Surveying........................................................................................................................ 73
7.3 Geosteering.................................................................................................................... 73
8. PRODUCTION TESTS ... ..................................................................................................... 76
8.1 Types of Production Tests.............................................................................................. 76
8.2 DST (Drill Stem Tests).................................................................................................... 77
8.3 WFT (Wareline Formation Tests)................................................................................... 83
8.4 IP (Initial Potential) test................................................................................................... 84
9. CONCLUSION ...................................................................................................................... 85
REFERENCES .......................................................................................................................... 89

5. 1
1. INTRODUCTION
As we finding Hydrocarbon as discovery requires a lot of technical
know-how, precision tools, and a lot of money. it is dirty it is dangerous but we
still do it, although there's no guarantee will find hydrocarbons, but then again we
might call drilling oil that technically challenging just creates a hole in the crust. In
this book we need to evaluate that hole to determine and if that well will be a
commercial oil or gas well or just another dry hole.
2. FORMATION EVALUATION PROCEDURE
2.1 Measure, Sample, and Test
We will describe how we measure, sample, and test the actual rock
formations and their properties at the various depths of the hole as we drill
downward (Pic. 001). We will show how we are able to use these measurements
samples and test evaluations at different stages and depths of the drilling
program to help us identify any reservoir rock that is present.
Pic. 001. Measure, sample, and test the actual rock formations and properties
2.2 Determine Rocks and Fluid Properties
Once it's identified will add this information to the mud log as we drill and
then compiled another more detailed electronic log after TD (Total Depth) has
been achieved (Pic. 002), along the way we will continue collecting samples and
performing tests that help us determine the porosity, the permeability, and
saturation of types of fluid present in the rock (Pic. 003).

6. 2
Pic. 002. Determine Rocks and Fluid Properties
Pic. 003. The porosity, the permeability, and saturation of types of fluid
Next we will determine the depths, size, thickness, temperature, and
pressure of rock formation (Pic. 004). finally by using the data from all of these
procedures that help us to evaluate the formation rock and from the results of the
seismic tests conducted earlier that gave us this area (Pic. 005), we'll be able to
calculate if there are enough commercial quantities of hydrocarbon present to
continue the development of the well (Pic. 006), as you might guess each of
these measurements samplings and tests required time and money.

7. 3
Pic. 004. The depths, size, thickness, temperature, and pressure
Pic. 005. The seismic tests conducted earlier
Pic. 006. The seismic tests conducted earlier

8. 4
2.3 MWD (Measuring While Drilling) & LWD (Logging While Drilling)
Because it is usually the team of engineers who decide what procedures
to run it is they who must justify and not only the costs of these procedures but
also the down time in the drilling program. although the industry as fast and
proving the technology to run procedure during drilling in what is called
measuring while drilling (MWD), and logging while drilling (LWD) (Pic. 007) and
many times it is still necessary to round trip in and out of the hole with specialized
equipment, remember round tripping is when the drill string with the drilling bit
and all of the stands of pipe are pulled out of the wellbore for testing and then put
back in when it was finished (Pic. 008).
Pic. 007. Measuring while drilling (MWD), and logging while drilling (LWD)

9. 5
Pic. 008. round tripping logging
The information we learned from the different procedures will help guide
us in deciding whether or not to abandon or complete this well (Pic. 009),
regardless of whether we find the next big reservoir or faced with a dry holes or
data acquired and a lot of time in expense will not go to waste. it will be uploaded
into powerful computers that can then be used to more accurately help predict
where to drill the next wildcat or development well.
Pic. 009. Deciding to abandon or complete this well
2.4 DST (Drills Stem Test) & WFT (Wireline Formation Tests)
Let’s look at some of the traditional ways we acquire data, collect sample,
and performed tests so that we can evaluate what's in the formation. first during
drilling in what is known as open hole well or wells that have not then prepared
for production, data from the mud log is compiled by the driller, the mud logger,
and the site geologist (Pic. 010). If zones of interest are detected, then samples
from cores are collected. Next while we are still in the open hole phase after TD

10. 6
has been reached, open hole well logs, DST (drills stem test), and WFT (wireline
formation tests) are perform and interpreted (Pic. 011).
Pic. 010. The mud log is compiled by the driller, the mud logger, and the site geologist
Pic. 011. Open hole well logs, DST (drills stem test), and WFT (wireline formation tests)

11. 7
2.5 IP (initial potential) test
Finally the last test, the IP (initial potential) test is conducted after the well
has been completed and equipped and what is known as cased hole or closed
hole, but before the well has been prepared for production (Pic. 012). This very
important test allows the reservoir fluid volumes or flows and pressure
measurements to be accurately determined.
Pic. 012. IP test run in Closed hole, before production
2.6 Petroleum Wells
let we point out here that because very little data is available in wild cat
wells, the testing emphasis for them is someway different than for development
wells. for example in wildcat well more core samples are collected to help identify
rock formation (Pic. 013), while in development wells more DST (drill stem tests)
help identify the various target zones and their characteristics (Pic. 014).

12. 8
Pic. 013. Wildcat well more core samples are collected
Pic. 014. Development wells more DST (drill stem tests)
2.7 Wild Cat Wells
When gathering data from wild cat wells there for the most critical step is
to pinpoint potentially productive zones as they are penetrated. this can be a very
trying task drilling through an oil or gas some can easily go unnoticed because
the weight of the mud column can prevent reservoir fluids from entering the
wellbore thus obscuring the data. the company representative, the site geologists
and the mud engineer must be very vigilante closely to scrutinized the rock
cuttings or a rock pieces (Pic. 015) that have been crushed out of the formation
by the drill bit, and sent to the surface with the returning mud through the annulus
and make sure that this data is accurately recorded in the drilling operation log.

13. 9
Pic. 015. Rock cuttings
2.8 Development Wells
A particular challenge when drilling development wells is correlating new
data from a particular well with existing data from previously drilled nearby well.
because rock structures and formations can change dramatically from one
location to another it is not uncommon to encountered conflicting, confusing data,
an example of this might be when the porosity of the rock for a particular zone
changes from one well to another (Pic. 016). When the geologist spots these
variances or differences, he'll be called on to explain this heterogenetic in the
subsequent constructed models.
Pic. 016. Particular zone changes from one well to another

14. 10
3. FORMATION DRILLING DATA
There are some methods used to collect data to evaluate wild cat well
and development wells in each method we’ll discuss how the need for different
data will influence how the data is hand and analyzed.
In this book we'll limit our discussion to open hole wells (Pic. 017). From
the day we spud in, we begin collecting drilling data, the record that we make is
called the drilling operations log or mud log, and this is continuous foot by foot or
meter by meter record of the hole as it is being drilled is refer to a mud love. all
important data gain from the cuttings and from the mud returns as well as from
the drilling operations or plotted against the depth on the same strip chart of log
so that they can be compiled on a chart, this drilling operations log is a record
with three main inputs from the driller, the mud loger, and the site geologists (Pic.
018).
Pic. 017. Open hole and cased hole well

15. 11
Pic. 018. Drilling operations log
3.1 The Drilling Rate
Let we discuss each input in a little more detail. we'll start with the input
from the driller, while rotating to kelly the driller measures how fast or how slow
the kelly goes down, for instance when drilling through hard rock the kelly
descends more slowly than when drilling through softer rock, the speed of the
kellys dissent is known as the drilling rate (Pic. 019).
Pic. 019. The speed of the kellys dissent is known as the drilling rate
The drilling rate is recorded on the log as the number of minutes per foot
or meter penetrated. Rate of penetration knowing this speed helps identify the
type are rock that is being penetrated and gives a general indication of the
porosity of that zone (Pic. 020), hard rock for example is usually associated with

16. 12
shale or other cap rock while softer rock is associated with sandstone or
limestone which can be oil or gas rich reservoir rock (Pic. 021).
Pic. 020. Rate of penetration identify the rock type and indication of porosity
Pic. 021. Hard rock, cap rock, and softer rock
3.2 Bottoms Up Circulation
When the drill bit excess the non-porous hard rock and enters softer
porous rock the recording instruments in the log show this gap as you can see on
the illustration (Pic. 022). This gap is called the drilling break, when this happens
the driller raises the drill bit a few feet breaking off from the bottom while
continuing to rotate and circulate mud, this circulating mud scoops up the last of
the cuttings and sends them to the surface this is called bottoms up circulation.
These cuttings from the last time of drill bit are then analyzed by the site
geologists, and our instrumental in helping it to determine future steps in the
drilling program. For example the geologists may make a determination to core
the next section of rock to be drill based on his analysis of these cutting.

17. 13
Pic. 022. Bottoms up circulation
In addition the driller keeps them running count of the number of lengths
or stands of pipe that have gone down into the hole. Using pipe stand
measurements to determine exactly at which depths different types rocks or
encountered the driller can provide the data that to allow the depths and the
thickness of hard and soft rock to be tabulated (Pic. 023).
Pic. 023. Running count of the number of lengths or stands of pipe that have
gone down into the hole
3.3 Oil and Gas Shows
The next input is information about the mud compound by the mud logers,
his job is to constantly monitor them mud for oil and gas shows, he does this in a
variety of ways. in addition to checking for any oil shows that may have migrated
to the surface with the mud or the floats in the mud pit, he also exposes mud
samples through ultra violet light, that will show fluorescence if oil is present.
With gas he’s looking for gas shows that bubble out of the mud and surface (Pic.
024). and not only is he on to look out for potentially hazards or kicks which is

18. 14
gas is entered the wellbore from the formation, he also uses gas chromatograph
to spot signs of gas that can be measured as they are released from the
formation of the rock as it is drilled (Pic. 025).
Pic. 024. The mud loggers, oil and gas shows, samples through ultra violet light
Pic. 025. Uses gas chromatograph to spot signs of gas
The mud loger carefully tracks and inputs both the depth and the
approximate locations of promising oil and gas shows on the log (Pic. 026).

19. 15
Pic. 026. The mud loger input the data
3.4 The Cuttings
The third input comes from the site geologists who identifies and studies
the cuttings that are filtered out by the shale shaker as the cuttings are brought
back to the surface in the mud pit. he collect samples of these cuttings every few
feet of drilling in order to examine them under a microscope (Pic. 027).
Pic. 027. Site geologists identifies and studies the cuttings
In studying these samples, he describes the lithology, porosity in detail,
and determines whether oil shows gas shows and hydrocarbon odor are present
(Pic. 028). For example, when describing the lithology he examines the rock to
define their characteristics or properties like color, size, shape, porosity, mineral
identification, etc (Pic. 029).

20. 16
Pic. 028. Mud log-the lithology, porosity oil and gas shows
Pic. 029. Rock characteristics
These rock type description then allow him two hypothetically place these
cutting in the appropriate zone in the stratigraphic column. The correlation will
also be necessary if data from previous drilled wells is available (Pic. 030), as we
may expect when working with these cuttings there is usually some guesswork
and analyzing and correlating all the data from the different input. This gas work
in fact can lead to errors or miscalculations in depicting the various compositions
of the layers and their depth in the strata graphic column on the mud log.

21. 17
Pic. 030. The correlation might be necessary
3.5 Three Major Considerations
There are three major important considerations or challenges the
geologist’s faces when trying to decipher and what actually record what is in the
sub surface (Pic. 031).
Pic. 031. Three major important considerations by geologist
Let discuss these important considerations or challenges in more detail,
the first challenge for the geologists is being able to accurately account for the
time lag between the time with the cuttings well to the time that it took for them to
reach the surface (Pic. 032).

22. 18
Pic. 032. Account for the time lag
The second important considerations or challenge for the geologist is to
be able to recognize and correctly place the different cuttings in the correct zone,
for example because not all cuttings rise to the surface at the same rate, large
low density cuttings can rise faster than small high density ones. in addition
particles from drill of portions of the well may have fallen into the hole because of
clay swelling or may have sloughed off from the formations further up in the hole
and can become mixed with other samples of cuttings deeper in the hole (Pic.
033).
Pic. 033. Recognize and correctly place the different cuttings in the correct zone

23. 19
Having to decide therefore the correct order of the cuttings or having to
recognize and discard material that has been seen previously requires a lot of
experience, fortunately the experience site geologist is more likely to place all of
these sometimes random cuttings into the stratigraphic column in the logs
properly (Pic. 034).
Pic. 034. Place all random cuttings into the stratigraphic column properly
The third important considerations or challenge is to be on the look out or
identifies the disintegration, disintegration is caused when the drill bit grinds up
the cuttings into such fine particles that these particles dissolve into the water of
the drilling mud, and they literally disappear and cause a blank space on the log
(Pic. 035), the geologists must therefore be on the alert for disintegration so that
he can use other tests to identify the type of rock that is in the formation but
maybe missing on the log (Pic. 036).

24. 20
Pic. 035. Disintegration particles dissolve into the water of the drilling mud, and
they literally disappear and cause a blank space on the log
Pic. 036. Identify missing rock type on the log by Another test

25. 21
3.6 The Main Task Drilling Department
In any event using the correlated data coupled with interpretative
experience, the geologist prepares the report of the stratigraphic descriptions of
the borehole from top to bottom. with the compiled data on the mud log from the
driller, the mud loger and the geologists, the drilling department is able to
determine the depth of the well, calculate the different drilling zones as measured
by the rate per hour that drill bit passed through the various rock types, check for
oil and gas shows in the mud, collect and analyze the cuttings for their
characteristics and lithology and place the cuttings at their appropriate placement
as they might appear on the stratigraphics column (Pic. 037).
Pic. 037. The main task drilling department
These formation evaluation techniques however give them only a partial
interpretative view of what is there in the subsurface (Pic. 038). For instance
when the driller notice a jump or break on the drilling log he performs a bottoms
of circulation, this break in the mud log may be the first indication of the reservoir
rock with good porosity (Pic. 039).

26. 22
Pic. 038. A partial Subsurface interpretative view
Pic. 039. First indication of the reservoir rock with good porosity
This preliminary data from the mud log can always suggests the potential
of oil reservoir. procedures and tests to collect actual samples and test for
formation characteristics and fluid pressures and volumes will have to be
conducted (Pic. 040), remember conducting the following series of procedures is
so important in fact that the society and petroleum engineers requires that when
a company claims it has found a new oil and gas reserve, actual production and
formation tests under SPEE best practices must be conducted (Pic. 041), at least
referred in reservoir performance references or literature for more information
about proven and unproven oil and gas reserves

27. 23
Pic. 040. Procedures and tests
Pic. 041. Actual production and formation tests under SPEE best practices
3.7 Core Sampling (Coring)
When performing a bottom up circulation he will have communicated this
maneuver to this site geologist. if geologists analysis of the bottom of circulation
is favorable he make all for the capture of an actual sample of the sub surface
rock, called coring the sampling method allows him to collect and actually
examples they can be picked up examined detail, smelled, weighed, and
analyzed for key reservoir parameters (Pic. 042).

28. 24
Pic. 042. Core Sampling (Coring)
These samples will then be sent to the companies laboratories for further
and analyses. Since to round trips are required to first install the coring assembly
and then to remove it, coring is not cheap in time or money. not only as a
additional time needed for these round trip, the core bit or core barrel drills and a
much slower rate than a conventional drill bit (Pic. 043).
Pic. 043. The core bit or core barrel drills and conventional drill bit
When the geologist thinks that there's enough justification to core however
instructs the driller to trip out and prepare for coring. As we can imagine the
geologists who delays drilling to core potential pay zones can be under a lot of
pressure from the drilling department to resumes drilling as fast as possible. The
honest is there for on the geologists to course sparingly and appropriately
something not always easy to distinguish when faced with incomplete

29. 25
information. In convention coring the drill string is pulled out of the hole and the
drill bit is replaced with a conventional core assembly that consists of a donut
shape diamond or pdc bit that runs on a hollow core barrel.
This string is then run back to the bottom where rotation and mud
circulation as we started. As the bit penetrates the rock faces, a solid core
undrilled, uncrushed rock rises through its center into the barrel. when the zone
of the interest has been penetrated, or when the core barrel is full with a sample
of 30ft (thirty feet) long the string with the barrel that contains the core is pulled
up to the surface with the spring load in court capture attached (Pic. 044).
Pic. 044. Coring data acquisition process
3.8 Core Analysis
once because retrieved it is taken to the laboratories for core analysis,
hole core analysis is sometime performed but usually only a small section of the
core called plug analyses is done. In this analysis the laboratory checks the core
sample for porosity, the fluid saturation, the permeability, lithology and other
areas of interest as requested (Pic. 045).

30. 26
Pic. 045. Core analysis- for porosity, fluid saturation, permeability, lithology ect.
Conventional coring does not work in every formation it works best in
consolidated hard reservoir rocks that are more frequently found in older on
shore formation (Pic. 046).
Pic. 046. Conventional coring best in consolidated hard reservoir rocks
3.9 SWC (Side Wall Coring)
For softer unconsolidated formations where conditions for conventional
coring are not suitable side wall coring is sometime perform instead. conducted
after coring would have been completed side wall coring is usually done at the
same time as the open hole logging, and like the open logging so it is run on a
wire line (Pic. 047). During the procedure side wall cores are taken from the side

31. 27
of open hole well by shooting exploding small cylindrical bullet into the formation
with a sidewall gun, these cylinder capture formation material.
Pic. 047. Side wall coring run on a wire line get small sample
Because the cylinder around wired tether they can be brought to the
surface at the time the gun is retreat. Although it much cheaper alternative to
conventional coring, sidewall coring is less informative then conventional cores
(Pic. 048). For example measurements for porosity and permeability can be
compromised inside well testing because the impact of the fire cylinders can
cause crushing and compaction (Pic. 049).
Pic. 048. Conventional coring and sidewall coring cost

32. 28
Pic. 049. fire cylinders can cause crushing and compaction
The main use aside well coring however is not to replace conventional
coring but to supplement the data retrieve to the open hole logging swift (Pic.
050). it is an excellent tool because it very accurately determines lithology or rock
type by checking specific spots especially regarding lithology and fluid saturation
(Pic. 051), the geologists can get a clearer picture then is visible on the mud log.
Pic. 050. Supplement the data retrieve to the open hole logging swift

33. 29
Pic. 051. Side wall coring lithology and fluid saturation
4. WELL LOGGING
Like the mud log it is a foot by foot or meter by meter chart that shows
what is actually in the thousands of feet of borehole (Pic. 066), it makes up the
most amount of formation evaluation data that is gathered on most wells and as
obtained by measuring the electrical, acoustical and radioactive characteristics of
the formations and their formation fluid (Pic. 067).
Pic. 066. Formation evaluation data

34. 30
Pic. 067. Measure the electrical, acoustical and radioactive characteristics of the
formations and their formation fluid
It is important to mention here that the main source for most of the
formation evaluation data comes from open hole logs that are run on all well
even those that have been cored or drill stem test, like the mud log open hole
logs providing continuous data flow from the bottom to the top of the open full but
with much more accuracy (Pic. 068).

35. 31
Pic. 068. Open hole logs
Because steel in casing interferes with most of the measurements open
hole logs are perform before the hole is cased, using some of the most advanced
oilfield technology developed by international service companies like slumber*er,
baker*uge, and whetherfo** these log allow of the site geologists and petroleum
engineer to virtually see inside the well (Pic. 069). Capturing electrical acoustic or
radioactive signals that are emitted naturally or induced by emissions, logging
tools measure the characteristics of the formation and their formation fluids.

36. 32
Pic. 069. Steel in casing interferes measurements open hole logs
4.1 Well Logging Tools
A well log analyst and petrophysicists interpret these log, let we discus a
few of the many logging tools available and how they help us determine what is
in the bore hole, most oil wells are log by service companies who are contracted
for this specific job, utilizing and their own professionals and cruise to run the
logs, these surface company employees performed the logs on site. before they
began the drill pipe is tripped out or removed and logging tools called sonde run
into the hole and an electrical conducting wireline spuldoff a drum mounded on
the back of a logging truck on shore, mounded on a skid offshore (Pic. 070).

37. 33
Pic. 070. Logging equipment’s - truck on shore and mounded on a skid offshore
4.2 Well Logging Operations
Even though new strategies logging techniques and tools are rapidly
improving and becoming available their costs can be prohibitively expensive,
Therefore we will described the traditional most common logging operations still
used in most locations (Pic. 071). In any event whether the latest technology
used to log the well are older technologies are used logging is and will remain to
be a major part of the wells overall financial costs in the foreseeable future first in
a typical scenario several sounds are combined into a single assembly and run
together (Pic. 072).

38. 34
Pic. 071. Most common logging operations still used
Pic. 072. A typical scenario several sounds are combined into a single assembly
and run together
By the way, the French words sonde meaning an electrical sensor was
first adapted for these tools because the technology was invented in france by a
company called schlumbe*g*r consequently the word sonde is still commonly

39. 35
used. In this method a sonde is run to the bottom of the hole and it's slowly
raised to the top recording the output and emissions on a chart as they accure,
this is called the actual logging sequence. The logs interval usually extends from
the bottom to casing shoe. This interval is referred to as the open whole portion
of the well.
4.3 Well Log Types
Wireline Open hole Logging
Once a section of hole has been completed, the bit is pulled out of the
hole and there is an opportunity to acquire further openhole logs either via
wireline or on the drillstring before the hole is either cased or abandoned.
Wireline versions of the LWD tools described above are available, and the
following additional tools may be run:
1. Gamma ray: This tool measures the strength of the natural radioactivity
present in the formation. It is particularly useful in distinguishing sands from
shales in siliciclastic environments.
2. Natural gamma ray spectroscopy: This tool works on the same principal as
the gamma ray, although it separates the gamma ray counts into three energy
windows to determine the relative contributions arising from (1) uranium, (2)
potassium, and (3) thorium in the formation. As described later in the book,
these data may be used to determine the relative proportions of certain
minerals in the formation.
3. Spontaneous potential (SP): This tool measures the potential difference
naturally occurring when mud filtrate of a certain salinity invades the formation
containing water of a different salinity. It may be used to estimate the extent
of invasion and in some cases the formation water salinity.
4. Caliper: This tool measures the geometry of the hole using either two or four
arms. It returns the diameter seen by the tool over either the major or both the
major and minor axes.
5. Density: The wireline version of this tool will typically have a much stronger
source than its LWD counterpart and also include a Pe curve, useful in
complex lithology evaluation.
6. Neutron porosity: The “standard” neutron most commonly run is a thermal
neutron device. However, newer-generation devices often use epithermal
neutrons (having the advantage of less salinity dependence) and rely on
minitron-type neutron generators rather than chemical sources.
7. Full-waveform sonic: In addition to the basic compressional velocity (Vp) of
the formation, advanced tools may measure the shear velocity, Stonely
velocity, and various other sound modes in the borehole, borehole/formation
interface, and formation.
8. Resistivity: These tools fall into two main categories: laterolog and induction
type. Laterolog tools use low-frequency currents (hence requiring water-
based mud [WBM]) to measure the potential caused by a current source over
an array of detectors. Induction-type tools use primary coils to induce eddy
currents in the formation and then a secondary array of coils to measure the
magnetic fields caused by these currents. Since they operate at high

40. 36
frequencies, they can be used in oil-based mud (OBM) systems. Tools are
designed to see a range of depths of investigation into the formation. The
shallower readings have a better vertical resolution than the deep readings.
9. Microresistivity: These tools are designed to measure the formation resistivity
in the invaded zone close to the borehole wall. They operate using low-
frequency current, so are not suitable for OBM. They are used to estimate the
invaded-zone saturation and to pick up bedding features too small to be
resolved by the deeper reading tools.
10.Imaging tools: These work either on an acoustic or a resistivity principle and
are designed to provide an image of the borehole wall that may be used for
establishing the stratigraphic or sedimentary dip and/or presence of
fractures/vugs.
11.Formation pressure/sampling: Unlike the above tools, which all “log” an
interval of the formation, formation-testing tools are designed to measure the
formation pressure and/or acquire formation samples at a discrete point in the
formation. When in probe mode, such tools press a probe through the
mudcake and into the wall of the formation. By opening chambers in the tool
and analyzing the fluids and pressures while the chambers are filled, it is
possible to determine the true pressure of the formation (as distinct from the
mud pressure). If only pressures are required (pretest mode), the chambers
are small and the samples are not retained. For formation sampling, larger
chambers are used (typically 23/4 or 6 gallons), and the chambers are sealed
for analysis at the surface. For some tools, a packer arrangement is used to
enable testing of a discrete interval of the formation (as opposed to a probe
measurement), and various additional modules are available to make
measurements of the fluid being sampled downhole.
12.Sidewall sampling: This is an explosive-type device that shoots a sampling
bullet into the borehole wall, which may be retrieved by a cable linking the
gun with the bullet. Typically this tool, consisting of up to 52 shots per gun, is
run to acquire samples for geological analysis.
13.Sidewall coring: This is an advanced version of the sidewall sampling tool.
Instead of firing a bullet into the formation, an assembly is used to drill a
sample from the borehole wall, thereby helping to preserve the rock structure
for future geological or petrophysical analyses.
14.NMR: These tools measure the T1 and T2 relaxation times of the formation.
use the interaction of Hydrogen nuclei with an external magnetic field.
15.Vertical seismic profiling (VSP): This tool fires a seismic source at the surface
and measures the sound arrivals in the borehole at certain depths using
either a hydrophone or anchored three-axis geophone. The data may be used
to build a localized high-resolution seismic picture around the borehole. If only
the first arrivals are measured, the survey is typically called a well shoot test
(WST) or checkshot survey. VSPs or WSTs may also be performed in cased
hole.

41. 37
Wireline Cased Hole Logging
When a hole has been cased and a completion string run to produce the
well, certain additional types of logging tools may be used for monitoring
purposes. These include:
Thermal decay tool (TDT): This neutron tool works on the same principle
as the neutron porosity tool, that is, measuring gamma ray counts when thermal
neutrons are captured by the formation. However, instead of measuring the HI,
they are specifically designed to measure the neutron capture cross-section,
which principally depends on the amount of chlorine present as formation brine.
Therefore, if the formation water salinity is accurately known, together with the
porosity, Sw may be determined.
1. Gamma ray spectroscopy tool (GST): This tool works on the same principal
as the density tool, except that by measuring the contributions arising in
various energy windows of the gamma rays arriving at the detectors, the
relative proportions of various elements may be determined. In particular, by
measuring the relative amounts of carbon and oxygen a (salinity
independent), measurement of Sw may be made.
2. Production logging: This tool, which operates using a spinner, does not
measure any properties of the formation but is capable of determining the
flow contributions from various intervals in the formation.
3. Cement bond log, TDT or GST: This tool is run to evaluate the quality of the
cement bond between the casing and the formation. It may also be run in a
circumferential mode, where the quality around the borehole is imaged. The
quality of the cement bond may affect the quality of other production logging
tools, such as TDT or GST.
4. Casing collar locator (CCL): This tool is run in order to identify the positions of
casing collars and perforated intervals in a well. It produces a trace that gives
a “pip” where changes occur in the thickness of the steel.
Pipe-Conveyed Logging
Where the borehole deviation is such that it is not possible to run tools
using conventional wireline techniques, tools are typically run on drillpipe. In
essence, this is no different from conventional logging. However, there are a
number of important considerations.
Because of the need to provide electrical contact with the toolstring, the
normal procedure is to run the toolstring in the hole to a certain depth before
pumping down a special connector (called a wet-connect) to connect the cable to
the tools. Then a side-entry sub (SES) is installed in the drillpipe, which allows
the cable to pass from the inside of the pipe to the annulus. The toolstring is then
run in farther to the deepest logging point, and logging commences. The reason
the SES is not installed when the toolstring is at the surface is partly to save time
while running in (and allowing rotation), and also to avoid the wireline extending
beyond the last casing shoe in the annulus. If the openhole section is longer than
the cased hole section, the logging will need to be performed in more than one
stage, with the SES being retrieved and repositioned in the string.

42. 38
Pipe-conveyed logging is expensive in terms of rig time and is typically
used nowadays only where it is not possible to acquire the data via LWD.
Most contractors now offer a means to convert an operation to pipe
conveyed logging if a toolstring, run into the hole on conventional wireline,
becomes stuck in the hole. This is usually termed “logging while fishing.”
4.4 Well Logging Methods
Wire line logging methods can classified based on physical principle of
several measurements such electrical (resistivity/conductivity, nuclear radiation,
elastic wave propagation properties, atomic effect, borehole geometry, borehole
wall (Pic. 073). There are two type of tools in the Logging methods, Passive tools
and Active tools. Passive tools measures properties or parameters delivered by
the formation or interaction –borehole-fluids without any source. Active tools
measure the signal, pulse, radiation, etc. typically they have a source and
detectors.
Pic. 073. Logging methods
The tools are describe by its response function its vertical resolution,
radius investigation (Pic. 074), and the tools have a specific vertical resolution,
means describe the ability to detect and separate layers individually (Pic. 075)

43. 39
Pic. 074. Radial characteristic and response, G® Integral and g® Differential
Response
Pic. 075. Depth of investigation and vertical resolution some tools.
4.5 Lithology logs
There are two logs we will described here are used to determine lithology
SP (spontaneous potential) log and GR (Gamma Ray) log (Pic. 076).

44. 40
Pic. 076. SP (spontaneous potential) log and GR (Gamma Ray) log
4.5.1 SP (spontaneous potential) Log
The first is called the SP (spontaneous potential) log. The SP
(spontaneous potential) refers to do the naturally occurring electric chemical
potential of cation. for example, when the drill bit penetrates the boundaries
between porous, permeable zones and the non-permeable surrounding shales
the equalibrium of these cation is disturbed causing them to move. These moving
cations which have been activated by the release at the boundaries can then be
measured using this log (Pic. 077), the data obtained is used to identify potential
sedimentary reservoir and to establish their thickness, and depth from the
surface (Pic. 078).

45. 41
Pic. 077. SP (spontaneous potential) log measurement
Pic. 078. SP Establish the thickness and depth
4.5.2 GR (Gamma Ray) Log
The second log GR (Gamma Ray) log measures the intensity of naturally
occurring gamma ray emissions in the surveyed formations. Containing an
installation counter that records the intensity of naturally occurring gamma ray,
these tools like geiger counter. because shale rock typically a bit high level of
radiation while sandstone or limestone reservoir rock typically a bit lower level of
radiation, these deflections can indicate for bed boundaries between shale and

46. 42
the reservoir rock, the reservoir rock the exact depth, and it's thickness (Pic.
079). Thus like SP log the GR log can give indication lithology identification.
Because the saltier mud water in the formation can obscure the results of the SP
log the SP and GR log are done in tandem to a sure accurate lithology
identification.
Pic. 079. GR (Gamma Ray) log measurement
4.6 Porosity Logs
Next the following three types of logs are used to measure the porosity of
the well. They are the one density log, two the neutron log, and three this sonic
log (Pic. 080). let we discussed how each of these is used in more detail.

47. 43
Pic. 080. Porosity Logs
4.6.1 Density Log
The density log is made by a radioactive source that is placed into the
sonde that records the emissions of gamma radiation, emitted from a radioactive
source these high intensity gamma rays differ from the naturally occurring ones
recorded on the GR log (Pic. 081).
Pic. 081. Density logs measurements

48. 44
This emitted gamma ray are directed into the formation and a detector
records how many reflected back to the sonde, the more gamma ray that
reflected back the lower the formations density. The lower density reading
indicates higher porosity (Pic. 082).
Pic. 082. Density logs recording process and data indication
4.6.2 Neutron Log
Second the neutron log records emissions from a neutron generating
radioactive source that is placed into the neutron sonde, a detector measures the
amount of neutrons captured, neutrons are highly influenced by the amount of
hydrogen that is present in the formation. Hydrogen found in water, oil, and gas
will greatly effect the amount of neutron that are captured. Porosity from the
formation is also related to the rate of capture of neutron because fluid with
hydrogen are present in porous rock, thus this the more hydrogen atoms present
indicates the greater porosity of the rock (Pic. 083).

49. 45
Pic. 083. Neutron porosity recording process and data indication
4.6.3 Gas Zone
Gas however contains much less hydrogen then water or oil, the presence
of gas we'll give a very low or false reading of the porosity, this porosity therefore
is compared with the density porosity, and gives us a better indication of the
presence of gas. High gas saturation rather than oils saturation, In the illustration
(Pic. 084), here we can see the density curve and the neutron curve well
generally track each other in measuring the porosity, but in a gas zone the
neutron curve greatly distorts the data, an indication of error when comparing the
two logs gives a good indication that this is a gas zone.
Pic. 084. Gas zone indication from Density-Neutron

50. 46
4.6.4 Sonic Log
Third the sonic log is the logging tool that generates is sound pulse that is
measured by its travel time through the formation by receivers noticed some
distance from the sound generators. this travel time or transit velocity is related to
porosity (Pic. 085), also by subtracting the sonic porosity results from the neutron
porosity results, we can more accurately separate the intergranular and vugular
porosity (Pic. 086), in addition knowing the lithologies rock from the SP and GR
logs the porosity can be more accurately calculated to give us total porosity.
Pic. 085. Sonic log recording proces

51. 47
Pic. 086. Neutron - Sonic log data indications
4.7 Resistivity Log
After identifying the boundaries, lithology and porosity (Pic. 087) with the
previous tools the engineer next needs to know something about fluid type.

52. 48
Pic. 087. Lithology Logs and Porosity logs
The resistivity log helps get us the fluid type information. Salty water made
of sodium and chlorine with the abundance of free ions within the pore space
conducts electricity better than oil or gas. This difference in conductivity in the
case of salty water or resistivty in the case of crude oil or gas can be measured
on the resistivity logs, as can be seen crude oil or gas is much more resistive to
the electrical current in salty water (Pic. 088).

53. 49
Pic. 088. Resistivity log recording process and data indication (fluid type)
In addition the resistivity log will give a good indication of the type of
saturation that is in the reservoir rock, also helps to establish a good
approximation of the oil water contact line (Pic. 089).

54. 50
Pic. 089. Resistivity data indication (fluid saturation)
4.7.1 Fluid Saturation (Archie formula)
Almost all saturation computation methods rely on work originally done by
Gus Archie in 1940-1941, he found from laboratory studies (Pic. 090) that in a
shale free, water filled rock, the formation factors (F) was a constant defined by
(Ro) equals (F) times (Rw), where (Ro) is the resistivity of the total formation, and
(Rw) is the resistivity of the water in the formation. he also found that (F) varied
with porosity in the follows relationship (F) equals (a) over theta (m) power (Pic.
091), combining these two equations gives (Ro) equals a over tetha (m)
empower times (Rw), where (Rw) is measured by taking water samples from the
well, archie then found a relationship between water saturation (Sw) and (Rt)
over (Ro), where (Sw) negative power of two equals (Rt) over (Ro), substitue
equation, we get the famous archie equation (Sw) equals one over Porosity or
tetha times square root of (Rw) over (Rt), where porosity is measured from a
density or sonic log, (Rt) is measured from the resistivity log and (Rw) is
measured from water samples taken from the formation.
The equation gives a simple approximation to estimate the hydrocarbon
saturation, (So) equals (1-Sw). More complex versions of the Archie equation
have been developed to include more complex lithologies.

55. 51
Pic. 090. Gus Archie - laboratory studies for Fluid Saturation
Pic. 091. Archie formula (Water Saturation)

56. 52
4.8 Caliper Log
The caliper log, it is used to physically measure the diameter of the
borhole from bottom to top, the hole diameter can give an indication of the type of
rocks present, a general indication of permeability and it gives the drilling
department an indication of potential hole problems (Pic. 092).
Pic. 092. Caliper log process, potential hole problem, and data indication
When using this tool several string loaded arms or the caliper are lower to
the bottom of the borehole, as the sonde raised it measures the hole diameter,
knowing the size of the hole is critical. A hole that is on gauge are equal to the bit
size can help located non permeable formation. For example a hole that is larger
in diameter than the bit can indicate weak or unconsolidated formations,
conversely holes that are smaller than the bit can indicates swelling shales, or
large mud cake development, which indicates porous permeable zones (Pic.
093). Each of these indications can impact the drilling program and needs to be
factored into that program.

57. 53
Pic. 093. Caliper log - mud cake development (porous permeable)
In addition the results from the caliper log can help in calculating the hole
volume, which will become necessary when determining the quantity of cement
needed for casing (Pic. 094) it is also good for locating good parker seats for the
DST.
Pic. 094. Caliper log - calculating the hole volume
4.9 Others Well Logs
There are two another logs we will describe in this book, they are NMR
(Nuclear Magnetic Resonance) measurements and Imaging techniques.

58. 54
NMR measurements use the interaction of Hydrogen nuclei with an
external magnetic field. Hydrogen nuclei (protons) have a magnetic and an
angular momentum. In an external magnetic field Interaction results in
precessing motion with a typical frequency. Hydrocarbon nuclei are a component
of fluid molecules of water and hydrocarbon in the pore space.
We can describe the principle of an NMR borehole tool (Pic 095). The
static magnetic field B0 is a function of the radial distance from the tool axis. For
a given magnitude of the field, the Larmor frequency is defined. Realizing the
measurements within this frequency band relates the measurements to an
exactly define radial distance (response space, sensitive volume).
.
Pic. 095. The principal of NMR tool
Here in the picture (Pic 096) the example of NMR analyses. The pore
volumetric portioning of T2, the dominant CBW indicates the indication in the
shaly parts on top and bottom, and the BVM in the reservoir zone.

59. 55
Pic. 096. NMR Log example
In Imaging Techniques log, the acoustic or electrical resistivity scanning
techniques can create electronic picture as image of the borehole wall in optically
non-transparent fluids (mud). It has an azimuthal orientation and characterize in
high resolution. The image carry information such bedding dip, faults, vug and
pore type, fractures etc.
The acoustic borehole televiewer (Pic. 097), scans the borehole wall with
a rotating ultrasonic beam. The transducer emits a high frequency signal, which
passes the mud and is reflected at the borehole wall. The reflected signal passes
the mud in the opposite direction and its received by a transmitter.

60. 56
Pic. 097. The principal Acoustic Bore Televiewer and Electrical Formation
Microscanner
Here are the picture (Pic. 098) the amplitude is color-coded in most case
and therefore looks like a real picture. Typical reading of electrical scanning
system may the high amplitude in smooth dense formation and hard layers,
medium amplitudes in porous rocks or shale, locally low amplitudes at factures or
vugs, etc.

61. 57
Pic. 098. Example Acoustic borehole televiewer
5. LOG INTERPRETATION
Generally the log interpretation goal is the determination of Lithology
characteristic, reservoir zone, shale content and shale type, Porosity (and
mineral composition), fluid saturation, type and moveable hydrocarbon, and
permeability etc.
The fundamentals and tools for log interpretation are knowledge of
characteristic log responses, equation and model of quantitative interpretation,
Implementation of all information (geology, cutting, cores, etc.).
5.1 Quick-Look Methods
Quick-look methods are helpful due to its provide flags or indicators that
point to possible hydrocarbon zones requiring further investigation. There is a
flowchart (Pic. 99) for scanning logs to identify zones of interest.

62. 58
Pic. 99. Flow chart for Scanning logs
The permeability of a formation is necessary for production, if a formation
is permeable, it has also got a certain amount of porosity/ Permeable beds can
be identified quickly using indicators such SP, Mud filtrate invasion (by
resistivity), and the presence of mud cake (Pic. 100).
Pic. 100. Example identification of permeable bed

63. 59
5.2 Quantitative Interpretation
Shale content can be estimate by SP, GR, and Neutron Density
combination logs. Calculation of the shale volume Vsh used for reservoir
description, volumetric rock model and various shale correction.
Porosity can be determined from GR-Density, Neutron log and Sonic log.
Porosity calculation requires the matrix properties and fluid properties. The matrix
properties can be determined from Lithology or mineral composition, Core (grain
density) and Cross plot techniques.
In the presence of borehole fluid invasion into gas-bearing reservoir, some
specific conditions must be considered. Invasion tends toforce the gas from the
formation and replace it with borehole fluid. porosity calculation from neutron and
Gamma-Gamma-Density measurement needs fluid properties. The influence
upon the two porosity logs depends on their radial sensitivities and their depths
of investigation.
If the invasion fluid front gets deep into the reservoir, the neutron and
density porosity measurements approach the true porosity for the assumption of
mud filtrate density and neutron response as fluid properties.
For shallow invasion the tools response are spatially weighted averages of
the invaded and non-invaded regions of the formation. The problem in deriving
porosity in the presence of shallow invasion come from the fact that the neutron
and density logging devices have different radial response (Thermal neutron
porosity 15-30cm & density 5-8cm).
5.3 Porosity and Mineral Composition
The importance of an exact porosity value for reservoir characterization
and fro calculation of other properties (saturation), mostly two or more
independent methods for porosity are applied. This gives the possibility of
multiple porosity methods.
There are several techniques for multiple porosity, they are overlays of
two logs technique (Pic. 101), cross plot (clean matrix) technique (Pic. 102),
Numerical solution technique.

64. 60
Pic. 101. Example Overlays of GR,Resistivity,Density-Neutron porosity logs
Pic. 102. Example Neutron-Density Crossplot

65. 61
In most cases the density porosity, with an appropriate choice of fluid
density, is still recommended. However, a calibration against the conventional
core analysis, corrected to in-situ conditions, should be made. The core data
should be depth-shifted to match the logs and plotted together with the
calculated porosity. A histogram should be made of the core grain density
measurements to determine the appropriate value to use in the sands (Pic.103).
Pic. 103. Example Core Calibration of Porosity
5.4 Water and Hydrocarbon Saturation
The determination of water saturation Sw is after shale content and
porosity, the Hydrocarbon saturation So equal 1(one) minus Sw. Calculation of
water saturation applies electrical methods, due to formation water is an
electrolytic conductor and hydrocarbons are insulator. Electrical methods cannot
distinguish between oil and gas but the Neutron log separate them.
Tools with different radial depth of investigation (deep-reading logs and
micrologs) evaluate water saturation in the non-invaded zone Sw and saturation
with mud filtrate Sxo in theinvaded zone. This technique results in a saturation
profile and a determination of moveable and non-moveable hydrocarbons.
In clean rocks the formation water is the only conductive component-
electrical properties are described by Archies equations. If shale is present, a
second electrical conductivity component occurs and Archies equation must be
replaced by a shaly sand equation. The two dominant case of shale presence in
a rock are laminated and dispersed shale (Pic. 104).

66. 62
Pic. 104. Shaly sand model, graph and Plot
5.5 Pressure or Sampling
In most cases there will be a requirement to run the pressure/sampling
tool to acquire pretests and possibly downhole samples. While these data are
also used by the reservoir and production engineer, they can be extremely
valuable to the petrophysicist in determining the fluids present in the formation.
Pretests can provide the following information:
a) The depths of any FWLs or GOC in the well
b) The in-situ fluid densities of the gas, oil, and water legs
c) The absolute value of the aquifer pressure and formation pressure
d) A qualitative indication of mobility and permeability
e) The bottomhole pressure and temperature in the wellbore
Additionally, acquiring downhole samples can provide the following
information:
a) Pressure/volume/temperature (PVT) properties of the oil and gas in the
reservoir
b) Formation-water salinity
c) Additional mobility/permeability information
In the conventional mode of operation, a probe is mechanically forced into
the borehole wall and chambers opened in the tool into which the formation
flows. Pretest chambers are small chambers of a few cubic centimeters that can
be reemptied before the next pretest station. For downhole sampling, larger
chambers are used, typically 23/4 or 6 gallons. Since the first fluid entering the
tool is typically contaminated by mud filtrate, normal practice is to make a
segregated sample; that is, fill one chamber, seal it, and then fill a second
chamber (hopefully uncontaminated). Once the chambers are retrieved at

67. 63
surface, they may be either drained on the wellsite or kept sealed for transferring
to a PVT laboratory.
Pretests and sampling are often not successful. Moreover, the fact that the
tool is stationary in the hole for long periods means that there is a higher than
usual chance of getting the tool stuck in the hole. One of these problems can
occur:
a) Seal failure. The rubber pad surrounding the probe, which provides a seal
between the mud pressure and the formation pressure, may fail, resulting in a
rapid pressure buildup to the mud pressure.
b) Supercharging. Tight sections of the formation may retain some of the
pressure they encounter during the drilling pressure (which is higher than the
static mud pressure). The pretest pressure is measured as a pressure that is
anomalously high.
c) Dry test. If the formation is very tight, there may be a very slow buildup of
pressure in the pretest chambers, and it is not operationally feasible to
attempt to wait until equilibrium is reached.
d) Anomalous gradients. If sands are isolated even over geological time scales,
then they may lie on different pressure trends, not sharing a common aquifer
of FWL. Also, if any depletion has occurred in the reservoir or the reservoir is
not in a true equilibrium state (for instance, due to a slowly leaking seal or
fault), then gradients may not be meaningful.
At this point it will probably be helpful if the distinction is explained among
FWL, FOL (free oil level), OWC, GWC (gas/water contact), and GOC and how
they are related in pressure measurements (Pic. 105).
Pic. 105. Example of Formation Pressure Plot

68. 64
The FWL is the point at which the capillary pressure, Pc, in the reservoir is
zero and below which depth no hydrocarbons will be found within that pressure
system. Often the FWL may be related to the spill point of the structure,
particularly where there is an abundant supply of hydrocarbons in the system. On
a formation pressure/depth plot, the intersection between the points of the oil and
the water (or gas and water) will fall at the FWL.
Above the FWL, Pc is available to allow the drainage of water by
hydrocarbons. However, particularly in low-permeability rocks, a certain entry
pressure is required before the value of Sw can fall below unity. Once this
pressure is reached, hydrocarbons will be found in the rock and one can be said
to be above the OWC or GWC. Note that between the FWL and the OWC/GWC,
pressure points will continue to fall on a waterline.
For an oil/gas reservoir, the pressure will rise above the OWC on a trend
corresponding to an oil gradient (but intersecting the waterline at the FWL). At
the GOC, technically one would expect some kind of similar FWL/OWC effect to
occur with an FOL. However, the situation is not the same as at the OWC,
because one is dealing with three phases (gas/oil/water) and not two, as before.
Hence, it is common practice to treat the GOC as being the same as the
intersection point of the gas and oil pressure lines.
For a gas-only reservoir, the pressure will rise above the GWC on a trend
corresponding to a gas gradient (but intersecting the waterline at the FWL).
5.6 Permeability
During a typical pretest, the pressure gauge will show a behavior (Pic.
106). The behavior of the pressure buildup, analogous to a production-test
buildup, may be used to estimate the properties of the formation. The mobility
(M) of the formation is defined by:
M = (k / µ)
Where k = permeability of formation, in md, and m = viscosity of fluid
entering chamber, in centipoises (cp).

69. 65
Pic. 106. Pressure Measurements During a Pretest
It may be shown theoretically that the mobility of the formation is related to
the drawdown pressure, drawdown time, and flow rate. From analysis of the
buildup, there will be a mobility estimate.
For conversion of the mobility to permeability, the viscosity needs to be
known. In most cases the pretest chamber will be filled with mud filtrate, either
water or oil based.
In general, pretests should be used to verify that a zone has some
permeability, but the other methods used (e.g., permeability as derived from a
poroperm relationship) are to determine an average permeability to be used in
dynamic models. A pretest permeability being lower than that derived from a
poroperm relationship may be a result of formation damage occurring while
drilling. This may also be observed when the zone is tested for production.
5.7 Core Capillary Pressure Analysis
Core capillary Pressure Analysis or can be call SCAL (Special core
Analysis). Special core analysis is a laboratory procedure for conducting flow
experiments on core. Special core analysis separates from "routine or
conventional core analysis" by adding more experiments.
These experiments include the measurements of two-phase flow
properties, determining relative permeability. The relative permeability of a phase
is a dimensionless measure of the effective permeability of that phase. It is the
ratio of the effective permeability of that phase to the absolute permeability.

70. 66
In relative permeability measurements, this method test sample is
confined at the ends between samples having same properties. The intimate
contact is maintained between the three cores which eliminate the capillary
effects on test sample. The saturation distribution of fluids in test sample will
uniform during the steady flow.
The upstream plug also serves as mixing head for the injected fluids. The
cores are saturated with fluids to be displaced which are commonly oil and the
weight of test section is recorded. A constant oil flow rate established such that
the desired pressure drop occurs. After that oil flow rate is slightly reduced and
the displacing fluids (water, gas) are injected in the sample at a sufficient rate to
maintain this pressure drop.
When input and outflow volumes are equal, equilibrium is established. The
oil rate decreased further and the gas, water flow increased proportionally. The
porosity and relative permeability also measured before the test.
A small core sample does not represent the average behavior of a
reservoir. For this purpose sufficient, properly selected cores are analyzed for
reasonable statistical sampling. There are two fundamental factors on which
effect the relative permeability. Wettability alterations and Saturation history
effects
WETTABILITY ALTERATIONS
Laboratory flow test commonly conducted on the cores which are
thoroughly cleaned and dried. The test fluids used are mainly synthetic brines ,
air or nitrogen because the
use of actual reservoir fluids may introduced the severe problems.
Because the reservoir temperature and pressure are not simulated in the
laboratory so the wettability results of the normal laboratory system is accidently
same as the reservoir. The alterations in wettability may change the relative
permeability behavior of the sample. The wettability may be visualized in terms of
contact angle (Pic. 107).

71. 67
Pic. 107. Simply Oil-Water-Rock System-3 stages of wettability
• (A) Zero contact angle represents the complete wettability by water
• (B) Intermediate wettabilities are indicated by angle between extremes 90.
• (C) A contact angle of 180 denotes the complete wettability by oil.
SATURATION HISTORY EFFECTS
Relative permeability is not a unique function of saturation but it depends
on the direction from which saturation approaches. The curve obtained by
displacing oil with water is not same as those from reverse processes. There are
two histories which are:
1. Gas drive process - Displacement of oil by gas, where oil is assumed as
wetting phase. This is also known as drainage process.
2. Water drive process - Displacement of oil by water, where water is assumed
as wetting phase
CAPILLARY PRESSURE
Capillary pressure is the difference between the ambient pressure and the
pressure exerted by the column of liquid. Capillarity is the phenomenon whereby
liquid is drawn up a capillary tube. Meniscus is the curved upper surface of a
liquid in a tube (Pic. 108).

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Pic. 108. Capillary tube in a liquid filled tank
Capillary tube in a liquid filled tank (Pic. 109) The pressure on the water
level equals the pressure due to the hydrostatic head of water (h) minus the
capillary pressure across the meniscus.
There are several factors on which capillary pressure depends on such
Capillary pressure increases with tube diameter, Translated into geological terms
the capillary pressure of a reservoir increases with decreasing pore size or more
specifically pore throat diameter. And Capillary pressure is also related to the
surface tension generated by the two adjacent fluids, it increases with increasing
surface tension.
6. INTEGRATION WITH SEISMIC
6.1 Synthetic Seismograms
There are two elements to synthetic seismograms. The first is the
derivation of the acoustic impedance (AI) from the log data, from which
reflectivity may be derived. The second is the conversion of the depth related
traces from a depth reference to a time reference so they can be compared with
seismic sections.
In order to make the well-derived AI(t) and R(t) comparable with the
seismic log, it is necessary to convolve them with a zero-phase wavelet.
Mathematically this is done by applying a zero-phase filter. One such example is
a Butterworth filter (Pic. 109), specified by four frequencies, such that ramps
occur between the min/max frequencies and the middle frequencies, between
which no attenuation is applied.

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Pic. 109. Example of Butterworth Filter
In the picture (Pic. 110) shows an example of logs converted to time and a
synthetic AI trace.
Pic. 110. Example of Synthetic Seismogram

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6.2 Fluid Replacement Modelling
Fluid replacement is a central part of AI modeling or creating synthetic
seismograms. In essence it involves predicting how the sonic or density log will
change as one porefluid replaces another
6.3 Acoustic/Elastic Impedance Modelling
There are two approaches to AI modeling. In the first approach, the AI
response of the same formation, encountered with a different porefill in different
wells, may be compared and also contrasted with the response of the
surrounding shales. While one would expect that the water leg would have the
highest AI, followed by the oil and gas legs, this is not always the case if the
reservoir quality is changing between wells. Fuzzy logic techniques are usually
used to fit AI distributions to the different facies types (water bearing, oil bearing,
gas bearing, and nonreservoir) and compare these to see the extent to which
they overlap. They will be distinguishable on seismic only if the distributions do
not overlap. In the picture (Pic. 111) shows an example of some distributions. In
the example given, which is based on real data, it may be seen that there is
extensive overlap between the distributions. Also, because the formation quality
was poorer in the well that encountered gas, the mean AI for the gas sands was
higher than that for the water/oil zones. This illustrates the fact that lithology
effects are usually an order of magnitude greater than fluid effects.
Pic. 111. Comparison of Acoustic Impedance Distributions for the Same
Formation Penetrated in Different Wells

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In the second approach, one may use the formation as seen in just one
well, and use the Gassmann equations to predict the change in AI as the porefill
is changed. In the example given, a well that found the sand to be oil bearing
was used to model the effect of changing the porefill to gasand water. In the
picture (Pic. 112) shows the distributions. It remains the case that the sands
would be overshadowed by the underlying shale distribution, although, as
expected, the gas case shows a lower AI than the oil case, which is itself lower
than the water case
Pic. 112. Comparison of Acoustic Impedance Distributions for the Same
Formation in One Well Modeled with Different Porefills
7. WELL DEVIATION, SURVEYING, AND GEOSTEERING
7.1 Well Deviation
The trajectory of a deviated well may be described in terms of its
inclination, depth, and azimuth. The inclination of a well at a given depth is the
angle (in degrees) between the local vertical and the tangent to the wellbore axis
at that depth (Pic 113). The convention is that 0 degrees is vertical and 90
degrees is horizontal. Parts of a degree are given in decimals, rather than
minutes and seconds. Gravity varies with latitude, and its direction may be
influenced by local features such as mineral deposits and mountains, as well as
the Earth’s rotation.
Depth in boreholes is measured either along the hole itself, in which case
it is referred to as measured or alonghole depths, with reference to a fixed point,
or as true vertical depth (TVD) with reference to a datum. Depth references that
are commonly used are as follows:

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• Derrick floor. This is the elevated deck on which the rig crew work, typically 10
m or so above ground level on a land rig and 20–30m on an offshore rig. Also
sometimes referred to as a rotary table.
• Kelly bushing. This is the top of the bushing, which rotates on the derrick floor
(although kellys are rarely used on modern drilling rigs with topdrives) and is
typically 1 ft higher than the derrick floor.
• Mean sea level. This is the elevation of the sea, averaging out the effect of
tides or seasonal variations. Usually the topography department will establish the
elevation of a land location prior to drilling. For offshore locations, the elevation of
the seabed will be known. On floating rigs, a correction using tide tables will be
used.
Pic. 113. Well Deviation
Azimuth, expressed in degrees between 0 and 360, is defined as the
angle of the horizontal component of the direction of the wellbore at a particular
point measured in a clockwise direction from magnetic north, grid north, or true
north. These are defined:
• Magnetic north. This is the direction of the horizontal component of the Earth’s
magnetic field lines at a particular point on the Earth’s surface.
• Grid north. Due to the curvature of the Earth, it is not possible to cover the
surface in a regular rectangular grid pattern using meridians (i.e., lines heading
north/south), although such a grid will be almost rectangular over limited areas.
The central meridian in a grid will be identical to true north, but vertical grid lines

77. 73
to the west of center will point west of true north in the Northern Hemisphere and
east of true north in the Southern Hemisphere.
• True north. This is the direction of the geographic north pole as defined by the
axis of rotation of the Earth. The meridians, or lines of longitude, on maps point
toward true north.
7.2 Surveying
Borehole position uncertainty defines the range of actual possible
positions of a particular point in a well in terms of eastings, northings, and TVD.
Factors that affect borehole position uncertainty are:
1. Accuracy of measured depth determination in the well. Both drillpipe and
wireline cable suffer from stretch and inaccuracies in the methods used to
measure how much pipe or cable has been run into the hole. This uncertainty
becomes greater with increasing depth and well deviation. For a vertical well
drilled to 3,500 m, one would expect the measured depth at total depth (TD) to
be known to an accuracy of roughly 2 m. For a deviated well drilled to 3,500m
TVD with a deviation at bottom of 50 degrees, this inaccuracy might rise to 5m.
2. Frequency of survey stations. When surveying a well, it is normal to acquire
“stations” at discrete depth intervals along the well. At each of these stations, the
hole’s inclination and azimuth will be measured.
3. Survey tool accuracy. Let us consider these different types of tools separately:
a) Magnetic survey tools. The accuracy of magnetic devices is limited by their
intrinsic accuracy and the extent to which they are affected by magnetic
interference.
b) Gyro survey tools. These types of tools are affected by drift in the alignment
of the gyro orientation during the survey. They are usually run only when
casing has been set in a well, so they cannot be used for decision making
during the course of drilling.
c) FINDS. These tools use highly accurate accelerometers and double-integrate
the accelerations to determine absolute distance moved by the tool during the
survey.
7.3 Geosteering
Geosteering is the use of information gained while drilling to make
realtime decisions on the trajectory of the well. Such decisions may be essential
to optimize the utility of a well. Geosteering is used in following:
a) High-angle deviated wells in thin formations where productivity can be
achieved only if the wellbore remains in a thin permeable zone and
b) Horizontal wells where it is necessary to remain a fixed distance from either a
fluid contact or an overlying tight formation, as well as during
c) Drilling in close proximity to a fault where it is necessary to establish whether
or not the fault is close and should be crossed and
d) Drilling with a fixed orientation to natural fractures.
Data that may be used in the decision-making process during geosteering
concern (1) deviation; (2) cuttings, including hydrocarbon shows and gas

78. 74
readings; (3) transmission of LWD (logging while drilling) tools in real time,
typically up/down GR (gamma ray), density, neutron, and resistivity; and (4)
drilling parameters, such as losses, kicks, rate of penetration (ROP), and torque.
Geosteering is often much harder in practice than anticipated, due to the
following factors:
1. Tools used in the decision-making process are typically run some way behind
the bit (possibly up to 30 m). Therefore, if the bit is not where you want it to
be, you will often not know about it until quite a bit of formation has been
penetrated.
2. In high-angle wells, there are often problems with real-time data transmission
through mud pulses arising from noise, high ROP, tool failures, battery life
limitations, and bandwidth.
3. Cuttings data may take up to 2 hours to reach surface (the “bottomsup” time).
Where a turbine is used, the cuttings may be very finely ground and difficult to
interpret. Also, highly deviated wells are often drilled with OBM (oil-based
mud), making hydrocarbon differentiation difficult.
4. Areal variation in the formation is usually much greater than that expected
from the working geological maps. It is very often the case that subseismic
faults of a few meters are encountered, which cause the well to suddenly go
out of the target zone. Often it is not clear whether one has exited the top or
base of the target zone, so one does not know whether to drill up or down to
get back in. Even where faulting is not present, there may be thinning or
deterioration of reservoir properties that were not envisaged.
5. Even where the right geosteering decisions can be made, control of deviation
in the well itself may be a problem. When one is entering a thin horizon at a
steep angle, it may be impossible to avoid immediately exiting the horizon on
the other side. There may also be a tendency for the bit to drop or turn to the
right or left, which cannot easily
6. be controlled. In very long horizontal wells, one may be limited by the need to
keep the drillpipe in tension and have sufficient weight on bit (WOB) to be
able to make further progress.
7. Where a horizontal well accidentally penetrates a water-bearing zone, there
may be significant practical difficulties in preventing a large proportion of the
well’s production from originating in the water zone. The possibilities of
isolating certain zones in long horizontal wells are very limited.
In spite of the above limitations, geosteering can be immensely valuable in
drilling very highly productive wells and can make the difference between a field
being economically viable or not. It may also be the case, if drilling in a
permeable formation surrounded by tight formations or in a long horizontal well,
that the bit will naturally follow a path of least resistance and steer itself within the
most permeable layer, effectively “bouncing off” the harder layers. An example of
a typical geosteered well through a thin formation is shown in picture (Pic. 114).

79. 75
With respect to the decisions made by the petrophysicist in the planning
and execution of a geosteered well, it is worthy of consideration that while one
would ideally want as many tools in the hole as possible, with both up and down
measurements of all parameters, one is necessarily limited by constraints as to
what the drillers are prepared to have in the toolstring (a greater number of tools
and their proximity to the bit affect drillers’ ability to steer the well) and what data
can be captured within the available bandwidth (of the mud pulse telemetry
system). Therefore, careful consideration should be given to which tools are most
effective in determining whether or not one is in the target formation as opposed
to above or below it.
Pic. 114. Example of Geosteered Well
Bear in mind that the density/neutron tools require the toolstring to be
rotating for meaningful data to be obtained, and when changing the well course it
is often necessary to slide the toolstring using a turbine and bentsub. Resistivity
data are generally more reliable, since they are not a statistical type of
measurement. The LWD-GR devices can generally be placed closer to the bit
and may be sufficient in many cases for determining whether one is exiting a
target formation from above or below. If a long bit run is planned, battery life may
be an issue (typical battery life is 50–100 hours), as may the downhole memory
in which data, assumedly, are being recorded, which may become full after a
certain number of hours. It is generally recommended to always record the data
in a downhole memory in addition to pulsing to surface. To avoid making
additional runs with pipe-conveyed logging at TD, it may be considered
worthwhile to include tools in the toolstring set to only record downhole and not
pulse to surface.
When permeability or presence of fractures is a particular issue, there may
be a requirement for tools (such as NMR, pressure testing, or sonic) that are not

80. 76
available from all the contractors. Data that are missing or of poor quality may be
reacquired during a round trip, either once TD is reached or at some other point
during pulling out of or running in the hole. Such decisions are typically made in
conjunction with the drillers. It is recommended at the start of a geosteered well
to set up a strict and rigorous system of naming data files transmitted from the rig
to the office, so that there is no confusion as to whether data are pulsed or
memory, and whether or not they were acquired during drilling or tripping.
Distinctions also need to be made between up/down data and data for which
depths have been corrected to be consistent with previous runs or known casing
shoes, etc.
For a geosteered well to be successful, there needs to be good
communication between the petrophysicist, wellsite geologist, office geologist,
and drilling department. The wellsite geologist, particularly if he has a good
knowledge of the field, is usually in the best position to know which formation the
well is in, but he needs the support of the petrophysicist to interpret the real-time
formation evaluation data. The necessary course of action that these two decide
upon needs to be fed back to the drillers so that the well trajectory is optimized.
8. PRODUCTION TESTS
8.1 Types of Production Tests
There are several types of production tests that can be performs but here
we will limit our discussion to the three main ones. They are number one the DST
(drill stem tests), the number two the WFT (wireline formation test), and number
three the IP (initial potential) test (Pic. 115). As we discused before the DST and
WFT are both performed an open hole while the IP is done in cased hole (Pic.
116).

81. 77
Pic. 115. Types of production tests
Pic. 116. DST and WFT - an open hole, while the IP - in cased hole
8.2 DST (Drill Stem Tests)
First DST (drill stem tests) measured fluid flow and reservoir pressure
(Pic. 117). let discused the steps involved in a drill stem test, it begins when the
drill bit or a BHA (bottom hole assembly) is pulled out and replaced with the DST
which consists of one 2 (two) more valves, two a packer or packers to form a
seal between the drill pipe and the open hole and three a pressure recorders
(Pic. 118). the DST is launch in the zone of interest, the packer or packer's are
set, then the first valve is open to expose the pressure recorder to the reserve or
where it records the formation pressure. then the second valve is open to allow
the formation fluid to flow to the surface, it's flow rate is measured along with the
saturation persentages samples are collected and sent to the lab for further
analysis (Pic. 119).

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Pic. 117. DST (drill stem tests) - fluid flow and reservoir pressure
Pic. 118. Valves, packers and pressure recorders

83. 79
Pic. 119. DST process and data analysis
This part of the test establishes whether oil gas or water will flow to or
near the surface and it what percentage of course the worst case scenario is
when the producing fluid is only salt water (Pic. 120).
Pic. 120. The main use of DST

84. 80
After a short period of time the second valve is then closed and a second
pressure measurement is recorded. Here having the rate of pressure build up go
back to the initial reservoir pressure is more important than the pressure itself
because a rapid buildup shows that the reservoir influx quickly replaced the fluids
removed during the drill stem flow test (Pic. 121).
Pic. 121. Pressure recording & chart
A rapid build up and returned to the initial formation pressure will most
likely demonstrate high permeability and a high accumulation of hydrocarbons
which are important indicators of the commercial quantity of the reservoir (Pic.
122), if however the final pressure does not return to the initial pressure level this
could indicate that the pressure in the zone has been depleted or partially
depleted and we'll probably not be able to sustain a necessary pressure over a
period of time demonstrating that this zone will most likely be ignored for further
analyses (Pic. 123).

85. 81
Pic. 122. Rapid buildup - indicators of the commercial quantity
Pic. 123. Pressure does not return - the zone has been depleted
Once the testing is complete, the packers released and the BHA is pulled
out. as the strings pulled out each stand is checked for water and oil, the number
of stands that contains oil or salt water is also recorded and becomes another
method of the evaluating the formation (Pic. 124).

86. 82
Pic. 124. The packers released and the BHA is pulled out and data are recorded
Like all tests there can be challenges when performing a DST, for
example it can often be difficult to get a good packer seating because of the
irregularities of the sides of the hole. Without a good seating the test may fail. this
is especially risky if the formation to be tested has been completely drill through,
packers set in tandem of one of the other may be used to rectify this problem, the
best solution those prevention it will require the site geologists to stop the bits
penetration before the zone is completely penetrated (Pic. 125).
Pic. 125. Difficult packer seating - the irregularities of the sides of the hole

87. 83
One last thing about DST usually run an open hole wells for a variety of
reasons they can also be run in hole that have been drilled to TD (total depth),
cased, cemented and then perforated. doing a DST at this time can avoid packer
seating problems and the possibility of getting stuck that has always present in
open whole well.
in addition because higher quality test results can be attain when
performed a case hole, it is sometimes more advantageous to wait until the hole
has been cased even with the added cost of casing cementing and perforating
especially if the formations look really promising.
8.3 WFT (Wareline Formation Tests)
In other method to obtain fluid flow and reservoir pressure data is called
WFT (wareline formation tests) it is less expensive than the DST but the data
obtained is lower quality because the samples retrieved are much smaller. in
WFT (wireline formation test) testing, the test tool is run an electrical conducting
wire (Pic. 126), the WFT is usually performed after the TD has been reach but
before the case in has been run (Pic. 127). in this method a spring forces the tool
into contact with the side of the hole so that the formation pressure and flow
sample can't be taken the main advantage of wireline formation testing is that
multiple zones can be tested at once on a single run (Pic. 128), at this point after
the TD has been reached the open hole logging swipt consisting of multiple open
hole logs is perform.
Pic. 126. WFT (wareline formation tests)

88. 84
Pic. 127. WFT (wareline formation tests) process
Pic. 128. WFT (wareline formation tests) – multi zone
8.4 IP (initial potential) Test
Finally the last test the IP (initial potential) test is conducted after the well
has been completed and equipped and what is known as cased hole or closed
hole, but before the well has unprepared for production. this very important test
allows reservoir fluid volume or flow rate and presure measurements to be
accurately determined. the IP (initial potential) test determines initial productivity
and as done over a period of from 24h - 26h (twenty four to thirty six hours) to
calculate the numbers of barrels of oil, of salt water, and the volume of gas that
can be produced during this 24h – 26h (twenty four to thirty six hours) period.
The report of the IP test is evaluated very carefully because it is often the first
dependable indication of wells productivity (Pic. 129).

89. 85
Pic. 129. IP (initial potential) test measurements
Because this test has done only after the well has been cased and after all
of its loader mud fluids have been remove, we mention it at this time only
because it completes the series of three tests, the DST, the WFT, and the IP in
more detail description of how this test is performed presented in Well
Completion.
9. CONCLUSION
In this book we have discussed the methods used to extract data from
that boreholes and describe how we measured the borhole area with the
mudlogs and various sondes in the logging swipt, how we captured rock types,
cores and how we tested pressure and fluid samples, with the DST (drill stem
test), the WFT (wire formation test) and the IP (initial potential) test.
We’ve shown how we were able to use these measurements, samples,
and test evaluations that different stages and depth of the drilling program (Pic.

90. 86
130) to help us identify any reservoir rock that was present. once identified we
added this information to the mud log as we drill and then compiled another more
detailed electronic log after TD (total depth) achieved.
Pic. 130. Well drilling Measurements, samples, and test
The logging tools the sondes, SP (spontaneus potentially) and the GR
(gamma ray) logs help us established lithology, the formation boundaries, and
thickness. the density, neutron and sonic log help calculate porosity of those
formations, the resistivity log helps determine the fluid type, the caliper log which
gives us a shape and diameter over the entire lines of the hole allows us to
calculate the volume of the hole which will be important when we begin the
casing run. The caliper log also allows us to identify the type and location of the
reservoir rock (Pic. 131). Finally knowing the hole diameter should be what it
actually is gives us notification of possible areas of concern of the length of the
borehole.

91. 87
Pic. 131. Four main of logging measurements
Along the way we continued collecting samples and performing tests that
helped us determine lithologies, porosity, permeability, and saturation or types of
fluid present in that rock and perform Log Interpretation (Pic. 132).
Pic. 132. (Rock formation and fluids) properties
Next we determine the depths, size, thickness, temperature, and pressure
of the rock formation (Pic. 133). Finally by using the data from all of these
procedures that help us evaluate the formation rock and from the results of the

92. 88
seismic tests conducted earlier and also integration with seismic data that gave
us the area we were able to calculate if there was enough commercial quantities
of hydrocarbons present to continue the development of the well or field.
Pic. 133. Determine reservoir description & properties
The test describe in this book gave us valuable information about what is
in our borehole, if the wild considered dry meaning no commercial value
hydrocarbon we will plug in abandon (P&A) that well, on the other hand if the
tests were positive we will move to the next phase called well completion.

93. 89
REFERENCES
 Amao M. Abiodun , 2013, Introduction to Formation Evaluation, Presentation
Well Logging PGE, petroleum and natural gas, King saud university.
 Bora Pradyut, 2017, FORMATION EVALUATION BASED ON LOGGING DATA,
Geology & Reservoir Deptt.
 Darling Toby, 2005, WELL LOGGING AND FORMATION EVALUATION, Gulf
Professional Publishing is an imprint of Elsevier Science.
 Hemingway James, 2017(?), Formation Evaluation Using Measurements made
Through Casing, Society of Petroleum Engineers Distinguished Lecturer
Program.
 Lau Richard, Overview of the Oil Industry – Petroleum Exploration, 2014.
 Mazwan B. M. Ali etal, 2016, Optimization of Formation Evaluation by Integration
of Advanced Surface Fluid Logging and Downhole Tools in Difficult, Geological
Settings, Search and Discovery Article.
 Mohd Fauzi Hamid, Wan Rosli Wan Sulaiman, 2017(?) Fundamentals Of
Petroleum Engineering - FORMATION EVALUATION, Department of Petroleum
Engineering Faculty of Petroleum & Renewable Engineering, Universiti
Technologi Malaysia.
 Schon Jurgen, 2015, Basic Well Logging and Formation, The eBook company.
 Segunda P. Maura, Gimbe, 2015, Formation Evaluation and Uncertainty Analysis
of the Ormen Lange Field, Norwegian Sea offshore Norway, Department of
Geology and Mineral Resources Engineering - Norwegian University of Science
and Technology.
 W. M. Alward, etal., 2015, Addressing The Formation Evaluation Challenges in
South Iraq: Re-Writing The Recipe With Advanced Analysis, Research gate
publication.
 http://www.mpgpetrole**.com/fundamentals.html
 www.drill-pi*es.com
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94. ABOUT THE WRITER
Having more than 10 years of work experiences in Oil and
Gas Industry both exploration and development such as
Bandarjaya / Lampung III Project (at PT. Harpindo Mitra
Kharisama), Reevaluation of Diski Oil field - North Sumatra
basin (at TAC PEP – PKDP), and Preliminary Fractured
evaluation some oil fields (at PT. OPAC Barata-Kejora Gas
Bumi Mandiri), Evaluation for Klamono Block - Salawati Basin and Evaluation for Tebat
Agung Block - South Sumatera Basin (at Trada Petroleum Pte. Ltd.), Operation of
Kampung Minyak oilfield (at KSO Pertamina EP – PKM) and Formation Evaluation of
Tsimororo Field - Madagascar (at Lemigas), J1J3 Oil Fields - NW Java basin (at ECC).
He Was Graduated from Institute Technology of Bandung, Geology Engineering
Department in 2006 as S.T. (Sarjana Teknik) or Bachelor degree in Geology. Before that
He was graduated from SMUN 2 Cimahi (Senior High School) in 2001, and from SLTPN
9 Cimahi (Junior High School) in 1998, also graduated SDN KIHAPIT I (Elementary
school) in 1995.